CONSOL Coal Resources LP - FORM 10-K

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EX-31.1 - EXHIBIT 31.1 - CONSOL Coal Resources LP	exhibit311-12312015.htm
EX-23.1 - EXHIBIT 23.1 - CONSOL Coal Resources LP	exhibit231-12312015.htm
EX-21.1 - EXHIBIT 21.1 - CONSOL Coal Resources LP	exhibit211-12312015.htm
EX-31.2 - EXHIBIT 31.2 - CONSOL Coal Resources LP	exhibit312-12312015.htm
EX-32.1 - EXHIBIT 32.1 - CONSOL Coal Resources LP	exhibit321-12312015.htm
EX-95 - EXHIBIT 95 - CONSOL Coal Resources LP	exhibit95-mshax12312015.htm
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EX-32.2 - EXHIBIT 32.2 - CONSOL Coal Resources LP	exhibit322-12312015.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________________________

FORM 10-K

_________________________________________________________________

(Mark One)



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CNX Coal Resources LP

(Exact name of registrant as specified in its charter)



Delaware		47-3445032
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

________________________________________________________________________

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



Title of Each Class		Name of Each Exchange On Which Registered
Common Units representing limited partner interests		New York Stock Exchange

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

__________________________________________________

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. 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 o Accelerated filer o Non-accelerated filer x Smaller Reporting Company o

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

The aggregate value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $149,278,350 as of June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on the reported closing price of the common units as reported on The New York Stock Exchange on such date.

CNX Coal Resources LP had 11,611,067 common units, 11,611,067 subordinated units and a 2% general partner interest outstanding at January 31, 2016.

DOCUMENTS INCORPORATED BY REFERENCE:

None

TABLE OF CONTENTS



		Page
	PART I

Item 1.	Business	5
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	40
Item 2.	Properties	40
Item 3.	Legal Proceedings	43
Item 4.	Mine Safety Disclosures	43

	PART II

Item 5.	Market for Registrant's Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities	44
Item 6.	Selected Financial Data	46
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	93
Item 9A.	Controls and Procedures	93
Item 9B.	Other Information	93

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance of Managing General Partner	94
Item 11.	Executive Compensation	98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	107
Item 13.	Certain Relationships and Related Transactions and Director Independence	109
Item 14.	Principal Accounting Fees and Services	115

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	117
	Signatures	119

PART I

Significant Relationships Referenced in this Annual Report


•	“CNX Coal Resources LP,” our "Partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to CNX Coal Resources LP, a Delaware limited partnership, and its subsidiaries;


•	“CNX Operating” refers to CNX Operating LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of the Partnership;


•	“CNX Thermal Holdings” refers to CNX Thermal Holdings LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of CNX Operating; CNX Thermal Holdings owns a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex;


•	“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;


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


•	the “Pennsylvania mining complex” refers to coal mines, coal reserves and related assets and operations, located primarily in southwestern Pennsylvania owned 80% by CONSOL Energy and 20% by CNX Thermal Holdings;


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


•	“Greenlight Capital” refers to certain funds managed by Greenlight Capital, Inc. and its affiliates.

FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this Annual Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:


•	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;


•	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 of environmental laws thereof;


•	the effect of new or expanded greenhouse gas regulations;


•	the effects of litigation; and


•	other factors discussed in this 2015 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

ITEM 1. BUSINESS

General

We are a growth-oriented master limited partnership recently formed by CONSOL Energy to manage and further develop all of its thermal coal operations in Pennsylvania. Our 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 are a leading producer of high-Btu thermal coal in the Northern Appalachian Basin and the eastern United States due to 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.

The Pennsylvania mining complex, which includes the Bailey Mine, the Enlow Fork Mine and the 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, 2015, CNXC's portion of the Pennsylvania mining complex included 158.3 million tons of proven and probable coal reserves with an average gross heat content of approximately 13,000 Btus per pound and approximately 3.6 pounds sulfur dioxide per million British thermal units ("lbs. SO₂/MMBTU"). Based on our current production capacity, these reserves are sufficient to support approximately 28 years of production. In addition, our reserves currently 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, the 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. Generally, we operate five longwalls and 18 continuous mining sections at the Pennsylvania mining complex. The current production capacity of CNXC's portion of the Pennsylvania mining complex’s five longwalls is 5.7 million tons of coal per year. The preparation plant 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 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.

Initial Public Offering and Concurrent Private Placement

On July 1, 2015, the Partnership’s common units began trading on the New York Stock Exchange under the ticker symbol “CNXC”. On July 7, 2015, the following transactions occurred in conjunction with the Partnership completing the initial public offering of CNXC (the "IPO") (in thousands, except unit information):


•	issued 1,050,000 common units (including 188,933 common units issued upon the expiration of the underwriters' option to purchase additional common units), and 11,611,067 subordinated units to CONSOL Energy, representing a 53.4% limited partner interest in us, and issued a 2.0% general partner interest in us and all of our incentive distribution rights to our general partner;


•	issued 5,000,000 common units to Greenlight Capital and certain of its affiliates at a price per unit equal to $15.00, equating to $75,000 in gross proceeds as part of a common unit purchase agreement ("Concurrent Private Placement");


•	issued 5,000,000 common units to the public at a price per unit equal to $15.00 ($14.10 per unit net of underwriting discount) equating to gross proceeds of $75,000. After the deduction of the underwriting discount and structuring fees of $5,500 and offering expenses of approximately $4,052, the net proceeds contributed to the Partnership were approximately $65,448;


•	granted the underwriters a 30-day option to purchase up to 750,000 common units from us at the IPO price, less the underwriter discount, if the underwriters sold more than 5,000,000 common units. The underwriters partially

exercised this option and sold an additional 561,067 common units to the public at $15.00 ($14.10 per unit net of underwriting discount) equating to additional net proceeds of $7,911. The remaining 188,933 common units that the underwriters did not exercise under their option, were issued to CONSOL Energy; and


•	entered into a $400,000 senior secured revolving credit facility with certain lenders and PNC Bank, National Association, as administrative agent (“PNC Bank N.A.”), under which we made an initial draw of $200,000 and paid $3,000 in origination fees.

We used the net proceeds from the IPO, the proceeds from the Concurrent Private Placement and net borrowings under our revolving credit facility to make a distribution of $342,711, including $4,352 of offering and structure fees, to CONSOL Energy. The Partnership retained cash of $7,000. Based on the IPO price of $15.00 per common unit, the aggregate value of the common units and subordinated units that were issued to CONSOL Energy in connection with the completion of the IPO was approximately $189,916.

Organization Structure

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

Our Relationship with CONSOL Energy

One of our principal strengths is our relationship with CONSOL Energy. CONSOL Energy is a producer of coal and natural gas headquartered in Canonsburg, Pennsylvania. CONSOL Energy has 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 $1.8 billion as of December 31, 2015.

Our Rights of First Offer

CONSOL Energy granted to us a right of first offer to acquire its retained 80% undivided interest in the Pennsylvania mining complex. In addition, CONSOL Energy granted to us a right of first offer to acquire three other assets. CONSOL Energy is under not obligation to sell those assets and we are under no obligation to purchase those assets from CONSOL Energy.

Our Assets

CNX Operating, the sole member of CNX Thermal Holdings, owns a 20% undivided interest in the Pennsylvania mining complex. CNX Thermal Holdings entered into an operating agreement with CPCC and Conrhein under which CNX Thermal Holdings is named as operator and assumes management and control over the day-to-day operations of the Pennsylvania mining complex for the life of the mines. We are managed by the directors and executive officers of our general partner. As a result, the directors and executive officers of our general partner have the ultimate responsibility for managing and conducting all of our and our subsidiaries’ operations, including with respect to CNX Thermal Holdings’ rights and obligations under the operating agreement. Based on our current production capacity utilizing five longwall mining systems, our recoverable reserves are sufficient to support approximately 28 years of production.

CONSOL Energy owns 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 owns a 53.4% limited partner interest in us.

Our Operations

Bailey Mine

The Bailey Mine is located in Enon, Pennsylvania. As of December 31, 2015, CNXC's portion of the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 54.4 million tons of clean recoverable proven and probable coal with an average gross heat content of approximately 12,900 Btus per pound and 4.1 lbs. SO₂/MMBTU. While operating two longwalls, the production capacity of our portion of the Bailey Mine is 2.3 million tons (11.5 million 100% basis) of coal per year. For the years ended December 31, 2015, 2014 and 2013, our portion of the Bailey Mine produced 2.1 million tons, 2.5 million tons and 2.2 million tons of coal, respectively.

Enlow Fork Mine

The Enlow Fork Mine is located directly north of the Bailey Mine. As of December 31, 2015, CNXC's portion of the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 63.2 million tons of clean recoverable proven and probable coal with an average gross heat content of approximately 12,900 Btus per pound and 3.4 lbs. SO₂/MMBTU. While operating two longwalls, the production capacity of our portion of the Enlow Fork Mine is 2.3 million tons (11.5 million 100% basis) of coal per year. For the years ended December 31, 2015, 2014 and 2013, our portion of the Enlow Fork Mine produced 1.8 million tons, 2.1 million tons and 2.0 million tons of coal, respectively.

Harvey Mine

The Harvey Mine is located directly east of the Bailey and Enlow Fork Mines. As of December 31, 2015, CNXC's portion of the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 40.7 million tons of clean recoverable proven and probable coal with an average gross heat content of approximately 13,100 Btus per pound and 3.4 lbs. SO₂/

MMBTU. While operating one longwall, the production capacity of our portion of the Harvey Mine is 1.1 million tons (5.5 million 100% basis) of coal per year. For the year ended December 31, 2015 2014 and 2013, our portion of the Harvey Mine produced 0.7 million tons, 0.6 million tons and 0.1 million tons of coal, respectively. Longwall production commenced in March 2014.

Coal Capital

In 2016, CNXC expects to invest $24.5-$27.5 million in maintenance capital expenditures. CNXC is not expecting to invest in expansion projects in 2016.

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. 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. The following table describes the forecasted contracted position (in millions of tons) our portion of the Pennsylvania mining complex, for the years ended 2016, 2017 and 2018 as of January 19, 2016:

The sales commitments under contract are the expected sales tons and can fluctuate up or down due to nominal provisions contained within our contracts. The contractual time commitments for customers to nominate future purchase volumes under these contracts are typically sufficient to allow us to balance our sales commitments with prospective production capacity or incremental sales volume. In addition, the nominal commitment can otherwise change because of reopener provisions contained in certain of these long-term contracts. For the year ended December 31, 2015 and 2014, approximately 70% of all the coal produced from the Pennsylvania mining complex was sold under contracts with terms of one year or more for each period.

The provisions of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the provisions of these contracts vary significantly in many respects, including, among other factors, price adjustment features, price and contract reopener terms, force majeure provisions, coal qualities and quantities. The long term contracts typically stipulate procedures for transportation of coal, quality control, sampling and weighing. Most contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility and other qualities. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments or termination of the contracts. Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume within specified limits.

Substantially all of our multi-year sales contracts contain base prices, subject only to pre-established adjustment mechanisms 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) changes in electric power prices in the markets in which our customers operate, as adjusted for any factors set forth in the applicable contract. The electric power price-related adjustments, if any, result only in positive monthly adjustments to the contracted base price that we receive for our coal. Price reopener provisions are present in several of our multi-year sales contracts. These price reopener provisions may automatically set a new price prospectively 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. Some of the long-term contracts also permit the contract to be reopened for renegotiation of terms and conditions other than pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract.

Of our 2015 coal sales, approximately 72% were made to U.S. electric generators, 24% were priced on export markets and 4% were made to other domestic customers. We derive a significant portion of our revenues from three customers: Duke Energy Corporation (“Duke Energy”), GenOn Energy, Inc. (“GenOn Energy”) and Xcoal Energy & Resources (“Xcoal

Energy”) from each of whom we derived at least 10% of our total coal sales revenues in 2015. As of December 31, 2015, we had approximately eight sales agreements with these customers that expire at various times from 2016 to 2019.

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. Most 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 is by rail. We believe our proximity to our core markets, dual rail transportation options, rail-to-barge access and customized on-site logistics infrastructure 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.

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.

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.

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 (CO2), 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, including CO2, 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 coalfired 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.

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

•

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. Implementation of CSAPR Phase I began in 2015, with Phase II scheduled to begin in 2017. Judicial challenges to the rule remain pending. On December 3, 2015 the EPA issued the proposed CSAPR Update Rule to require reductions of seasonal nitrogen oxides (NOX) emissions from power plants in 23 of the original 28 proposed Eastern states to address interstate ozone air quality impacts for downwind states.


•	Mercury and Air Toxics Standards (“MATS”) Rule, which requires coal-fired power plants to reduce air toxics emissions began in April 2015. On June 29, 2015, however, the U.S. Supreme Court issued a ruling holding that the EPA should have considered compliance costs when developing the MATS rule. The Supreme Court remanded the case back to the D.C. Circuit for further review.


•	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, on October 1, 2015, finalized a lower revised standard for ozone.


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


•	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.


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


•	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 December 2015, the United Nations Climate Change Conference was held and an agreement reached between the participating countries, including the United States, to limit global warming to less than 2 degrees Celsius as compared to pre-industrial levels. This agreement, known as the Paris Agreement, calls for zero net anthropogenic emissions to be reached in the second half of the 21^st century. To become effective, at least 55 countries, representing at least 55 percent of the global greenhouse gas emissions, must sign the agreement in New York between April 22, 2016 and April 21, 2017, and adopt it within their own legal systems through ratification, acceptance, approval or accession. 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 began to regulate GHG emissions from power plants. On September 30, 2013, the EPA re-proposed New Source Performance Standards (“NSPS”) for carbon dioxide (“CO2”) for new fossil fuel fired power plants, and on June 2, 2014 re-proposed NSPS for existing and modified power plants, which rescinded the rules that were originally proposed in 2012. In addition, on June 2, 2014, the EPA announced the Clean Power Plan, which proposed to limit CO2 emissions from existing power plants through state-specific rate-based goals. On August 3, 2015, the EPA finalized the Clean Power Plan which became effective December 22, 2015. States, industry and labor organizations filed at least 17 petitions for review on the rule in the D.C. Circuit Court of Appeals.

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. 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. 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, on June 29, 2015, the EPA issued a final rule effective August 28, 2015, clarifying which waterways are subject to federal jurisdiction under the Clean Water Act, which would impose additional permitting obligations on our operations. On August 27^th, 2015, the District Court for the District of North Dakota blocked implementation of the rule in 13 states. On October 9, 2015, the U.S. Circuit Court of Appeals for the Sixth Circuit blocked implementation of the rule nationwide.

The EPA issues permits for the discharge of pollutants into surface waters, and the U.S. Army Corps of Engineers (“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 permits issued by the ACOE, which remains under litigation. 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 September 30, 2015, the EPA finalized the Steam Electric Power Generating Effluent Guidelines which set federal limits on the levels of toxic metals in wastewater that can be discharged from power plants. This, coupled with the Clean Water Act 316(b) rulemaking promulgated on October 14, 2015 that requires new and existing power plants to reduce fish mortality caused by cooling water intake structures, imposes further capital upgrades on the power generating sector.

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 in 2016. 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 thousand for our portion, 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 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 was listed as a threatened species 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 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. Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined out areas, and engage in additional training. We have also experienced more aggressive inspection protocols, and with new regulations the amount of civil penalties have increased. The actions taken thus far by federal and state governments include requiring:


•	the caching of additional supplies of self-contained self-rescuer (SCSR) devices underground;


•	the purchase and installation of electronic communication and personal tracking devices underground;


•	the purchase and installation of proximity detection devices on continuous miner machines;


•	the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;


•	the purchase of new fire resistant conveyor belting underground;


•	additional training and testing that creates the need to hire additional employees;


•	more stringent rock dusting requirements; and


•	the purchase of personal dust monitors for collecting respirable dust samples from certain miners.

On October 2, 2015, the Mine Safety and Health Administration (MSHA) published proposed rules for underground coal mining operations concerning proximity detection systems for coal hauling machines and scoops. On January 15, 2015, MSHA published a final rule requiring underground coal mine operations to equip continuous mining machines, except full-face continuous mining machines, with proximity detection systems. The proximity detection system strengthens protection for miners by reducing the potential of pinning, crushing and striking hazards that result in accidents involving life-threatening injuries and death. The final rule became effective March 15, 2015 and included a phased in schedule for newly manufactured and in-service equipment.

In 2010, MSHA rolled out the “End Black Lung, Act Now” initiative. As a result, MSHA implemented a new final rule on August 1, 2014 to lower miners’ exposure to respirable coal mine dust including using the new Personal Dust Monitor (PDM) technology. This final rule will be implemented in three phases. The first phase began on August 1, 2014 and utilizes the current gravimetric sampling device to take full shift dust samples from the current designated occupations and areas. It also requires additional record keeping and immediate corrective action in the event of overexposure. The second phase began on

February 1, 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor (CPDM) technology, which provides real time dust exposure information to the miner. We have ordered the necessary CPDM equipment which is required to meet compliance with the new rule at a cost to CNXC of $0.4 million. We are also in the process of hiring Dust Coordinators and Dust Technicians to meet the staffing demand to manage compliance with the new rule at an estimated cost to CNXC of $0.6 million. The final phase of the rule will take effect on August 1, 2016. The current respirable dust standard will then be reduced from 2.0 to 1.5mg/m3 for designated occupations and from 1.0 to 0.5mg/m3 for Part 90 Miners.

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:


•	current and former coal miners totally disabled from black lung disease;


•	certain survivors of miners who have died from black lung disease; and

•

a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner's last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

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 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. The changes have increased the cost to us of complying with the Federal Black Lung Benefits Act. In addition to the federal legislation, we are also liable under various state statutes for our portion of black lung claims.

Employees

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. The directors and executive officers of our general partner manage our and our subsidiaries’ operations and activities. The executive officers of our general partner are employed and compensated by CONSOL Energy or its affiliates, other than the general partner. Under our omnibus agreement with CONSOL Energy, we reimburse CONSOL Energy for compensation related expenses (including salary, bonus, incentive compensation and other amounts) attributable to the portion of an executive’s compensation that is allocable to our general partner. Pursuant to the operating agreement with CONSOL Energy, CNX Thermal Holdings, a wholly-owned subsidiary, manages and controls the day-to-day operations of the Pennsylvania mining complex. Under our employee services agreement with CONSOL Energy, CONSOL Energy employees 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 are employed by CONSOL Energy or its subsidiaries and are subject to the employee services agreement that we entered into with CONSOL Energy. As of December 31, 2015, CONSOL Energy employed approximately 1,600 people who will provide direct support to our operations pursuant to the employee services agreement. None of the employees who provide direct support to our operations are represented by a labor union or collective bargaining agreement. CONSOL Energy considers its relations with its employees to be satisfactory.

Jumpstart Our Business Startups Act ("JOBS Act")

Under the JOBS Act, for as long as the Partnership remains an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from the SEC's reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and seeking unitholder approval of any golden parachute payments not previously approved. We may take advantage of these reporting exemptions until we are no longer an emerging growth company.

The Partnership will remain an emerging growth company for up to five years, although we will lose that status sooner if:


•	we have more than $1 billion of revenues in a fiscal year;


•	limited partner interests held by non-affiliates have a market value of more than $700 million (large accelerated filer); or


•	we issue more than $1 billion of non-convertible debt over a three-year period.

The JOBS Act also provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. The Partnership has irrevocably elected to “opt out” of this exemption and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

Available Information

CNX Coal Resources LP maintains a website at www.cnxlp.com. CNX Coal Resources LP makes available, free of charge, on this website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the 1934 Act), as soon as reasonably practicable after such reports are available, electronically filed with, or furnished to the SEC, and are also available at the SEC's website www.sec.gov. Apart from SEC filings, we also use our website to publish information which may be important to investors.

ITEM 1A. RISK FACTORS

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 $0.5125 per unit per quarter, or $2.05 per unit on an annualized basis, we must generate distributable cash flow of approximately $12.1 million per quarter, or approximately $48.6 million per year, based on the number of common units and subordinated units and the general partner interest to be outstanding. 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;


•	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.

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 a right of first offer pursuant to our omnibus agreement to purchase the undivided interest in the Pennsylvania mining complex retained by our sponsor. However, our sponsor is under no obligation to sell us additional undivided interests in the Pennsylvania mining complex and we are under no obligation to purchase additional undivided interests in the Pennsylvania mining complex from our sponsor. We may never purchase additional undivided interests in the Pennsylvania mining complex for several reasons, including the following:


•	our sponsor may choose not to sell any portion of its undivided interests in the Pennsylvania mining complex;


•	we may not make offers to buy any additional interests in the Pennsylvania mining complex;


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


•	we may be unable to obtain financing to purchase additional undivided interests in the Pennsylvania mining complex on acceptable terms or at all; or

•

we may be prohibited by the terms of our debt agreements (including our revolving credit facility) or other contracts from purchasing additional undivided interests in the Pennsylvania mining complex, and our sponsor may be prohibited by the terms of its debt agreements or other contracts from selling all or any portion of it. 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 our sponsor's undivided interests in the Pennsylvania mining complex, we or our sponsor may be unable to do so in a timely manner or at all.

We can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of CONSOL Energy's retained 80% undivided interest in the Pennsylvania mining complex. In addition, our right of first offer will terminate upon the date that CONSOL Energy no longer controls our general partner. For additional information regarding our right of first offer and its terms and conditions, please read: Item 13 - Omnibus Agreement - Our Right of First Offer.

Furthermore, if our sponsor reduces its ownership interest in us, it may be less willing to sell to us additional undivided interests in the Pennsylvania mining complex. Except for our right of first offer, there are no restrictions on our sponsor’s ability to transfer the assets covered by our right of first offer to a third party. If we do not acquire all or a significant portion of CONSOL Energy's retained 80% undivided interest in the Pennsylvania mining complex, 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 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.

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. The general economic challenges for some of our customers continued in 2015 and the outlook is uncertain. In addition, liquidity is essential to our Partnership and developing our assets. 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 steel demand in the United States and globally, which if weakened would negatively impact the revenues, margins and profitability of our metallurgical coal business including our ability to sell our thermal coal as higher-priced high volatile metallurgical coal;


•	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, as of June 2014, the domestic electric power sector accounts for more than 93% of total U.S. coal consumption. In 2015, the Pennsylvania mining complex sold approximately 72% 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. 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 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;


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


•	weather conditions in our markets which 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. Currently, China, a key participant in the seaborne market, has experienced a decrease in demand for imports while there has been an increase in availability of supply, primarily from Australia. Our average sales price per ton sold in 2015 declined 8.9% from 2014 due to oversupply and 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.

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. Competition from other producers may or may 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. Current or further consolidation in the coal industry or current or future bankruptcy proceedings of coal competitors may or may 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 may be adversely impacted 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.

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 results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.

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;


•	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. 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 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.

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

During the year ended December 31, 2015, approximately 70% 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 would 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 business, financial condition, results of operations, cash flows and ability to make cash distributions.

We derive a significant portion of our revenues from three customers: Duke Energy Corporation (“Duke Energy”), GenOn Energy, Inc. (“GenOn Energy”) and Xcoal Energy & Resources (“Xcoal Energy”) from each of whom we derived at least 10% of our total coal sales revenues in 2015. There are inherent risks whenever a significant percentage of total revenues are concentrated with a limited number of customers. Revenues from our largest customers may fluctuate from time to time based on numerous factors, including market conditions, which may be outside of our control. As of December 31, 2015, we had approximately eight sales agreements with these customers that expire at various times from 2016 to 2019. If any of our largest customers experience declining revenues due to market, economic or competitive conditions, we could be pressured to reduce the prices that we charge for our coal, which could have an adverse effect on our margins, profitability, cash flows and financial position. In addition, if any of our largest customers were to significantly reduce their purchases of coal from us, including by failing to buy and pay for coal they committed to purchase in sales contracts, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be adversely affected.

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.

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 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. Our production levels may decrease or may not be able 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.

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.

We may be unsuccessful in integrating the operations of any future acquisitions, including acquisitions involving new lines of business, with our existing operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we may evaluate and acquire assets and businesses that we believe complement our existing assets and business. The assets and businesses we acquire may be dissimilar from our existing lines of business. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of future acquisitions. Acquisitions and business expansions, including the acquisition of assets on which we have a right of first offer, involve numerous risks, including the following:


•	difficulties in the integration of the assets and operations of the acquired businesses;


•	inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas;


•	the possibility that we have insufficient expertise to engage in such activities profitably or without incurring inappropriate amounts of risk; and


•	the diversion of management’s attention from other operations.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Entry into certain lines of business may subject us to new laws and regulations with which we are not familiar, and may lead to increased litigation and regulatory risk. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions. If a new business generates insufficient revenue or if we are unable to efficiently manage our expanded operations, our results of operations may be adversely affected.

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

Our revolving credit facility limits 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 revolving credit facility contains covenants requiring us to maintain certain financial ratios. For example, we are obligated to maintain at the end of each fiscal quarter (i) an interest coverage ratio of at least 3.0 to 1.0 and (ii) a maximum leverage ratio of no greater than 3.5 to 1.0. Our ability to meet those financial ratios can be affected by events beyond our control, and we cannot assure that we will meet any such ratios.

The provisions of our 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 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. Based on our current debt level of $185,000, comprised of funds drawn on our revolving credit facility, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $1,850. 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.

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 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 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.

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

revolving credit facility 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.

Environmental regulations introduce uncertainty that could adversely impact the market for coal with potential short and long-term liabilities.

The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on species that have been identified and the current application of endangered species laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties. However, In April 2015 the US Fish and Wildlife Service (USFWS) announced a Section 4(d) threatened listing final rule for the Northern Long-Eared Bat throughout our operations area. This listing will establish habitat protection for the species but will not prevent the cause of the decline in the population of the Long-Eared bat, which is due to a disease commonly referred to as White Nose Syndrome (WNS). This listing could lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for construction activities.

The Partnership's coal business must obtain permits with associated mitigation from the Army Corps of Engineers (ACOE) for impacts to streams and wetlands that are unavoidable. In 2013, the EPA issued a draft report entitled Connectivity of Streams and Wetlands to Downstream Waters, which affects a proposed rulemaking known as the WOTUS rule that would expand the scope of the Clean Water Act (CWA) to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal Waters of the U.S. On June 29, 2015 the EPA published the final WOTUS Rule which becomes effective on August 28, 2015. This rule making will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs, add unwarranted delays to the permitting process and extend review times even further for regulatory agencies already under resourced, and lead to additional mitigation cost and severely limit the Partnership’s ability to avoid regulated jurisdictional waters.

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 December 2015, the United Nations Climate Change Conference was held and an agreement reached between the participating countries, including the United States, to limit global warming to less than 2 degrees Celsius compared to pre-industrial levels. This agreement, known as the Paris Agreement, calls for zero net anthropogenic greenhouse gas emissions to be reached in the second half of the 21^st century. To become effective, at least 55 countries, representing at least 55 percent of global greenhouse gas emissions, must sign the agreement in New York between April 22, 2016 and April 21, 2017, and adopt it within their own legal systems through ratification, acceptance, approval or accession. 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 began to regulate GHG emissions from power plants. On September 30, 2013, EPA re-proposed New Source Performance Standards (“NSPS”) for carbon dioxide (“CO2”) for new fossil fuel fired power plants, and on June 2, 2014 re-proposed NSPS for existing and modified power plants, which rescinded the rules that were originally proposed in 2012. In addition, on June 2, 2014, the EPA announced the Clean Power Plan, which proposed to limit CO2 emissions from existing power plants through state-specific rate-based goals. On August 3, 2015 EPA finalized the Clean Power Plan which became effective December 22, 2015. States, industry and labor organizations filed at least 17 petitions for review on the rule in the D.C. Circuit Court of Appeals.

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.

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. 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.

Apart from governmental regulation, investment banks both domestically and internationally have announced that they have 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, there have also been efforts in recent years to promote the divestiture by the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, of fossil fuel equities and also pressure applied to lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

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 (i) implementation of Phase I of the Cross-State Air Pollution Rule (“CSAPR”) that began in May 2015, with implementation of Phase 2 planned to begin in 2017; (ii) the issuance by EPA on December 3, 2015 of the proposed CSAPR Update Rule to require reductions of seasonal nitrogen oxides(NOX) emissions from power plants in 23 or the original 28 proposed Eastern states to address interstate ozone air quality impacts for downwind states; (iii) the October 1, 2015 promulgation by EPA for a revised National Ambient Air Quality Standard (NAAQS) for ozone pollution which further lowered the standard and resulted in more air quality non-attainment counties across the U.S.; and (iv) promulgation of the Mercury and Air Toxics Standards, known as the MATS rule, which included reduced emissions limits for particulate matter (PM), mercury, sulfur dioxide (SO2) and NOX. Although the U.S. Supreme Court issued a ruling on June 29, 2015 holding that the EPA should have considered compliance costs when developing the MATS rule, a number of coal-fired power plants, particularly smaller and older plants, already have retired or announced that they will retire rather than retrofit to meet the obligations of the MATS rules. Prior to the Supreme Court’s ruling, 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.

On October 14, 2014, the EPA Clean Water Act Section 316(b) rulemaking went into effect which requires new and existing power plants, including coal and natural gas-fired plants to reduce fish mortality caused by their cooling water intake structures through either the installation of technologies or the reduction of intake velocity.

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 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.

One such proposed regulation was issued by the Office of Surface Mining on July 27, 2015 to amend regulations concerning stream buffer zones, stream channel diversions, excess spoil and coal mine waste. As drafted, this proposed rule would extend the impacts of mining to include surrounding areas of the entire coal reserve previously not included in assessments submitted as part of the permit application. The proposed rule would also prohibit mining in or through a perennial, intermittent or ephemeral stream, even if impacts were temporary, and require a 100 foot buffer zone on either side of a stream. As drafted, this proposed rule has the potential to impact the profitability of our longwall coal mines.

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.

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.

Our sponsor owns and controls our general partner and appoints all of the directors of our general partner. In addition, our sponsor directly owns an aggregate 53.4% limited partner interest in us, 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.

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;


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


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


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


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


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

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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;


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


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

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our partnership agreement permits us to distribute up to $50.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;


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


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


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


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


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

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

Neither our partnership agreement nor our omnibus agreement 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.

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.

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. Our sponsor owns an aggregate of approximately 9.0% of our outstanding common units and all of our subordinated units.

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

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

reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action.

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

decisions that our general partner may make in its individual capacity include:


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


•	whether to exercise its limited call right;


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


•	whether to exercise its registration rights;


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


•	whether to elect to reset target distribution levels;


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


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

By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above.

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;


•	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 nonappealable 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 intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and


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

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our general partner, 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.

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 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 reimbursements for salary, bonus, incentive compensation and other amounts paid to affiliates of our general partner for the costs incurred in providing 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. The total amount of such reimbursed expenses was $5.0 million for the period ended July 7, 2015 through December 31, 2015. Payments to our general partner and its affiliates may be substantial and may 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 66.67% 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 intentional 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. Our sponsor owns 54.5% of our total outstanding common units and subordinated units on an aggregate basis. 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.

The restrictions in our partnership agreement applicable to holders of 20% or more of any class of our outstanding partnership interests will not apply to Greenlight Capital.

Unitholders’ voting rights are restricted by the partnership agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons or groups who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. In connection with the Concurrent Private Placement, our general partner waived this provision with respect to Greenlight Capital. As a result of this waiver, the common units purchased by Greenlight Capital in the Concurrent Private Placement are generally considered to be outstanding under our partnership agreement and will be entitled to vote on any matter on which the common unitholders are otherwise entitled to vote. Greenlight Capital owns 47.3% of our outstanding common units.

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

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership

agreement on the ability of our sponsor to transfer its membership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices.

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

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

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

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


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


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


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


•	the ratio of taxable income to distributions may increase;


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


•	the market price of our common units may decline.

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


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


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

Our sponsor and Greenlight Capital 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.

Our sponsor holds 1,050,000 common units and 11,611,067 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. In addition, Greenlight Capital holds 5,488,438 common units, per public filings. We also agreed to provide our sponsor and Greenlight Capital with certain registration rights under applicable securities laws. The sale of these units described above 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, common unit holders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. They may also incur a tax liability upon a sale of their units. Our general partner and its affiliates own approximately 9.0% of our common units (excluding any common units purchased by the directors, director nominees 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, our general partner and its affiliates will own approximately 54.5% 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.

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 the common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. 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.

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 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.

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 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.

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 provides 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.

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

Our common units have been approved for listing on the NYSE. Because we are 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, are not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Tax Risks

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 a common unitholder. 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. 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.

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 report 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 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.

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-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 adopted 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 a common unitholder. Our tax counsel 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 a 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.

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 tax 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.

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. 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 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. Our sponsor and our general partner collectively own an aggregate 55.4% interest in our capital and profits. 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.

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 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, unitholders 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Coal Reserves

The estimates of our proven and probable reserves are calculated by CONSOL Energy’s geologists and mining engineers, using the face positions of the Pennsylvania mining complex’s longwall mines as of December 31, 2015. The December 31, 2015 reserve calculations were computed using the same techniques as the December 31, 2014 estimates and methods, which were audited by an independent mining and geological consulting firm. 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, our reserves currently 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 crossover market adds additional assurance that our proven and probable coal reserves are commercially marketable.

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 as of December 31, 2015 (tons in thousands):



Mine	Proven Reserves (tons) (1)	Probable Reserves (tons) (1)	Total Recoverable Reserves (tons) (1)	Mine Recovery (%)		Preparation Plant Yield (%)		Out of Seam Dilution (feet)	Raw Reserves (tons)
Bailey	30,930	23,418	54,348	79.44	%	63.29	%	0.35	85,871
Enlow Fork	49,781	13,450	63,231	83.37	%	60.56	%	0.35	104,411
Harvey	25,611	15,086	40,697	79.84	%	60.16	%	0.35	67,645
Total	106,322	51,954	158,276						257,927

(1) Economic viability of the reported proven and probable coal reserves is established through a life of mine plan for each mine operation, pursuant to SEC Industry Guide 7. Economic viability is determined by providing a net value on a cash-forward looking basis which is based on historical performance, with forward adjustments based on planned changes in production volumes, in fixed and variable proportion of costs and forecasted fluctuation in costs of supplies, energy costs and wages. Coal sales prices are forecasted based on management’s internal market analysis throughout each mine’s life of mine plan. Based on these calculations, we concluded that the reported reserve tons produce a positive economic impact over each

mine’s life. Our mines operate in the Pittsburgh No. 8 Coal Seam and have historically generated positive net income and positive cash flow which demonstrates the economic viability of the coal reserves. The Pittsburgh No. 8 Coal Seam is consistent in geological formation, including seam thickness, coal quality and other characteristics. Therefore, our mines are expected to continue to produce positive economic results using mining technologies currently employed. The reported coal reserves do not exceed the quantities that we estimate could be extracted economically at average prices received and costs incurred as discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The historical three-year average realized prices received for production at these locations was $60.70 per ton.

The following table sets forth additional information regarding the recoverable coal reserves at the Pennsylvania mining complex as of December 31, 2015 (tons in millions):



			As Received Heat Value (1) (Btu/lb)			Recoverable Reserves (2) (3)
Mine	Reserve Class	Average Seam Thickness (feet)	Typical	Range	As Received Lbs. SO2 / MMBTU	Owned (%)		Leased (%)		Total (tons)
Bailey:	Assigned	7.6	12,950	12,800 - 13,040	3.9	44	%	56	%	20,217
	Accessible	7.5	12,910	12,700 - 13,170	4.2	78	%	22	%	34,131
Enlow Fork:	Assigned	7.8	12,950	12,830 - 13,200	4.3	99	%	1	%	2,173
	Accessible	7.6	13,010	12,750 - 13,150	3.4	76	%	24	%	61,058
Harvey:	Assigned	6.4	13,040	12,940 - 13,210	2.9	88	%	12	%	4,681
	Accessible	7.6	12,910	12,850 - 13,140	3.5	99	%	1	%	36,016
Total										158,276

(1) The heat value shown for assigned reserves are based on the 2015 actual quality and five-year forecasted quality for each mine/reserve, assuming that the coal is washed to an extent consistent with normal full-capacity operation of each mine's/complex's preparation plant. Actual quality is based on laboratory analysis of samples collected from coal shipments delivered in 2015. Forecasted quality is derived from exploration sample analysis results, which have been adjusted to account for anticipated moisture and for the effects of mining and coal preparation. The heat values shown for Accessible Reserves are based on as received, dry values obtained from drill hole analyses, adjusted for moisture, and prorated by the associated Assigned Operating product values to account for similar mining and processing methods.

(2) 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.

(3) Our reserves currently 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, 2015, 2014 and 2013, our portion of the Pennsylvania mining complex sold approximately 0.2 million tons, 0.3 million tons and 0.5 million tons of coal, respectively, in the metallurgical market.

ITEM 3. 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. Refer to paragraph one and two of Note 19 "Commitments and Contingent Liabilities," in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K, Incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this annual report.

PART II

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

The Partnership’s common units have been listed on the New York Stock Exchange (NYSE) under the symbol “CNXC” since July 1, 2015. Prior to that, the Partnership’s equity securities were not listed on any exchange or traded on any public trading market. The following table sets forth the range of high and low sales prices per common unit as reported on the New York Stock Exchange and the cash distributions declared on the common units from the closing of the IPO through December 31, 2015:



Period	High Price	Low Price	Distribution per Limited Partner Unit
Third Quarter 2015 (a)	$17.34	$10.68	$0.4791 (b)
Fourth Quarter 2015	$13.71	$8.25	$0.5125

(a) Since July 1, 2015, the commencement date of trading.

(b) The third quarter distribution was prorated from the closing date of the IPO based upon a minimum quarterly distribution of $0.5125 per unit per quarter.

Transfer Agent and Registrar The transfer agent and registrar for our common limited partnership units is Computershare Trust Company, N.A.

Unitholders Profile Pursuant to the records of the transfer agent, as of January 26, 2016, the number of registered holders of our common units was approximately nine. The Fourth Quarter 2015 cash distribution of $0.5125 per common unit was declared on January 28, 2016 and will be paid on February 15, 2016.

Equity Compensation Plan Information Please read “Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters - Securities Authorized for Issuance Under Equity Compensation Plans.”

Market Repurchases

The Partnership did not repurchase any of its common units during 2015.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter we distribute all of our available cash to unitholders of record on the applicable record date.

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 cash reserves established by our general partner to:


◦	provide for the proper conduct of our business (including 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 cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of 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 but on or before the date of determination of available cash for that 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 the Partnership's current cash distribution policy, the Partnership intends to make a minimum quarterly distribution to the holders of common units and subordinated units of $0.5125 per unit per quarter, or $2.05 per unit on an annualized basis, to the extent the Partnership has sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that the Partnership will pay the minimum quarterly distribution on those units in any quarter. The amount of distributions paid under the Partnership's cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of the partnership agreement. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

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.

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 in excess of $0.58938 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.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected historical financial data of CNX Coal Resources LP and its Predecessor for the periods indicated. 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. The following table should be read together with, and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in this Form 10-K. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



	For the Years Ended December 31,
	2015		2014		2013
CONSOLIDATED STATEMENTS OF OPERATIONS:	(in thousands, except per share amounts)
Coal revenue	$	257,809	$	323,398	$	271,467
Freight revenue	3,047		3,353		3,556
Other revenues and income	753		7,728		1,212
Total Revenue and Other Income	261,609		334,479		276,235

Operating and Other Costs	140,415		171,993		151,514
Royalties and Production Taxes	10,271		14,111		11,046
Selling and Direct Administrative Expenses	5,085		6,444		5,687
Depreciation, Depletion and Amortization	35,309		34,671		25,846
Freight Expense	3,047		3,353		3,556
General and Administrative Expenses	8,324		13,062		12,201
Interest Expense	8,495		6,946		2,093
Total Costs	210,946		250,580		211,943
Net Income	$	50,663	$	83,899	$	64,292

Net Income Attributable to General and Limited Partner Ownership Interest in CNX Coal Resources	$	23,356	N/A		N/A
Less: General Partner Interest in Net Income	468		N/A		N/A
Limited Partner Interest in Net Income	$	22,888	N/A		N/A

Net Income per Limited Partner Unit - Basic (1)	$	0.99	N/A		N/A
Net Income per Limited Partner Unit - Diluted (1)	$	0.99	N/A		N/A

Limited Partner Units Outstanding - Basic	23,222,134		N/A		N/A
Limited Partner Units Outstanding - Diluted	23,223,045		N/A		N/A



	As of December 31,
	2015			2014
CONSOLIDATED BALANCE SHEETS:	(in thousands)
Working Capital (2)	$	(11,156	)	$	(54,597	)
Total Assets	$	422,129		$	418,811
Long Term Debt (3)	$	181,046		$	161,160
Total Liabilities	$	239,759		$	248,185
Total Partners' Capital and Parent Net Investment	$	182,370		$	170,626



	For the Years Ended December 31,
	2015			2014			2013
OTHER FINANCIAL DATA:	(in thousands, except per share amounts)
Net Cash Provided by Operating Activities	$	60,795		$	114,109		$	94,416
Net Cash Used in Investing Activities	$	(27,201	)	$	(52,824	)	$	(67,628	)
Net Cash Used in Financing Activities	$	(27,066	)	$	(61,285	)	$	(26,789	)
Actual Maintenance Capital Expenditures	$	(27,257	)	$	(68,061	)	$	(82,182	)
Tons Sold	4,575			5,227			4,246
Tons Produced	4,558			5,213			4,287
Coal Sales Per Ton Sold (4)	$	56.36		$	61.88		$	63.93
Cost Per Ton Sold (5)	$	41.91		$	42.74		$	44.53
Adjusted EBITDA (6)	$	92,598		$	125,872		$	96,975
Estimated Maintenance Capital Expenditures (7)	$	29,708		$	30,042		$	29,573

(1) Diluted earnings per unit (“EPU”) gives effect to all dilutive potential common units outstanding during the period using the treasury stock method.

(2) Working capital is impacted by current maturities of long term debt, which at December 31, 2015, included the revolver. For information regarding long-term debt, please read “Item 8. Financial Statements and Supplementary Data—Note 10. Debt” of this Annual Report on Form 10-K.

(3) Long-term debt excludes the current portions of debt and capital lease obligations.

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

(5) Cost per ton sold is based on the total of operating expenses divided by tons sold.

(6) 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. The Generally Accepted Accounting Principles ("GAAP") measure most directly comparable to adjusted EBITDA is net income. 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.

The non-GAAP financial measures should not be considered an alternative to total costs, net income, operating cash flow, or any other measure of financial performance or liquidity presented in accordance with GAAP. These measures exclude 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, the items 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 for each of the periods indicated.



	Years Ended December 31,
	2015			2014			2013
Net income	$	50,663		$	83,899		$	64,292
Interest expense	8,495			6,946			2,093
Depreciation, depletion and amortization	35,309			34,671			25,846
OPEB plan change	(4,271		)	—			—
OPEB transition payment	—			3,299			—
Backstop loan fees	1,516			—			—
Coal contract buyout	—			(6,000		)	—
Litigation settlement	—			(855		)	—
Business interruption proceeds	—			—			(1,089		)
Bailey belt repairs	—			551			1,662
Stock/Unit based compensation	886			3,361			4,171
Adjusted EBITDA	$	92,598		$	125,872		$	96,975

(7) Our estimated maintenance capital expenditures, as defined under the terms of our partnership agreement, are those capital expenditures required to maintain, over the long-term, the operating capacity of our capital assets.

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

Overview

We are a growth-oriented master limited partnership recently formed by CONSOL Energy to manage and further develop all of its thermal coal operations in Pennsylvania. Our 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 uses 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 sold and average cash margin per ton, non-GAAP financial measures; (iii) adjusted EBITDA, a non-GAAP financial measure and (iv) distributable cash flow, a non-GAAP financial measure.

Reconciliation of Non-GAAP Financial Measures

We evaluate our cost of coal sales on a cost per ton basis. Our cost of coal sold per ton represents our costs divided by the tons of coal we sell. We define cost of coal sold as operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The cost of coal sold per ton includes items such as direct operating costs, royalty and production taxes, direct administration and selling expenses, and depreciation, depletion and amortization costs. Our costs exclude any indirect costs such as general and administrative costs and other costs not directly attributable to the production of coal. The GAAP measure most directly comparable to cost of coal sold is total costs.

We define average cash margin per ton, which is an operating ratio derived from non-GAAP measures, as (i) average coal revenue per ton, net of average cost of coal sold per ton, depreciation, depletion and amortization, as adjusted for (ii) non-production related costs.

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. The GAAP measure most directly comparable to adjusted EBITDA is net income.

We define distributable cash flow as adjusted EBITDA less net cash interest paid and estimated maintenance capital expenditures. Distributable cash flow will not reflect changes in working capital balances. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities.

Cost of coal sold, average cash margin per ton, adjusted EBITDA and distributable cash flow are used as supplemental financial measures 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.

The following table presents a reconciliation of cost of coal sold to total costs, the most directly comparable GAAP financial measure, on a historical basis for each of the periods indicated.



	Years Ended December 31,
	2015			2014			2013
Total Costs	$	210,946		$	250,580		$	211,943
Freight expense	(3,047		)	(3,353		)	(3,556		)
General and administrative expenses	(8,324		)	(13,062		)	(12,201		)
Interest expense	(8,495		)	(6,946		)	(2,093		)
Other costs (non-production)	2,610			(2,236		)	(3,846		)
Depreciation, depletion and amortization (non-production)	(1,969		)	(1,606		)	(1,157		)
Cost of coal sold	$	191,721		$	223,377		$	189,090

The following table presents a reconciliation of average cash margin per ton for each of the periods indicated.



	Years Ended December 31,
	2015			2014			2013
Total coal revenue	$	257,809		$	323,398		$	271,467

Operating and other costs	140,415			171,993			151,514
Royalties and production taxes	10,271			14,111			11,046
Selling and direct administrative expenses	5,085			6,444			5,687
Depreciation, depletion and amortization	35,309			34,671			25,846
Less: Other costs (non-production)	2,610			(2,236		)	(3,846		)
Less: Depreciation, depletion and amortization (non-production)	(1,969		)	(1,606		)	(1,157		)
Total cost of coal sold	$	191,721		$	223,377		$	189,090
Total coal sold	4,575			5,227			4,246
Average sales price per ton sold	$	56.36		$	61.88		$	63.93
Average cost per ton sold	41.91			42.74			44.53
Average margin per ton sold	14.45			19.14			19.40
Add: Total depreciation, depletion and amortization costs per ton sold	7.31			6.34			5.76
Average cash margin per ton sold	$	21.76		$	25.48		$	25.16

The following table presents a reconciliation of adjusted EBITDA to net income, the most directly comparable GAAP financial measure, on a historical basis for each of the periods indicated. The table also presents a reconciliation of distributable cash flow to net income and operating cash flows, the most directly comparable GAAP financial measures, on a historical basis for each of the periods indicated.



	Years Ended December 31,
	2015			2014			2013
Net income	$	50,663		$	83,899		$	64,292
Interest expense	8,495			6,946			2,093
Depreciation, depletion and amortization	35,309			34,671			25,846
OPEB plan change	(4,271		)	—			—
OPEB transition payment	—			3,299			—
Backstop loan fees	1,516			—			—
Coal contract buyout	—			(6,000		)	—
Litigation settlement	—			(855		)	—
Business interruption proceeds	—			—			(1,089		)
Bailey belt repairs	—			551			1,662
Stock/Unit based compensation	886			3,361			4,171
Adjusted EBITDA	$	92,598		$	125,872		$	96,975
Less:
Cash interest	7,896			9,538			9,308
Estimated maintenance capital expenditures	29,708			30,042			29,573
Expansion capital expenditures	—			39,653			32,898
Add:
Borrowings to fund expansion capital expenditures	—			39,653			32,898
Distributable Cash Flow	$	54,994		$	86,292		$	58,094

Net cash provided by operating activities	$	60,795		$	114,109		$	94,416
Less: Interest expense, net	8,495			6,946			2,093
Less: Other, including working capital	(40,298		)	(18,709		)	(4,652		)
Adjusted EBITDA	$	92,598		$	125,872		$	96,975
Less:
Cash interest	7,896			9,538			9,308
Estimated maintenance capital expenditures	29,708			30,042			29,573
Expansion capital expenditures	—			39,653			32,898
Add:
Borrowings to fund expansion capital expenditures	—			39,653			32,898
Distributable Cash Flow	$	54,994		$	86,292		$	58,094

Results of Operations

Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Total net income was $50,663 for the year ended December 31, 2015 compared to $83,899 for the year ended December 31, 2014. Our results of operations for each of these periods are presented in the table below. Variances are discussed following the table.



	For the Years Ended
	December 31,
	2015			2014		Variance
	(in thousands)
Coal revenue	$	257,809		$	323,398	$	(65,589	)
Freight revenue	3,047			3,353		(306		)
Miscellaneous other income	704			7,580		(6,876		)
Gain on sale of assets	49			148		(99		)
Total revenue and other income	261,609			334,479		(72,870		)
Cost of coal sold:
Operating costs	143,055			169,975		(26,920		)
Royalties and production taxes	10,271			14,104		(3,833		)
Selling and direct administrative expenses	5,055			6,233		(1,178		)
Depreciation, depletion and amortization	33,340			33,065		275
Total cost of coal sold	191,721			223,377		(31,656		)
Other costs:
Other costs	(2,610		)	2,236		(4,846		)
Depreciation, depletion and amortization	1,969			1,606		363
Total other costs	(641		)	3,842		(4,483		)
Freight expense	3,047			3,353		(306		)
General and administrative expenses	8,324			13,062		(4,738		)
Interest expense	8,495			6,946		1,549
Total costs	210,946			250,580		(39,634		)
Net income	$	50,663		$	83,899	$	(33,236	)
Adjusted EBITDA	$	92,598		$	125,872	$	(33,274	)
Distributable Cash Flow	$	54,994		$	86,292	$	(31,298	)

Coal Production Rates

The table below presents total tons produced from the Pennsylvania mining complex on our 20% undivided interest for the periods indicated:



	Years Ended December 31,
Mine	2015	2014	Variance
Bailey	2,037	2,465	(428	)
Enlow Fork	1,800	2,111	(311	)
Harvey	721	637	84
Total	4,558	5,213	(655	)

Coal production was 4,558 tons for the year ended December 31, 2015 compared to 5,213 tons for the year ended December 31, 2014. The 655 tons decrease was attributable to reducing the production to adjust to contracted sales commitments. The production at the Harvey Mine increased as a result of the commencement of longwall mining operations in March 2014.

Coal Operations

Coal revenue and cost components on a per unit basis for the year ended December 31, 2015 and 2014 were as indicated in the table below. Our operations also include various costs such as general and administrative, freight and other costs not included in our unit cost analysis because these costs are not directly associated with coal production.



	For the Years Ended December 31,
	2015		2014		Variance			Percent Variance
Total Tons Sold (in thousands)	4,575		5,227		(652		)	(12.5	)%
Average Sales Price Per Ton Sold	$	56.36	$	61.88	$	(5.52	)	(8.9	)%

Operating Costs Per Ton Sold	$	31.24	$	32.49	$	(1.25	)	(3.8	)%
Royalties and Production Taxes Per Ton Sold	2.25		2.71		(0.46		)	(17.0	)%
Selling and Direct Administrative Expenses Per Ton Sold	1.11		1.20		(0.09		)	(7.5	)%
Depreciation, Depletion and Amortization Per Ton Sold	7.31		6.34		0.97			15.3	%
Total Costs Per Ton Sold	$	41.91	$	42.74	$	(0.83	)	(1.9	)%
Average Margin Per Ton Sold	$	14.45	$	19.14	$	(4.69	)	(24.5	)%
Add: Depreciation, Depletion and Amortization Costs Per Ton Sold	7.31		6.34		0.97			15.3	%
Average Cash Margin Per Ton Sold (1)	$	21.76	$	25.48	$	(3.72	)	(14.6	)%

(1) Average cash margin per ton is an operating ratio derived from non-GAAP measures.

Revenue and Other Income

Coal revenue was $257,809 for the year ended December 31, 2015 compared to $323,398 for the year ended December 31, 2014. The $65,589 decrease was attributable to a $5.52 per ton lower average sales price and a 652 tons decrease in tons sold. The lower average coal sales price per ton sold in the 2015 period was primarily the result of the overall decline in the domestic thermal and global coal markets. Due to a weak domestic thermal spot market, 1,108 tons were sold on the export market for the year ended December 31, 2015 as compared to 669 tons for the year ended December 31, 2014, which negatively impacted the average sales price per ton sold in the year-to-year comparison.

Freight revenue, which is completely offset in freight expense, is the amount billed to customers based on the weight of coal shipped and negotiated freight rates for rail transportation. Freight revenue was $3,047 for the year ended December 31, 2015 compared to $3,353 for the year ended December 31, 2014. The $306 decrease in freight revenue was due to decreased shipments to customers where we were contractually obligated to provide transportation services.

Miscellaneous other income was $704 for the year ended December 31, 2015 compared to $7,580 for the year ended December 31, 2014. The $6,876 decrease was due to a $6 million coal customer contract buyout and $876 of various transactions in each period, none of which were individually material.

Gain on sale of assets decreased $99 in the period-to-period comparison due to various immaterial transactions in both periods.

Cost of Coal Sold

Cost of coal sold 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, royalties and production taxes, selling and direct administrative expenses, and depreciation, depletion, and amortization costs. Total cost of coal sold was $191,721 for the year ended December 31, 2015, or $31,656 lower than the $223,377 for the year ended December 31, 2014. Total costs per ton sold were $41.91 per ton for the year ended December 31, 2015 compared to $42.74 per ton for the year ended December 31, 2014. The decrease in the cost of coal sold was driven by a reduced workforce, approximately 90,000 less feet of coal mined with continuous mining units, improved operational efficiencies, reduction of Pennsylvania stream subsidence expense and other ongoing cost reduction efforts as a result of reducing production for 2015 to match the contracted sales commitments of the Partnership. There was also a decrease in the unit costs due to Other Post-Retirement Benefit ("OPEB") liabilities being retained by CONSOL Energy, in conjunction with the IPO.

Total Other Costs

Total other costs is comprised of various costs that are not allocated to each individual mine and therefore are not included in unit costs. Total other costs decreased $4,483 for the year ended December 31, 2015 compared to the year ended December 31, 2014. This decrease is primarily attributable to the remeasurement of the OPEB plans to reflect a plan amendment for Salaried and P&M workers that occurred on May 31, 2015. OPEB was excluded from the Partnership at the time of the IPO.

General and Administrative Expense

The Partnership has a service arrangement for CONSOL Energy to provide certain general and administrative services. These services are paid monthly based on agreed upon rates. In addition, the Partnership incurred various costs as a result of being a publicly traded entity for the year ended December 31, 2015. For the year ended December 31, 2014, CONSOL Energy allocated general and administrative expenses based upon the level of operating activity of its underlying business units. These expenses include CONSOL Energy's stock based compensation and short-term incentive compensation program as well as 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. The amount of general and administrative expenses incurred was $8,324 for the year ended December 31, 2015 compared to general and administrative expenses allocated to us from CONSOL Energy of $13,062 for the year ended December 31, 2014. The $4,738 decrease was primarily attributable to lower short-term incentive compensation payouts.

Interest Expense

Interest expense, net of amounts capitalized, was $8,495 for the year ended December 31, 2015, which includes interest on the revolving credit facility that we entered into in connection with the completion of the IPO and interest expense incurred on the CONSOL Financial Inc. ("CFI"), a wholly owned subsidiary of CONSOL Energy, loan which was excluded from the Partnership at the time of the IPO. Interest expense, net of amounts capitalized, was $6,946 for the year ended December 31, 2014, which includes interest expense incurred on the CFI loan. The $1,549 increase in the year-to-year comparison was primarily due to lower capitalized interest as a result of the commencement of longwall mining operations at the Harvey Mine in March 2014.

Adjusted EBITDA

Adjusted EBITDA was $92,598 for the year ended December 31, 2015 compared to $125,872 for the year ended December 31, 2014. The $33,274 decrease was attributed to 652 less tons sold and a $3.72 per ton decrease in the average cash margin per ton sold. The $3.72 per ton decrease in the average cash margin which was primarily a result of the $5.52 decreased coal sales price per ton offset, in part, against a $1.25 improvement in operating costs per ton sold and a $0.46 improvement in royalties and production taxes per ton sold, which resulted in a $19,428 decrease to adjusted EBITDA. The remaining decrease in adjusted EBITDA of $13,846 is primarily due to 652 less tons sold during 2015.

Distributable Cash Flow

Distributable cash flow was $54,994 for the year ended December 31, 2015 compared to $86,292 for the year ended December 31, 2014. The $31,298 decrease was primarily attributed to a $33,274 decrease in adjusted EBITDA as discussed above, offset in part, by a reduction in cash interest paid for the year ended December 31, 2015 of $7,896 compared to $9,538 for the year ended December 31, 2014.

Years Ended December 31, 2014 Compared to the Years Ended December 31, 2013

Total net income was $83,899 for the year ended December 31, 2014 compared to $64,292 for the year ended December 31, 2013. Our results of operations for each of these periods are presented in the table below. Variances are discussed following the table.



	For the Years Ended
	December 31,
	2014		2013			Variance
	(in thousands)
Coal revenue	$	323,398	$	271,467		$	51,931
Freight revenue	3,353		3,556			(203		)
Miscellaneous other income	7,580		1,336			6,244
Gain on sale of assets	148		(124		)	272
Total revenue and other income	334,479		276,235			58,244
Cost of coal sold:
Operating costs	169,975		147,668			22,307
Royalties and production taxes	14,104		11,046			3,058
Selling and direct administrative expenses	6,233		5,687			546
Depreciation, depletion and amortization	33,065		24,689			8,376
Total cost of coal sold	223,377		189,090			34,287
Other costs:
Other costs	2,236		3,846			(1,610		)
Depreciation, depletion and amortization	1,606		1,157			449
Total other costs	3,842		5,003			(1,161		)
Freight expense	3,353		3,556			(203		)
General and administrative expenses	13,062		12,201			861
Interest expense	6,946		2,093			4,853
Total costs	250,580		211,943			38,637
Net income	$	83,899	$	64,292		$	19,607
Adjusted EBITDA	$	125,872	$	96,975		$	28,897
Distributable Cash Flow	$	86,292	$	58,094		$	28,198

Coal Production Rates

The table below presents total tons produced from the Pennsylvania mining complex on our 20% undivided interest for the periods indicated:



	Years Ended December 31,
Mine	2014	2013	Variance
Bailey	2,465	2,151	314
Enlow Fork	2,111	2,022	89
Harvey	637	114	523
Total	5,213	4,287	926

Coal production was 5,213 tons for the year ended December 31, 2014 compared to 4,287 tons for the year ended December 31, 2013. The 926 tons increase was attributable to the commencement of longwall mining operations at the Harvey Mine in March 2014 and increasing production to match committed and spot sales tons during 2014.

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 directly associated with coal production.



	For the Years Ended December 31,
	2014		2013		Variance			Percent Variance
Total Tons Sold (in thousands)	5,227		4,246		981			23.1	%
Average Sales Price Per Ton Sold	$	61.88	$	63.93	$	(2.05	)	(3.2	)%

Operating Costs Per Ton Sold	$	32.49	$	34.93	$	(2.44	)	(7.0	)%
Royalties and Production Taxes Per Ton Sold	2.71		2.58		0.13			5.0	%
Selling and Direct Administrative Expenses Per Ton Sold	1.20		1.26		(0.06		)	(4.8	)%
Depreciation, Depletion and Amortization Per Ton Sold	6.34		5.76		0.58			10.1	%
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	6.34		5.76		0.58			10.1	%
Average Cash Margin Per Ton Sold (1)	$	25.48	$	25.16	$	0.32		1.3	%

(1) Average cash margin per ton is an operating ratio derived from non-GAAP measures.

Revenue and Other Income

Coal revenue was $323,398 for the year ended December 31, 2014 compared to $271,467 for the year ended December 31, 2013. The $51,931 increase was attributable to 981 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 669 tons of coal being priced in the export market for the year ended December 31, 2014, which was 166 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 additional available tons due to the commissioning of the Harvey Mine in March 2014.

Freight revenue, which is completely offset in freight expense, is the amount billed to customers based on the weight of coal shipped and negotiated freight rates for rail transportation. Freight revenue was $3,353 for the year ended December 31, 2014 compared to $3,556 for the year ended December 31, 2013. The $203 decrease in freight revenue was due to decreased shipments to customers where we were contractually obligated to provide transportation services.

Miscellaneous other income was $7,580 for the year ended December 31, 2014 compared to $1,336 for the year ended December 31, 2013. The $6,244 increase was due to a $6,000 coal customer contract buyout and $244 in other miscellaneous other income, none of which were individually material.

Cost of Coal Sold

Cost of coal sold 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 cost of coal sold was $223,377 for the year ended December 31, 2014, or $34,287 higher than the $189,090 for the year ended December 31, 2013. Total costs per ton sold were $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.

Total Other Costs

Total other costs is comprised of various costs that are not allocated to each individual mine and therefore not included in unit costs. Total other costs decreased $1,161 for the year ended December 31, 2014 compared to the year ended December 31, 2013. The decrease was attributable 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. The decrease was offset, in part, by an increase in depreciation, depletion, and amortization due to additional assets placed in service during 2014 compared to 2013.

General and Administrative Expense

CONSOL Energy allocated general and administrative expense based upon the level of operating activity of its underlying business units. The amount of general and administrative expenses incurred was $13,062 for the year ended December 31, 2014 compared to $12,201 for the year ended December 31, 2013. The $861 increase was due to various transactions, none of which were individually material.

Interest Expense

Interest expense increased $4,853 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.

Adjusted EBITDA

Adjusted EBITDA was $125,872 for the year ended December 31, 2014 compared to $96,975 for the year ended December 31, 2013. The $28,897 increase was attributed to 981 additional tons sold during 2014 and a $0.32 increase in the average cash margin per ton sold. The $0.32 per ton increase in the average cash margin per ton, which was primarily a result of the decreased cost of coal sales per ton offset, in part, against a decrease in the coal sales price per ton, resulted in an adjusted EBITDA increase of $1,347. The remaining increase in adjusted EBITDA of $27,550 is primarily due to 981 additional tons sold during 2014.

Distributable Cash Flow

Distributable cash flow was $86,292 for the year ended December 31, 2014 compared to $58,094 for the year ended December 31, 2013. The $28,198 increase was primarily attributed to a $28,897 increase in adjusted EBITDA as discussed above.

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. Our sources of liquidity include cash generated from operations, borrowings under our revolving credit facility and the issuance of equity 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.

We will pay a minimum quarterly distribution of $0.5125 per unit per quarter, which equates to an aggregate distribution of approximately $12,144 per quarter, or approximately $48,576 per year, based on the number of common units, subordinated units and the general partner interest that are outstanding as of December 31, 2015. The quarterly distribution for the quarter ended December 31, 2015 was $0.5125 per unit. 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).

Revolving Credit Facility

We entered into a $400,000 senior secured revolving credit facility on July 7, 2015 with certain lenders and PNC Bank N.A., as administrative agent. Obligations under our revolving credit facility are guaranteed by our subsidiaries (the “guarantor subsidiaries”) and are secured by substantially all of CNXC's, and our subsidiaries', assets pursuant to a security agreement and various mortgages. CONSOL Energy is not a guarantor of our credit facility.

Borrowings under our revolving credit facility can be used by us to fund cash distributions, make capital expenditures, pay fees and expenses related to our revolving credit facility and for general partnership purposes. In connection with the completion of the IPO and our entry into our revolving credit facility, we made an initial draw of $200,000 that was distributed to CONSOL Energy, net of origination fees.

The unused portion of our revolving credit facility will be subject to a commitment fee of 0.50% per annum. Interest on outstanding indebtedness under our revolving credit facility accrues, at our option, at a rate based on either:


•	The highest of (i) PNC Bank N.A.’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 1.50% to 2.50%; or


•	the LIBOR rate plus a margin ranging from 2.50% to 3.50%.

As of December 31, 2015, the $400,000 facility had $185,000 of borrowings outstanding, leaving $215,000 of unused capacity. Interest on outstanding borrowings under the revolving credit facility was accrued at 3.17% based on a LIBOR rate of 0.42%, plus a margin of 2.75%.

Our revolving credit facility matures on July 7, 2020 and requires compliance with conditions that must be satisfied prior to any borrowing as well as ongoing compliance with certain affirmative and negative covenants.

Affirmative covenants include, among others, requirements relating to: (i) the preservation of existence; (ii) the payment of obligations, including taxes; (iii) the maintenance of properties and equipment, insurance and books and records; (iv) the compliance with laws and material contracts; (v) use of proceeds; (vi) the subordination of intercompany loans; (vii) compliance with anti-terrorism, anti-money laundering, anti-corruption and sanctions laws; and (viii) collateral.

Negative covenants include, among others, restrictions on our and our guarantor subsidiaries’ ability to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) make or pay any dividends or distributions; provided that we will be able to make cash distributions of available cash to partners so long as no event of default is continuing or would result therefrom; (iv) merge with or into another person, liquidate or dissolve, acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another

person’s assets; (v) make particular investments and loans; provided that we will be able to increase our ownership percentage of our undivided interest in the Pennsylvania mining complex and make investments in the Pennsylvania mining complex in accordance with our ratable ownership; (vi) sell, transfer, convey, assign or dispose of our assets or properties other than in the ordinary course of business and other select instances; (vii) deal with any affiliate except in the ordinary course of business on terms no less favorable to us than we would otherwise receive in an arm’s length transaction; (viii) amend organizational documents or any documentation governing certain material debt; and (ix) amend, waive or grant a consent under any material contract. In addition, we are obligated to maintain at the end of each fiscal quarter (x) a minimum interest coverage ratio of at least 3.0 to 1.0 and (y) a maximum leverage ratio of no greater than 3.50 to 1.0 (or 4.0 to 1.0 for two fiscal quarters after consummation of a material acquisition). At December 31, 2015, the interest coverage ratio was 11.31 to 1.00 and the maximum total leverage ratio was 1.89 to 1.00. The revolving credit facility also contains various reporting requirements.

Our revolving credit facility also contains events of default, including, but not limited to, cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants.

Cash Flows



	For the Years Ended December 31,
	2015			2014			Variance
	(in thousands)
Cash flows provided by operating activities	$	60,795		$	114,109		$	(53,314	)
Cash used in investing activities	$	(27,201	)	$	(52,824	)	$	25,623
Cash used in financing activities	$	(27,066	)	$	(61,285	)	$	34,219

Years Ended December 31, 2015 Compared to the Years Ended December 31, 2014:

Cash flows provided by operating activities decreased $53,314 in the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily due to the following items:


•	Net income decreased $33,236 in the period-to-period comparison;


•	Other adjustments to reconcile net income to cash flow provided by operating activities increased $638 from additional depreciation, depletion, and amortization in the year ended December 31, 2015, and $139 for various immaterial transactions; and

•

Changes in operating and other assets and liabilities decreased $21,303 primarily due to the $15,246 change in trade receivables. As part of the IPO, the Partnership no longer sells its receivables to CONSOL Energy. The decrease was also attributable to a $6,567 change in other operating liabilities, primarily subsidence liabilities. The remaining change is due to various other items, none of which are material.

Net cash used in investing activities decreased $25,623 in the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily due to the following items:


•	Capital expenditures decreased $40,804 primarily due to $36,184 spent on the completion of the Harvey Mine in 2014;


•	Proceeds from sale of assets decreased $15,181 due to the sale-leaseback agreements for longwall shields at Harvey Mine in the year ended December 31, 2014.

Net cash used in financing activities decreased $34,219 in the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily due to the following items:


•	Net parent advances decreased $63,965 for the year ended December 31, 2015. At the closing of the IPO, there were no further net parent advances;


•	For the year ended December 31, 2015 there were:


◦	Proceeds of $148,359 from the sale of limited partner units;


◦	Cash distributions of $11,353 to limited unitholders and the general partner;


◦	Proceeds of $180,671 from the revolver, net of repayments and payments of debt issuance costs of $4,329; and


◦	Distributions of $342,711 to CONSOL Energy as part of the IPO.

Capital Expenditures

For the year ended December 31, 2015, the total capital expenditures of our Partnership were $27,257 compared to capital expenditures of $68,061 for the year ended December 31, 2014. The decrease in the capital expenditures is primarily due to the completion of longwall mining development at the Harvey Mine in March 2014.



	For the Years Ended December 31,
	2015		2014		Variance
	(in thousands)
Harvey Mine development	$	—	$	36,184	$	(36,184	)
Equipment purchases and rebuilds	9,582		10,774		(1,192		)
Building and infrastructure	11,743		10,763		980
Water treatment systems	2,606		3,216		(610		)
Refuse storage area	2,615		4,175		(1,560		)
Other	711		2,949		(2,238		)
Total capital expenditures	$	27,257	$	68,061	$	(40,804	)

Off-Balance Sheet Arrangements

We do not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Audited Consolidated Financial Statements of this Form 10-K.

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 and related notes thereto and believe those policies are reasonable and appropriate.

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, Basis of Presentation and Recent Accounting Pronouncements) of the audited consolidated financial statements included elsewhere in this report for a complete listing of our accounting policies.

Other Post-Employment Benefits ("OPEB"), Worker’s Compensation and Coal Workers’ Pneumoconiosis ("CWP")

Liabilities and expenses for OPEB, worker’s compensation and 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.

Prior to the IPO, the Partnership was contractually obligated for a portion of the medical and life insurance benefits to retired employees of CPCC. In conjunction with the IPO, on July 7, 2015 the OPEB liability and related accumulated other comprehensive income was retained by CONSOL Energy, and the Partnership has no further OPEB obligation as of such date.

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 Partnership specific yield curve uses a subset of the expanded bond universe to determine the Partnership 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, 2015 and the benefit payments made for the year end December 31, 2015 were as follows (in thousands):



Plan	Estimated Liability as of December 31, 2015		Benefit Payments for the year ended December 31, 2015
Workers’ Compensation	$	3,433	$	1,586
CWP	$	1,582	$	31

Contingencies

The Partnership, 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.

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. 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. 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 $8,329 at December 31, 2015 and $9,111 at December 31, 2014. These liabilities are 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.

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 on engineering, economic and geological data assembled and analyzed by our staff. In 2014, our significant estimates and methods for coal reserves were 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.

Significant Contractual Obligations

The following is a summary of our significant contractual obligations at December 31, 2015 (in thousands).



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Long-term debt	$	—	$	—	$	185,000	$	—	$	185,000
Interest on long-term debt	5,920		11,840		9,021		—		26,781
Capital (finance) lease obligations	49		75		25		—		149
Interest on capital (finance) lease obligations	2		5		1		—		8
Operating lease obligations	9,582		16,931		5,281		3,069		34,863
Long-term liabilities—employee related (a)	1,288		2,612		2,825		8,213		14,938
Other long-term liabilities (b)	27,699		1,320		806		5,701		35,526
Total contractual obligations	$	44,540	$	32,783	$	202,959	$	16,983	$	297,265


(a)	Long-term liabilities—employee related include liabilities for work-related injuries and illnesses.


(b)	Other long-term liabilities include mine reclamation and closure and other long-term liability costs.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES 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 in the spot market and under both short-term and multi-year contracts that may contain base prices subject to pre-established price adjustments that reflect (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) changes in electric power prices in the markets in which our customers operate, as adjusted for any factors set forth in the applicable contract.

Interest Rate Risk

Based on our current debt level of $185,000, comprised of funds drawn on our revolving credit facility, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $1,850. 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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



	Page
Report of Independent Registered Public Accounting Firm	64
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014, and 2013	65
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014, and 2013	66
Consolidated Balance Sheets at December 31, 2015 and 2014	67
Consolidated Statements of Partners' Capital and Parent Net Investment for the Years Ended December 31, 2015, 2014, and 2013	69
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013	70
Notes to the Consolidated Financial Statements	71

Report of Independent Registered Public Accounting Firm

The Board of Directors of CNX Coal Resources GP LLC and Unitholders of CNX Coal Resources LP

We have audited the accompanying consolidated balance sheets of CNX Coal Resources LP (including its Predecessor as defined in Note 1) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’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 Partnership’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 Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CNX Coal Resources LP at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 5, 2016

CNX COAL RESOURCES LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)



	For the Years Ended December 31,
	2015		2014		2013
Coal Revenue	$	257,809	$	323,398	$	271,467
Freight Revenue	3,047		3,353		3,556
Miscellaneous Other Income	704		7,580		1,336
Gain (Loss) on Sale of Assets	49		148		(124		)
Total Revenue and Other Income	261,609		334,479		276,235

Operating and Other Costs ¹	140,415		171,993		151,514
Royalties and Production Taxes	10,271		14,111		11,046
Selling and Direct Administrative Expenses ²	5,085		6,444		5,687
Depreciation, Depletion and Amortization	35,309		34,671		25,846
Freight Expense	3,047		3,353		3,556
General and Administrative Expenses ³	8,324		13,062		12,201
Interest Expense ⁴	8,495		6,946		2,093
Total Costs	210,946		250,580		211,943
Net Income	$	50,663	$	83,899	$	64,292

Calculation of Limited Partner Interest in Net Income:
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Coal Resources ⁵	$	23,356	N/A		N/A
Less: General Partner Interest in Net Income	468		N/A		N/A
Limited Partner Interest in Net Income	$	22,888	N/A		N/A

Net Income per Limited Partner Unit - Basic	$	0.99	N/A		N/A
Net Income per Limited Partner Unit - Diluted	$	0.99	N/A		N/A

Limited Partner Units Outstanding - Basic	23,222,134		N/A		N/A
Limited Partner Units Outstanding - Diluted	23,223,045		N/A		N/A

¹Related Party of $3,709, $12,866 and $12,461 for the years ended December 31, 2015, 2014, and 2013, respectively.

²Related Party of $5,085, $6,444 and $5,687 for the years ended December 31, 2015, 2014, and 2013, respectively.

³Related Party of $3,829, $9,303 and $7,937 for the years ended December 31, 2015, 2014, and 2013, respectively.

⁴Related Party of $4,840, $9,534 and $9,310 for the years ended December 31, 2015, 2014, and 2013, respectively.

⁵Reflective of general and limited partner interest in net income since closing of Initial Public Offering. See Note 2 - Initial Public Offering.

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

CNX COAL RESOURCES LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)



	For the Years Ended December 31,
	2015			2014		2013
Net Income	$	50,663		$	83,899	$	64,292
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	(1,473		)	33,439		8,419

Other Comprehensive Income (Loss)	(1,473		)	33,439		8,419

Comprehensive Income	$	49,190		$	117,338	$	72,711

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

CNX COAL RESOURCES LP

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	December 31, 2015		December 31, 2014
ASSETS
Current Assets:
Cash	$	6,531	$	3
Trade Receivables	15,518		—
Other Receivables	377		384
Inventories	9,791		10,639
Prepaid Expenses	4,080		3,922
Total Current Assets	36,297		14,948
Property, Plant and Equipment:
Property, Plant and Equipment	692,482		686,593
Less—Accumulated Depreciation, Depletion and Amortization	320,729		287,707
Total Property, Plant and Equipment—Net	371,753		398,886
Other Assets:
Other	14,079		4,977
Total Other Assets	14,079		4,977
TOTAL ASSETS	$	422,129	$	418,811

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

CNX COAL RESOURCES LP

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	December 31, 2015		December 31, 2014
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	14,023	$	15,713
Accounts Payable—Related Party	3,452		—
Current Portion of Long Term Notes—Related Party	—		17,931
Current Portion of Long Term Debt—Other	49		330
Other Accrued Liabilities	29,929		35,571
Total Current Liabilities	47,453		69,545
Long-Term Debt:
Revolver, net of debt issuance and financing fees (Note 10)	180,946		—
Long-Term Notes Payable—Related Party	—		160,831
Advanced Royalty Commitments	—		278
Capital Lease Obligations	100		51
Total Long-Term Debt	181,046		161,160
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	—		5,279
Pneumoconiosis Benefits	1,547		1,250
Workers’ Compensation	2,343		2,381
Asset Retirement Obligations	6,799		7,961
Other	571		609
Total Deferred Credits and Other Liabilities	11,260		17,480
TOTAL LIABILITIES	239,759		248,185
Partners' Capital:
Common Units (11,611,067 Units Outstanding at December 31, 2015)	154,309		—
Subordinated Units (11,611,067 Units Outstanding at December 31, 2015)	6,188		—
General Partner Interest	13,081		—
Parent Net Investment	—		139,259
Accumulated Other Comprehensive Income	8,792		31,367
Total Partners' Capital	182,370		170,626
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	422,129	$	418,811

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

CNX COAL RESOURCES LP

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

(Dollars in thousands)



				Limited Partners
	Parent Net Investment			Common			Subordinated			General Partner			Accumulated Other Comprehensive Income			Total
Balance at 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
Net Working Capital Advances to the Partnership	(66,529		)	—			—			—			—			(66,529		)
Balance at December 31, 2014	$	139,259		$	—		$	—		$	—		$	31,367		$	170,626
Net Income Attributable from January 1, 2015 to July 6, 2015	27,307			—			—			—			—			27,307
Net Working Capital Advances to the Partnership	(21,585		)	—			—			—			—			(21,585		)
Assets and Liabilities Contributed/Distributed	210,906			—			—			—			(21,102		)	189,804
Deemed Distribution to the Partnership	(355,887		)	28,450			314,597			12,840			—			—
Issuance of Common Units to Public, Net of Offering Costs	—			148,359			—			—			—			148,359
Distribution of Proceeds	—			(28,421		)	(314,290		)	—			—			(342,711		)
Unitholder Distributions	—			(5,563		)	(5,563		)	(227		)				(11,353		)
Net Income Attributable to the Partnership	—			11,444			11,444			468			—			23,356
Unit Based Compensation	—			40			—			—			—			40
Actuarially determined long-term liability adjustments	—			—			—			—			(1,473		)	(1,473		)
Balance at December 31, 2015	$	—		$	154,309		$	6,188		$	13,081		$	8,792		$	182,370

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

CNX COAL RESOURCES LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)



	For the Years Ended December 31,
	2015			2014			2013
Cash Flows from Operating Activities:
Net Income	$	50,663		$	83,899		$	64,292
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	35,309			34,671			25,846
(Gain) Loss on Sale of Assets	(49		)	(148		)	124
Unit Based Compensation	40			—			—
Other Adjustments to Net Income	677			229			305
Changes in Operating Assets:
Accounts and Notes Receivable	(15,511		)	(265		)	214
Inventories	848			293			(3,537		)
Prepaid Expenses	(158		)	(203		)	(1,134		)
Changes in Other Assets	(2,597		)	(1,274		)	(513		)
Changes in Operating Liabilities:
Accounts Payable	(1,068		)	(1,820		)	(1,816		)
Accounts Payable—Related Party	3,452			—			—
Other Operating Liabilities	(5,573		)	994			8,342
Changes in Other Liabilities	(5,238		)	(2,267		)	2,293
Net Cash Provided by Operating Activities	60,795			114,109			94,416
Cash Flows from Investing Activities:
Capital Expenditures	(27,257		)	(68,061		)	(82,182		)
Proceeds from Sales of Assets	56			15,237			14,554
Net Cash Used in Investing Activities	(27,201		)	(52,824		)	(67,628		)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Miscellaneous Borrowings	(40		)	(19		)	(13		)
Payments on Related Party Long-Term Notes	(8,761		)	(1,849		)	(9,591		)
Proceeds from Related Party Long-Term Notes	13,592			11,371			18,893
Proceeds from Revolver, Net of Payments	185,000			—			—
Proceeds from Issuance of Common Units, Net of Offering Costs	148,359			—			—
Distribution of Proceeds	(342,711		)	—			—
Payments on Unitholder Distributions	(11,353		)	—			—
Debt Issuance and Financing Fees	(4,329		)	—			—
Net Change in Parent Advances	(6,823		)	(70,788		)	(36,078		)
Net Cash Used In Financing Activities	(27,066		)	(61,285		)	(26,789		)
Net Increase in Cash	6,528			—			(1		)
Cash at Beginning of Period	3			3			4
Cash at End of Period	$	6,531		$	3		$	3

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

CNX COAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands)

NOTE 1—SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies is included below. These, together with the other notes to the consolidated financial statements, are an integral part of the consolidated financial statements.

Basis of Consolidation and Presentation:

For the year ended December 31, 2015, the Consolidated Financial Statements include the accounts of CNX Operating and CNX Thermal Holdings, wholly-owned and controlled subsidiaries.

For the years ended December 31, 2014 and 2013, these audited Consolidated 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. These Audited Consolidated Financial Statements represent the combination of two separate legal entities wholly owned by CONSOL Energy, the net assets of the Partnership have been presented as a Parent Net Investment. Parent Net Investment is primarily comprised of the Partnership’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 Partnership and CONSOL Energy or CONSOL Energy’s other subsidiaries have been identified in the financial statements as transactions between related parties.

Transactions between the Partnership and CONSOL Energy have been identified in the consolidated financial statements as transactions between related parties and are discussed in Note 20.

Jumpstart Our Business Startups Act ("JOBS Act"):

The Partnership will remain an emerging growth company for up to five years, although we will lose that status sooner if:


•	we have more than $1 billion of revenues in a fiscal year;


•	limited partner interests held by non-affiliates have a market value of more than $700 million (large accelerated filer); or


•	we issue more than $1 billion of non-convertible debt over a three-year period.

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 consolidated financial statements are related to coal workers’ pneumoconiosis, workers’ compensation, asset retirement obligations, contingencies, and coal reserve values.

Cash:

Cash includes cash on hand and on deposit with banking institutions.

Accounts Receivable:

Accounts receivable are recorded at the invoiced amount and do not bear interest. We reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. We regularly review collectability and establish or adjust the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible trade amounts in the periods presented.

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.

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 Consolidated Statements 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 are calculated on a clean coal ton equivalent, which excludes non-recoverable coal reserves and anticipated preparation plant processing refuse. 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, 2015, 2014 and 2013.

Pension:

The personnel who operate CPCC and Conrhein’s assets are employees of CPCC and participate in certain defined benefit retirement plans administered by CONSOL Energy through December 31, 2015. Effective December 31, 2015, CONSOL Energy's qualified defined benefit retirement plans have been frozen. CONSOL Energy directly charges the Partnership for its portion of the service costs associated with these employees that participate in the salary retirement pension plans. The Partnership’s share of those costs is reflected in Operating and Other Costs in the accompanying Consolidated Statements of Operations.

On September 30, 2014, the qualified pension plan was remeasured to reflect an announced plan amendment that would reduce future accruals of pension benefits as of January 1, 2015. The plan amendment called for a hard freeze of the qualified defined benefit pension plan on January 1, 2015 for employees who were under age 40 or had less than ten years of service as of September 30, 2014. Employees who were age 40 or over and had at least 10 years of service would continue in the defined benefit pension plan unchanged. On August 31, 2015, the qualified pension plan was remeasured to reflect another announced plan amendment that reduced future accruals of pension benefits as of January 1, 2016. The plan amendment called for a hard freeze of the qualified defined benefit pension plan on January 1, 2016 for all remaining participants in the plan and eliminated CONSOL Energy contributing an additional 3% of eligible compensation into the 401(k) accounts.

Postretirement Benefits Other Than Pensions:

Postretirement benefits other than pensions ("OPEB") 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. Prior to the IPO, the Partnership was contractually obligated for a portion of the medical and life insurance benefits to retired employees of CPCC. In conjunction with the IPO, on July 7, 2015 the OPEB liability and related accumulated other comprehensive income was retained by CONSOL Energy, and the Partnership has no further OPEB obligation as of such date.

Pneumoconiosis Benefits and Workers’ Compensation:

The Partnership is required by federal and state statutes to provide our portion of benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers’ pneumoconiosis (“CWP”). The Partnership is also required by various state statutes to provide our portion of 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 our portion of estimated benefits are determined on an actuarial basis for the Partnership’s dedicated contract labor provided under a service agreement with CONSOL Energy.

Asset Retirement Obligations:

Mine closing reclamation costs, perpetual water care costs and other costs associated with dismantling and removing 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 Depreciation, Depletion and Amortization on the Consolidated 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 other costs of dismantling and removing facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.

Subsidence:

Subsidence occurs when there is damage of the ground surface due to the removal of underlying coal. Areas affected may include, although not limited to, streams, 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 Consolidated Statements of Operations and Other Accrued Liabilities on the Consolidated Balance Sheets. On occasion we prepay the estimated damages prior to undermining the property, in return for release of liability. Prepayments are included as assets and either recognized as Prepaid Expenses or in Other Assets on the Consolidated Balance Sheets, if the payment is made less than or greater than one year, respectively, prior to undermining the property.

Income Taxes:

The Partnership's assets and liabilities are comprised of a 20% undivided interest in the Pennsylvania mining complex which assets and liabilities are held by 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, 2015 and 2014, the Partnership had no liability reported for unrecognized tax benefits and had not incurred interest and penalties related to income taxes. The Partnership’s operations are 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 Partnership 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 generally occurs when coal is loaded onto marine vessels at terminal locations.

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 Consolidated Statements of Operations when the related revenue for the coal sale is recognized.

Contingencies:

Other Comprehensive Income:

Changes in Accumulated Other Comprehensive Income by component were as follows:



	Postretirement Benefits
Balance at December 31, 2014	$	31,367
Other comprehensive income before reclassifications	4,493
Amounts reclassified from accumulated other comprehensive income	(5,966		)
Other comprehensive income	(1,473		)
OPEB accumulated other comprehensive income retained by CONSOL Energy	(21,102		)
Balance at December 31, 2015	$	8,792

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



	For the For the Years Ended December 31,
	2015			2014			2013
Actuarially Determined Long-Term Liability Adjustments
Amortization of prior service costs	$	(6,962	)	$	(1,865	)	$	(624	)
Recognized net actuarial loss	996			437			779
Curtailment gain	—			(2,042		)	—
Total	$	(5,966	)	$	(3,470	)	$	155

Reclassifications:

Certain amounts have been reclassified to conform with the current reporting classifications with no effect on previously reported net income or partners' capital.

Recent Accounting Pronouncements:

In January 2016, the FASB issued Update 2016-01 - Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Asset and Financial Liabilities. The main objective in developing this Update is enhancing the reporting model for financial instruments to provide users of financial statements with more decision-useful information. The amendments in this Update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. This Update requires the following: equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, a qualitative assessment to identify impairment of equity investments without readily determinable fair values, the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes, an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, and separate presentation of financial assets and financial liabilities by measurement category and form of financial assets on the balance sheet or the accompanying notes to the financial statements. The Update also eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet and clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. For public business entities, the

amendments in this Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early application to financial statements of fiscal years or interim periods that have not yet been issued is permitted as of the beginning of the fiscal year of adoption. Management is currently evaluating the impact this guidance may have on the Partnership's financial statements.

In July 2015, the FASB issued Update 2015-11 - Inventory (Topic 330): Simplifying the Measurement of Inventory. The Board is issuing this Update as part of its Simplification Initiative. The amendments in this Update do not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first-out (FIFO) or average cost. Topic 330, Inventory, currently requires an entity to measure inventory at the lower of cost or market, where market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. In accordance with this Update, an entity should now measure inventory within the scope of this Update at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Subsequent measurement is unchanged for inventory measured using LIFO or the retail inventory method. Other than the change in the subsequent measurement guidance from the lower of cost or market to the lower of cost and net realizable value for inventory within the scope of this Update, there are no other substantive changes to the guidance on measurement of inventory. For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments in this Update should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. Management is currently evaluating the impact this guidance may have on the Partnership's financial statements.

In February 2015, the Financial Accounting Standards Board ("FASB") issued Update 2015-02 - Consolidation (Topic 810): Amendments to the Consolidation Analysis. The objective of the amendments in this update is to change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The amendments in this update affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, the amendments: (1) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities ("VIEs") or voting interest entities; (2) eliminate the presumption that a general partner should consolidate a limited partnership; (3) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships; and (4) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. The amendments in this update affect the following areas: (1) limited partnerships and similar legal entities; (2) evaluating fees paid to a decision maker or a service provider as a variable interest; (3) the effect of fee arrangements on the primary beneficiary determination; (4) the effect of related parties on the primary beneficiary determination; and (5) certain investment funds. Current U.S. GAAP includes different requirements for performing a consolidation analysis if, among other factors, the entity under evaluation is any one of the following: (1) a legal entity that qualifies for the indefinite deferral of Statement 167; (2) a legal entity that is within the scope of Statement 167; and (3) a limited partnership or similar legal entity that is considered a voting interest entity. Under the amendments in this update, all reporting entities are within the scope of Subtopic 810-10, Consolidation-Overall, including limited partnerships and similar legal entities, unless a scope exception applies. The presumption that a general partner controls a limited partnership has been eliminated. Overall, the amendments in this update are an improvement to current U.S. GAAP because they simplify the Codification and reduce the number of consolidated models through the elimination of the indefinite deferral of Statement 167 and because they place more emphasis on risk of loss when determining a controlling financial interest. The amendments in this update are effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. Management is currently evaluating the impact this guidance may have on the Partnership's financial statements.

In April 2015, the FASB issued update 2015-03 - Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. This update is part of the FASB's initiative to reduce complexity in accounting standards (the Simplification Initiative). The FASB received feedback that having different balance sheet presentation requirements for debt issuance costs and debt discounts and premiums creates unnecessary complexity. Recognizing debt issuance costs as a deferred charge (that is, an asset) also is different from the guidance in International Financial Reporting Standards ("IFRS"), which requires that transaction costs be deducted from the carrying value of the financial liability and not recorded as separate assets. Additionally, the requirement to recognize debt issuance costs as deferred charges conflicts with the guidance in FASB Concepts Statement No. 6, Elements of Financial Statements, which states that debt issuance costs are similar to debt discounts and in effect reduce the proceeds of borrowing, thereby increasing the effective interest rate. Concepts Statement 6 further states that debt issuance costs cannot be an asset because they provide no future economic benefit. To simplify the presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued update 2015-15 Amendment to Interest-Imputation of Interest (Subtopic 835-30). This amendment clarifies that, in relation

to line-of-credit arrangements, the SEC would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratable over the term of the line-of-credit arrangement. For public business entities, the amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. The Partnership's election to early adopt this guidance does not have a material impact on the Partnership's financial statements, see Note 10 - Debt.

In April 2015, the FASB issued update 2015-06 - Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the dropdown transaction as if it occurred on the earliest date during which the entities were under common control. The objective of this update is to address the diversity in practice in relation to presentation of historical earnings per unit for periods before the date of a dropdown transaction that occurs after formation of a master limited partnership. Some reporting entities recalculate previously reported earnings per unit by allocating the earnings (losses) of the transferred business that occurred in periods before the date of the dropdown transaction to the general partner, limited partners, and incentive distribution rights holders on a hypothetical basis and treat their rights to those earnings (losses) in a manner that is consistent with their contractual rights immediately after the dropdown transaction has occurred. Other reporting entities allocate the earnings (losses) of the transferred business that occurred in periods before the date of the dropdown transaction entirely to the general partner and do not adjust previously reported earnings per unit of the limited partners. The amendments in this update specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The amendments in this update should be applied retrospectively for all financial statements presented and are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Earlier adoption is permitted. The adoption of this new guidance will not have a material impact on the Partnership's financial statements.

In May 2014, the FASB 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 U.S. GAAP and 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 and 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, 2017, including interim periods within that reporting period. Early application is not permitted. In August 2015, the FASB issued Update 2015-14 - Revenue from Contracts with Customers (Topic 606): Deferral of Effective Date. In response to stakeholders’ requests to defer the effective date of the guidance in Update 2014-09 - Revenue from Contracts with Customers (Topic 606), and in consideration of feedback received through extensive outreach with preparers, practitioners, and users of financial statements, the Board issued proposed Accounting Standards Update, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. Respondents to the proposed Update overwhelmingly support a deferral and noted that providing sufficient time for implementation of the guidance in Update 2014-09 is critical to its success. As such, the Board is issuing this Update in consideration of respondents’ feedback, including the timing of when Update 2014-09 was issued, the current status of key standard-setting activities associated with the guidance in Update 2014-09, and the availability of information technology solutions to facilitate the implementation of the guidance in Update 2014-09. The amendments in this Update defer the effective date of Update 2014-09 for all entities by one year. Public business entities, certain not-for-profit entities, and certain employee benefit plans should apply the guidance in Update 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. Management is currently evaluating the impact this guidance may have on the Partnership's financial statements.

NOTE 2—INITIAL PUBLIC AND CONCURRENT PRIVATE PLACEMENT OFFERING:

The Transaction

CONSOL Energy

In connection with the IPO, the Partnership issued 1,050,000 common units (including 188,933 common units issued upon the expiration of the underwriters' option to purchase additional common units), and 11,611,067 subordinated units to CONSOL Energy, representing a 53.4% limited partner interest in us, and issued a 2.0% general partner interest in us and all of our incentive distribution rights to our general partner. In connection with these issuances of common and subordinated units and other ownership interests, we relied upon the “private placement” exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(a)(2) thereof and, accordingly, the common and subordinated units and other ownership interests issued to CONSOL Energy were not registered under the Securities Act. The Partnership also entered into an operating agreement, employee services agreement, contract agency agreement, terminal and throughput agreement, cooperation and safety agreement, water supply and services agreement, omnibus agreement and contribution agreement with CONSOL Energy.

Concurrent Private Placement

In connection with the IPO, Greenlight Capital and certain of its affiliates entered into a common unit purchase agreement with us to purchase 5,000,000 common units at a price per unit equal to $15.00 equating to $75,000 in gross proceeds. In connection with our issuance and sale of common units pursuant to the Concurrent Private Placement, we relied upon the “private placement” exemption from the Securities Act, provided by Section 4(a)(2) thereof and, accordingly, the common units issued to Greenlight Capital were not registered under the Securities Act. We distributed all of the proceeds from the Concurrent Private Placement to CONSOL Energy.

Initial Public Offering

As part of the IPO, we sold 5,000,000 common units to the public at a price per unit equal to $15.00 ($14.10 per unit net of underwriting discount) equating to gross proceeds of $75,000. After the deduction of the underwriting discount and structuring fees of $5,500 and offering expenses of approximately $4,052, the net proceeds contributed to the Partnership were approximately $65,448. We granted the underwriters a 30-day option to purchase up to 750,000 common units from us at the IPO price, less the underwriter discount, if the underwriters sold more than 5,000,000 common units. The underwriters partially exercised this option and sold an additional 561,067 common units to the public at $15.00 ($14.10 per unit net of underwriting discount) equating to additional net proceeds of $7,911. We distributed $70,711 of net proceeds from the IPO to CONSOL Energy. The remaining 188,933 common units that the underwriters did not exercise under their option, were issued to CONSOL Energy.

Revolving Credit Facility

In connection with the IPO, we entered into a $400,000 senior secured revolving credit facility with certain lenders and PNC Bank, National Association, as administrative agent (“PNC Bank N.A.”). Obligations under our revolving credit facility are guaranteed by our subsidiaries (the“guarantor subsidiaries”) and are secured by substantially all of our and our subsidiaries’ assets pursuant to a security agreement and various mortgages. CONSOL Energy is not a guarantor of our revolving credit facility.

Borrowings under our revolving credit facility may be used by us to fund cash distributions, make capital expenditures, pay fees and expenses related to our revolving credit facility and for general partnership purposes. In connection with the completion of the IPO and our entry into our revolving credit facility, we made an initial draw of $200,000 and paid $3,000 in origination fees with net proceeds of $197,000 which were distributed to CONSOL Energy.

Use of Proceeds

In connection with the IPO, we used the net proceeds from the IPO, the proceeds from the Concurrent Private Placement and net borrowings under our revolving credit facility to make a distribution of $342,711, including $4,352 of offering and structure fees, to CONSOL Energy. The Partnership retained cash of $7,000. Based on the IPO price of $15.00 per common

unit, the aggregate value of the common units and subordinated units that were issued to CONSOL Energy in connection with the completion of the IPO was approximately $189,916.

NOTE 3—NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST:

The Partnership allocates net income among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method and in accordance with our partnership agreement, we allocate our net income to our limited partners and our general partner, allocate any earnings in excess of distributions to our limited partners and our general partner, and allocate any distributions in excess of earnings for the period to our general partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the incentive distribution rights.

Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.

The following table illustrates the Partnership's calculation of net income per unit for common and subordinated partner units (in thousands, except for per unit information):



	For the Year Ended
	December 31, 2015
Net Income	$	50,663
Less: Net (Loss) Income Attributable to CONSOL Energy, Pre-IPO	27,307
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Coal Resources	$	23,356
Less: General Partner Interest in Net Income	468
Limited Partner Interest in Net Income	$	22,888

Net Income Allocable to Common Units	$	11,444
Net Income Allocable to Subordinated Units	11,444
Limited Partner Interest in Net Income	$	22,888

Weighted Average Limited Partner Units Outstanding - Basic
Common Units	11,611,067
Subordinated Units	11,611,067
Total	23,222,134
Weighted Average Limited Partner Units Outstanding - Diluted
Common Units	11,611,978
Subordinated Units	11,611,067
Total	23,223,045

Net Income Per Limited Partner Unit - Basic and Diluted
Common Units	$	0.99
Subordinated Units	$	0.99

NOTE 4—ACQUISITIONS AND DISPOSITIONS:

In March 2014, CPCC 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, CPCC completed a sale-leaseback of longwall shields for the Bailey Mine. Cash proceeds for the sale were $14,233. CPCC recognized a loss of $72 due to transaction fees and was included in Gain (Loss) on Sale of Assets in the Consolidated Statements of Operations. The five-year lease has been accounted for as an operating lease.

NOTE 5—MISCELLANEOUS OTHER INCOME:



	For the Years Ended December 31,
	2015		2014		2013
Right of way sales	$	487	$	291	$	10
Coal contract buyout	—		6,000		—
Litigation	—		855		—
Business interruption proceeds	—		—		1,089
Other	217		434		237
Total Miscellaneous Other Income	$	704	$	7,580	$	1,336

NOTE 6—INTEREST EXPENSE:



	For the Years Ended December 31,
	2015			2014			2013
Interest on notes - related party	$	4,840		$	9,534		$	9,310
Revolver interest	3,928			—			—
Capitalized interest	(278		)	(2,589		)	(7,209		)
Interest on other payables, net	5			1			(8		)
Total Interest Expense	$	8,495		$	6,946		$	2,093

NOTE 7—INVENTORIES:



	December 31, 2015		December 31, 2014
Coal	$	932	$	1,718
Supplies	8,859		8,921
Total Inventories	$	9,791	$	10,639

NOTE 8—PROPERTY, PLANT AND EQUIPMENT:



	December 31, 2015		December 31, 2014
Coal and other plant and equipment	$	456,821	$	442,028
Coal properties and surface lands	96,789		107,158
Airshafts	70,374		68,855
Mine development	65,245		65,245
Coal advance mining royalties	3,253		3,307
Total property, plant and equipment	692,482		686,593
Less: Accumulated depreciation, depletion and amortization	320,729		287,707
Total Net Property, Plant and Equipment	$	371,753	$	398,886

Coal reserves are either owned in fee or controlled 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.

As of December 31, 2015 and 2014, property, plant and equipment includes gross assets under capital lease of $385 and $333, respectively. Accumulated amortization for capital leases was $237 and $252 at December 31, 2015 and 2014, respectively. Amortization expense for assets under capital leases approximated $29, $19, and $10 for the years ended December 31, 2015, 2014, and 2013, respectively, and is included in Depreciation, Depletion and Amortization in the accompanying Consolidated Statements of Operations.

NOTE 9—OTHER ACCRUED LIABILITIES:



	December 31, 2015		December 31, 2014
Subsidence liability	$	17,922	$	20,854
Accrued payroll and benefits	2,842		3,253
Equipment lease rental	1,953		1,948
Litigation	1,710		2,346
Short-term incentive compensation	181		1,103
Other	2,449		2,310
Current portion of long-term liabilities:
Postretirement benefits other than pensions	—		1,540
Workers' compensation	1,144		922
Asset retirement obligations	1,530		1,150
Long-term disability	163		121
Pneumoconiosis benefits	35		24
Total Other Accrued Liabilities	$	29,929	$	35,571

NOTE 10—DEBT:



	December 31, 2015		December 31, 2014
Revolver, carrying amount (3.17% interest rate at December 31, 2015)	$	185,000	$	—
Less: Unamortized debt issuance and financing fees	4,054		—
Revolver, net	180,946		—

Advance royalty commitments (7.91% weighted average interest rate for December 31, 2014)	—		578
CONSOL Financial Inc. loan (5.46% weighted average interest rate at December 31, 2014)	—		178,762
	180,946		179,340
Less amounts due in one year *	—		18,231
Long-Term Debt	$	180,946	$	161,109

___________

*Excludes current portion of Capital Lease Obligations of $49 and $30 at December 31, 2015 and 2014, respectively.

In April 2015, FASB issued Update 2015-03 - Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. To simplify the presentation of debt issuance costs, the amendments in this Update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability, consistent with debt discounts. Update 2015-03 is effective for fiscal years beginning after December 15, 2015 and is required to be applied retrospectively to all prior periods presented. As permitted by the Update, the Partnership elected to early adopt this guidance beginning in the third quarter of fiscal year 2015. There were no unamortized debt issuance costs as of December 31, 2014.

Revolving Credit Facility

In connection with the completion of the IPO, we entered into a $400,000 senior secured revolving credit facility with certain lenders and PNC Bank N.A., as administrative agent. Obligations under our revolving credit facility are guaranteed by our subsidiaries and are secured by substantially all of CNXC's, and our subsidiaries', assets pursuant to a security agreement and various mortgages. CONSOL Energy is not a guarantor of our revolving credit facility.

Borrowings under our revolving credit facility were used by us to fund cash distributions, make capital expenditures, pay fees and expenses related to our revolving credit facility and for general partnership purposes. In connection with the completion of the IPO and our entry into our revolving credit facility, we made an initial draw of $200,000 that was distributed to CONSOL Energy, net of origination fees.


•	The highest of (i) PNC Bank N.A.’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 1.50% to 2.50%; or


•	the LIBOR rate plus a margin ranging from 2.50% to 3.50%.

Our revolving credit facility matures on July 7, 2020 and requires compliance with conditions precedent that must be satisfied prior to any borrowing as well as ongoing compliance with certain affirmative and negative covenants. The facility requires that the Partnership maintains a minimum interest coverage ratio of at least 3.00 to 1.00, which is calculated as the ratio of trailing 12 months Adjusted EBITDA to cash interest expense of the Partnership, measured quarterly. The Partnership must also maintain a maximum total leverage ratio not greater than 3.50 to 1.00, which is calculated as the ratio of total consolidated indebtedness to trailing 12 months Adjusted EBITDA, measured quarterly. At December 31, 2015, the minimum interest coverage ratio was 11.31 and the maximum total leverage ratio was to 1.89.

CONSOL Financial Inc. Loan

The loan represents multiple 10-year term notes between CPCC and CONSOL Financial Inc. ("CFI"), a wholly owned subsidiary of CONSOL Energy, at the applicable federal rates upon execution, which were due at various future dates throughout the year. In conjunction with the IPO, these notes were excluded from the Partnership.

NOTE 11—LEASES:

We use 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 as of December 31, 2015 are as follows:



	Capital Leases		Operating Leases
2016	$	51	$	9,582
2017	45		9,329
2018	35		7,602
2019	19		3,583
2020	7		1,698
Thereafter	—		3,069
Total minimum lease payments	$	157	$	34,863
Less amount representing interest	8
Present value of minimum lease payments	149
Less amount due in one year	49
Total Long-Term Capital Lease Obligations	$	100

Rental expense related to operating leases approximated $10,792, $10,006 and $7,153 during the years ended December 31, 2015, 2014 and 2013, respectively.

NOTE 12—FAIR VALUE OF FINANCIAL INSTRUMENTS:

The Partnership 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 Partnership'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 Partnership'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, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Revolver	$	185,000	$	185,000	$	—	$	—
CONSOL Financial Inc. Loan	$	—	$	—	$	178,762	$	159,109

The Partnership’s debt obligations are valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.

NOTE 13—ASSET RETIREMENT OBLIGATIONS:



	December 31, 2015			December 31, 2014
Balance at beginning of period	$	9,111		$	7,662
Accretion expense	699			723
Payments	(796		)	(801		)
Revisions in estimated cash flows	(685		)	1,527
Balance at end of period	$	8,329		$	9,111

NOTE 14— OTHER POST-EMPLOYMENT BENEFIT PLANS:

Prior to the IPO, the Partnership was contractually obligated for a portion of the medical and life insurance benefits to retired employees of CONSOL Pennsylvania Coal Company LLC (the “OPEB Plans”). In conjunction with the IPO, on July 7, 2015 the OPEB liability and related accumulated other comprehensive income was retained by CONSOL Energy, and the Partnership has no further OPEB obligation as of such date.

The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2015 and December 31, 2014, is as follows:



	Other Postretirement Benefits
	at December 31,
	2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	6,819		$	38,401
Service cost	—			741
Interest cost	47			1,408
Actuarial gain	(381		)	(3,905		)
Plan amendments	(3,771		)	(28,375		)
Plan transfer	(2,507		)	—
Participant contributions	34			79
Benefits and other payments	(241		)	(1,530		)
Benefit obligation at end of period	$	—		$	6,819

Change in plan assets:
Company contributions	$	207		$	1,451
Participant contributions	34			79
Benefits and other payments	(241		)	(1,530		)
Fair value of plan assets at end of period	$	—		$	—

Funded status:
Current liabilities	$	—		$	(1,540	)
Noncurrent liabilities	—			(5,279		)
Net obligation recognized	$	—		$	(6,819	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial loss	$	—		$	(3,796	)
Prior service credit	—			26,264
Net amount recognized	$	—		$	22,468

The components of net periodic benefit costs are as follows:



	Other Postretirement Benefits
	For the Years Ended December 31,
	2015			2014			2013
Service cost	$	—		$	741		$	1,236
Interest cost	47			1,408			1,753
Amortization of prior service credits	(6,962		)	(1,865		)	(624		)
Recognized net actuarial loss	1,043			640			1,146
Curtailment gain	—			(2,042		)	—
Net periodic benefit cost	$	(5,872	)	$	(1,118	)	$	3,511

NOTE 15—COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION:

The Partnership is contractually obligated for our portion of medical and disability benefits to CPCC employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. Conrhein has no current or former employees. The Partnership is also responsible under various state statutes for our portion of pneumoconiosis benefits. The calculation of our portion 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 experience and outside sources. Although recent CWP legislation has not had a significant impact on the liability, there as been a noticed 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 Partnership is also contractually responsible to compensate individuals who sustain employment related physical injuries or some types of occupational diseases and, on some occasions, for our portion of costs of their rehabilitation. Workers’ compensation laws will also compensate survivors of workers who suffer employment 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 Partnership primarily provides for our portion of these claims through a self-insurance program. The Partnership recognizes an actuarial present value for our portion 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,
	2015			2014			2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	1,274		$	3,750		$	3,303		$	3,511
State administrative fees and insurance bond premiums	—			—			340			493
Service, legal and administrative cost	204			698			1,324			1,440
Interest cost	52			171			117			148
Actuarial loss (gain)	83			(3,253		)	(65		)	(1,251		)
Benefits and fees paid	(31		)	(92		)	(1,586		)	(1,038		)
Benefit obligation at end of period	$	1,582		$	1,274		$	3,433		$	3,303

Current assets	$	—		$	—		$	54		$	—
Current liabilities	(35		)	(24		)	(1,144		)	(922		)
Noncurrent liabilities	(1,547		)	(1,250		)	(2,343		)	(2,381		)
Net obligation recognized	$	(1,582	)	$	(1,274	)	$	(3,433	)	$	(3,303	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain	$	5,998		$	6,137		$	2,740		$	2,675
Net amount recognized	$	5,998		$	6,137		$	2,740		$	2,675

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,
	2015			2014			2013			2015			2014			2013
Service cost	$	204		$	698		$	501		$	1,325		$	1,440		$	1,478
Interest cost	52			171			149			117			148			111
Recognized net actuarial gain	(56		)	(192		)	(348		)	(1		)	(16		)	(44		)
State administrative fees and insurance bond premiums	—			—			—			340			493			493
Net periodic benefit cost	$	200		$	677		$	302		$	1,781		$	2,065		$	2,038

Amounts that are currently included in accumulated other comprehensive income are $71 and $17 for CWP benefits and workers' compensation benefits, respectively, that are expected to be recognized in 2016 net periodic benefit costs:

Assumptions:

The weighted-average discount rates used to determine benefit obligations and net periodic cost (benefit) are as follows:



	CWP						Workers' Compensation
	For the Years Ended						For the Years Ended
	December 31,						December 31,
	2015		2014		2013		2015		2014		2013
Benefit obligations	4.60	%	4.21	%	4.75	%	4.26	%	3.84	%	4.57	%
Net periodic cost (benefit)	4.21	%	4.75	%	4.03	%	3.84	%	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	$	(14	)	$	15
Workers' compensation costs (decrease) increase	$	(13	)	$	14

Cash Flows:

The Partnership does not intend to make contributions to the CWP or Workers’ Compensation plans in 2016. 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		Total		Actuarial		Other
	Benefits		Benefits		Benefits		Benefits
2016	$	35	$	1,251	$	1,090	$	161
2017	46		1,253		1,088		165
2018	76		1,291		1,122		169
2019	96		1,334		1,161		173
2020	118		1,393		1,216		177
Year 2021-2025	969		7,685		6,729		956

NOTE 16—OTHER BENEFIT PLANS:

Salaried Pension:

The Partnership is contractually obligated to fund 20% of the service cost for CPCC employees, which provide mining services to the Partnership, that participate in the CONSOL Energy Salaried Pension Plan. CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all salaried employees through December 31, 2015. Effective December 31, 2015, CONSOL Energy's qualified defined benefit plans have been frozen. The benefits for these plans are based primarily on years of service and employees’ pay. On September 30, 2014, the qualified pension plan was remeasured to reflect an announced plan amendment that would reduce future accruals of pension benefits as of January 1, 2015. The plan amendment called for a hard freeze of the qualified defined benefit pension plan on January 1, 2015 for employees who were under age 40 or had less than ten years of service as of September 30, 2014. Employees who were age 40 or over and had at least ten years of service would continue in the defined benefit pension plan unchanged. On August 31, 2015, the qualified pension plan was remeasured to reflect another announced plan amendment that reduced future accruals of pension benefits as of January 1, 2016. The plan amendment called for a hard freeze of the qualified defined benefit pension plan on January 1, 2016 for all remaining participants in the plan. The costs of these benefits during the years ended December 31, 2015, 2014 and 2013 were $707, $1,402 and $1,464, respectively. These costs are reflected in Operating and Other Costs in the Consolidated Statements of Operations.

Investment Plan:

The Partnership is contractually obligated to fund 20% of CPCC’s portion of CONSOL Energy’s investment plan. CONSOL Energy’s investment plan is available to most, non-represented employees. CONSOL Energy’s plan includes company matching of 6% of eligible compensation contributed by eligible employees of CPCC. Total payments and costs were $786, $612 and $584 for the years ended December 31, 2015, 2014 and 2013, respectively. These costs are reflected in Operating and Other Costs in the Consolidated Statements of Operations.

In conjunction with the qualified pension plan changes, beginning January 1, 2015, CONSOL Energy contributed an additional 3% of eligible compensation into the 401(k) plan accounts for employees hired or rehired on or after October 1, 2014 or who were under age 40 or had less than 10 years of service as of September 30, 2014. This additional contribution was eliminated as of January 1, 2016. The Plan also provides for discretionary contributions ranging from 1% to 4% (1% to 6% beginning January 1, 2016 and forward) of eligible compensation for eligible employees (as defined by the Plan). There were no such discretionary contributions made for the years ended December 31, 2015, 2014 and 2013, respectively.

Long-Term Disability:

The Partnership is contractually obligated for a Long-Term Disability Plan available to all eligible full-time salaried employees of CPCC. 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, 2015			December 31, 2014			December 31, 2013
Benefit costs	$	111		$	126		$	198
Discount rate assumption used to determine net periodic benefit costs	3.71		%	3.53		%	3.04		%

Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities-Other and Other Accrued Liabilities on the Consolidated Balance Sheets and amounted to $520 and $527 at December 31, 2015 and 2014, respectively.

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION:

For the years ended December 31, 2015, 2014 and 2013, the Partnership paid interest expense, net of capitalized interest, of $7,618, $6,949 and $2,090, respectively.

The following are non-cash transactions that impact the operating, investing and financing activities of the Partnership.

Prior to IPO,

•The CFI Loan was retained by CONSOL Energy and considered a deemed contribution in the amount of $183,596.

•CONSOL Energy contributed stream credit assets to the Partnership in the amount of $6,505.

•OPEB liabilities were retained by CONSOL Energy and treated as a deemed contribution in the amount of $2,507.

•As of December 31, 2015, 2014 and 2013, there were capital equipment contributions of $17,566, $4,259 and

$3,858, respectively, between the Partnership and CONSOL Energy that are included in equity.

As of December 31, 2015, 2014 and 2013, the Partnership purchased goods and services related to capital projects in the amount of $1,026, $454 and $1,226, respectively, that are included in accounts payable.

The Partnership obtains capital lease arrangements for company-used vehicles. For the years ended December 31, 2015, 2014 and 2013, the Partnership entered into non-cash capital lease arrangements of $111, $52 and $34, respectively.

NOTE 18—CONCENTRATION OF CREDIT RISK:

The Partnership primarily markets thermal coal principally to electric utilities in the eastern United States.

For the year ended December 31, 2015, coal sales to the following customers individually exceeded 10% of our revenues: Duke Energy, GenOn Energy Management and XCoal Energy & Resources.

For the year ended December 31, 2014, coal sales to the following customers individually exceeded 10% of our revenues: Duke Energy and GenOn Energy Management.

For the year ended December 31, 2013, coal sales to the following customers individually exceeded 10% of our revenues: Duke Energy, GenOn Energy Management, XCoal Energy & Resources and South Carolina Public Service Commission.

NOTE 19—COMMITMENTS AND CONTINGENT LIABILITIES:

The Partnership 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 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 Partnership, 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 Partnership; however, such amounts cannot be reasonably estimated.

Clean Water Act - Bailey Mine. CONSOL Energy received from the U.S. Environmental Protection Agency (the "EPA") on April 8, 2011, a request for information relating to the National Pollutant Discharge Elimination System

("NPDES") permit compliance at the Partnership’s Bailey and Enlow Fork Mines. In response, CPCC submitted water discharge monitoring and other data to the EPA. The investigation has focused primarily on exceedances at three discharge points. In early 2013, the case was referred to the U.S. Department of Justice (the "DOJ"), and PA DEP also became involved. On December 18, 2014, the DOJ provided the Partnership a proposed Consent Decree to resolve certain Clean Water Act and Clean Streams Law claims against CONSOL Energy and CPCC with respect to the Bailey Mine. The parties continue to negotiate the terms of the proposed Consent Decree. The Partnership has established an accrual to cover its estimated liability in this matter. This accrual is immaterial to the overall financial position of the Partnership and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

At December 31, 2015, the Partnership is contractually obligated to CONSOL Energy for financial guarantees and letters of credit to certain third parties which were issued by CONSOL Energy on behalf of the Partnership. The maximum potential total of future payments that we could be required to make under these instruments is $56,358. The instruments are comprised of $1,150 employee-related and other letters of credit expiring in the next three years, $47,141 of environmental surety bonds expiring within the next three years, and $8,067 of employee-related and other surety bonds expiring within the next three years. Employee-related financial guarantees have primarily been provided to support various state workers’ compensation and federal black lung 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. 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 Partnership’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 Partnership.

NOTE 20—RELATED PARTY:

The Consolidated 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 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 consolidated financial statements. Management believes the assumptions underlying the Consolidated Financial Statements, including the assumptions regarding allocating general corporate expenses from CONSOL Energy are reasonable. Nevertheless, these statements may not include all of the actual expenses that would have been incurred by the Partnership and may not reflect our Consolidated Statements of Operations, Balance Sheets and Cash Flows had we been a stand-alone company during the periods presented. Actual costs that would have been incurred if the Partnership 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.

In conjunction with the IPO, the Partnership entered into several agreements, including an omnibus agreement, with CONSOL Energy. The omnibus agreement provides that CONSOL Energy will perform certain shared services for a fee, including general, selling and direct administrative expenses related to stock based compensation, legal, treasury, human resources, information technology and other administrative services agreement. This agreement also provides that CONSOL Energy extend insurance and other employee benefit coverages for a fee.

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 Consolidated Statements of Operations. On December 12, 2014, Fairmont Supply was sold by CONSOL Energy and is no longer a related party of CONSOL Energy or the Partnership.

CPCC had several related party long-term notes with CFI that are disclosed within Note 9 - Debt. Payments for these notes were $8,761, $1,849, and $9,591 for the years ended December 31, 2015, 2014, and 2013, respectively. Proceeds from additional notes were $13,592, $11,371 and $18,893 for the years ended December 31, 2015, 2014, and 2013, respectively. Interest Expense related to these notes was $4,840, $9,534 and $9,310 for the years ended December 31, 2015, 2014, and 2013, respectively. These costs are included in Interest Expense in the accompanying Consolidated Statements of Operations.

Charges for services from CONSOL Energy include the following:



	For the Years Ended December 31,
	2015		2014		2013
Operating and Other Costs	$	3,709	$	4,186	$	3,290
Selling and Direct Administrative Expenses	5,085		6,444		5,687
General and Administrative Expenses	3,829		9,303		7,937
Total Service from CONSOL Energy	$	12,623	$	19,933	$	16,914

At December 31, 2015, the Partnership had a net payable to CONSOL Energy in the amount of $3,452. This payable includes reimbursements for business expenses, executive fees, debt issuance and financing fees, stock-based compensation and other items.

NOTE 21—LONG-TERM INCENTIVE PLAN:

Under the CNX Coal Resources LP 2015 Long-Term Incentive Plan (the “LTIP”), 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 are 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. We are responsible for the cost of awards granted

under the LTIP and all determinations with respect to awards to be made under the 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.

The LTIP limits the number of units that may be delivered pursuant to vested awards to 2,300,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled,

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.

The Partnership's general partner has granted equity-based phantom units to non-employee directors of the general partner that vest over a period of a director's continued service with the Partnership. The value of the phantom units will be paid in common units or an amount of cash equal to the fair market value of a unit based on the grant date. The awards may be accelerated upon a change in control of the Partnership. Compensation expense for these awards is recognized on a straight-line basis over the requisite service period, which is generally the vesting term. The Partnership recognized $40 of compensation expense for the year ended December 31, 2015, which is included in General and Administrative Expense in the Consolidated Statements of Operations.

As of December 31, 2015, 6,456 units have been issued under our LTIP. The weighted average fair value of these grants, based on the Partnership's common unit price on the grant date, was $14.39 per unit. There are no awards yet vested or forfeited. As of December 31, 2015, there is $52 of unearned compensation that will vest over a weighted average period of seven months.

NOTE 22—SUBSEQUENT EVENTS:

On January 28, 2016, the Board of Directors of CNX Coal Resources GP LLC, the general partner of CNX Coal Resources LP, declared a cash distribution to the Partnership's unitholders for the fourth quarter of 2015 of $0.5125 per common and subordinated unit. The cash distribution will be paid on February 15, 2016 to the unitholders of record at the close of business on February 8, 2016.

SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED):



	Three months ended
	March 31, 2015		June 30, 2015		September 30, 2015		December 31, 2015
Coal sales	$	76,887	$	63,799	$	64,635	$	52,488
Freight revenue	474		541		242		1,790
Other income	231		145		275		102
Total Revenue	77,592		64,485		65,152		54,380
Cost of goods sold and other costs	55,369		48,866		46,388		40,457
Freight expense	474		541		242		1,790
General and administrative expenses	2,019		2,774		1,969		1,562
Interest expense	2,381		2,328		1,888		1,898
Total Expense	60,243		54,509		50,487		45,707
Net income	$	17,349	$	9,976	$	14,665	$	8,673
Net income per limited partner unit
Basic	*		*		$	0.62	$	0.37
Diluted	*		*		$	0.62	$	0.37

* Net income per limited partner unit was not applicable for the period presented.



	Three months ended
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014
Coal sales	$	82,416	$	86,989	$	75,928	$	78,065
Freight revenue	1,486		1,344		156		367
Other income	408		6,920		61		339
Total Revenue	84,310		95,253		76,145		78,771
Cost of goods sold and other costs	50,533		61,500		59,351		55,835
Freight expense	1,486		1,344		156		367
General and administrative expenses	3,927		3,045		2,623		3,467
Interest expense	471		2,048		2,190		2,237
Total Expense	56,417		67,937		64,320		61,906
Net income	$	27,893	$	27,316	$	11,825	$	16,865

Net income per limited partner unit was not applicable for the period presented.

SUPPLEMENTAL COAL DATA (UNAUDITED):



	Thousands of Tons
	For the Year Ended December 31,
	2015		2014		2013
Proven and probable reserves at beginning of period	157,127		125,066		131,437
Purchased reserves	4,680		1		1
Reserves sold in place	—		—		(2,037	)
Production	(4,558	)	(5,213	)	(4,287	)
Revisions and other changes	1,027		37,273		(48	)
Consolidated proven and probable reserves at end of period*	158,276		157,127		125,066

* Proven 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, 2015, 158,276 tons of proven and probable reserves were assigned and/or accessible to our three active mines (Bailey, Enlow Fork and Harvey Mines). Of the 2015 total reserves, Enlow Fork Mine equates to 63,231 tons, Bailey Mine to 54,348 tons and Harvey Mine to 40,697 tons. On average, the reserves have a sulfur content equivalent of approximately 3.6 lbs SO₂/MMBTU, in which Enlow Fork Mine equates to 3.4 lbs SO₂/MMBTU, Bailey Mine to 4.1 lbs SO₂/MMBTU and Harvey Mine to 3.4 lbs SO₂/MMBTU.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures pursuant to Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), was conducted as of the end of the period covered by this report. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer of the Partnership's general partner have concluded that the Partnership's disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the year ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

The management of the Partnership’s general partner is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control system is designed to provide reasonable assurance to the Partnership’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only

reasonable assurance with respect to financial statement preparation and presentation.

This annual report on Form 10-K for the fiscal year ended December 31, 2015 does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Partnership's independent public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for emerging growth companies.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF MANAGING GENERAL PARTNER

We are managed and operated 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.

Our general partner has seven directors of which three have been determined by our board to be independent as defined under the independence standards established by the New York Stock Exchange (“NYSE”) and the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the board of directors of its general partner.

The following table presents information for the board of directors and executive officers of CNX Coal Resources GP LLC as of December 31, 2015. 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. Directors 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.



Name	Age	Position with Our General Partner
James A. Brock	59	Chief Executive Officer and Director
Lorraine L. Ritter	50	Chief Financial Officer and Chief Accounting Officer
Martha A. Wiegand	45	General Counsel and Secretary
Nicholas J. DeIuliis	47	Chairman of the Board
Stephen W. Johnson	56	Director
David M. Khani	52	Director
James E. Altmeyer, Sr	77	Director and Member of Audit Committee
Michael L. Greenwood	60	Director and Member of Audit* and Conflicts Committees
Jeffrey L. Wallace	59	Director and Member of Audit and Conflicts* Committees

*Indicates Chair of Committee

James A. Brock was appointed Chief Executive Officer and a director of our general partner effective March 16, 2015. Mr. Brock also serves as Chief Operating Officer-Coal of CONSOL Energy, a position he has held 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, a position she held until July 20, 2015. 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.

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 Administrative Officer of CONSOL Energy and CNX Gas Corporation since April 13, 2015. From December 31, 2012 until April 13, 2015, he served as Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy and CNX Gas Corporation. 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.

James E. Altmeyer, Sr. became a member of the board of directors on July 1, 2015 and has agreed to serve for a term of 18 months. Mr. Altmeyer is the former President and Chief Executive Officer of Altmeyer Funeral Homes, Inc. of West Virginia, Ohio, Virginia and North Carolina from 1972 until 2007, at which time he became chairman of Altmeyer Funeral Homes, Inc. He has also been President of Altmeyer Realty, a real estate holding company, and of Martin-Steadfast Insurance Company since 1972. Mr. Altmeyer served on the board of directors of CONSOL Energy from November 2003 to May 2015. Mr. Altmeyer also served on the board of directors of WesBanco, Inc., a multi-state bank holding company from 1987 until April 2010, when he retired from the board. Mr. Altmeyer is also a member of the executive committee of the Wheeling Hospital board of directors and vice chairman of the Chambers Foundation. Mr. Altmeyer is a graduate of the United States Military Academy at West Point and served on active duty in the United States Army until October 1972. Among his numerous combat (Vietnam) awards are a Silver Star and three Bronze Stars. We believe that Mr. Altmeyer’s significant corporate governance and financial expertise, along with his extensive experience in leadership roles, provides the board of directors of our general partner with valuable experience.

Michael L. Greenwood became a member of the board of directors on July 1, 2015. Mr. Greenwood is Managing Director of Carnegie Capital LLC (2004 - present), a private financial advisory firm providing corporate and private equity clients investment banking assistance with acquisitions, divestitures and debt and equity capital fundings. From 2002 to 2004, Mr. Greenwood was Vice President-Finance and Treasurer of Energy Transfer Partners, L.P., a diversified energy company, and Chief Financial Officer and Treasurer of its predecessor, Heritage Propane Partners, L.P. From 1994 to 2002, he was Chief Financial Officer and Treasurer of Alliance Resource Partners, L.P., a producer and marketer of coal to major utilities. Prior to his career at Alliance Resource Partners, Mr. Greenwood held a number of financial positions in the energy industry with Mapco Inc., Penn Central Corporation and The Williams Companies. Additionally, Mr. Greenwood previously served on the boards of Hiland Partners, LP, Libra Natural Resources plc, Global Power Equipment Group Inc., Hiland Holdings GP and International Resource Partners GP. He also serves as a trustee of the Oklahoma State University Foundation and as a director of the OSU Research Foundation. Mr. Greenwood’s previous experience with public master limited partnerships and the coal industry, as well as his expertise in financial matters, provide him with the necessary skills to be a member of the board of directors of our general partner.

Jeffrey L. Wallace became a member of the board of directors on July 1, 2015. Mr. Wallace was the Vice President of Fuel Services (2006 to 2015) of Southern Company Generation, the generation subsidiary of The Southern Company, an electric utility serving 4.2 million customers in the southeast United States, with more than 40,000 megawatts of generating capacity. In that role, Mr. Wallace is responsible for managing the $7 billion annual fuel planning, procurement and delivery program for 85 power plants. Prior to that position, he was Vice President of Planning and Utility Relations at Georgia Power, a Southern Company subsidiary. He joined the company in 1978, working in accounting and budgeting, resource management and customer service, among other areas, since that time. Mr. Wallace is a graduate of the University of Georgia with degree in accounting and he earned his MBA in finance from Georgia State University. He also has an Executive MBA from Harvard Business School. Mr. Wallace has served on the boards of directors of the Boy Scouts of America (Atlanta Area Council), the South Fulton Chamber of Commerce, the American Coal Council, the National Coal Council and the Rail Energy Transportation Advisory Committee to the Surface Transportation Board. Mr. Wallace’s experience with electric utilities and the coal industry, as well as his expertise in financial matters, provide him with the necessary skills to be a member of the board of directors of our general partner.

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. Currently our CEO is a member of our board of directors but is not its chairman.

Board Role in Risk Oversight

Our corporate governance guidelines 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.

Meetings of Non-Management Directors and Communications with Directors

At least annually, all of the independent directors of our general partner meet in executive session without management participation or participation by non-independent directors. Mr. Greenwood, as the Chairman of the audit committee, serves as the presiding director for such executive sessions. The presiding director may be contacted by mail or courier service:

Presiding Director of the Board of Directors,

C/O Martha A. Wiegand, General Counsel and Secretary,

CNX Coal Resources LP

1000 CONSOL Energy Drive

Canonsburg, PA 15317

Committees of the Board of Directors

The board of directors of our general partner has one standing committee: an audit committee. The conflicts committee is convened on an as needed basis. NYSE does not require a publicly traded limited partnership like us to establish a compensation or a nominating and corporate governance committee.

Audit Committee

Our general partner is required by NYSE to have an audit committee of at least three members and all of the audit committee members must meet the independence and experience requirements established by NYSE and the Exchange Act.

The audit committee consists of Messrs. Greenwood (Chairman), Altermeyer and Wallace. Each member of the audit committee satisfies the independence requirements established by NYSE and the Exchange Act and is financially literate. In addition, the board of directors of our general partner has determined that each member of the audit committee qualifies as an “audit committee financial expert” as such term is defined under the SEC’s regulations. This designation is a disclosure requirement of the SEC related to each audit committee members’ experience and understanding with respect to certain accounting and auditing matters. The designation does not impose upon the audit committee members any duties, obligations or liabilities that are greater than those generally imposed on them as members of the audit committee and the board of directors of our general partner. As audit committee financial experts, each member of the audit committee also has the accounting or related financial management expertise required by NYSE rules.

The audit committee of the board of directors of our general partner assists 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 has 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 is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

Conflicts Committee

From time to time, on an as needed basis, our board of directors convene a conflicts committee under our partnership agreement, 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, Messrs. Wallace (Chairman), and Greenwood, are not officers or employees of our general partner or directors, officers or employees of its affiliates (including CONSOL Energy), and 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. Our partnership agreement provides that 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.

Compensation Committee Interlocks and Insider Participation

The listing rules of the NYSE do not require us to maintain, and we do not maintain, a compensation committee.

Code of Conduct and Code of Ethics

We have adopted a code of business conduct and ethics applicable to all of our directors, officers, employees, and other personnel and to our subsidiaries, as well as to our suppliers, vendors, agents, contractors and consultants. The code of business conduct and ethics, along with our corporate governance guidelines and audit committee charter, are posted on our website, www.cnxclp.com. You may also obtain a copy by contacting Martha A. Wiegand, General Counsel and Secretary, CNX Coal Resources LP, 1000 CONSOL Energy Drive, Canonsburg PA 15317. We intend to satisfy our disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of business conduct and ethics by posting such information on our website.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities (collectively, “Insiders”) to file with the SEC initial reports of ownership and reports of changes in ownership of such equity securities. Insiders are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of forms furnished to us, or written representations from certain reporting persons were required, we believe that the Insiders complied with all filing requirements under Rule 16(a) with respect to transactions in our equity securities during 2015.

ITEM 11. EXECUTIVE COMPENSATION

Compensation of Our Officers and Directors

We are currently considered an emerging growth company for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, our reporting obligations for this Item 11 extend only to the individual serving as CEO and the two other most highly compensated executive officers receiving compensation of at least $100,000 in 2015 and allows us to provide reduced disclosure about executive compensation arrangements.

The Compensation Discussion and Analysis and Executive Compensation sections of CONSOL Energy’s 2016 Proxy Statement will include a full discussion of CONSOL Energy’s compensation policies and programs. CONSOL Energy’s Proxy Statement will be available upon its filing on the SEC’s website at http://www.sec.gov and on CONSOL Energy’s website at http://www.consolenergy.com.

Executive Compensation

The executive officers of our general partner are employed and compensated by CONSOL Energy or its affiliates (other than our general partner). 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, is set by CONSOL Energy and its affiliates. The executive officers of our general partner also participate in employee benefit plans and arrangements sponsored by CONSOL Energy and its affiliates, including plans that may be established in the future.

Summary Compensation Table for 2015

On July 6, 2015, we entered into an omnibus agreement with CONSOL Energy under which we agreed to reimburse CONSOL Energy on a monthly basis for compensation related expenses (including salary, bonus, incentive compensation and other amounts) attributable to the portion of an executive’s compensation that is allocable to our general partner. James A. Brock, Chief Executive Officer of our general partner, Lorraine L. Ritter, Chief Financial Officer and Chief Accounting Officer of our general partner, and Martha A. Wiegand, General Counsel and Secretary of our general partner, devote approximately 75%, 100% and 100%, respectively, of their overall professional working time to the business and affairs of the Pennsylvania mining complex (on a 100% basis). Net to our 20% undivided interest in the Pennsylvania mining complex, we reimburse CONSOL Energy for approximately 15%, 20% and 20% of the total compensation related expenses (including salary, bonus, incentive compensation and other amounts) incurred by CONSOL Energy and attributable to Mr. Brock’s, Ms. Ritter’s and Ms. Wiegand’s compensation, respectively. The total reimbursable compensation related expenses attributable to each of Mr. Brock, Ms. Ritter and Ms. Wiegand for the period from July 7, 2015 to December 31, 2015 was approximately $33,400, $30,600 and $21,800, respectively.

For periods prior to July 6, 2015, the executive officers of our general partner were employed by CONSOL Energy and, in addition to their responsibilities related to the Pennsylvania mining complex, also performed services for CONSOL Energy that were unrelated to the Pennsylvania mining complex. During these periods, no amounts of compensation for our executive officers were separately allocated to our business.

The following summarizes the total compensation earned by the executive officers of our general partner during 2015, including all compensation related expenses disclosed above, which were paid by CONSOL Energy:



Name and Principal Position	Salary		Stock Awards (1)		Non-Equity Incentive Compensation (2)		Change in Pension Value and Nonqualified Deferred Compensation Earnings (3)		All Other Compensation (4)		Total
James A. Brock, Chief Executive Officer	$	399,032	$	750,000	$	212,000	$	7,422	$	21,873	$	1,390,327
Lorraine L. Ritter, Chief Financial Officer & Chief Accounting Officer	$	289,880	$	100,000	$	147,539	$	—	$	28,900	$	566,319
Martha A Wiegand, General Counsel & Secretary	$	191,660	$	57,720	$	31,845	$	—	$	17,316	$	298,541



(1)	The values set forth in this column reflect awards of performance based stock units ("PSU") and restricted stock units ("RSU"), and are based on the aggregate grant date fair value of the awards computed in accordance with FASB ASC Topic 718 (disregarding the impact of estimated forfeitures related to service-based vesting conditions). For RSU's, the grant date fair value is computed based upon the closing price of CONSOL Energy’s stock on the date of grant. There were no CNXC unit based awards in 2015.
(2)	Includes cash incentives earned in the applicable year under the CONSOL Energy Short-Term Plan. The relevant performance measures underlying the cash awards were satisfied in the applicable annual performance period.
(3)	Amounts reflect the actuarial increase in the present value of the named executive’s benefits under the CONSOL Energy Employee Retirement Plan, the CONSOL Retirement Restoration Plan, the CONSOL Supplemental Retirement Plan and the Defined Contribution Restoration Plan. These amounts were determined using the interest rate and mortality assumptions consistent with those used in its financial statements. For Ms. Ritter and Ms. Wiegand, zero is shown for 2015 because the actual actuarial change in pension value was a decrease in the amounts of ($60,171) and ($2,675), respectively.
(4)	Mr. Brock’s personal benefits for 2015 include: financial planning, and $15,900 in matching contributions made by CONSOL Energy under its 401(k) plan. Ms. Ritter’s personal benefits for 2015 include: $15,900 in matching contributions made by CONSOL Energy under its 401(k) plan and a vehicle allowance of $13,000. Ms. Wiegand’s personal benefits for 2015 include $17,316 in matching and qualified non-elective contributions made by CONSOL Energy under its 401(k) plan.

Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure

CONSOL Energy provides compensation to its executives in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefits plans and arrangements, including broad-based and supplemental defined contribution and defined benefit retirement plans. In the future, as CONSOL Energy and our general partner formulate and implement the compensation programs for our executive officers, our executive officers may be provided different and/or additional compensation components, benefits and/or perquisites to ensure that they are provided with a comprehensive and competitive compensation structure.

The following sets forth a more detailed explanation of the elements of CONSOL Energy’s compensation programs as they relate to Mr. Brock, Ms. Ritter and Ms. Wiegand:

Base Salary. Base salary is designed to provide a competitive fixed rate of pay recognizing employees’ different levels of responsibility and performance. In setting an executive’s base salary, CONSOL Energy considers factors including, but not limited to, external market data, the internal worth and value assigned to the executive’s role and responsibilities at CONSOL Energy, and the named executive’s skills and performance.

Annual Cash Incentives. CONSOL Energy’s annual cash incentive program provides participants with an opportunity to earn performance based annual cash bonus awards. Target annual bonus levels are established at the beginning of each year and are based on a percentage of the executive’s base salary. For 2015, Mr. Brock had a target bonus of 65% of his annual base salary, with a potential payout up to 200% of target based on company performance metrics, which for 2015 included metrics relating to employee and miner safety, environmental compliance, production and operating costs. For 2015, Ms. Ritter had a target bonus of 40% of her annual base salary, with a potential payout up to 300% of target based on company performance metrics, which for 2015 included metrics relating to employee and miner safety, environmental compliance, production and operating costs. For 2015, Ms. Wiegand had a target bonus of 15% of her annual base salary, with a potential payout up to

300% of target based on company performance metrics, which for 2015 included metrics relating to employee and miner safety, environmental compliance, production and operating costs. For 2015, CONSOL Energy paid a cash bonus to Mr. Brock at a level of approximately 81% of his target award level. For 2015, CONSOL Energy paid a cash bonus to Ms. Ritter at a level of approximately 126% of her target award level and paid a cash bonus to Ms. Wiegand at a level of approximately 110% of her target award level in recognition of CONSOL Energy’s performance at above target levels for several of the above-specified criteria.

Long-Term Equity-Based Compensation Awards. CONSOL Energy maintains a long-term incentive program pursuant to which it grants equity-based awards in CONSOL Energy to its executives and key employees. For 2015, CONSOL Energy’s equity-based awards for Ms. Wiegand consisted of restricted stock units, which vest, one-third per year and for Mr. Brock and Ms. Ritter, consisted of restricted stock units and performance share units which vest one-third per year and after the end of a three-year performance period, respectively.

Outstanding Equity Awards at December 31, 2015. As a newly formed company, we have not granted and none of our executive officers have received any grants of equity or equity-based awards in us and no such awards were outstanding as of December 31, 2015. In connection with our initial public offering, we adopted a new long-term incentive plan, under which we may make grants of equity and equity-based awards in us to our executive officers and other key employees.

Our executive officers have received and may continue to receive equity or equity-based awards in CONSOL Energy under its equity compensation program. The following provides additional information about our executive officers’ outstanding equity awards in CONSOL Energy as of December 31, 2015.



	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options Unexercisable	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($) (10)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (11)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (12)
James A. Brock, Chief Executive Officer	3,226 6,432 3,111 6,347 4,115 6,329 12,420	(1) (2) (3) (4) (5) (6) (7)		44.10 34.85 78.65 27.90 50.50 48.61 36.14	05/02/2016 02/20/2017 02/19/2018 02/17/2019 02/16/2020 02/23/2021 01/26/2022	18,046 10,886	(8) (9)	$142,563 $85,999	25,751	$203,433
Lorraine L. Ritter, Chief Financial Officer & Chief Accounting Officer	2,483 4,073 1,642 5,994 4,001 3,165 4,436	(1) (2) (3) (4) (5) (6) (7)		44.10 34.85 78.65 27.90 50.50 48.61 36.14	05/02/2016 02/20/2017 02/19/2018 02/17/2019 02/16/2020 02/23/2021 01/26/2022	3,988	(8)	$31,505	5,807	$45,875
Martha A. Wiegand, General Counsel & Secretary	248 487 608 880	(4) (5) (6) (7)		27.90 50.50 48.61 36.14	02/16/2019 02/16/2020 02/23/2021 01/26/2022	3,447	(8)	$27,231

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(1)		Options granted 5/2/06 that vested and became exercisable in four equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(2)		Options granted 2/20/07 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(3)		Options granted 2/19/08 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(4)		Options granted 2/17/09 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(5)		Options granted 2/16/10 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(6)		Options granted 2/23/11 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(7)		Options granted 1/26/12 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(8	)	RSU's granted on 1/31/13 and 1/31/14 and vest in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(9	)	RSU's granted on September 24, 2014, which, subject to continued employment, vest in one lump sum on the fifth anniversary of the grant date.
(10	)	The market value for RSU's were determined by multiplying the closing market price for CONSOL Energy common stock on December 31, 2015 ($7.90) by the number of shares underlying the RSU awards.
(11	)	This column shows the number of unvested PSU’s and CSU's as of December 31, 2015. The performance period for the PSU’s granted in 2015 is January 1, 2015 through December 31, 2017 and for the CSU awards granted in 2013 is January 1, 2013 through December 31, 2015. The amounts presented for the 2015 PSU awards are based on achieving performance goals at a target level for 2015. The amounts presented for the the 2013 CSU awards are based on the achieving the target level for 2013.
(12	)	The market value for PSU's and CSU's was determined by multiplying the closing market price for CONSOL Energy common stock on December 31, 2015 ($7.90) by the number of shares underlying the PSU and CSU awards.

Retirement, Health, Welfare and Additional Benefits. CONSOL Energy employees are eligible to participate in a variety employee benefit plans and programs, subject to the terms and eligibility requirements of those plans, which include a broad-based defined benefit pension plan and 401(k) savings plan, as well as a supplemental defined contribution retirement plan that provides benefits to executive officers and key employees, including Mr. Brock and Ms. Ritter, in excess of IRS imposed limits under the broad-based pension and savings plan. CONSOL Energy also provides limited executive perquisites, which are described in the footnotes to the Summary Compensation Table for 2015.

Employee Retirement Plan (the “Pension Plan”)

CONSOL Energy’s Pension Plan is a defined benefit plan that pays retirement benefits based on years of service and compensation. It is a qualified plan, meaning that it is subject to a variety of IRS rules. These rules contain various requirements on coverage, funding, vesting and the amount of compensation that can be taken into account in calculating benefits. The Pension Plan has a fairly broad application across CONSOL Energy’s employee population and forms a part of the general retirement benefit program available to employees.

•

Eligibility: The Pension Plan covers employees of CONSOL Energy and affiliated participating companies that are classified as regular, full-time employees or that complete 1,000 hours of service during a specified twelve-month period. The Pension Plan was amended to reduce future accruals of pension benefits as of December 31, 2014, to provide for a hard freeze of the 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 and that employees hired or rehired on or after October 1, 2014 are not eligible to participate in the Pension Plan. Beginning January 1, 2015, employees who were age 40 or over and had at least 10 years of service as of September 30, 2014 continued in the Pension Plan unchanged.

•

Form of Payment: The portion of accrued pension benefits earned under the Pension Plan as of December 31, 2005 may be, upon the election of the participant, paid in the form of a lump-sum payment except in the case of an incapacity retirement as discussed above. Pension benefits earned after January 1, 2006 are payable in the form of a single life annuity, 50% joint and survivor annuity, 75% joint and survivor annuity or 100% joint and survivor annuity.


•	Calculation of Benefits: Pension benefits are based on an employee’s years of service and average monthly pay during the employee’s five highest-paid years. Average monthly pay for this purpose excludes compensation in excess of

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limits imposed by the Code (up to $265,000 for 2015). Prior to January 1, 2006, pension benefits were calculated based on the average monthly pay during the employee’s three highest-paid years and included annual amounts payable under CONSOL Energy’s STIC, again excluding compensation in excess of limits imposed by the Code.


•	Categories: The Pension Plan provides for various categories of retirement, including normal retirement, early retirement, separation retirement, and incapacity retirement, based upon years of service, age and certain other factors.

Supplemental Retirement Plan

The CONSOL Energy Supplemental Retirement Plan was designed primarily for the purpose of providing benefits for a select group of management and highly compensated employees of CONSOL Energy and its subsidiaries and is intended to qualify as a “top hat” plan under the Employee Retirement Income Security Act of 1974, as amended. CONSOL Energy froze the plan effective December 31, 2011 for current and future CONSOL employees except for certain “excepted employees".

The amount of each participant’s benefit under the plan as of age 65 (expressed as an annual amount) will be equal to 50% of “final average compensation” multiplied by the “service fraction” as calculated on the participant’s date of employment termination with CONSOL Energy. “Final average compensation” means the average of a participant’s five highest consecutive annual compensation amounts (annual base salary plus amounts received under the STIC) while employed by CONSOL Energy or its subsidiaries. The “service fraction” means a fraction with a numerator equal to a participant’s number of years of service and with a denominator of 20. The service fraction can never exceed one.

The benefit described above will be reduced by a participant’s age 65 vested benefits (including benefits which have been paid or are payable in the future (converted to an annual amount)) under: (i) the Pension Plan; (ii) the Restoration Plan; and (iii) any other plan or arrangement providing retirement-type benefits, to the extent service under such arrangement is credited under the Supplemental Retirement Plan.

No benefit will be vested under the Supplemental Retirement Plan until a participant has five years of service with CONSOL Energy or its participating subsidiaries while the participant meets the eligibility standards in the plan.

Benefits under the Supplemental Retirement Plan will be paid in the form of a life annuity with a guaranteed term of 20 years (which will be the actuarial equivalent of a single life annuity) commencing in the month following the later to occur of: (a) the end of the month following the month in which the participant turns age 50 or (b) the end of the month following the month in which the employment termination of a participant occurs. In the event the benefits commence prior to the participant’s normal retirement age, the benefit will be actuarially reduced as necessary (using assumptions specified in the Pension Plan).

New Restoration Plan

CONSOL Energy adopted a New Restoration Plan, effective January 1, 2012, designed primarily for the purpose of providing benefits for a select group of management and highly compensated employees of CONSOL Energy and its subsidiaries and is intended to qualify as a “top hat” plan under the Employee Retirement Income Security Act of 1974, as amended. CONSOL employees who are eligible to participate and accrue benefits in the Supplemental Retirement Plan are ineligible to participate in the New Restoration Plan.

The CONSOL Energy Compensation Committee has reserved the right to terminate a participant’s participation in the New Restoration Plan at any time. Additionally, if a participant’s employment is terminated or if a participant no longer meets the New Restoration Plan’s basic eligibility standards, the participant’s participation in New Restoration Plan (and such person’s right to accrue any benefits thereunder) will terminate automatically with no further action required.

Eligibility for benefits under the New Restoration Plan is determined each calendar year (the “Award Period”). Participants whose sum of annual base pay as of December 31 and amounts received under the STIC or other annual incentive program earned for services rendered by the participant during the Award Period exceed the compensation limits imposed by section 401(a)(17) of the Code (up to $260,000 for 2014) are eligible for benefits under the New Restoration Plan for the Award Period. The amount of each eligible participant’s benefit under the plan is equal to 9% times annual base salary as of December 31 including amounts received under the STIC or other annual incentive program earned for services rendered by the participant during the Award Period less 6% times the lesser of annual base salary as of December 31 or the compensation limit imposed by the Code for the Award Period.

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Benefits under the New Restoration Plan will be paid in the form of two hundred forty (240) equal monthly installments, with each installment equal to the value of the participant’s account at commencement divided by two hundred forty (240). Benefits shall commence in the month immediately following the later to occur of: (i) the month in which the participant turns age 60 or (ii) the month containing the six-month anniversary date of the participant’s separation from service.

Severance and Change in Control Programs. CONSOL Energy has entered into change in control severance agreements with each of Mr. Brock and Ms. Ritter, which are described below.

Agreements Between Our Executive Officers and CONSOL Energy

Our general partner’s executive officers have not entered into any agreements or arrangements with us or our general partner or with CONSOL Energy specifically in relation to their services with us and our general partner. However, in relation to their employment with CONSOL Energy, each of Mr. Brock and Ms. Ritter have entered into a change in control severance agreement with CONSOL Energy (the “CIC Agreements”). Ms. Wiegand has not entered into any employment agreements or other arrangements with CONSOL Energy.

The CIC Agreements provide severance benefits to Mr. Brock and Ms. Ritter if they are terminated (i) for any reason, other than cause (as defined below), death or disability, that occurs not more than three months prior to or within two years after a change in control, or is requested by a third party initiating the change in control or (ii) within the two-year period after a change in control, if the executive is constructively terminated (as defined below).

Under the two circumstances described above, each of Mr. Brock and Ms. Ritter would be entitled to receive:


•	a lump sum cash payment equal to a multiple of base pay plus a multiple of incentive pay (the multiple, in each case, for Mr. Brock is 2.0 and for Ms. Ritter is 1.5);


•	a pro-rated payment of the executive’s incentive pay for the year in which termination occurs;


•	for a specified period (for Mr. Brock 24 months and for Ms. Ritter 18 months), the continuation of medical and dental coverage (or monthly reimbursements in lieu of continuation);

•

if the executive would have been eligible for post-retirement medical benefits had the executive retired from employment during the applicable period, but is not so eligible due to termination, then at the conclusion of the benefit period, the executive is entitled to receive additional continued group medical coverage comparable to that which would have been available under the post-retirement program for so long as such coverage would have been available under such program, or the executive will receive monthly reimbursements in lieu of such coverage;

•

a lump sum cash payment equal to the total amount that the executive would have received under CONSOL Energy’s 401(k) plan as a match if the executive was eligible to participate in the 401(k) plan for a specified period after the executive’s termination date (for Mr. Brock 24 months and for Ms. Ritter 18 months) and the executive contributed the maximum amount to the 401(k) plan for the match;

•

a lump sum cash payment equal to the difference between the present value of the executive’s accrued pension benefits at the executive’s termination date under CONSOL Energy’s qualified defined benefit pension plan and (if eligible) any plan or plans providing nonqualified retirement benefits and the present value of the accrued pension benefits to which the executive would have been entitled under the pension plans if the executive had continued participation in those plans for a specified period after the executive’s termination date (for Mr. Brock 24 months and for Ms. Ritter 18 months);


•	a lump sum cash payment of $25,000 in order to cover the cost of outplacement assistance services and other expenses associated with seeking other employment; and


•	any amounts earned, accrued or owing but not yet paid as of the executive’s termination date, payable in a lump sum, and any benefits accrued or earned in accordance with the terms of any applicable benefit plans or programs.

In addition, upon a change in control, all equity awards granted to each of Mr. Brock and Ms. Ritter will become fully vested and/or exercisable on the date the change in control occurs and all stock options and/or stock appreciation rights will remain exercisable for the period set forth in the applicable award agreement.

The CIC Agreements contain confidentiality, non-competition and non-solicitation obligations pursuant to which each of Mr. Brock and Ms. Ritter have agreed not to compete with the business for one year, or to solicit employees for two years, following a termination of employment, when such executive is receiving severance benefits under the CIC Agreement.

No payments or benefits are provided under the CIC Agreements unless the executive executes, and does not revoke, a written release of any and all claims (other than for entitlements under the terms of the CIC Agreement or which may not be

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released under the law).

For purposes of the CIC Agreements, “cause” is a determination by the board of directors of CONSOL Energy that the executive has:

(a) been convicted of, or has pleaded guilty or nolo contendere to, any felony or any misdemeanor involving fraud, embezzlement or theft; or

(b) wrongfully disclosed material confidential information, intentionally violated any material express provision of CONSOL Energy’s code of conduct for executives and management employees (as then in effect) or intentionally failed or refused to perform any of the executive’s material assigned duties, and any such failure or refusal has been demonstrably and materially harmful to CONSOL Energy.

Notwithstanding the foregoing, the executive will not be deemed to have been terminated for “cause” under clause (b) above unless the majority of the members of CONSOL Energy’s board of directors, plus one additional member of such board, find that, in its good faith opinion, the executive has committed an act constituting “cause,” and such resolution is delivered in writing to the executive.

For purposes of Ms. Ritter’s CIC Agreement, a “change in control” generally means a change in control of CONSOL Energy. For purposes of Mr. Brock’s CIC Agreement, a “change of control” generally means a change in control of CONSOL Energy and also includes a change in control of CONSOL Energy’s coal division.

For purposes of the CIC Agreements, a “constructive termination” means:

(a) a material adverse change in position;

(b) a material reduction in annual base salary or target bonus or a material reduction in employee benefits;

(c) a material adverse change in circumstances as determined in good faith by the executive, including a material change in the scope of business or other activities for which the executive was responsible prior to the change in control, which has rendered the executive unable to carry out, has materially hindered the executive’s performance of, or has caused the executive to suffer a material reduction in, any of the authorities, powers, functions, responsibilities or duties attached to the position the executive held immediately prior to the change in control;

(d) the liquidation, dissolution, merger, consolidation or reorganization of CONSOL Energy or transfer of substantially all its business or assets, unless the successor assumes all duties and obligations of CONSOL Energy under the applicable CIC Agreement; or

(e) the relocation of the executive’s principal work location to a location that increases the executive’s normal commute by 50 miles or more or that requires travel increases by a material amount.

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 do not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner or of our sponsor, or “non-employee directors,” receive cash and equity-based compensation for their services as directors. We directly pay all compensation earned by our non-employee directors for their services to us. The non-employee director compensation program consists of the following:


•	an annual retainer of $60,000 (payable in quarterly installments);


•	an additional annual retainer of $20,000 (payable in quarterly installments) for service as chair of the audit committee;


•	an additional payment of $1,000 for service as chair of the conflicts committee, if convened, per transaction;


•	$5,000 per member for conflicts committee service if convened, per transaction; and


•	an annual equity-based award granted under the LTIP, having a value as of the grant date of approximately $60,000 and vesting on the first anniversary of the grant date.

Non-employee directors also receive reimbursement for out-of-pocket expenses they incur in connection with attending

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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.

The following table sets forth the compensation earned by our directors for the 2015 fiscal year.



Name (1)	Fees Earned or Paid in Cash ($)	Stock Awards (1)	Option Awards	All Other Compensation	Total
Michael Greenwood	$50,000	$30,000	$0	$0	$80,000
James Altmeyer	$35,000	$30,000	$0	$0	$65,000
Jeff Wallace	$41,000	$30,000	$0	$0	$71,000

(1) The values set forth in this column reflect awards of phantom units, and are based on the aggregate grant date fair value of the awards computed in accordance with FASB ASC Topic 718 (disregarding the impact of estimated forfeitures related to service-based vesting conditions). For phantom units, the grant date fair value is computed based upon the closing price of CNX Coal Resources’ common units on the date of grant. The phantom units were granted on August 5, 2015 and vest in one lump sum on the first anniversary of the grant date. As of December 31, 2015, the number of phantom units held by our current non-employee directors was 2,152 for each of Messrs. Altmeyer, Greenwood and Wallace.

Our Long-Term Incentive Plan

Our general partner adopted the CNX Coal Resources LP 2015 Long-Term Incentive Plan (our “LTIP”) under which our general partner may issue long-term equity based awards in our Partnership 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 are 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 general partner or a committee thereof will be designated as the plan administrator. The following description reflects the terms that are included in the LTIP.

General

The LTIP provides 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 in our Partnership. 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 limits the number of units that may be delivered pursuant to vested awards to 2,300,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, 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

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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 to our unit holders 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.

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

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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.

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.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the beneficial ownership of common units and subordinated units of CNX Coal Resources LP that were outstanding at December 31, 2015 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 nominees and named executive officers of our general partner as a group.

In addition, our general partner holds 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 percentage of units beneficially owned is based on a total of 11,611,067 common units and 11,611,067 subordinated units outstanding at December 31, 2015.

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Name of Beneficial Owner (1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Common Units and Subordinated Units Beneficially Owned
CONSOL Energy Inc. (2)	1,050,000	9.0	%	11,611,067	100.0	%	54.5	%
Greenlight Capital, Inc.	5,488,438	47.3	%	—	—		23.6	%
Directors/Director Nominees/Named Executive Officers
Michael L. Greenwood	12,500	*		—	—		*
David M. Khani	10,000	*		—	—		*
Nicholas J. DeIuliis	7,500	*		—	—		*
James A. Brock	6,660	*		—	—		*
James E. Altmeyer, Sr.	4,000	*		—	—		*
Stephen W. Johnson	3,800	*		—	—		*
Jeffrey L. Wallace	2,500	*		—	—		*
Lorraine L. Ritter	650	*		—	—		*
Martha A. Wiegand	500	*		—	—		*
All Directors, Director Nominees and Executive Officers as a group (9 persons)	48,110	*		—	—		*



*		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 issued 1,050,000 common units and 11,611,067 subordinated units to CONSOL Energy in connection with the completion of the IPO.

The following table sets forth, as of December 31, 2015, the number of shares of CONSOL Energy common stock beneficially owned by each of the directors and named executive officers of our general partner and all of the directors and named executive officers of our general partner as a group. The percentage of total shares is based on 229,054,236 shares outstanding as of December 31, 2015. Amounts shown below include options that are currently exercisable or that may become exercisable within 60 days of December 31, 2015 and the shares underlying deferred stock units and the shares underlying restricted stock units that will be settled within 60 days of December 31, 2015. 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 Nominees/Named Executive Officers
James A. Brock	87,902	*
Lorraine L. Ritter	48,343	*
Martha A. Wiegand	8,177	*
Nicholas J. DeIuliis	786,971	*
Stephen W. Johnson	226,665	*
David M. Khani	36,720	*
James E. Altmeyer, Sr.	42,192	*
Michael L. Greenwood	-	-
Jeffrey L. Wallace	-	-
All Directors, Director Nominees and Executive Officers as a group (9 persons)	1,236,970	*

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*	Less than 1%.

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information regarding the number of common units that are available for issuance under our existing long-term incentive plan as of December 31, 2015.



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensations plans (excluding securities reflected in column)
Equity compensation plans approved by security holders	6,456	(1)	—	2,293,544
Equity compensation plans not approved by security holders	—		—	—
Total	6,456		—	2,293,544

(1) Of this total, 6,456 are phantom units.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our sponsor, CONSOL Energy owns 1,050,000 common units and 11,611,067 subordinated units, representing a 53.4% limited partner interest. In addition, our general partner owns 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 made or 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 that have been made were determined by and among affiliated entities and, consequently, were 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 in connection with our initial public offering completed in July of 2015 for the contribution to us of all of the limited liability company interests in CNX Operating, the sole member of CNX Thermal Holdings, which owns a 20% undivided interest in the Pennsylvania mining complex.


•	1,050,000 common units;


•	11,611,067 subordinated units;


•	a 2% general partner interest in us;


•	the incentive distribution rights; and


•	a distribution of approximately $70 million from the net proceeds from the initial public offering.

Operational Stage

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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 1,050,000 common units and 11,611,067 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 an annual distribution of approximately $1.0 million on the 2% general partner interest, and our sponsor would receive an annual distribution of approximately $27.1 million on its common units and subordinated 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 With Affiliates,” 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, (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; and (iii) an allocated proportionate share of costs and payments for retiree medical and life insurance, workers’ compensation, disability and coal workers’ pneumoconiosis benefits for employees (including former employees whose employment terminated prior to the completion of our initial public offering in July of 2015) of CPCC. Please read “- Agreements With Affiliates” below.


•	The total amount of such reimbursed expenses was approximately $25.5 million for the period of July 7, 2015 through December 31, 2015.

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 case for an amount equal to the fair market value of those interests.

Liquidation Stage


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

Agreements with Affiliates

We have entered into various agreements with CONSOL Energy and certain of its affiliates, other than us, as described in detail below. These agreements were negotiated in connection with, among other things, our formation, our initial public offering in July of 2015 and our acquisitions from CONSOL Energy. While not the result of arm’s-length negotiations, we believe the terms of all of the agreements with our sponsor and its affiliates are generally no less favorable to either party than

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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, were paid for with the proceeds from our initial public offering completed in July of 2015.

Operating Agreement

CNX Thermal Holdings entered into an operating agreement for the Pennsylvania mining complex with CPCC and Conrhein. Under the operating agreement, CNX Thermal Holdings was named as operator and assumed management and control over the day-to-day operations of the Pennsylvania mining complex for the life of the mines. As operator, CNX Thermal Holdings is responsible for managing and conducting all operations with respect to the Pennsylvania mining complex, including the following operational services:


•	mining the Pennsylvania mining complex;


•	handling coal production and delivery thereof to purchasers and/or facilities;


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


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


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


•	planning and coordinating of anticipated mining operations.

Pursuant to the operating agreement, CNX Thermal Holdings, on one hand, and CPCC and Conrhein, on the other, each appoint one representative to a two-member operating committee, which meets quarterly to review the annual budget for the Pennsylvania mining complex. While CNX Thermal Holdings has been delegated the authority and responsibility for managing and further developing 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. CNX Thermal Holdings may be removed as operator only in the event of its bankruptcy or gross negligence or willful misconduct in connection with the operational services.

Any liabilities arising from the operation of the Pennsylvania mining complex that are not the result of CNX Thermal Holdings’ gross negligence or willful misconduct will be borne by CNX Thermal Holdings, CPCC and Conrhein pro rata in relation to such person’s ownership percentage of the Pennsylvania mining complex. Under the operating agreement, CNX Thermal Holdings invoices CPCC and Conrhein on a monthly basis for its pro rata share of the costs associated with the operation of the Pennsylvania mining complex. The total amount of such amounts invoiced was approximately $189.2 million for the period of July 7, 2015 through December 31, 2015.

Employee Services Agreement

Through our subsidiary CNX Thermal Holdings, we entered into an employee services agreement with CPCC, a subsidiary of CONSOL Energy. Under the employee services agreement, CPCC, subject to our management, direction and control, provides personnel to mine and process coal from the Pennsylvania mining complex and perform the operational services that we are charged with providing under the operating agreement described above. The employees of CPCC are not our employees, and CPCC has the sole and exclusive responsibility to pay and provide benefits for such employees.

Pursuant to the employee services agreement, we reimburse CPCC monthly for (i) all direct third-party costs and expenses actually incurred by CPCC 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 CPCC’s performance of the operational services, except to the extent such penalties were as a result of CPCC’s gross negligence or willful misconduct, (ii) salary, benefits and other compensation costs of CPCC’s employees performing the operational services to the extent such employees are performing the operational services; and (iii) market rate rental fees for use of CPCC’s assets in performing the operational services, if any. We paid approximately $20.4 million to CPCC for such reimbursed expenses for the period of July 7, 2015 through December 31, 2015.

Contract Agency Agreement

Through our subsidiary CNX Thermal Holdings, we entered into a contract agency agreement with CONSOL Energy Sales Company (“CES”), a subsidiary of CONSOL Energy. Under the contract agency agreement, CES, at our direction and subject to our control, acts as agent to market and sell the coal produced from the Pennsylvania mining complex and

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administers 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.

The administration of these coal purchase and sale contracts includes CES’ 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 CES’ interest in the Pennsylvania mining complex. CES will cause all revenues under these coal purchase and sale contracts to be deposited directly into our account.

Terminal and Throughput Agreement

Through our subsidiary CNX Thermal Holdings, we entered into a terminal throughput agreement with CNX Marine Terminals, Inc. (“CNX Marine”), a subsidiary of CONSOL Energy. Under the terminal and throughput agreement, we have the option, but not the obligation, to transport or to cause to be transported through CONSOL’s Baltimore Marine Terminal up to 5 million tons of coal each calendar year (prorated for 2015) for a terminal fee of $4 per ton of coal transported through the Baltimore Marine Terminal, plus certain standard fees for long-term or excess storage of coal at the Baltimore Marine Terminal, re-handling services at the Baltimore Marine Terminal (if we elect such services) and certain fees related to the docking and undocking of vessels at the Baltimore Marine Terminal. The per ton terminal fee and other fees may be reasonably escalated by the owner of the Baltimore Marine Terminal on a quarterly basis based on changes in the volume of coal shipped through the Baltimore Marine Terminal and increases in operating costs at the terminal.

Cooperation and Safety Agreement

We, on behalf of ourselves and CPCC and Conrhein, entered 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 contains 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 and subsidence issues.

Water Supply and Services Agreement

We entered 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 treatment fee. The supply fee is subject to a renegotiation based on market conditions at the end of the initial term, and the disposal fee is subject to annual renegotiation based on market conditions and operating costs of the water treatment facility. The water supply and 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 30 days’ prior notice.

Omnibus Agreement

We and our general partner entered into an omnibus agreement with CONSOL Energy, CPCC, Conrhein and certain other subsidiaries of CONSOL Energy that 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, in the amount of $0.7 million, for the provision of certain executive support services by CONSOL Energy and its affiliates;


•	our obligation to reimburse CONSOL Energy for the provision of certain management, operating and investor relation 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);


•	our right of first offer to acquire CONSOL Energy’s retained 80% undivided interest in the Pennsylvania mining complex, as well as three other assets; and

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•	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 pay CONSOL Energy an administrative support fee, initially in the amount of $9.4 million per year, for the provision of certain administrative support services for our benefit, including: financial and administrative services (including treasury, accounting and internal audit); information technology; legal serves; human resources; tax matters; payroll services; procurement services; government relations, governmental compliance and public affairs; analytical and engineering services; business development services; risk management services; health, environmental, safety and security services; real property and land management; permitting and bonding services; market services; logistics management; and operational reporting. We also pay CONSOL Energy an executive support fee, initially in the amount of $0.7 million, for the provision of certain executive support services for our benefit. The administrative support fee may change each calendar year, as determined by CONSOL Energy in good faith after consultation with our general partner, 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. In addition, we will reimburse CONSOL Energy and its affiliates for all reasonable direct and indirect costs and expenses incurred by CONSOL Energy or its affiliates in connection with the provision of certain management, operating and investor relation services (“management services”) to our general partner, us and our subsidiaries, including the compensation and employee benefits of employees of CONSOL Energy or its affiliates (and any employment, payroll or similar taxes related thereto), to the extent, but only to the extent, such employees perform management services for the benefit of our general partner, us or our subsidiaries. This includes CONSOL Energy stock-based compensation expense and net of any re-allocated partnership equity compensation expense, as determined by CONSOL Energy pursuant to its reasonable allocation procedures and methodologies.

Under the omnibus agreement, we 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 obligation to reimburse 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. All notices from CONSOL Energy regarding our right of first offer, and our responses to such notices, as well as any negotiations by us with CONSOL Energy are confidential and will not be publicly disclosed. 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 asset 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. In addition, until the earlier of the fifth anniversary of our initial public offering, which was completed in July 2015, or the date that CONSOL Energy no longer controls our general partner, we have a similar right of first offer with respect to three other assets - the Baltimore Marine Terminal (provides coal transshipments from railcar primarily to ocean going vessels), the Buchanan Mine (Virginia mining complex which produces a premium low volatile metallurgical coal) and the Cardinal States Gathering System (a 110 miles of pipeline natural gas gathering system and associated assets located in Virginia, Kentucky and West Virginia). There is also an exception for Buchanan Mine from the right of first offer in the event CONSOL energy conducts an initial public offering of the Buchanan Mine.

Since we hold only a right of first offer, no assurance can be given that we ultimately will purchase from CONSOL Energy additional undivided interests in the Pennsylvania mining complex or any of the three other assets subject to the right of first offer. A variety of reasons or circumstances may exist from time to time which result in the holder of a right of first offer, never purchasing the asset covered by the right of first offer. 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.”

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


•	the consummation of the transactions contemplated by the contribution agreement;


•	all tax liabilities attributable to the assets contributed to us arising prior to the closing of our initial public offering in July 2015 or otherwise related to CONSOL Energy’s contribution of those assets to us in connection with this offering;


•	certain operational and 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;


•	certain liabilities retained by CONSOL Energy;


•	CONSOL Energy’s gross negligence or willful misconduct in connection with the provision of general and administrative services or management services under the omnibus agreement; and


•	a breach by CONSOL Energy of the employee services agreement, the contract agency agreement, the water supply and services agreement, the terminal and throughput agreement and/or the cooperation and safety agreement.

Subject to and without limiting our rights to indemnification by CONSOL Energy, we will indemnify CONSOL Energy for certain liabilities, including those relating to:


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


•	any liabilities incurred by CONSOL Energy (i) under the employee services agreement or the contract agency agreement, (ii) in connection with CONSOL Energy’s performance of services under the water supply and services agreement or the terminal and throughput agreement or (iii) by our breach of the cooperation and safety agreement; and


•	our operation of the Pennsylvania mining complex under permits and/or bonds, letters of credit, guarantees, deposits and other pre-payments held by CONSOL Energy.

Under the omnibus agreement, certain indemnification by CONSOL Energy will be limited to liabilities identified prior to the third anniversary of the closing of our initial public offering completed in July of 2015. Certain of our and CONSOL Energy’s indemnification obligations will be subject to a deductible of $1.0 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.

Contribution Agreement

We entered into a contribution, conveyance and assumption agreement, which we refer to as our contribution agreement, with CONSOL Energy, CNX Operating and our general partner under which CONSOL Energy will contribute to us all of the limited liability company interests in CNX Operating, which is the sole member of CNX Thermal Holdings. CNX Thermal Holdings owns a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex.

Concurrent Private Placement

Common Unit Purchase Agreement. On June 25, 2015, we entered into a common unit purchase agreement with Greenlight Capital pursuant to which Greenlight Capital agreed to purchase, and we agreed to sell, at least 2,000,000 common units and up to 5,000,000 common units at a price per unit equal to $15.00. We agreed to sell a number of common units to Greenlight Capital in the Concurrent Private Placement, subject to the limitations in the preceding sentence, such that the aggregate number of common units sold in our initial public offering and the Concurrent Private Placement would equal 10,000,000 common units. If we sold more than 5,000,000 common units in the initial offering (other than as a result of the exercise of the underwriters’ option to purchase additional common units), we agreed to sell a correspondingly fewer amount of common units to Greenlight Capital in the Concurrent Private Placement. Because we ultimately sold 5,000,000 common units to the public in our initial public offering, Greenlight Capital purchased 5,000,000 common units. In connection with our issuance and sale of common units pursuant to the Concurrent Private Placement, we relied upon the “private placement” exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) thereof and, accordingly, the common units issued to Greenlight Capital were not registered under the Securities Act.

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Registration Rights Agreement. We entered into a registration rights agreement with Greenlight Capital relating to the common units issued to Greenlight Capital in the Concurrent Private Placement (the “registrable securities”). Pursuant to the registration rights agreement, we agreed to file up to three shelf registration statements for the resale of the registrable securities as soon as practicable following receipt of written notice from Greenlight Capital and no later than 30 days after such notice; provided, that we will not be required to file a shelf registration statement for 90 days after the closing of our initial public offering. As of December 31, 2015, we had not received such written notice from Greenlight Capital. In addition, we agreed to use commercially reasonable efforts to cause each shelf registration statement to be declared effective by the SEC as soon as practicable after its filing and no later than 90 days after its filing. The registration rights agreement also provided Greenlight Capital with rights that allow Greenlight Capital to include its registrable securities in certain registered offerings for our own account. The registration rights agreement contained representations, warranties, covenants and indemnities that are customary for private placements by public companies.

Other Related Party Transactions

Please see Note 20 to our audited consolidated financial statements contained in Item 8 of Part II of this Annual Report on Form 10-K for a description of certain other transactions with related parties, which descriptions are incorporated by reference herein.

Director Independence

Our disclosures in Item 10. “Directors, Executive Officers and Corporate Governance” are incorporated herein by reference.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner has adopted a written code of business conduct and ethics that provides 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 provides 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.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Ernst & Young LLP served as the Partnership’s independent auditor for the year ended December 31, 2015. The following table presents fees billed for professional audit services rendered by E&Y in connection with its audits of CNXC's annual financial statements for the year ended December 31, 2015.

The fees billed to the Partnership by Ernst & Young LLP during 2015 were the following:

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	2015 (E&Y Fees)
Audit Fees	$	452,000
Audit-Related Fees	10,255
Tax Fees	—
All Other Fees	—
Total	$	462,255

As used in the table above, the following terms have the meanings set forth below.

Audit Fees

The fees for professional services rendered in connection with the audit of Partnership's annual financial statements, for the review of the financial statements included in Partnership's Quarterly Reports on Form 10-Q and for services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements.

Audit-Related Fees

The fees for assurance and related services that are reasonably related to the performance of the audit or review of Partnership's financial statements.

Tax Fees

The fees for professional services rendered for tax compliance, tax advice and tax planning.

All Other Fees

The fees for products and services provided, other than for the services reported under the headings “Audit Fees,” “Audit-Related Fees” and “Tax Fees.”

The audit committee of the Partnership’s general partner has adopted a policy regarding the services of its independent auditors under which the Partnership’s independent accounting firm is not allowed to perform any service which may have the effect of jeopardizing the registered public accountant’s independence. Without limiting the foregoing, the independent accounting firm shall not be retained to perform the following:

• Bookkeeping or other services related to the accounting records or financial statements

• Financial information systems design and implementation

• Appraisal or valuation services, fairness opinions or contribution-in-kind reports

• Actuarial services

• Internal audit outsourcing services

• Management functions

• Human resources functions

• Broker-dealer, investment adviser or investment banking services

• Legal services

• Expert services unrelated to the audit

• Prohibited tax services

All audit and permitted non-audit services must be pre-approved by the audit committee. In 2015, 100% of the professional fees reported as audit-related fees were pre-approved pursuant to the above policy.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



Exhibits	Description	Method of Filing

3.1	First Amended and Restated Agreement of Limited Partnership of CNX Coal Resources LP, dated as of July 7, 2015	Filed as Exhibit 3.1 to Form 8-K (#001-37456) filed on July 6, 2015

4.1	Registration Rights Agreement, dated as of July 7, 2015, by and among, CNX Coal Resources LP and the purchaser parties thereto	Filed as Exhibit 4.1 to Form 8-K (#001-37456) filed on July 6, 2015

4.2	Waiver of 20% Voting Limitation Agreement, dated as of July 7, 2015, by and among CNX Coal Resources GP LLC and the purchaser parties thereto	Filed as Exhibit 4.2 to Form 8-K (#001-37456) filed on July 6, 2015

10.1	Contribution, Conveyance and Assumption Agreement, dated as of July 7, 2015, by and among CNX Coal Resources LP, CNX Coal Resources GP LLC, CONSOL Energy Inc. and CNX Operating LLC	Filed as Exhibit 10.1 to Form 8-K (#001-37456) filed on July 6, 2015

10.2	Omnibus Agreement, dated as of July 7, 2015, by and among CNX Coal Resources LP, CNX Coal Resources GP LLC, CONSOL Energy Inc. and the other parties listed on Exhibit A thereto	Filed as Exhibit 10.2 to Form 8-K (#001-37456) filed on July 6, 2015

10.3	Pennsylvania Mine Complex Operating Agreement, dated as of July 7, 2015, by and among CONSOL Pennsylvania Coal Company LLC, Conrhein Coal Company and CNX Thermal Holdings LLC	Filed as Exhibit 10.3 to Form 8-K (#001-37456) filed on July 6, 2015

10.4	Employee Services Agreement, dated as of July 7, 2015, by and between CONSOL Pennsylvania Coal Company LLC and CNX Thermal Holdings LLC	Filed as Exhibit 10.4 to Form 8-K (#001-37456) filed on July 6, 2015

10.5	Contract Agency Agreement, dated as of July 7, 2015, by and between CONSOL Energy Sales Company and CNX Thermal Holdings LLC	Filed as Exhibit 10.5 to Form 8-K (#001-37456) filed on July 6, 2015

10.6	Terminal and Throughput Agreement, dated as of July 7, 2015, by and between CNX Marine Terminals, Inc. and CNX Thermal Holdings LLC	Filed as Exhibit 10.6 to Form 8-K (#001-37456) filed on July 6, 2015

10.7	Amendment and Restatement of Master Cooperation and Safety Agreement, dated as of July 7, 2015, by and among CNX Thermal Holdings LLC, CONSOL Pennsylvania Coal Company LLC, Conrhein Coal Company, CNX Gas Company LLC, CONSOL Energy Inc. and the CONSOL Energy Inc. subsidiaries party thereto	Filed as Exhibit 10.7 to Form 8-K (#001-37456) filed on July 6, 2015

10.8	Water Supply and Services Agreement, dated as of July 7, 2015, by and between CNX Water Assets LLC and CNX Thermal Holdings LLC	Filed as Exhibit 10.8 to Form 8-K (#001-37456) filed on July 6, 2015

10.9*	CNX Coal Resources LP 2015 Long-Term Incentive Plan	Filed as Exhibit 10.9 to Form 8-K (#001-37456) filed on July 6, 2015

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10.10*	Form of Restricted Phantom Award Agreement under CNX Coal Resources' LP 2015 Long-Term Incentive Plan	Filed as Exhibit 4.2 to Registration Statement on Form S-8 (#333-205639) filed on July 13, 2015

10.11	Credit Agreement, dated July 7, 2015, by and among CNX Coal Resources LP, as Borrower, certain subsidiaries of the Borrower as Guarantors, PNC Bank, N.A., as Administrative Agent,, and other lender parties thereto	Filed as Exhibit 10.10 to Form 8-K (#001-37456) filed on July 6, 2015

10.12	Amended and Restated Change in Control Agreement dated August 24, 2015 between CONSOL Energy Inc. and James A. Brock	Filed as Exhibit 10.10 to Form 10Q (#001-37456) filed on November 3, 2015

21.1	Subsidiaries of CNX Coal Resources LP	Filed herewith

23.1	Consent of Ernst & Young LLP	Filed herewith

31.1	Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley Act of 2002	Filed herewith

31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	Filed herewith

32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	Filed herewith

95	Mine Safety and Health Administration Safety Data.	Filed herewith

101	Interactive Data File (Form 10-K for the annual period ended December 31, 2015, furnished in XBRL).	Filed herewith

*	Compensatory plan or arrangement

Pursuant to the rules and regulations of the SEC, CNX Coal Resources LP has filed certain agreements as exhibits to this Annual Report on Form 10-K. These agreements may contain representations and warranties by the parties. These representations and warranties have been made solely for the benefit of the other party or parties to such agreements and (i) may have been qualified by disclosures made to such other party or parties, (ii) were made only as of the date of such agreements or such other date(s) as may be specified in such agreements and are subject to more recent developments, which may not be fully reflected in CNX Coal Resources LP’s public disclosure, (iii) may reflect the allocation of risk among the parties to such agreements and (iv) may apply materiality standards that are different from what may be viewed as material to investors. Accordingly, these representations and warranties may not describe CNX Coal Resources LP’s actual state of affairs at the date hereof and should not be relied upon.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Dated: February 5, 2016



	CNX Coal Resources LP
	By:		CNX Coal Resources GP LLC, its general partner
	By:		/s/ JAMES A. BROCK
			James A. Brock
			Chief Executive Officer and Director (Duly Authorized Officer and Principal Executive Officer)

	By:		CNX Coal Resources GP LLC, its general partner
	By:		/s/ LORRAINE L. RITTER
			Lorraine L. Ritter
			Chief Financial Officer and Chief Accounting Officer (Duly Authorized Officer and Principal Financial Officer and Principal Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on February 5, 2016.



	By:		/s/ JAMES A. BROCK
			James A. Brock
			Chief Executive Officer and Director (Duly Authorized Officer and Principal Executive Officer)

	By:		/s/ LORRAINE L. RITTER
			Lorraine L. Ritter
			Chief Financial Officer and Chief Accounting Officer (Duly Authorized Officer and Principal Financial Officer and Principal Accounting Officer)

	By:		/s/ NICHOLAS J. DEIULIIS
			Nicholas J. DeIuliis
			Chairman of the Board

	By:		/s/ STEPHEN W. JOHNSON
			Stephen W. Johnson
			Director

	By:		/s/ DAVID M. KHANI
			David M. Khani
			Director

	By:		/s/ MICHAEL L. GREENWOOD
			Michael L. Greenwood
			Director

	By:		/s/ JEFFREY L. WALLACE
			Jeffrey L. Wallace
			Director

	By:		/s/ JAMES E. ALTMEYER, SR.
			James E. Altmeyer, Sr.
			Director

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Committed Sales Tons