Edgar Filing: CONSOL Coal Resources LP

Document

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, 2017



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

__________________________________________________

CONSOL 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, Suite 100

Canonsburg, PA 15317-6506

(724) 485-3300

(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. o

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

Large accelerated filer o Accelerated filer x Non-accelerated filer o Smaller Reporting Company o Emerging Growth Company x

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act x

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 $146,858,493 as of June 30, 2017, 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.

CONSOL Coal Resources LP had 15,906,728 common units, 11,611,067 subordinated units, and a 1.7% general partner interest outstanding at February 8, 2018.

DOCUMENTS INCORPORATED BY REFERENCE:

None

TABLE OF CONTENTS



		Page
	PART I

Item 1.	Business	6
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	44
Item 2.	Properties	44
Item 3.	Legal Proceedings	46
Item 4.	Mine Safety Disclosures	46

	PART II

Item 5.	Market for Registrant’s Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities	47
Item 6.	Selected Financial Data	49
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	66
Item 8.	Financial Statements and Supplementary Data	68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	98
Item 9A.	Controls and Procedures	98
Item 9B.	Other Information	99

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance of Managing General Partner	99
Item 11.	Executive Compensation	103
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	116
Item 13.	Certain Relationships and Related Transactions and Director Independence	118
Item 14.	Principal Accounting Fees and Services	126

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	128
	Signatures	131

PART I

Significant Relationships and Other Important Definitions Referenced in this Annual Report

•

“Affiliated Company Credit Agreement” refers to an agreement entered into on November 28, 2017 among the Partnership and certain of its subsidiaries (collectively, the “Credit Parties”), CONSOL Energy, as lender and administrative agent, and PNC Bank, National Association, as collateral agent (“PNC”). The Affiliated Company Credit Agreement provides for a revolving credit facility in an aggregate principal amount of up to $275 million to be provided by CONSOL Energy, as lender.

•

“Class A Preferred Units” refers to the convertible preferred units representing limited partner interests in CONSOL Coal Resources LP. The Partnership issued 3,956,496 Class A Preferred Units to CNX on September 30, 2016. On October 2, 2017 the 3,956,496 Class A Preferred Units were converted to common units on a one-for-one basis, in accordance with our Partnership Agreement. The key terms of the Class A Preferred Units were described in our Annual Report on Form 10-K for the year ended December 31, 2016 (our “2016 Form 10-K”);


•	“CONSOL Coal Finance” refers to CONSOL Coal Finance Corporation, a Delaware corporation and a direct, wholly owned subsidiary of the Partnership;

•

“CONSOL Coal Resources LP,” the “Partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to CONSOL Coal Resources LP, a Delaware limited partnership, and its subsidiaries, with common units listed for trading on the New York Stock Exchange under the ticker “CCR.” Prior to November 28, 2017, we were called CNX Coal Resources LP and our common units traded on the New York Stock Exchange under the ticker “CNXC”;


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


•	“CONSOL Thermal Holdings” refers to CONSOL Thermal Holdings LLC, a Delaware limited liability company and a direct, wholly owned subsidiary of CONSOL Operating; following the PA Mining Acquisition, CONSOL Thermal Holdings owns a 25% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania Mining Complex;


•	“common units” refer to the limited partner interests in CONSOL Coal Resources LP. The holders of common units are entitled to participate in partnership distributions and are entitled to exercise the rights or privileges of limited partners under the Partnership Agreement. The common units are listed on the New York Stock Exchange under the symbol “CCR”;


•	“Concurrent Private Placement” refers to the issuance (concurrent with the IPO) of 5,000,000 common units to Greenlight Capital pursuant to a common unit purchase agreement;


•	“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;


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


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


•	“IPO” refers to the completion of the Partnership’s initial public offering on July 7, 2015;


•	“Omnibus Agreement” refers to the Omnibus Agreement dated July 7, 2015, as replaced by the First Amended and Restated Omnibus Agreement dated as of September 30, 2016, and as amended by the First Amendment to the First Amended and Restated Omnibus Agreement, dated November 28, 2017;

•

“PA Mining Acquisition” refers to a transaction which closed on September 30, 2016, wherein the Partnership and its wholly owned subsidiary, CONSOL Thermal Holdings, entered into a Contribution Agreement with CNX, CPCC and Conrhein, under which CONSOL Thermal Holdings acquired an undivided 6.25% of the contributing parties’ right, title and interest in and to the Pennsylvania Mining Complex (which represents an aggregate 5% undivided interest in and to the Pennsylvania Mining Complex);


•	“CNX” refers to CNX Resources Corporation and its consolidated subsidiaries on or after November 28, 2017 and to CONSOL Energy Inc. and its consolidated subsidiaries prior to November 28, 2017;


•	“Partnership Agreement” refers to the First Amended and Restated Agreement of Limited Partnership of the Partnership, as replaced by the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated as of September 30, 2016, as replaced by the Third Amended and Restated Partnership Agreement dated as of November 28, 2017;

•

“Pennsylvania Mining Complex” refers to the coal mines, coal reserves and related assets and operations, located primarily in southwestern Pennsylvania. The Pennsylvania Mining complex was owned 80% by CNX and 20% by CONSOL Thermal Holdings from July 2015 until the closing of the PA Mining Acquisition in September 2016. Following the PA Mining Acquisition until November 28, 2017, the Pennsylvania Mining Complex was owned 75% by CNX and its subsidiaries and 25% by CONSOL Thermal Holdings. In connection with the separation on November 28, 2017, CNX’s undivided interest in the Pennsylvania Mining Complex was transferred to CONSOL Energy;

•

“PNC Revolving Credit Facility” refers to a credit agreement that the Partnership entered into on July 7, 2015, as borrower, and certain subsidiaries of the Partnership, as guarantors, for a $400 million revolving credit facility with PNC, as administrative agent, and other lender parties. On November 28, 2017, in connection with the separation, the Partnership paid all fees and other amounts outstanding under the PNC Revolving Credit Facility and terminated the PNC Revolving Credit Facility and the related loan documents;


•	“Predecessor” refers to CNX’s ownership of CPCC and the Conrhein assets and liabilities prior to the IPO on July 7, 2015;


•	“preferred units” refer to any limited partnership interests, other than the common units and subordinated units, issued in accordance with the Partnership Agreement that, as determined by our general partner, have special voting rights to which our common units are not entitled. As of the date of this Annual Report on Form 10-K, there are no outstanding preferred units;


•	“SEC” refers to the United States Securities and Exchange Commission;


•	“separation” refers to the separation of the coal business from CNX’s other businesses and the creation, as a result of the distribution, of an independent, publicly traded company (CONSOL Energy) to hold the assets and liabilities associated with the coal business (including CNX’s interest in the general partner and in us) after the distribution;


•	“sponsor” or “our sponsor” refers to CNX prior to the completion of the separation on November 28, 2017 and to

CONSOL Energy following the completion of the separation; and

•

“subordinated units” refer to limited partner interests in CONSOL Coal Resources LP having the rights and obligations specified with respect to subordinated units in the Partnership Agreement. In connection with the completion of the IPO, we issued 11,611,067 subordinated units to CNX. In connection with the separation and the Affiliated Company Credit Agreement, all of the subordinated units were transferred directly to CONSOL Energy.

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,” “continue,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “will,” 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, acquire additional 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;


•	operating in a single geographic area;


•	interest rates;


•	our reliance on a few major customers;


•	labor availability, relations and other workforce factors;


•	defaults by CONSOL Energy under our operating agreement, employee services agreement and Affiliated Company Credit Agreement;


•	restrictions in our Affiliated Company Credit Agreement that may adversely affect our business;


•	changes in our tax status;


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


•	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;


•	conflicts of interest that may cause our general partner or CONSOL Energy to favor their own interest to our detriment;


•	the requirement that we distribute all of our available cash; and


•	other factors discussed in this Annual Report Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file at the SEC.

ITEM 1. BUSINESS

General

We are a master limited partnership formed on March 16, 2015 by our then-sponsor, CNX Resources Corporation (formerly known as CONSOL Energy Inc.), to manage and further develop all of its active coal operations in Pennsylvania. As part of the separation, all of CNX’s ownership interest in our general partner and in us was transferred to CONSOL Energy as our new sponsor. All amounts except per unit or per ton are displayed in thousands.

At December 31, 2017, our assets are comprised of a 25% undivided interest in, and operational control over, the 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. 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, 2017, the Partnership’s portion of the Pennsylvania Mining Complex included 183,867 tons of proven and probable coal reserves with an average gross heat content of approximately 12,915 British thermal units (“Btu”) per pound and approximately 3.6 pounds of sulfur dioxide per million British thermal units (“lb SO2/mmBtu”). Based on our current production capacity, these reserves are sufficient to support approximately 26 years of production. In addition, our reserves currently exhibit thermoplastic behavior suitable for cokemaking and contain an average of approximately 39%-40% volatile matter (on a dry basis), which enables us, if market dynamics are favorable, to capture greater margins from selling our coal as a crossover product in the high-vol 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 15-17 continuous mining sections at the Pennsylvania Mining Complex. The current production capacity of the Partnership’s portion of the Pennsylvania Mining Complex’s five longwalls is 7,125 tons of coal per year. The preparation plant is connected via conveyor belts to each of our mines and cleans and processes up to 8,200 tons of coal per hour. Our on-site 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 from empty inbound trains to fully loaded outbound trains at our facility.

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 Partnership completed the issuance of common units in connection with the IPO, a private placement of common units with Greenlight Capital, and entered into a $400,000 senior secured revolving credit facility. In connection with the IPO, CNX contributed to the Partnership a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania Mining Complex.

On September 30, 2016, we acquired an additional 5% undivided interest in the Pennsylvania Mining Complex from CNX and its affiliates for $21,500 in cash and the issuance of 3,956,496 Class A Preferred Units with a value of $67,300. All information (except distributable cash flow, which reflects the ownership percentage at the time) included within this filing has been recast to reflect the Partnership’s current 25% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania Mining Complex. On October 2, 2017, all of the Class A Preferred Units were converted into common units on a one-for-one basis.

Appalachian, Central Appalachian and Illinois basins and certain related coal assets and liabilities. As part of the separation, CONSOL Mining Corporation changed its name to CONSOL Energy Inc. and its ticker to “CEIX”, CNX changed its name to CNX Resources Corporation and its ticker to “CNX”, the Partnership changed its name to CONSOL Coal Resources LP and its ticker to “CCR” and the general partner changed its name to CONSOL Coal Resources GP LLC.

Our principal executive offices are located at 1000 CONSOL Energy Drive, Suite 100, Canonsburg, Pennsylvania 15317-6506, and our telephone number is (724) 485-3300. Our website is located at www.ccrlp.com. Information on our website is not incorporated by reference into this Annual Report on Form 10-K and does not constitute a part of this Annual Report on Form 10-K.

Organization Structure

The following simplified diagram depicts our organizational structure and our relationship with CONSOL Energy as of December 31, 2017:

Our Relationship with CONSOL Energy

One of our principal strengths is our relationship with CONSOL Energy. CONSOL Energy is a leading, low-cost producer of high-quality bituminous coal, headquartered in Canonsburg, Pennsylvania. CONSOL Energy and its predecessors have been mining coal, primarily in the Appalachian Basin, since 1864. CONSOL Energy deploys an organic growth strategy focused on efficiently developing its resource base. CONSOL Energy’s premium coal grades are sold to electricity generators, steel makers, coke producers and industrial consumers, both domestically and internationally. CONSOL Energy is listed on the NYSE under the symbol “CEIX” and had a market capitalization of approximately $1.1 billion as of December 31, 2017.

Our Assets

CONSOL Thermal Holdings owns a 25% undivided interest in the Pennsylvania Mining Complex. CONSOL Thermal Holdings entered into an operating agreement with CPCC and Conrhein under which CONSOL 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 CONSOL 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 26 years of production.

Following the separation, CONSOL Energy owns a 75% undivided interest in the Pennsylvania Mining Complex, as well as 100% of our general partner, all of our incentive distribution rights and, indirectly through our general partner, our 1.7% general partner interest. In addition, CONSOL Energy owns 60.6% of the limited partner interest in us.

Our Operations

Bailey Mine

The Bailey Mine is located in Enon, Pennsylvania. As of December 31, 2017, the Partnership’s portion of the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 61,296 tons of clean recoverable proven and probable coal. While operating two longwalls, the typical production capacity of our portion of the Bailey Mine is 2,875 tons (11,500 on a 100% basis) of coal per year. For the years ended December 31, 2017, 2016 and 2015, our portion of the Bailey Mine produced 3,031 tons, 3,014 tons and 2,547 tons of coal, respectively.

Enlow Fork Mine

The Enlow Fork Mine is located directly north of the Bailey Mine. As of December 31, 2017, the Partnership’s portion of the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 73,867 tons of clean recoverable proven and probable coal. While operating two longwalls, the typical production capacity of our portion of the Enlow Fork Mine is 2,875 tons (11,500 on a 100% basis) of coal per year. For the years ended December 31, 2017, 2016 and 2015, our portion of the Enlow Fork Mine produced 2,295 tons, 2,409 tons and 2,250 tons of coal, respectively.

Harvey Mine

The Harvey Mine is located directly east of the Bailey and Enlow Fork Mines. As of December 31, 2017, the Partnership’s portion of the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 48,704 tons of clean recoverable proven and probable coal. While operating one longwall, the typical production capacity of our portion of the Harvey Mine is 1,375 tons (5,500 on a 100% basis) of coal per year. For the years ended December 31, 2017, 2016 and 2015, our portion of the Harvey Mine produced 1,201 tons, 743 tons and 901 tons of coal, respectively. Longwall production commenced in March 2014.

Capital Expenditures

In 2018, the Partnership expects to invest $31,000-$36,000 in maintenance capital expenditures. The Partnership is not expecting to invest in expansion projects in 2018, however, the Partnership continually evaluates potential acquisitions.

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”. We are greater than 95% contracted for 2018, 70% contracted for 2019 and 24% contracted for 2020, assuming an annual production rate of approximately 6,750 tons. With our planned coal production in 2018 largely sold out, our focus now has shifted to maximizing realizations for any additional production and booking additional sales for contract years 2019 and 2020. Our contracted position includes a mix of sales to our top domestic customers, to the export thermal market, and to the export metallurgical market, maintaining our diversified market exposure and providing a solid revenue base for meeting our long-term market strategy.

The sales commitments under contract are our expected sales tons and can fluctuate up or down due to provisions contained within our contracts. The contractual time commitments for customers to nominate future purchase volumes under our contracts are typically sufficient to allow us to balance our sales commitments with prospective production capacity or incremental sales volume. In addition, the commitments can change because of reopener provisions contained in certain of these long-term contracts. For the years ended December 31, 2017, 2016 and 2015, approximately 68%, 80% and 75%, respectively, of all the coal produced from the Pennsylvania Mining Complex was sold under contracts with terms of one year or more.

The provisions of our contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the provisions of our 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. Our 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, volatile matter content 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 customers 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 2017 sales tons, approximately 65% were sold to U.S. electric generators, 32% were priced on export markets and 3% were sold to other domestic customers. We derive a significant portion of our revenues from two customers: Duke Energy Corporation (“Duke Energy”) and Xcoal Energy & Resources (“Xcoal Energy”) from each of whom we derived at least 10% of our total coal sales for the year ended December 31, 2017. As of January 1, 2018, we had nine sales agreements with these customers that expire at various times in 2018 and 2019. As of February 16, 2018, CONSOL Energy has entered into an additional contract with Xcoal Energy. It is anticipated that these combined contracts with Xcoal Energy will account for more than 10% of the Partnership’s total revenue for the year ended December 31, 2018.

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, or FOB, at the Pennsylvania Mining Complex, which means that our customers bear the transportation costs from the mining complex, and essentially all of our coal transported to our domestic customers or to an export terminal facility originates 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 coal export terminals located on the U.S. east coast.

Information About Geographic Areas

Our revenue is derived predominantly from sales to customers in the United States. Less than 1% of our revenue is derived from sales to Canada over the past 3 years. We have contractual relationships with certain United States-based coal exporters who distribute coal to international markets. For the year ended December 31, 2017, 2016, and 2015 approximately 31%, 16%, and 19% of our coal revenues were derived from these United States-based exporters, respectively, in which our coal was intended to be shipped to Asia, Europe, South America, and Africa.

All of the Partnership’s long-lived assets are located in the United States.

Seasonality

Our business has historically experienced 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, including those who export coal abroad. 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.

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 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 regulated greenhouse gas (“GHG”), is also emitted when coal is burned. Environmental regulations governing emissions from coal-fired electric generating plants increase the costs to operate and could affect demand for coal as a fuel source and affect the volume of our sales. Moreover, additional environmental regulations increase the likelihood that existing coal-fired electric generating plants will be decommissioned, including plants to which the Partnership sells coal to, and reduce the likelihood that new coal-fired plants will be built in the future.

In early 2012, the United States Environmental Protection Agency (“EPA”) promulgated or finalized several rules for New Source Performance Standards (“NSPS”) for coal and oil fired power plants which also have a negative effect on coal-generating facilities. The Utility Maximum Control Technology (“UMACT”) rule requires more stringent NSPS for particulate matter (“PM”), Sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_X”) and the Mercury and Air Toxics Standards (“MATS”) rule requires new mercury and air toxic standards. In November 2012, the EPA published a notice of reconsideration of certain aspects of the UMACT and MATS rules. Following reconsideration in April 2013 and again in April 2014, the EPA promulgated final UMACT and MATS rules in November 2014. The rule was rejected by the U.S. Supreme Court on June 29, 2015 and sent back to the D.C. Circuit Court to determine whether to remand and allow the EPA to address the rule’s deficiencies or to vacate and nullify the rule; nevertheless most coal-fired electric power generators have already taken steps to comply with the rule. On April 18, 2017 the EPA asked the Court to delay arguments over MATS to allow the Trump Administration time to fully review the findings. On April 27, 2017, the Court granted the requested stay.

The CAA requires the EPA to set National Ambient Air Quality Standards (“NAAQS”) for certain pollutants and the CAA identifies two types of NAAQS. Primary standards provide public health protection, including protecting the health of “sensitive” populations such as asthmatics, children, and the elderly. Secondary standards provide public welfare protection, including protection against decreased visibility and damage to animals, crops, vegetation, and buildings. On October 1, 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 parts per billion (ppb) from the previous 75 ppb standard. The final rule could have a large impact on the coal mining industry as states would be required to update their permitting standards to meet these potentially unachievable limits. Several states have filed a petition for review in the D.C. Circuit of Appeals. On April 7, 2017, the EPA advised the Court that it intended to reconsider the final rule. On April 11, 2017, the Court stayed the litigation pending further action by the EPA. On August 10, 2017, EPA withdrew a previously-announced one-year extension to the compliance deadline.

On July 6, 2011, the EPA finalized a rule known as the Cross-State Air Pollution Rule (“CSAPR”). CSAPR regulates cross-border emissions of criteria air pollutants such as SO₂ and NO_X, as well as byproducts, fine particulate matter (“PM_2.5”) and ozone by requiring states to limit emissions from sources that “contribute significantly” to noncompliance with air quality standards for the criteria air pollutants. If the ambient levels of criteria air pollutants are above the thresholds set by the EPA, a region is considered to be in “nonattainment” for that pollutant and the EPA applies more stringent control standards for sources of air emissions located in the region. In April 2014, the Supreme Court reversed a decision of the D.C. Circuit Court of Appeals that vacated the rule. Following remand and briefing the D.C. Circuit Court, in October 2014, granted a motion to lift a stay of the rule and allow the EPA to modify the CSAPR compliance deadline by three years, setting the stage for issuance of the proposed rule. Implementation of CSAPR Phase 1 began in 2015, with Phase 2 scheduled to begin in 2017. On September 7, 2016, the EPA finalized an update to the CSAPR for the 2008 ozone NAAQS by issuing the final CSAPR Update. As of May 2017, this rule limits summertime (May - September) NO_X emissions from power plants in 22 states in the eastern United States.

On March 27, 2012, the EPA published its proposed NSPS for CO₂ emissions from new coal-powered electric generating units. The proposed rule would have applied to new power plants and to existing plants that make major modifications. If the rule had been adopted as proposed, only new coal-fired power plants with CO₂ capture and storage (“CCS”) could have met the proposed emission limits. Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal-fired electric generation units uneconomical compared to new gas-fired electric generation units. On January 8, 2014, the EPA re-proposed NSPS for CO₂ for new fossil fuel fired power plants and rescinded the rules that were proposed on April 13, 2012.

On September 20, 2013, the EPA issued a new proposal, “Carbon Pollution Standard for New Power Plants”, to establish separate NSPS for CO₂ emissions for natural gas-fired turbines and coal-fired units. On June 2, 2014, the EPA announced the Clean Power Plan (“CPP Rule”) rules intended to cut carbon emissions from existing power plants. Under this proposed rule, the EPA would create emission guidelines for states to follow in developing plans to address GHG emissions from existing fossil fuel-fired electric generating units. Specifically, the EPA proposed state-specific rate-based goals for CO₂ emissions from

the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. On August 3, 2015, the EPA finalized the CPP Rule and the Carbon Pollution Standards for New Power Plants.

Numerous petitions challenging the CPP Rule have been consolidated into one case, West Virginia v. EPA. While the

litigation is still ongoing at the circuit court level, a mid-litigation application to the Supreme Court resulted in a stay of the CPP Rule. On September 27, 2016, an en banc panel of the U.S. Court of Appeals for the D.C. Circuit heard oral arguments in the case. The decision, originally expected in early 2017, has been stayed as a result of a March 28, 2017 executive order directing the EPA to begin the process of reviewing and possibly rescinding the CPP Rule. The EPA filed a motion and the motion was granted by the U.S. Court of Appeals for the D.C. Circuit requesting the stay while the EPA conducts their review of the CPP Rule. If the review does not result in any rule changes, the U.S. Court of Appeals for the D.C. Circuit will rule on the legality of the CPP Rule. On October 16, 2017, the EPA formally proposed repeal of the CPP, which relies on a re-interpretation of Clean Air Act 111(d), on which the CPP was originally premised.

Similarly, various states and industry groups challenged the Carbon Pollution Standards for New Power Plants. That litigation has also been stayed following the March 28, 2017 executive order.

The current Administration’s executive order promoting energy independence and economic growth issued on March 28, 2017 requires the review of existing regulations that potentially burden the development or use of domestically produced energy resources. On October 25, 2017, the EPA issued a report in compliance with the March 28, 2017 executive order recommending changes to the NAAQS and NSPS programs. It also recommended that the EPA’s regulations consider employment impacts and that the EPA develop a database of industry-knowledgeable contacts. The review of existing regulations may not result in any changes and any changes made to existing regulations may not produce the intended favorable results desired by the new Administration. The executive order also directed the Council on Environmental Quality to rescind its final guidance entitled, “Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews.” The guidance previously directed agencies to consider proposed actions and their effects on climate change (GHG emissions would have been a key indicator being assessed under any NEPA review). Such review considerations may have created additional delays or costs in any NEPA review processes for energy producers and generators and may have prevented the acquisition of any necessary federal approvals for energy producers and generators.

Clean Water Act. The federal Clean Water Act (“CWA”) and corresponding state laws affect our coal operations by regulating discharges into surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. The CWA and corresponding state laws include requirements for: improvement of designated “impaired waters” (i.e., 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; requirements to minimize impacts and compensate for unavoidable impacts resulting from discharges of fill materials to regulated streams and wetlands; and requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. In addition, the Spill Prevention, Control and Countermeasure (“SPCC”) requirements of the CWA apply to all CONSOL Energy operations that use or produce fluids and require the implementation of plans to address any spills and the installation of secondary containment around all storage tanks. These requirements may cause us to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.

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 (“2015 Clean Water Rule”), which would impose additional permitting obligations on our operations. On August 27, 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. On February 28, 2017, Presidential Executive Order on “Restoring the Rule of Law, Federalism, and Economic Growth by reviewing the ‘Waters of the United States’ Rule” was issued. In response, on June 27, 2017, the U.S. Environmental Protection Agency, Department of the Army, and the Army Corps of Engineers issued a rule proposing to re-codify the definition of “waters of the United States” to the text that existed prior to the 2015 Clean Water Rule. The proposed rule provides certainty in the interim period until a subsequent rulemaking on the definition of “waters of the United States” can be finalized. On January 22, 2018, the U.S. Supreme Court ruled that challenges to the 2015 Clean Water Rule are properly decided in federal district courts and not federal courts of appeal. This decision implicates the nationwide injunction previously enacted by the Sixth Circuit, but has no impact on the current Administration’s efforts to replace the rulemaking. Additionally, on January 31, 2018, the EPA finalized a rule delaying the effective date of the 2015 Clean Water Rule for two years.

In order to obtain a permit for certain coal mining activities, including the construction of coal refuse areas and slurry impoundments, 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.

Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws and regulations affect coal mining by imposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposed of are subject to corrective action orders issued by the EPA that could adversely affect our results, financial condition and cash flows. In 2010, the EPA proposed options for the regulation of Coal Combustion Residuals from the electric power sector as either hazardous waste or non-hazardous waste. On December 19, 2014, the EPA announced the first national regulations for the disposal of Coal Combustion Receivables from electric utilities and independent power producers under RCRA. On April 17, 2015, the EPA finalized these regulations under the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C) which became effective on October 19, 2015. The EPA affirms in the preamble to the final rule that “this rule does not apply to Coal Combustion Receivables placed in active or abandoned underground or surface mines.” Instead, “the U.S. Department of Interior (“DOI”) and the EPA will address the management of Coal Combustion Receivables in mine fills in a separate regulatory action(s).” On September 14, 2017, EPA stated its intention to reconsider certain Coal Combustion Receivables provisions. It is unclear whether this reconsideration will result in changes to the Coal Combustion Receivables regulations.

On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards (“ELG”), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. On September 13, 2017, EPA finalized a rule postponing certain compliance dates for specific waste streams subject to the effluent limitations for a period of two years. The combined effect of the Coal Combustion Receivables and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal burning power plants that cannot comply with the new standards.

Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (“SMCRA”) establishes minimum national operational and reclamation standards for all surface mines as well as most aspects of underground mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all mining operations must be obtained from the U.S. Office of Surface Mining (“OSM”) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards which are more stringent than the requirements of SMCRA and OSM’s regulations and in many instances have done so. The Pennsylvania Mining Complex is located in states which have achieved primary jurisdiction for enforcement of SMCRA through approved state programs. In addition, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund, which is used to restore unreclaimed and abandoned mine lands mined before 1977. The current per ton fee is $0.12 per ton for underground mined coal. This fee is 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 provided by CONSOL Energy and 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 therefor. Any failure by CONSOL Energy or us to maintain, or our inability to acquire, surety bonds that are required by state and federal laws or the related collateral required by the bond issuers therefor, would have a material adverse effect on our ability to produce coal, which could adversely affect our business, financial condition, liquidity, results of operations and cash flows.

Excess Spoil, Coal Mine Waste, Diversions, and Buffer Zones for Perennial and Intermittent Streams. The OSM has issued final amendments to regulations concerning stream buffer zones, stream channel diversions, excess spoil, and coal mine waste to comply with an order issued by the U.S. District Court for the District of Columbia on February 20, 2014, which vacated the stream buffer zone rule that was published December 12, 2008. On July 27, 2015, the OSM published the proposed Stream Protection Rule (SPR). After much debate and thousands of comments, the final SPR was published by the OSM in the Federal Register on December 20, 2016. The final SPR requires the restoration of the physical form, hydrologic function, and ecological

function of the segment of a perennial or intermittent stream that a permittee mines through. Additionally, it requires that the post-mining surface configuration of the reclaimed mine site include a drainage pattern, including ephemeral streams, similar to the pre-mining drainage pattern, with exceptions for stability, topographical changes, fish and wildlife habitat, etc. The rule also requires the establishment of a 100-foot-wide streamside vegetative corridor of native species (including riparian species, when appropriate) along each bank of any restored or permanently-diverted perennial, intermittent, or ephemeral stream. This rulemaking was nullified by Congress under the Congressional Review Act in February 2017.

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 volume 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. The rulemaking record for this proposed rule was closed on December 15, 2016, but on January 9, 2017, MSHA published a notice reopening the record and extending the comment period for this proposed rule for 30 days. 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 technology. This final rule was implemented in three phases. The first phase began on August 1, 2014 and utilized the current gravimetric sampling device to take full shift dust samples from the current designated occupations and areas. It also required additional record keeping and immediate corrective action in the event of overexposure. The second phase began on February 1, 2016 and required 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. CPDM equipment was purchased and was placed into service which was required to meet compliance with the new rule. Dust Coordinators and Dust Technicians were hired in order to meet the staffing demand to manage compliance with the new rule. The final phase of the rule went into effect on August 1, 2016. The current respirable dust standard was 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.

Other State and Local Laws

Ownership of Coal Rights. The Partnership’s coal business acquires ownership or leasehold rights to coal properties prior to conducting operations on those properties. As is customary in the coal industry, we have generally conducted only a summary review of the title to coal rights that are not in our development plans, but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land records to determine control of coal rights. Given our experience as a coal producer, we believe we have a well-developed ownership position relating to our coal control. Prior to the commencement of development operations on coal properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We generally will not commence operations on a property until we have cured any material title defects on such property. We are typically responsible for the cost of curing any title defects. We have completed title work on substantially all of our coal producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.

Permits

Environmental Proceedings. On September 4, 2017, the Pennsylvania Department of Environmental Protection (the “DEP”) provided notice that it required additional time to review the technical merits of a prior permit submission (the “Application”) for continued longwall mining within the 4L panel under Polen Run at the Bailey Mine, in light of a recent Environmental Hearing Board (the “EHB”) decision, which is discussed further below. As a result, the longwall was idled at that time and workforce adjustments were made, pending further developments with the DEP and permit submission. This was the first time in the 35-year history of the Bailey Mine that a needed mining permit had not been received in a timely fashion.

As noted above, the DEP’s consideration of the Application related to part of an August 2017 EHB decision that impacts the application of DEP-required stream mitigation techniques, specifically the installation of synthetic stream-channel liner systems. The EHB is the quasi-judicial agency that hears appeals of DEP permitting decisions. The EHB decision held, in part, that the requirement to install a stream-channel liner system constituted impermissible pollution under applicable environmental laws. That determination had direct and specific implications for the Application with respect to undermining one particular stream, Polen Run in the 4L Panel, for which the DEP was proposing to require the installation of the stream-channel liner system as a mitigation measure. The DEP requested alternative mitigation measures for consideration, which our sponsor supplied. Given the potential for a protracted review, our sponsor felt it prudent to temporarily idle the longwall and dismantle and relocate it to another panel where it held an operating permit.

To that end, on September 18, 2017, we issued a press release stating that the DEP was requiring additional time to evaluate the approval of the Application and that, as a result of this ongoing evaluation, we determined to move the longwall to another permitted panel in order to resume operations. The longwall was moved and resumed operations the first week of October 2017. Our management implemented several measures to mitigate the production impact from this delay, including working additional unscheduled shifts as compared to the previous five and a half day schedule. Our management continued to take steps to mitigate the production impact from this delay and worked closely with the necessary agencies to obtain operating permits to allow for continuity of longwall mining operations. In November 2017, the DEP issued permitting authorizing revised longwall mining plans in the 5L Panel and longwall mining in Panels 6L through 8L.

The Application also sought authorization for continued longwall mining under the Polen Run stream in the Bailey Mine 5L Panel under Polen Run. Additionally, the Application has been revised to conform to the DEP’s interpretation of the August 2017 EHB decision. The Application proposes to conduct stream mitigation through techniques approved by the DEP under existing permits. The Application remains under the DEP’s review with respect to longwall mining under the Polen Run stream in the Baily Mine 5L Panel.

The Pennsylvania Mining Complex operates five total longwalls, with many of the approved permits as far out as ten years in advance.

Employees

Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for procuring 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 (which CONSOL Energy assumed from CNX as part of the separation), 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 (which CONSOL Energy assumed from CNX as part of the separation), CONSOL Thermal Holdings, our wholly owned subsidiary, manages and controls the day-to-day operations of the Pennsylvania Mining Complex. Under our employee services agreement (which CONSOL Energy assumed from CNX as part of the separation), employees of CONSOL Energy and its subsidiaries 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. As of December 31, 2017, CONSOL Energy employed approximately 1,600 people who provide direct support to our operations pursuant to the employee services agreement. None of the employees who provide direct support to the Pennsylvania Mining Complex are represented by a labor union or collective bargaining agreement.

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 until December 31, 2020, although we will lose that status sooner if:


•	we have more than $1.07 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

The Partnership maintains a website at www.ccrlp.com. Information on our website is not incorporated by reference into this Annual Report on Form 10-K and does not constitute a part of this Annual Report on Form 10-K. We make available, free of charge, on our 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, 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 common and subordinated unitholders.

In order to support the payment of the minimum quarterly distribution of $0.5125 per common and subordinated unit per quarter, or $2.05 per common and subordinated unit on an annualized basis, we must generate distributable cash flow of approximately $14,285 per quarter, or approximately $57,142 per year, based on the number of common units, subordinated units and the general partner interest outstanding as of December 31, 2017.

The amount of available cash (as defined in the Partnership Agreement. See Item 5 - Market for Registrant’s Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities - “Definition of Available Cash”) that we can distribute on our common 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 CONSOL Energy) 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 CONSOL Energy.

Our primary strategy for growing our business and increasing distributions to our unitholders is to increase operating efficiencies to maximize realizations and make acquisitions that increase our distributable cash flow. The primary component of our growth strategy is based upon our expectation of future divestitures by CONSOL Energy to us of portions of its currently retained 75% undivided interest in the Pennsylvania Mining Complex. CONSOL Energy 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 CONSOL Energy. We may never purchase additional undivided interests in the Pennsylvania Mining Complex for several reasons, including the following:


•	CONSOL Energy 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 CONSOL Energy 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 the Affiliated Company Credit Agreement) or other contracts from purchasing additional undivided interests in the Pennsylvania Mining Complex, and CONSOL Energy may be prohibited by the terms of its debt agreements or other contracts from selling all or any portion of it. If we or CONSOL Energy must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of CONSOL Energy’s undivided interests in the Pennsylvania Mining Complex, we or CONSOL Energy 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 75% undivided interest in the Pennsylvania Mining Complex. If CONSOL Energy reduces its ownership interest in us, it may be less willing to sell to us additional undivided interests in the Pennsylvania Mining Complex. There are no restrictions on CONSOL Energy’s ability to transfer Pennsylvania Mining Complex assets to a third party. If we do not acquire all or a significant portion of CONSOL Energy’s retained 75% undivided interest in the Pennsylvania Mining Complex or other assets, 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 reserves are economically recoverable when the price at which they are expected to be sold exceeds their expected cost of production and selling. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our coal 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 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. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:


•	geologic 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 governing 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 that 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, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Deterioration in the global economic conditions in any of the industries in which our customers operate, or a worldwide financial downturn, or negative credit market conditions may have a materially adverse effect on our liquidity, results of operations, cash flows, business and financial condition 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 2017 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 we serve or are served by our customers could adversely affect 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 industrial production, which if weakened would negatively impact the revenues, margins and profitability of our coal business;


•	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;


•	our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our coal reserves, or for strategic acquisitions of assets, including from CONSOL Energy; and


•	decline in our creditworthiness, which may require us to post letters of credit, cash collateral or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.

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 U.S. Energy Information Administration (EIA), in 2017, the domestic electric power sector accounted for approximately 93% of total U.S. coal consumption. In 2017, the Pennsylvania Mining Complex sold approximately 65% of its coal to U.S. electric power generators, and we have annual or 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 power 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 five of the eight years between 2008 and 2015. 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 more efficient, less expensive to construct and less difficult to permit than coal-fired plants has the most potential to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators. For example, according to the EIA, installed U.S. natural gas-fired net summer generating capacity increased by about 7 gigawatts from 2014-2015, while installed coal-fired net summer generating capacity decreased by about 19 gigawatts over the same period. Additionally, there are currently no new coal-fired plants under construction in the United States and there is no guarantee that new coal-fired power plants will be constructed in this United States. If no new coal-fired power plants are constructed in the United States, the Partnership could be forced to rely more heavily on foreign customers to purchase its coal. Finally, 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. In addition, demand can fluctuate widely due to a number of matters beyond our control, including:


•	the market price for coal;


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


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


•	competition from other coal suppliers;


•	the price and availability of alternative fuels and sources for electricity generation, especially natural gas and renewable energy sources;


•	with respect to thermal coal, the price and availability of natural gas and the price and supply of imported liquefied natural gas;


•	technological advances affecting energy consumption;


•	the costs, availability and capacity of transportation infrastructure;


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


•	international developments impacting supply of metallurgical coal; and


•	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 coal industry also faces concerns with respect to oversupply from time to time. For example, the unusually warm 2015-16 winter left utilities with large coal stockpiles and depressed the demand for thermal coal. Also, China, a key participant in the seaborne market, has experienced highly volatile swings in seaborne coal demand which can adversely affect the supply/demand balance. The domestic and international supply-demand fundamentals for coal became more balanced in 2017 vs. 2016, as domestic power plant coal inventories were reduced to 143 million tons, or 27 million tons below year-ago levels, as of the end of November 2017, and U.S. coal exports were up by 67% in January-November 2017 vs. the same period in 2016. A substantial or extended decline in the prices we receive for our coal could adversely affect our business, results of operations, financial condition, cash flow and liquidity.

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, wind and solar 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 coal mining operations are underground mines. 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 at particular mines for varying lengths of time thereby adversely affecting our operating results. In addition, if an operating risk occurs in our mining operations, we may not be able to produce sufficient amounts of coal to deliver under our multi-year coal contracts. Our inability to satisfy contractual obligations could result in our customers initiating claims against us or canceling their contracts. 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 geological 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, which may result in reduced coal production at that mine;


•	environmental hazards;


•	equipment failures or 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.

The occurrence of any of these risks at our coal mining operations 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 occurrence of any of these events in our coal mining operations which prevents our delivery of coal to a customer and which is not excusable as a force majeure event under our coal sales agreement, could result in economic penalties, suspension or cancellation of shipments or ultimately termination of the coal sales agreement.

Although we, through CONSOL Energy, 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 or CONSOL Energy may elect not to obtain insurance for any or all of these risks if we or CONSOL Energy 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 adverse conditions or events, including 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. Our coal is transported from the Pennsylvania Mining Complex by rail, truck or a combination of these methods. To reach markets and end customers, our coal may also be transported by barge or by ocean vessels loaded at terminals. Disruption of transportation services because of weather-related problems, strikes, lock-outs, terrorism, governmental regulation, third-party action 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 fluctuation in the price of diesel fuel and demurrage, could make our coal less competitive. Any disruption of the transportation services we use or increase in transportation costs could have a materially adverse effect on our business, financial condition, results of operations and cash flows.

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

During the year ended December 31, 2017 approximately 68% of the coal the Pennsylvania Mining Complex produced was sold under multi-year sales contracts. If a substantial portion of our multi-year sales contracts are modified or terminated, if force majeure is exercised, or if we are unable to replace or extend the contracts or 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 existing contractual obligations, our revenues will decrease and we may have to reduce production at our mines until such customers honor their contractual obligations and begin accepting shipments of our coal again or we can find an alternative customer.

The profitability of our multi-year coal 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 long-term coal 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 long-term coal sales contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price and electric power price volatility. As a result, we may not be able to obtain long-term 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 coal customers or the failure of any of our customers to buy and pay for coal they committed to purchase could adversely affect our business, financial condition, results of operation and cash flows.

We derive a significant portion of our revenues from two customers: Duke Energy and Xcoal Energy. For the year ended December 31, 2017, Duke Energy and Xcoal Energy each accounted for over 10% of our total coal sales. Furthermore, approximately 45% of our total coal sales were derived from our four largest coal customers in fiscal year 2017. At January 1, 2018, we had nine coal sales agreements with Duke Energy and Xcoal Energy that expire at various times in 2018 and 2019. 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. 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. Additionally, one of our customers is currently under bankruptcy protection, which could potentially result in that customer being unable to purchase coal from us at the same levels it did prior to entering into bankruptcy protection. If any 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 coal 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 coal sales contracts may reduce the protection from coal price volatility traditionally provided by coal sales contracts. Price reopener provisions are present in several of our multi-year coal 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 coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal quality characteristics such as heat content, sulfur, ash, moisture, volatile matter, grindability, ash fusion temperature, and size consist. Failure to meet these conditions could result in penalties or rejection of the coal at the election of the customer. Our coal 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 and some contracts may obligate us to perform notwithstanding what would typically be a force majeure event.

Some of our coal sales agreements contain electric power price-related adjustments which result only in positive monthly adjustments to the contracted base price that we receive for our coal. These adjustments vary month to month with the volatility in the electric power markets and during market downturns yield contract prices below expectations. While management considers the expectations and assumptions regarding the electric power price-related adjustments to be reasonable, they are inherently subject to business, economic, competitive, regulatory, and other risks and uncertainties, most of which are beyond our control.

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 industry 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 contracts to supply coal to energy trading and brokering customers under which those customer sell 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. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customers’ contractual obligations are honored. Our inability to collect payment from counterparties to our sales contracts may have a materially adverse effect on 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 we may not 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 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 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 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 operating issues.

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 Affiliated Company Credit Agreement and our level of indebtedness could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Our Affiliated Company Credit Agreement limits our ability to, among other things:


•	incur or guarantee additional debt;


•	make distributions under certain circumstances;


•	make certain investments and loans;


•	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 Affiliated Company Credit Agreement contains covenants requiring us to maintain certain financial ratios. For example, we are obligated to maintain at the end of each fiscal quarter (i) a maximum first lien gross leverage ratio of 2.75 to 1.00 and (ii) a maximum total net leverage ratio of 3.25 to 1.00, each of which will be calculated on a consolidated basis for the Partnership and its restricted subsidiaries at the end of each fiscal quarter. 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 restrictions in our Affiliated Company Credit Agreement and our 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 planning for and 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.

In addition, a failure to comply with the provisions of our Affiliated Company Credit Agreement 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.”

Increases in interest rates could adversely affect our business.

We have exposure to increases in interest rates. Based on our current debt level of $196,583 as of December 31, 2017, comprised of funds drawn under our Affiliate Company Credit Agreement, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $1,966. 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.

Our ability to operate our business effectively could be impaired if CONSOL Energy fails to attract and retain skilled personnel, or if a meaningful segment of its employees become unionized.

Our ability to operate our business and implement our strategies depends, in part, on CONSOL Energy’s continued ability to attract and retain the skilled personnel necessary to conduct our business. Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as electricians, equipment operators, mechanics, engineers and welders, among others. Although CONSOL Energy has not historically encountered shortages for these types of skilled labor, competition in the future may increase for such positions, especially as it relates to needs of other industries with respect to these positions, including oil and gas. If CONSOL Energy experiences shortages of skilled labor in the future, our labor and overall productivity or costs could be materially adversely affected. In the future, we may utilize a greater number of external contractors for portions of our operations. The costs of these contractors have historically been higher than that of our employed laborers. If CONSOL Energy’s labor and contractor prices increase, or if it experiences materially increased health and benefit costs with respect to its employees, our results of operations could be materially adversely affected.

None of CONSOL Energy’s employees who conduct mining operations at the Pennsylvania Mining Complex are currently 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 employees who conduct mining operations at the Pennsylvania Mining Complex may join or seek recognition to form a labor union, or CONSOL Energy 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 CONSOL Energy’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 do not have any officers or employees and rely on officers of our general partner and employees of CONSOL Energy.

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 CONSOL Energy to conduct mining activities. CONSOL Energy 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 CONSOL Energy. If our general partner and the officers and employees of CONSOL Energy 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 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

Affiliated Company Credit Agreement 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 our assets, 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 Partnership’s coal business utilizes certain pipelines in connection with its coal businesses. Mitigation permits from the Army Corps of Engineers are typically required for certain impacts these pipelines cause to streams and wetlands. On June 29, 2015 the EPA promulgated a proposed rule called “Definition of ‘Waters of the United States’ Under the Clean Water Act.” The rule expanded the scope of the CWA to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal waters of the U.S. On August 27, 2015, the District Court of North Dakota blocked implementation of the rule in 13 states prior to the rule’s effective date of August 28, 2015. On October 9, 2015, the Court of Appeals for the Sixth Circuit blocked implementation of the rule nationwide. On February 28, 2017, Presidential Executive Order on “Restoring the Rule of Law, Federalism, and Economic Growth by reviewing the ‘Waters of the United States’ Rule” was issued. In response, on June 27, 2017, the U.S. Environmental Protection Agency, Department of the Army, and the Army Corps of Engineers issued a rule proposing to re-codify the definition of “waters of the United States” to the text that existed prior to the 2015 Clean Water Rule. The proposed rule provides certainty in the interim period until a subsequent rulemaking on the definition of “waters of the United States” can be finalized. On January 22, 2018, the U.S. Supreme Court ruled that challenges to the rule are properly heard by federal district courts and not federal courts of appeal. Legal scholars are not in agreement about how the decision impacts the Sixth Circuit’s stay of the rule. Meanwhile, the current Administration is working to rescind and replace the rulemaking that would re-establish the 1986 rule and implement the 2008 guidance, which is less onerous than the currently litigated rule. The EPA has stated that it intends to repeal the rule in April 2018.

Management and regulation of point source discharges covered under the National Pollutant Discharge Eliminations System (NPDES) of the CWA have undergone recent changes and proposed changes at both the state and federal level that have the potential to affect the long-term treatment and discharge of water from coal mines. CWA section 304(b) requires EPA to annually review and, if appropriate, revise Effluent Guidelines. States are required by the CWA to conduct a comprehensive review of the state water quality standards every three years. On December 23, 2016 EPA published a draft Field-Based Methods for Developing Aquatic Life Criteria for Specific Conductivity, which could impact NPDES permits with conductivity limits. However, this draft document is also under review pursuant to Executive Order 13783.

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

While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (“GHGs”) such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal we produce, results in the creation of carbon dioxide emissions into the atmosphere by coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative in the northeastern U.S. Additionally, increasing attention to climate change risk has resulted in an increased possibility of governmental investigations and, potentially, private litigation against the Partnership.

The Obama Administration laid out the Climate Action Plan to limit emissions of carbon dioxide (CO2) from coal-fired and natural gas-fired power plants. The EPA proposed numerous regulatory actions to address CO2, including New Source Performance Standards for CO2 from both new power plants and existing and modified/reconstructed power plants. The agency’s CPP Rule, which went into effect on December 22, 2015, set state-specific rate-based goals for CO2 emissions from existing fossil fuel-fired electric generating units, and created emission guidelines for states to follow in developing plans to address greenhouse gas emissions from existing fossil fuel-fired electric generating units. Numerous petitions challenging the CPP Rule were consolidated into one case, West Virginia v. EPA. While the litigation was still ongoing at the circuit court level, a mid-litigation application to the Supreme Court resulted in a stay of the CPP Rule. On September 27, 2016, an en banc panel of the U.S. Court of Appeals for the D.C. Circuit heard oral arguments in the case. The decision, originally expected in early 2017, has been stayed as a result of a March 28, 2017 executive order directing the EPA to begin the process of reviewing and possibly rescinding the CPP Rule. The EPA filed a motion and the motion was granted by the U.S. Court of Appeals for the D.C. Circuit requesting the stay while the EPA conducts their review of the CPP Rule. If the review does not result in any rule

changes, the U.S. Court of Appeals for the D.C. Circuit will rule on the legality of the CPP Rule. On October 16, 2017, the EPA published a proposed rule which, if finalized, would rescind the CPP Rule.

The current Administration’s executive order promoting energy independence and economic growth issued on March 28,

2017 requires the review of existing regulations that potentially burden the development or use of domestically produced energy resources. The review of existing regulations may not result in any changes and any changes made to existing regulations may not produce the intended favorable results desired by the new Administration. The executive order also directed the Council on Environmental Quality to rescind its final guidance entitled, “Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act (NEPA) Reviews.” The guidance previously directed agencies to consider proposed actions and their effects on climate change (GHG emissions would have been a key indicator being assessed under any NEPA review). Such review considerations may have created additional delays or costs in any NEPA review processes for energy producers and generators and may have prevented the acquisition of any necessary federal approvals for energy producers and generators.

Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (which was not 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 was reached between the countries participating in the conference, including the United States, to limit global warming to less than 2 degrees Celsius (3.6° Fahrenheit) compared to pre-industrial levels. This agreement, known as the Paris Agreement, calls for zero net anthropogenic greenhouse gas emissions to be reached during the second half of the 21^st century. Each party is to prepare a plan on its contributions to reach this goal; each plan is to be filed in a publicly available registry. The Paris Agreement does not create any binding obligations for nations to limit their GHG emissions but rather includes pledges to voluntarily limit or reduce future emissions. Although the United States became a party to the Paris Agreement in April 2016, the current Administration subsequently terminated its participation in June 2017. However, the Paris Agreement stipulates that participating countries must wait four years before withdrawing from the agreement.

Additionally, coalbed methane must be expelled from our underground coal mines for mining safety reasons and is vented into the atmosphere when the coal is mined. Coalbed methane has a greater GHG effect than carbon dioxide. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to further reduce our methane emissions, 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. In 2010, the EPA declined a petition to regulate methane emissions from coal mines, and on May 13, 2014 the U.S. Court of Appeals upheld the EPA’s denial of the petition.

Apart from governmental regulation, investment banks based 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.

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 fossil fuel fired (especially coal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural

gas-fueled power generation could become more economically attractive than coal-fueled power generation. 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 or substantial delay in the amount of coal consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. 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, there have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring 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 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 domestic 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 along with fine particulate matter and carbon dioxide when it is burned. Complying with regulations on these emissions can be costly for electric power generators. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase) or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which electric power generators switch to alternative fuel could materially affect us. Recent Environmental Protection Agency (EPA) rulemaking proceedings 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 are (i) implementation of the Cross-State Air Pollution Rule to require reductions of seasonal nitrogen oxides emissions from power plants in the eastern United States to address ozone pollution; and (ii) the Utility Maximum Achievable Control Technology rule, better known as the Mercury and Air Toxics Standard rule, which included more stringent new source performance standards for particulate matter, mercury, sulfur dioxide and nitrogen oxides, for new and existing coal-fired power plants. The rule was rejected by the U.S. Supreme Court on June 29, 2015 and sent back to the D.C. Circuit Court to determine whether to remand and allow the EPA to address the rule’s deficiencies or to vacate and nullify the rule; nevertheless most coal-fired electric power generators have already taken steps to comply with the rule. On April 18, 2017 the EPA asked the Court to delay arguments over Mercury and Air Toxics Standards (MATs) to allow the Trump Administration time to fully review the findings. On April 21, 2017, the Court granted the requested stay.

Apart from actual and potential regulation of emissions, water use, waste water discharge and solid waste management 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 domestic 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 for coal and may restrict our coal operations.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign 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, groundwater quality and availability, 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 and competitive position. In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign 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 and competitive position. The Clean Water Act is being used by opponents of mountain top removal mining as a means to challenge permits and bring citizen suits to make coal mining more expensive.

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.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us. An example of this is Naturally Occurring Radioactive Material (NORM) or Technologically-Enhanced, Naturally Occurring Radioactive Material (TENORM). NORM or TENORM is produced when activities such as deep drilling concentrate or expose radioactive materials that occur naturally in ores, soils, water, or other natural materials. State and federal agencies are examining the possibility for worker exposure or associated environmental hazards due to processing and disposal of wastes containing NORM or TENORM.

We must obtain, maintain and renew governmental permits and approvals which if we cannot obtain in a timely manner would 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 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/or for on-going operations to continue mining continues to pose significant negative effects. Further, in 2011 the EPA revoked an Army Corps of Engineers issued Section 404 permit to a coal mining operator. Following the U.S. Supreme Court’s refusal in March 2012 to hear an appeal from the D.C. Circuit Court’s ruling upholding the EPA’s power to revoke a permit, in September 2014 the U.S. Court of Appeals upheld the EPA’s action to revoke the permit. In addition, in July 2014 the D.C. Circuit reversed a lower court’s decision and affirmed the EPA’s authority to adopt the Enhanced Coordination Process governing coordination with the Army Corps of Engineers in the processing of CWA permits. The Court also rejected challenges to EPA’s 2012 “Final Guidance” document regarding appropriate permit conditions, namely those affecting acceptable conductivity limits (e.g., acceptable ionic strength to support aquatic life). However, the Court left it up to the states on whether to adopt the guideline recommendations when issuing final NPDES permits. This decision has left coal mining permits in some degree of uncertainty whether the EPA will concur with a state’s draft permit conditions should they not contain specified limits regarding conductivity, further increasing operational uncertainty and costs.

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 Federal 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 are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures and other matters. Most states in which we operate have programs 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 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 coal 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, mine closing obligations and gas well plugging 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 as well as various state laws establish operational, reclamation and closure standards for all our coal mining operations and require us, under certain circumstances, to plug natural gas wells. We accrue for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing and degasification and well plugging liabilities, which are based upon permit requirements and our experience, were approximately $10,496 at December 31, 2017. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proved 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. Most states where we operate require us to post bonds for the full cost of coal mine reclamation (full cost bonding). West Virginia is not a full cost bonding state. West Virginia has an alternative bond system (ABS) for coal mine reclamation which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a bond pool (Special Reclamation Fund) funded by a per ton fee on coal mined in the State which is used to supplement the site specific bonds if needed in the event of bond forfeiture. In an effort to settle a citizen suit filed in 2012 before the U.S. District Court in West Virginia related to the Special Reclamation Fund being underfunded, the West Virginia legislature authorized an increase in the per ton fee levied on coal production to make up the shortfall. The Special Reclamation Fund became fully funded in June of 2016. There remains the possibility that West Virginia may move to full cost bonding in the future which could cause individual mining companies and/or surety companies to exceed bonding capacity and would result in the need to post cash bonds or letters of credit which would reduce operating capital.

Pennsylvania is expanding its full cost bonding program to cover all coal mine bonding, further increasing the amount of surety bonds we must seek in order to permit our mining activities. We have been able to post surety bonds with the states to secure our reclamation obligations. If our creditworthiness declines, states may seek to require us to post letters of credit or cash collateral to secure those obligations, or we may be unable to obtain surety bonds, in which case we would be required to post letters of credit. Additionally, the sureties that post bonds on our behalf may require us to post security in order to secure the obligations underlying these bonds. Posting letters of credit in place of surety bonds or posting security to support these surety bonds would have an adverse effect on our liquidity.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including CONSOL Energy, 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 CONSOL Energy, and CONSOL Energy is under no obligation to adopt a business strategy that favors us.

Our sponsor, CONSOL Energy, owns 5,006,496 common units and 11,611,067 subordinated units, representing 60.6% of the limited partner interest and all of our incentive distribution rights. In addition, our general partner owns a 1.7% general partner interest in us. Our sponsor also continues to own a 75% 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 CONSOL Energy. Conflicts of interest may arise between CONSOL Energy 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 CONSOL Energy, over the interests of our unitholders. These conflicts include, among others, the following situations:

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


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


•	CONSOL Energy 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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CONSOL Energy, which holds all of our incentive distribution rights, 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 CONSOL Energy 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 CONSOL Energy. 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, CONSOL Energy 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 CONSOL Energy 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 (which is defined in the Partnership Agreement) 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 required cash distributions 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 other 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 unitholders will have no preemptive or other rights (solely as a result of their status as 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. CONSOL Energy owns an aggregate of approximately 31.7% 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 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 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:

•

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


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

•

our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in 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 with Affiliates,” our general partner determines the amount of these expenses. Under the terms of the omnibus agreement we will be required to reimburse CONSOL Energy for the provision of certain administrative support services to us. Under our employee services

agreement, we will be required to reimburse CONSOL Energy for all direct third-party and allocated costs and expenses actually incurred by CONSOL Energy 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 $2,248 for the year ended December 31, 2017. 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, CONSOL Energy 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. CONSOL Energy owns 60.6% of our total outstanding common units and subordinated units on an aggregate basis. This will give CONSOL Energy 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 do 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 34.8% 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 CONSOL Energy to transfer its membership interest in our general partner to a third party after June 30, 2025 without the consent of the unitholders. 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 CONSOL Energy may be transferred to a third party without unitholder consent.

Subject to the Affiliated Company Credit Agreement, CONSOL Energy may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If CONSOL Energy transfers its incentive distribution rights to a third party, our general partner, which is owned by CONSOL Energy, may not have the same incentive to grow our Partnership and increase quarterly distributions to unitholders over time as it would if CONSOL Energy had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by CONSOL Energy could reduce the likelihood that it will sell or contribute additional assets to us, as CONSOL Energy 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 CONSOL Energy:


•	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.

CONSOL Energy 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.

CONSOL Energy holds 5,006,496 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 CONSOL Energy 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, CONSOL Energy, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Neither our Partnership Agreement nor our omnibus agreement will prohibit CONSOL Energy 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 CONSOL Energy. 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, CONSOL Energy 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, neither

CONSOL Energy 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 CONSOL Energy 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 31.7% of our common units (excluding any common units purchased by the directors, director nominees and executive officers of our general partner, directors of CONSOL Energy and certain other individuals as selected by CONSOL Energy under our directed unit program). At the end of the subordination period, our general partner and its affiliates will own approximately 60.6% of our outstanding common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner, directors of CONSOL Energy and certain other individuals as selected by CONSOL Energy under our directed unit program) and therefore would not be able to exercise the call right at that time.

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.

CONSOL Energy, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to 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.

CONSOL Energy 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%) 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 CONSOL Energy elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to CONSOL Energy 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. We anticipate that CONSOL Energy 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 CONSOL Energy 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, CONSOL Energy 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 CONSOL Energy 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 designates 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 limits 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 are listed 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 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 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 21%, 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 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 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 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 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. 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 units.

Our unitholders’ allocated share of our income will be taxable to them for U.S. 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 U.S. federal income tax positions we take, the market for our 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 U.S. 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 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 units could be more or less than expected.

If our unitholders sell 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 units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of 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 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 units that may result in adverse tax consequences to them.

Investment in our 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 units.

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

Because we cannot match transferors and transferees of 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 “Code”) referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a 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 units and could have a negative impact on the value of our 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 units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The 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 issued 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 regulations do not specifically authorize the use of the proration method we adopted. 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 units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for U.S. federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for U.S. federal income tax purposes as a partner with respect to those 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

units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those 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 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 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 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 units and could have a negative impact on the value of the 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 unit will be counted only once. 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 U.S. federal income tax purposes, but instead we would be treated as a new partnership for U.S. 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 Code, and we could be subject to penalties if we are unable to determine that a termination occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to terminating partnership. 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.

The elimination of any U.S. federal income tax preferences currently available with respect to coal exploration and development could negatively impact the value of our units.

The passage of any legislation 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 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 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 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

The following map provides the location of the Partnership’s significant properties. Our principal executive offices are located at 1000 CONSOL Energy Drive, Suite 100, Canonsburg, Pennsylvania 15317-6506.

Coal Reserves

The estimates of our proven and probable reserves are calculated internally using the face positions of the Pennsylvania Mining Complex’s longwall mines as of December 31, 2017. The December 31, 2017 reserves were estimated using the same techniques and assumptions as in prior years. 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 7,920 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%-40% 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. For the years ended December 31, 2017, 2016 and 2015, our portion of the Pennsylvania Mining Complex sold approximately 0.4 million tons, 0.5 million tons and 0.3 million tons of coal, respectively, in the metallurgical market.

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 additional information regarding the recoverable coal reserves at the Pennsylvania Mining Complex as of December 31, 2017 (tons in thousands):



			As Received Heat Value (1) (Btu/lb)			Recoverable Reserves (2)(3)
Mine	Reserve Class	Average Seam Thickness (feet)	Typical	Range	As Received lb SO2 / mmBtu	Owned (%)		Leased (%)		Total (tons)
Bailey:	Assigned	7.5	12,940	12,780 - 13,040	3.8	42	%	58	%	18,845
	Accessible	7.5	12,880	12,670 - 13,140	4.2	78	%	22	%	42,451
Enlow Fork:	Assigned	7.5	13,000	12,840 - 13,220	3.0	94	%	6	%	23,346
	Accessible	7.7	12,850	12,630 - 13,020	3.4	67	%	33	%	50,521
Harvey:	Assigned	6.9	13,040	12,900 - 13,210	2.9	95	%	5	%	14,447
	Accessible	7.7	12,930	12,880 - 13,190	3.6	99	%	1	%	34,257
Total										183,867

(1) ) The heat values (gross calorific values) shown for Assigned Operating reserves are based on the 2017 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 2017. 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 (gross calorific values) shown for Accessible Reserves are on an as received basis (dry values obtained from drill hole analyses, adjusted for moisture) and are 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 tons are reported on an as-received basis, based on the anticipated product moisture. Reserves are reported only for those coal seams that are controlled by ownership or leases.

(3) 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 estimations, 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 typically 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 $48.40 per ton.

ITEM 3. LEGAL PROCEEDINGS

Our operations are subject to a variety of risks and disputes normally incidental 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 18 “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) since July 1, 2015 and trade under the symbol “CCR”. 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 for the periods indicated:



Period	High Price	Low Price	Distribution per Limited Partner Unit
First Quarter 2016	$9.39	$5.98	$0.5125
Second Quarter 2016	$10.29	$6.70	$0.5125 (a)
Third Quarter 2016	$16.72	$8.80	$0.5125
Fourth Quarter 2016	$22.30	$15.15	$0.5125
First Quarter 2017	$19.55	$14.57	$0.5125
Second Quarter 2017	$17.55	$14.75	$0.5125
Third Quarter 2017	$16.95	$14.50	$0.5125
Fourth Quarter 2017	$15.75	$12.56	$0.5125

(a) The Partnership elected not to pay a distribution to holders of subordinated units for the second quarter 2016. The second quarter 2016 distribution paid to common unit holders was $0.5125 per unit.

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

Unitholders Profile. Pursuant to the records of the transfer agent, as of February 8, 2018, the number of registered holders of our common units was approximately nine. The Fourth Quarter 2017 cash distribution of $0.5125 per common and subordinated unit was declared on January 25, 2018 to holders of record as of February 8, 2018 and will be paid on February 15, 2018.

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 the year ended December 31, 2017.

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 for this purpose 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

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. The Partnership Agreement requires that all available cash that is deemed to be “Operating Surplus” under the terms of the Partnership Agreement be distributed, however, there is no guarantee that the Partnership will pay the minimum quarterly distribution on those units in any quarter. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity.”

General Partner Interest

Initially, our general partner was entitled to 2% of all quarterly distributions from inception that we made 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 was reduced as a result of issuing additional limited partner interests in the form of Class A Preferred Units and our general partner did not contribute a proportionate amount of capital to maintain a 2% general partner interest. This resulted in our general partner now having a 1.7% general partner interest. As of the date of this Annual Report on Form 10-K, there are no outstanding Class A Preferred Units.

Incentive Distribution Rights

CONSOL Energy 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 $0.5894 per unit per quarter.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected historical financial data, representing the Partnership’s 25% undivided interest in Pennsylvania Mining Complex, of CONSOL 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,
	2017		2016			2015			2014		2013
CONSOLIDATED STATEMENTS OF OPERATIONS:	(Dollars in thousands, except per unit data)
Coal Revenue	$	296,913	$	266,395		$	322,261		$	404,247	$	339,334
Freight Revenue	18,423		11,603			3,809			4,192		4,445
Other Income	7,448		3,119			941			9,660		1,515
Total Revenue and Other Income	322,784		281,117			327,011			418,099		345,294

Operating and Other Costs	194,986		183,001			193,961			239,863		209,776
Depreciation, Depletion and Amortization	41,437		41,994			44,136			43,337		32,291
Freight Expense	18,423		11,603			3,809			4,192		4,445
Selling, General and Administrative Expenses	15,697		9,949			10,931			17,149		15,778
Loss on Extinguishment of Debt	2,468		—			—			—		—
Interest Expense	9,309		8,719			9,636			8,683		2,616
Total Costs	282,320		255,266			262,473			313,224		264,906
Net Income	$	40,464	$	25,851		$	64,538		$	104,875	$	80,388

Net Income Allocable to Limited Partner Units	$	34,076	$	19,487		$	22,888		N/A		N/A

Net Income per Limited Partner Unit - Basic (1)	$	1.40	$	0.84		$	0.99		N/A		N/A
Net Income per Limited Partner Unit - Diluted (1)	$	1.39	$	0.83		$	0.99		N/A		N/A
Cash Distribution per Limited Partner Unit	$	2.0500	$	2.0500	(8)	$	0.9916	(9)	N/A		N/A

Limited Partner Units Outstanding - Basic	24,325,575		23,225,142			23,222,134			N/A		N/A
Limited Partner Units Outstanding - Diluted	24,461,373		23,402,897			23,223,045			N/A		N/A



	As of December 31,
	2017			2016			2015			2014
CONSOLIDATED BALANCE SHEETS:	(in thousands)
Working Capital (2)	$	(15,261	)	$	(16,060	)	$	(15,266	)	$	(68,242	)
Total Assets	$	494,239		$	504,296		$	525,944		$	523,510
Long-Term Debt (3)	$	196,656		$	197,989		$	181,070		$	201,451
Total Liabilities	$	281,083		$	277,726		$	254,141		$	310,227
Total Partners’ Capital and Parent Net Investment	$	213,156		$	226,570		$	271,803		$	213,283



	For the Years Ended December 31,
	2017			2016			2015			2014			2013
OTHER FINANCIAL DATA:	(in thousands, except per ton amounts)
Net Cash Provided by Operating Activities	$	72,642		$	73,098		$	76,908		$	142,636		$	118,020
Net Cash Used in Investing Activities	$	(17,996	)	$	(34,181	)	$	(34,002	)	$	(66,030	)	$	(84,535	)
Net Cash Used in Financing Activities	$	(62,898	)	$	(35,666	)	$	(36,376	)	$	(76,606	)	$	(33,486	)
Actual Maintenance Capital Expenditures	19,496			12,704			34,073			39,847			61,524
Tons Sold	6,523			6,151			5,719			6,533			5,308
Tons Produced	6,527			6,166			5,698			6,516			5,359
Coal Revenue Per Ton Sold (4)	$	45.52		$	43.31		$	56.36		$	61.88		$	63.93
Cost Per Ton Sold (5)	$	35.03		$	34.35		$	41.78		$	42.61		$	44.53
Adjusted EBITDA (6)	$	99,551		$	77,749		$	115,964		$	157,340		$	121,219
Estimated Maintenance Capital Expenditures (7)	$	35,764		$	28,964		$	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 and capital lease obligations. For information regarding long-term debt, please read “Item 8. Financial Statements and Supplementary Data—Note 9 Long-Term 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 revenue per ton sold is based on total coal revenue 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.

(7) Our estimated maintenance capital expenditures, as defined under the terms of our Partnership Agreement, are those forecasted average capital expenditures required to maintain, over the long-term, the operating capacity of our capital assets. These do not reflect the actual cash capital incurred in the period presented.

(8) The Partnership elected not to pay a distribution to holders of subordinated units for the second quarter 2016. The second quarter 2016 distribution paid to common unit holders was $0.5125 per unit.

(9) The third quarter 2015 distribution was prorated from the closing date of the IPO based upon a minimum quarterly distribution of $0.5125 per unit.

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,
	2017		2016		2015			2014			2013
Net Income	$	40,464	$	25,851	$	64,538		$	104,875		$	80,388
Interest Expense	9,309		8,719		9,636			8,683			2,616
Depreciation, Depletion and Amortization	41,437		41,994		44,136			43,337			32,291
OPEB Plan Change	—		—		(5,339		)	—			—
OPEB Transition Payment	—		—		—			4,124			—
Backstop Loan Fees	—		—		1,895			—			—
Coal Contract Buyout	—		—		—			(7,500		)	—
Litigation Settlement	—		—		—			(1,069		)	—
Business Interruption Proceeds	—		—		—			—			(1,361		)
Bailey Belt Repairs	—		—		—			689			2,078
Loss on Extinguishment of Debt	2,468		—		—			—			—
Stock/Unit Based Compensation	5,873		1,185		1,098			4,201			5,214
Adjusted EBITDA	$	99,551	$	77,749	$	115,964		$	157,340		$	121,226


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

Unless otherwise indicated, the following discussion and analysis of the financial condition and results of operations of our Partnership reflect a 25% undivided interest in the assets, liabilities and results of operations of the Pennsylvania Mining Complex. As used in the following discussion and analysis of the financial condition and results of operations of our Partnership, the terms “we,” “our,” “us,” or like terms refer to the Partnership with respect to its 25% undivided interest in the Pennsylvania Mining Complex’s combined assets, liabilities revenues and costs. All amounts except per unit or per ton are displayed in thousands.

Overview

We are a master limited partnership formed by CNX, which was then named “CONSOL Energy Inc.,” in 2015 to manage and further develop all of its coal operations in Pennsylvania. Our primary strategy for growing our business and increasing distributions to our unitholders is to increase operating efficiencies to maximize realizations and make acquisitions that increase our distributable cash flow. The primary component of our growth strategy is based upon our expectation of future divestitures by CONSOL Energy to us of portions of its retained 75% undivided interest in the Pennsylvania Mining Complex. At December 31, 2017, the Partnership’s assets include a 25% 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. 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, and the industry experience of our management team position us as a leading producer of high-Btu thermal coal in the Northern Appalachian Basin and the eastern United States.

The Pennsylvania Mining Complex, which includes the Bailey Mine, the Enlow Fork Mine and the 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, 2017, the Partnership’s portion of the Pennsylvania Mining Complex included 183,867 tons of proven and probable coal reserves with an average gross heat content of approximately 12,915 Btu per pound and approximately 3.6 pounds sulfur dioxide per million British thermal units (“lb SO2/mmBtu”). Based on our current production capacity, these reserves are sufficient to support approximately 26 years of production. In addition, our reserves currently exhibit thermoplastic behavior suitable for cokemaking and contain an average of approximately 39%-40% volatile matter (on a dry basis), which enables us, if market dynamics are favorable, to capture greater margins from selling our coal as a crossover product in the high-vol metallurgical market to cokemakers and steel manufacturers who utilize modern cokemaking technologies.

On September 30, 2016, the Partnership and its wholly owned subsidiary, CONSOL Thermal Holdings, entered into a Contribution Agreement (the “Contribution Agreement”) with CNX, CPCC and Conrhein and together with CPCC, (the “Contributing Parties”), under which CONSOL Thermal Holdings completed the PA Mining Acquisition to acquire an undivided 6.25% of the Contributing Parties’ right, title and interest in and to the Pennsylvania Mining Complex (which represents an aggregate 5% undivided interest in and to the Pennsylvania Mining Complex). This acquisition was a transaction between entities under common control; therefore, the Partnership recorded the assets and liabilities of the acquired 5% of Pennsylvania Mining Complex at their carrying amounts on CNX’s financial statements at the date of the transaction. The difference between CNX’s net carrying amount and the total consideration paid to CNX was recorded as a capital transaction with CNX, which resulted in a reduction in partners’ capital. The Partnership recast its historical consolidated financial statements to retrospectively reflect ownership of the additional 5% (a total 25%) interest in the Pennsylvania Mining Complex as if the business was owned for all periods presented; however, the consolidated financial statements are not necessarily indicative of the results of operations that would have occurred if the Partnership had owned it during the periods reported.

On November 28, 2017, CONSOL Energy separated from CNX into an independent, publicly traded coal company

through a pro rata distribution of all of CONSOL Energy’s common stock to CNX’s stockholders. CONSOL Energy was

originally formed as CONSOL Mining Corporation in Delaware on June 21, 2017 to hold CNX’s coal business including its interest in the Pennsylvania Mining Complex and certain related coal assets, including CNX’s ownership interest in the Partnership and our general partner, CNX’s terminal operations at the Port of Baltimore and undeveloped coal reserves located in the Northern Appalachian, Central Appalachian and Illinois basins and certain related coal assets and liabilities. As part of the separation and distribution, CONSOL Mining Corporation changed its name to CONSOL Energy Inc., CNX changed its name to CNX Resources Corporation, the Partnership changed its name to CONSOL Coal Resources LP and its ticker to “CCR” and our general partner changed its name to CONSOL Coal Resources GP LLC.

How We Evaluate Our Operations

Our management team uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability. The metrics include: (i) coal production, sales volumes and average revenue per ton; (ii) cost of coal sold, a non-GAAP financial measure; (iii) cash cost of coal sold, a non-GAAP financial measure; (iv) average cash margin per ton, an operating ratio derived from non-GAAP financial measures; (v) adjusted EBITDA, a non-GAAP financial measure; and (vi) distributable cash flow, a non-GAAP financial measure.

Cost of coal sold, cash cost of coal sold, average cash margin per ton, adjusted EBITDA and distributable cash flow normalize the volatility contained within comparable GAAP measures, by adjusting certain non-operating or non-cash transactions. Each of these non-GAAP metrics 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;

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

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

Reconciliation of Non-GAAP Financial Measures

We evaluate our cost of coal sold and cash cost of coal sold on a cost per ton basis. Our cost of coal sold per ton represents our costs of coal sold 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 depreciation, depletion and amortization costs. Our costs exclude any indirect costs such as selling, general and administrative costs, freight expenses, interest expenses 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. The cash cost of coal sold includes cost of coal sold less depreciation, depletion and amortization cost on production assets. The GAAP measure most directly comparable to cash cost of coal sold is total costs.

We define average cash margin per ton as average coal revenue per ton, net of average cash cost of coal sold per ton. The GAAP measure most directly comparable to average cash margin per ton sold is total coal revenue.

We define adjusted EBITDA as (i) net income (loss) before net interest expense, depreciation, depletion and amortization, as adjusted for (ii) certain non-cash items, such as long-term incentive awards including phantom units under the CONSOL Coal Resources LP 2015 Long-Term Incentive Plan (“Unit Based Compensation”). The GAAP measure most directly comparable to adjusted EBITDA is net income.

We define distributable cash flow as (i) net income (loss) before net interest expense, depreciation, depletion and amortization, as adjusted for (ii) certain non-cash items, such as Unit Based Compensation, less net cash interest paid and estimated maintenance capital expenditures, which is defined as those forecasted average capital expenditures required to maintain, over the long-term, the operating capacity of our capital assets. These estimated capital expenditures do not reflect the actual cash capital incurred in the period presented. 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. We define distribution coverage ratio as a ratio of the distributable cash flow to the minimum quarterly

distributions, which is the $0.5125 per quarter distribution for all limited partner units, including common and subordinated, issued for the periods presented, as defined in the Partnership Agreement.

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



	Years Ended December 31,
	2017			2016			2015
Total Costs	$	282,320		$	255,266		$	262,473
Freight Expense	(18,423		)	(11,603		)	(3,809		)
Selling, General and Administrative Expenses	(15,697		)	(9,949		)	(10,931		)
Loss on Extinguishment of Debt	(2,468		)	—			—
Interest Expense	(9,309		)	(8,719		)	(9,636		)
Other Costs (Non-Production)	(5,714		)	(10,330		)	3,263
Depreciation, Depletion and Amortization (Non-Production)	(2,187		)	(3,400		)	(2,461		)
Cost of Coal Sold	$	228,522		$	211,265		$	238,899
Depreciation, Depletion and Amortization (Production)	(39,250		)	(38,594		)	(41,675		)
Cash Cost of Coal Sold	$	189,272		$	172,671		$	197,224

The following table presents a reconciliation of average cash margin per ton to coal revenue, the most directly comparable GAAP financial measure for each of the periods indicated (in thousands, except for per ton information).



	Years Ended December 31,
	2017			2016			2015
Coal Revenue	$	296,913		$	266,395		$	322,261
Operating and Other Costs	194,986			183,001			193,961
Less: Other Costs (Non-Production)	(5,714		)	(10,330		)	3,263
Cash Cost of Coal Sold	189,272			172,671			197,224
Depreciation, Depletion and Amortization	41,437			41,994			44,136
Less: Depreciation, Depletion and Amortization (Non-Production)	(2,187		)	(3,400		)	(2,461		)
Cost of Coal Sold	$	228,522		$	211,265		$	238,899
Total Tons Sold	6,523			6,151			5,719
Average Revenue Per Ton Sold	$	45.52		$	43.31		$	56.36
Average Cash Cost Per Ton Sold	29.02			28.09			34.47
Depreciation, Depletion and Amortization Costs Per Ton Sold	6.01			6.26			7.31
Average Cost Per Ton Sold	35.03			34.35			41.78
Average Margin Per Ton Sold	10.49			8.96			14.58
Add: Depreciation, Depletion and Amortization Costs Per Ton Sold	6.01			6.26			7.31
Average Cash Margin Per Ton Sold	$	16.50		$	15.22		$	21.89

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 (in thousands).



	Years Ended December 31,
	2017		2016			2015
Net Income	$	40,464	$	25,851		$	64,538
Plus:
Interest Expense	9,309		8,719			9,636
Depreciation, Depletion and Amortization	41,437		41,994			44,136
OPEB Plan Change	—		—			(5,339		)
Backstop Loan Fees	—		—			1,895
Loss on Extinguishment of Debt	2,468		—			—
Accounts Receivable Securitization Fees	—		—			—
Stock/Unit Based Compensation	5,873		1,185			1,098
Adjusted EBITDA	$	99,551	$	77,749		$	115,964
Less:
Cash Interest	8,224		8,049			7,896
PA Mining Acquisition Adjusted EBITDA¹	—		10,272			23,366
Distributions to Preferred Units²	5,553		1,851			—
Estimated Maintenance Capital Expenditures	35,764		28,964			29,708
Expansion Capital Expenditures	—		21,500			—
Plus:
Borrowings to Fund Expansion Capital Expenditures	—		21,500			—
Distributable Cash Flow	$	50,010	$	28,613		$	54,994

Net Cash Provided by Operating Activities	$	72,642	$	73,098		$	76,908
Plus:
Interest Expense	9,309		8,719			9,636
Other, Including Working Capital	17,600		(4,068		)	29,420
Adjusted EBITDA	$	99,551	$	77,749		$	115,964
Less:
Cash Interest	8,224		8,049			7,896
PA Mining Acquisition Adjusted EBITDA¹	—		10,272			23,366
Distributions to Preferred Units²	5,553		1,851			—
Estimated Maintenance Capital Expenditures	35,764		28,964			29,708
Expansion Capital Expenditures	—		21,500			—
Add:
Borrowings to Fund Expansion Capital Expenditures	—		21,500			—
Distributable Cash Flow	$	50,010	$	28,613		$	54,994
Minimum Quarterly Distributions	$	50,982	$	48,589		$	48,576
Distribution Coverage Ratio³	1.0		0.6			1.1

¹PA Mining Acquisition Adjusted EBITDA relates to the amount of Adjusted EBITDA acquired with the PA Mining Acquisition included in the recast Adjusted EBITDA amounts. It is backed out to derive distributable cash flows reflecting the ownership percentage for all periods presented.

²Distributions to Preferred Units represents income attributable to preferred units prior to conversion.

³Distribution coverage ratio for the year ended December 31, 2015 is based on the pro forma minimum quarterly distributions per unit as if the Partnership was formed on January 1, 2015.

Results of Operations

Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016

Total net income was $40,464 for the year ended December 31, 2017 compared to $25,851 for the year ended December 31, 2016. 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,
	2017		2016		Variance
Revenue:	(in thousands)
Coal Revenue	$	296,913	$	266,395	$	30,518
Freight Revenue	18,423		11,603		6,820
Other Income	7,448		3,119		4,329
Total Revenue and Other Income	322,784		281,117		41,667
Cost of Coal Sold:
Operating Costs	189,272		172,671		16,601
Depreciation, Depletion and Amortization	39,250		38,594		656
Total Cost of Coal Sold	228,522		211,265		17,257
Other Costs:
Other Costs	5,714		10,330		(4,616		)
Depreciation, Depletion and Amortization	2,187		3,400		(1,213		)
Total Other Costs	7,901		13,730		(5,829		)
Freight Expense	18,423		11,603		6,820
Selling, General and Administrative Expenses	15,697		9,949		5,748
Loss on Extinguishment of Debt	2,468		—		2,468
Interest Expense	9,309		8,719		590
Total Costs	282,320		255,266		27,054
Net Income	$	40,464	$	25,851	$	14,613
Adjusted EBITDA	$	99,551	$	77,749	$	21,802
Distributable Cash Flow	$	50,010	$	28,613	$	21,397
Distribution Coverage Ratio	1.0		0.6		0.4

Coal Production Rates

The table below presents total tons produced from the Pennsylvania Mining Complex on our 25% undivided interest for the periods indicated:



	Years Ended December 31,
Mine	2017	2016	Variance
	(in thousands)
Bailey	3,031	3,014	17
Enlow Fork	2,295	2,409	(114	)
Harvey	1,201	743	458
Total	6,527	6,166	361

Coal production was 6,527 tons for the year ended December 31, 2017 compared to 6,166 tons for the year ended December 31, 2016. The Partnership’s coal production increased 361 tons to satisfy demand. Production at the Harvey mine increased due to the temporary idling of one longwall for 90 days in the prior year, offset in part, by a decrease in coal production at the Enlow Fork mine due to adverse geological conditions and permit delays at the Bailey Mine.

Coal Operations

Coal revenue and cost components on a per unit basis for the years ended December 31, 2017 and 2016 were as indicated in the table below. Our operations also include various costs such as selling, 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,
	2017		2016		Variance
Total Tons Sold (in thousands)	6,523		6,151		372
Average Sales Price Per Ton Sold	$	45.52	$	43.31	$	2.21

Operating Costs Per Ton Sold (Cash Costs)	$	29.02	$	28.09	$	0.93
Depreciation, Depletion and Amortization Per Ton Sold (Non-Cash Cost)	6.01		6.26		(0.25		)
Total Costs Per Ton Sold	$	35.03	$	34.35	$	0.68
Average Margin Per Ton Sold	$	10.49	$	8.96	$	1.53
Add: Depreciation, Depletion and Amortization Costs Per Ton Sold	6.01		6.26		(0.25		)
Average Cash Margin Per Ton Sold (1)	$	16.50	$	15.22	$	1.28

(1) Average cash margin per ton is an operating ratio derived from non-GAAP measures. See “– How We Evaluate Our Operations –

Reconciliation of Non-GAAP Financial Measures” for a reconciliation of non-GAAP measures to the most directly comparable GAAP

measures.

Revenue and Other Income

Coal revenue was $296,913 for the year ended December 31, 2017 compared to $266,395 for the year ended December 31, 2016. The $30,518 increase was attributable to a 372 ton increase in tons sold and a $2.21 per ton higher average sales price. The increase in tons sold was driven by increased demand from our customers in the export thermal market, largely due to continued growth in demand from developing markets such as India, coupled with a variety of labor, weather and policy-related issues that affected the supply of seaborne thermal coal and petroleum coke throughout the year. The higher average sales price per ton sold in the 2017 period was primarily the result of a tighter supply-demand balance in the international thermal and crossover metallurgical coal markets that we serve. The API 2 index (the benchmark price reference for coal imported into northwest Europe) was up more than 42% for the year ended December 31, 2017 compared to the year ended December 31, 2016, and global coking coal prices were up by an even greater percentage in the year-over-year comparison.

Freight revenue, which is completely offset by 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 $18,423 for the year ended December 31, 2017 compared to $11,603 for the year ended December 31, 2016. The $6,820 increase in freight revenue was due to increased shipments to customers where we were contractually obligated to provide transportation services.

Other income is comprised of income generated by the Partnership not in the ordinary course of business. Other income was $7,448 for the year ended December 31, 2017 compared to $3,119 for the year ended December 31, 2016. The $4,329 increase was primarily attributable to several customer contract buyouts and an increase in externally purchased coal in 2017 for blending purposes only and a gain to an agreement to avoid mining approximately 85 acres of reserves, offset by a contract buyout that occurred in the prior year.

Cost of Coal Sold

Cost of coal sold is comprised of operating 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, royalties and production taxes, direct administration expenses, and depreciation, depletion, and amortization costs. Total cost of coal sold was $228,522 for the year ended December 31, 2017, or $17,257 higher than the $211,265 for the year ended December 31, 2016. Total costs per ton sold were $35.03 per ton for the year ended December 31, 2017 compared to $34.35 per ton for the year ended December 31, 2016. The increase in the cost of coal sold was primarily driven by additional operating expenses incurred at the Bailey Mine, related to operational delays as a result of the Bailey Mine permit delays discussed in Part I, and adverse geological conditions at the Enlow Mine. In addition, the average cost per ton sold increased due to additional costs related to an increase in development mining footage.

Total Other Costs

Total other costs are comprised of various costs that are not allocated to each individual mine and therefore are not included in unit costs. Total other costs decreased $5,829 for the year ended December 31, 2017 compared to the year ended December 31, 2016. The decrease is primarily attributable to $4,518 of costs in the prior year related to temporarily idling one of the longwalls at the Pennsylvania Mining Complex to optimize the production schedule, a $2,271 decrease related to discretionary 401(k) contributions, which we were required to reimburse under the omnibus agreement, and a $616 decrease related to a coal customer contract buyout in the prior year. These were offset, in part, by an increase of $1,780 in the year-over-year comparison related to the cost of purchased coal sold for blending purposes only and $1,402 of separation costs incurred in the current year related to organizational restructuring.

Selling, General and Administrative Expense

Selling, general, and administrative expenses increased $5,748 due to an increase in short-term incentive compensation paid to employees based on the results of operations achieved at our mines, increases in long-term incentive compensation recognized in relation to award modifications due to organizational restructuring, and increases in purchased services related to the conversion to a different Enterprise Resource Planning software.

Interest Expense

Interest expense, net of amounts capitalized, was $9,309 for the year ended December 31, 2017 compared to $8,719 for the year ended December 31, 2016 primarily due to higher interest rates.

Adjusted EBITDA

Adjusted EBITDA was $99,551 for the year ended December 31, 2017 compared to $77,749 for the year ended December 31, 2016. The $21,802 increase was a result of a $2.21 per ton increase in the average sales price, offset in part, by a $0.93 per ton increase in the cash cost of coal sold, resulting in a $8,350 increase in Adjusted EBITDA. In addition, an increase of 372 sales tons resulted in an increase of $5,662 in Adjusted EBITDA. The remaining variance is due to changes in other income and other costs as discussed above and various other transactions throughout both periods, none of which are individually material.

Distributable Cash Flow

Distributable cash flow was $50,010 for the year ended December 31, 2017 compared to $28,613 for the year ended December 31, 2016. The $21,397 increase was primarily attributed to a $21,802 increase in Adjusted EBITDA as discussed above, offset by a $6,800 increase in Estimated Maintenance Capital Expenditures and a $3,702 increase in distributions to holders of the Class A Preferred Units. These reductions were offset in part, by a $10,272 decrease in the PA Mining Acquisition Adjusted EBITDA. The remaining variance was due to various transactions that occurred throughout both periods, none of which are individually material.

Years Ended December 31, 2016 Compared to the Years Ended December 31, 2015

Total net income was $25,851 for the year ended December 31, 2016 compared to $64,538 for the year ended December 31, 2015. 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,
	2016		2015			Variance
Revenue:	(in thousands)
Coal Revenue	$	266,395	$	322,261		$	(55,866	)
Freight Revenue	11,603		3,809			7,794
Other Income	3,119		941			2,178
Total Revenue and Other Income	281,117		327,011			(45,894		)
Cost of Coal Sold:
Operating Costs	172,671		197,224			(24,553		)
Depreciation, Depletion and Amortization	38,594		41,675			(3,081		)
Total Cost of Coal Sold	211,265		238,899			(27,634		)
Other Costs:
Other Costs	10,330		(3,263		)	13,593
Depreciation, Depletion and Amortization	3,400		2,461			939
Total Other Costs	13,730		(802		)	14,532
Freight Expense	11,603		3,809			7,794
Selling, General, and Administrative Expenses	9,949		10,931			(982		)
Interest Expense	8,719		9,636			(917		)
Total Costs	255,266		262,473			(7,207		)
Net Income	$	25,851	$	64,538		$	(38,687	)
Adjusted EBITDA	$	77,749	$	115,964		$	(38,215	)
Distributable Cash Flow	$	28,613	$	54,994		$	(26,381	)
Distribution Coverage Ratio	0.6		1.1			(0.5		)

Coal Production Rates

The table below presents total tons produced from the Pennsylvania Mining Complex on our 25% undivided interest for the periods indicated:



	Years Ended December 31,
Mine	2016	2015	Variance
	(in thousands)
Bailey	3,014	2,547	467
Enlow Fork	2,409	2,250	159
Harvey	743	901	(158	)
Total	6,166	5,698	468

Coal production was 6,166 tons for the year ended December 31, 2016 compared to 5,698 tons for the year ended December 31, 2015. The 468 ton increase was attributable to improved production at the Bailey Mine and Enlow Fork Mine, offset partially by a decrease in production at the Harvey Mine due to the temporary idling of one longwall for 90 days.

Coal Operations

Coal revenue and cost components on a per unit basis for the years ended December 31, 2016 and December 31, 2015 were as indicated in the table below. Our operations also include various costs such as selling, 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,
	2016		2015		Variance
Total Tons Sold (in thousands)	6,151		5,719		432
Average Sales Price Per Ton Sold	$	43.31	$	56.36	$	(13.05	)

Operating Costs Per Ton Sold (Cash Costs)	$	28.09	$	34.47	$	(6.38	)
Depreciation, Depletion and Amortization Per Ton Sold (Non-Cash Cost)	6.26		7.31		(1.05		)
Total Costs Per Ton Sold	$	34.35	$	41.78	$	(7.43	)
Average Margin Per Ton Sold	$	8.96	$	14.58	$	(5.62	)
Add: Depreciation, Depletion and Amortization Costs Per Ton Sold	6.26		7.31		(1.05		)
Average Cash Margin Per Ton Sold (1)	$	15.22	$	21.89	$	(6.67	)

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

Revenue and Other Income

Coal revenue was $266,395 for the year ended December 31, 2016 compared to $322,261 for the year ended December 31, 2015. The $55,866 decrease was attributable to a $13.05 per ton lower average sales price, offset by a 432 increase in tons sold. The lower average coal sales price per ton sold in the 2016 period was primarily the result of the overall decline in the domestic and global thermal coal markets, particularly in the first half of 2016. This was related to higher customer inventories and lower gas prices after mild 2015 weather. The average realized price per ton declined by 23% compared to the prior year as some of the high priced coal contracts rolled off and were replaced by lower priced sales. The increased sales volumes reflect the improvement in coal demand throughout the second half of 2016, both domestic and international.

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 $11,603 for the year ended December 31, 2016 compared to $3,809 for the year ended December 31, 2015. The $7,794 increase in freight revenue was due to decreased shipments to customers where we were contractually obligated to provide transportation services.

Other income is comprised of income generated by the Partnership not in the ordinary course of business. Other income was $3,119 for the year ended December 31, 2016 compared to $941 for the year ended December 31, 2015. The $2,178

increase was primarily attributable to a customer’s partial coal contract buyout and sales of coal purchased from third parties and resold to end users in the 2016 period.

Cost of Coal Sold

Cost of coal sold is comprised of operating 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 includes items such as direct operating costs, royalties and production taxes, direct administration expenses, and depreciation, depletion, and amortization costs. Total cost of coal sold was $211,265 for the year ended December 31, 2016, or $27,634 lower than the $238,899 for the year ended December 31, 2015. Total costs per ton sold were $34.35 per ton for the year ended December 31, 2016 compared to $41.78 per ton for the year ended December 31, 2015. The decrease in the cost of coal sold was driven by the idling of one longwall for approximately 90 days in the first quarter of 2016, reduction of staffing levels, vendor concessions and the realignment of employee benefits. Productivity for the year ended December 31, 2016, as measured by tons per employee-hour, also improved by 17% compared to the year-ago period, despite the reduced average number of longwalls in operation over the 2016 period.

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 increased $14,532 for the year ended December 31, 2016 compared to the year ended December 31, 2015. The increase in other costs was primarily attributable to a net periodic benefit credit of $7,341 related to the OPEB plan remeasurement for the year ended December 31, 2015 compared to the year ended December 31, 2016, where no benefit credits were recorded, as the Partnership had no further OPEB obligation in connection with the completion of the IPO. The increase was also attributable to $4,518 of costs related to temporarily idling one of the longwalls at the Pennsylvania Mining Complex for approximately 90 days in the first quarter of 2016 due to market conditions. The remaining variance was related to costs to purchase coal from third parties for blending purposes and discretionary 401(k) contributions in the 2016 period, which we are required to reimburse under the omnibus agreement.

Selling, General and Administrative Expense

Selling, general and administrative expenses decreased $982 in the period-to-period comparison primarily due to reduced staffing levels and the realignment of employee benefits in 2016 compared to 2015.

Interest Expense

Interest expense, net of amounts capitalized, for the year ended December 31, 2016 was $8,719, which primarily related

to obligations under the PNC Revolving Credit Facility. For the year ended December 31, 2015, $9,636 of interest expense was incurred primarily on several related party long-term notes with CONSOL Financial Inc. (“CFI”), a wholly owned subsidiary of

CONSOL Energy (see Note 9 - Long-Term Debt and Note 20 - Related Party in Item 8 of this Form 10-K for additional information), which were excluded from the Partnership’s assets and liabilities at the time of the IPO. Also, interest

expense related to the PNC Revolving Credit Facility was $3,928 for the year ended December 31, 2015.

Adjusted EBITDA

Adjusted EBITDA was $77,749 for the year ended December 31, 2016 compared to $115,964 for the year ended December 31, 2015. The $38,215 decrease was a result of a $13.05 per ton decrease in the average sales price, offset in part, by a $6.38 per ton improvement in the cash cost of coal sold, resulting in a $41,028 decrease to Adjusted EBITDA. Additional decreases to Adjusted EBITDA were due to cash costs of $3,300 related to idling one of the longwalls at the Pennsylvania Mining Complex for approximately 90 days in the first quarter of 2016, and $2,271 related to a CONSOL Energy discretionary 401(k) contribution. These decreases in Adjusted EBITDA were offset by $9,457 related to increased sales tons. The remaining variance was due to various transactions throughout both periods, none of which were individually material.

Distributable Cash Flow

Distributable cash flow was $28,613 for the year ended December 31, 2016 compared to $54,994 for the year ended December 31, 2015. The $26,381 decrease was primarily attributed to a $38,215 decrease in Adjusted EBITDA as discussed above, offset in part, by a $13,094 decrease in the PA Mining Acquisition Adjusted EBITDA. The remaining variance was due to various other transactions in both periods, none of which are individually material.

Capital Resources and Liquidity

Liquidity and Financing Arrangements

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our Affiliated Company Credit Agreement, and, if necessary, the issuance of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and our long-term capital expenditure requirements and to make quarterly cash distributions as declared by the board of directors of our general partner. The Partnership filed a universal shelf registration on Form S-3 (333-215962) on March 10, 2017 with the SEC, which was declared effective by the SEC on March 14, 2017, for an aggregate amount of $750,000 to provide the Partnership with additional flexibility to access capital markets quickly.

We expect the cash flow generated from operations in 2018 to be comparable to 2017. We expect strong demand from the export and thermal domestic markets. Through consistent cost control measures, we expect to provide adequate cash flows to meet our maintenance capital requirements. We started the course refuse disposal area project, maintenance capital, in 2017, which is expected to continue through 2021. Our 2018 capital needs are expected to be between $31,000 to $36,000, which is increased from 2017 levels due to additional capital expenditures related to the refuse disposal area project, as well as additional maintenance equipment and other purchases.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon financing under the Affiliated Company Credit Agreement and the issuance of debt and equity securities to fund our acquisitions and expansion capital expenditures, if any.

On January 25, 2018, the Board of Directors of our general partner declared a cash distribution to the Partnership’s unitholders for the quarter ended December 31, 2017 of $0.5125 per common and subordinated unit. The cash distribution will be paid on February 15, 2018 to the unitholders of record at the close of business on February 8, 2018.

Credit Facility (PNC Revolving Credit Facility and Affiliated Company Credit Agreement)

On July 7, 2015, the Partnership, as borrower, and certain subsidiaries of the Partnership, as guarantors, entered into a credit agreement for a $400,000 revolving credit facility with PNC, as administrative agent, and other lender parties thereto (the “PNC Revolving Credit Facility”). On November 28, 2017, in connection with the separation, the Partnership paid all fees and other amounts outstanding, which aggregated to $200,583, under the PNC Revolving Credit Facility and terminated the PNC Revolving Credit Facility and the related loan documents.

On November 28, 2017, the Partnership and certain of its subsidiaries (collectively, the “Credit Parties”) entered into the Affiliated Company Credit Agreement by and among the Credit Parties, CONSOL Energy, as lender and administrative agent, and PNC. The Affiliated Company Credit Agreement provides for a revolving credit facility in an aggregate principal amount of up to $275,000 to be provided by CONSOL Energy, as lender. In connection with the completion of the separation and the Partnership’s entry into the Affiliated Company Credit Agreement, the Partnership made an initial draw of $200,583, the net proceeds of which were used to repay the PNC Revolving Credit Facility, to provide working capital for the Partnership following the separation and for other general corporate purposes. Additional drawings under the Affiliated Company Credit Agreement are available for general partnership purposes. The Affiliated Company Credit Agreement matures on February 27, 2023. The collateral obligations under the Affiliated Company Credit Agreement generally mirror the PNC Revolving Credit Facility, including the list of entities that will act as guarantors thereunder. The obligations under the Affiliated Company Credit Agreement are guaranteed by the Partnership’s subsidiaries and secured by substantially all of the assets of the Partnership and its subsidiaries pursuant to the security agreement and various mortgages.

Interest on outstanding obligations under our Affiliated Company Credit Agreement accrues at a fixed rate ranging from 3.75% to 4.75% depending on the total net leverage ratio. The unused portion of our Affiliated Company Credit Agreement is subject to a commitment fee of 0.50% per annum.

As of December 31, 2017, the Partnership had $196,583 thousand of borrowings outstanding under the Affiliated Company Credit Agreement, leaving $78,417 thousand of unused capacity. Interest on outstanding borrowings under the Affiliated Company Credit Agreement at December 31, 2017 was accrued at a rate of 4.25%.

is continuing or would result therefrom; (iii) incur certain liens or permit them to exist; (iv) 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; (v) enter into certain types of transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer, sell or otherwise dispose of assets. The Partnership is also subject to covenants that require the Partnership to maintain certain financial ratios. For example, the Partnership is obligated to maintain at the end of each fiscal quarter (a) maximum first lien gross leverage ratio of 2.75 to 1.00 and (b) a maximum total net leverage ratio of 3.25 to 1.00, each of which will be calculated on a consolidated basis for the Partnership and its restricted subsidiaries at the end of each fiscal quarter. At December 31, 2017, the first lien gross leverage ratio was 1.95 to 1.00 and the total net leverage ratio was 1.94 to 1.00.

Receivables Financing Agreement

On November 30, 2017, (i) CONSOL Marine Terminals LLC, formerly known as CNX Marine Terminals LLC, as an originator of receivables, (ii) CPCC, as an originator of receivables and as initial servicer of the receivables for itself and the other originators (collectively, the “Originators”), each a wholly owned subsidiary of CONSOL Energy, and (iii) CONSOL Funding LLC (the “SPV”), a Delaware special purpose entity and wholly owned subsidiary of CONSOL Energy, as buyer, entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”). Concurrently, (i) CONSOL Thermal Holdings, as sub-originator, and (ii) CPCC, as buyer and as initial servicer of the receivables for itself and CONSOL Thermal Holdings, entered into a Sub-Originator Sale Agreement (the “Sub-Originator PSA”). In addition, on that date, the SPV entered into a Receivables Financing Agreement (the “Receivables Financing Agreement”) by and among (i) the SPV, as borrower, (ii) CPCC, as initial servicer, (iii) PNC, as administrative agent, LC Bank and lender, and (iv) the additional persons from time to time party thereto as lenders. Together, the Purchase and Sale Agreement, the Sub-Originator PSA and the Receivables Financing Agreement establish the primary terms and conditions of an accounts receivable securitization program (the “Securitization”).

Loans under the Securitization will accrue interest at a reserve-adjusted LIBOR market index rate equal to the one-month Eurodollar rate. Loans and letters of credit under the Securitization also will accrue a program fee and a letter of credit participation fee, respectively, equal to 4.00% per annum. In addition, the SPV paid certain structuring fees to PNC Capital Markets LLC and will pay other customary fees to the lenders, including a fee on unused commitments equal to 0.60% per annum.

The SPV’s assets and credit are not available to satisfy the debts and obligations owed to the creditors of CONSOL Energy, CONSOL Thermal Holdings or any of the Originators. CONSOL Thermal Holdings, the Originators and CPCC as servicer are independently liable for their own customary representations, warranties, covenants and indemnities. In addition, CONSOL Energy has guaranteed the performance of the obligations of CONSOL Thermal Holdings, the Originators and CPCC as servicer, and will guarantee the obligations of any additional originators or successor servicer that may become party to the Securitization. However, neither CONSOL Energy nor its affiliates will guarantee collectability of receivables or the creditworthiness of obligors thereunder.

The Securitization contains various customary representations and warranties, covenants and default provisions which provide for the termination and acceleration of the commitments and loans under the Securitization in circumstances including, but not limited to, failure to make payments when due, breach of representation, warranty or covenant, certain insolvency events or failure to maintain the security interest in the trade receivables, and defaults under other material indebtedness.

As of December 31, 2017, the Partnership, through CONSOL Thermal Holdings, sold $31,447 thousand of trade receivables to CPCC. The Partnership has agreed to pay CPCC a fee based upon market rates for similar services to continue servicing the sold receivables. Costs associated with the receivables facility totaled $77 thousand for the year ended December 31, 2017. These costs have been recorded as financing fees which are included in Operating and Other Costs in the Consolidated Statements of Operations. The Partnership has not derecognized the receivables due to its continued involvement in the collections efforts.

Cash Flows



	For the Years Ended December 31,
	2017			2016			Variance
	(in thousands)
Cash flows provided by operating activities	$	72,642		$	73,098		$	(456	)
Cash used in investing activities	$	(17,996	)	$	(34,181	)	$	16,185
Cash used in financing activities	$	(62,898	)	$	(35,666	)	$	(27,232	)

Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016:

Cash flows provided by operating activities decreased $456 in the year ended December 31, 2017 compared to the year ended December 31, 2016 primarily due to a change in working capital, offset in part, by an increase in net income.

Net cash used in investing activities decreased $16,185 in the year ended December 31, 2017 compared to the year ended December 31, 2016 as a result of a $21,500 payment related to the PA Mining Acquisition in the year ended December 31, 2016 that did not recur and increased proceeds from the sale of assets of $1,477. This was offset against an increase in capital expenditures of $6,792. The increase in capital expenditures is due to the following items:



	For the Years Ended December 31,
	2017		2016		Variance
	(in thousands)
Building and infrastructure	$	8,166	$	8,358	$	(192	)
Equipment purchases and rebuilds	2,185		2,734		(549		)
Refuse storage area	8,002		591		7,411
Water treatment systems	348		223		125
Other	795		798		(3		)
Total capital expenditures	$	19,496	$	12,704	$	6,792

Net cash used in financing activities increased $27,232 in the year ended December 31, 2017 compared to the year ended December 31, 2016. The increase was primarily due to a $217,000 difference in PNC Revolving Credit Facility activity in the year-over-year comparison, which was comprised of $201,000 in payments during the year ended December 31, 2017 versus $16,000 in borrowings during the year ended December 31, 2016. The change in the PNC Revolving Credit Facility activity was primarily due to the repayment and refinancing of the PNC Revolving Credit Facility that occurred in the year ended December 31, 2017. The year-over-year increase was offset, in part, by $196,583 of borrowings under the Affiliated Company Credit Agreement. The increase in net cash used in financing activities was also attributable to an increase in cash distributions of $13,766 in the year-over-year comparison. This was primarily due to cash distributions made to the converted Class A Preferred Units during the year ended December 31, 2017 and the suspension of the second quarter subordinated unit distributions during the year ended December 31, 2016, offset in part, by a change of $8,953 in the net change in parent advances.

Off-Balance Sheet Arrangements

We do not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that have or 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.

Worker’s Compensation and Coal Workers’ Pneumoconiosis (“CWP”)

Liabilities and expenses for 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.

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, 2017 and the benefit payments made for the year end December 31, 2017 were as follows (in thousands):



Plan	Estimated Liability as of December 31, 2017		Benefit Payments for the year ended December 31, 2017
Workers’ Compensation	$	4,785	$	1,394
CWP	$	4,028	$	68

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.

The Partnership believes that the accounting estimates related to contingencies are “critical accounting estimates” because the Partnership must assess the probability of loss related to contingencies. In addition, the Partnership must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Partnership’s assumptions. See Note 18 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

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 $10,496 at December 31, 2017 and $9,937 at December 31, 2016. 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.

The Partnership believes that the accounting estimates related to asset retirement obligations are “critical accounting estimates” because the Partnership must assess the expected amount and timing of asset retirement obligations. In addition, the Partnership must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Partnership’s assumptions.

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. 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, 2017 (in thousands).



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Long-term debt	$	—	$	—	$	—	$	196,583	$	196,583
Interest on long-term debt	8,355		16,710		16,710		8,355		50,130
Capital (finance) lease obligations	77		73		—		—		150
Interest on capital (finance) lease obligations	4		5		—		—		9
Operating lease obligations	17,948		12,827		7,683		2,559		41,017
Long-term liabilities—employee related (a)	1,719		3,574		3,878		7,494		16,665
Other long-term liabilities (b)	41,586		948		1,174		7,761		51,469
Total contractual obligations	$	69,689	$	34,137	$	29,445	$	222,752	$	356,023


(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 $196,583, comprised of funds drawn under our Affiliate Company Credit Agreement, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $1,966. 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	69
Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016, and 2015	70
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015	71
Consolidated Balance Sheets at December 31, 2017 and 2016	72
Consolidated Statements of Partners’ Capital and Parent Net Investment for the Years Ended December 31, 2017, 2016, and 2015	74
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	75
Notes to the Consolidated Financial Statements	76

Report of Independent Registered Public Accounting Firm

To the Unitholders of CONSOL Coal Resources LP and the Board of Directors of CONSOL Coal Resources GP LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CONSOL Coal Resources LP (the Partnership) as of December 31, 2017 and 2016, 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, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting 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.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2015.

Pittsburgh, Pennsylvania

February 16, 2018

CONSOL COAL RESOURCES LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)



	For the Years Ended December 31,
	2017		2016		2015
Coal Revenue	$	296,913	$	266,395	$	322,261
Freight Revenue	18,423		11,603		3,809
Other Income	7,448		3,119		941
Total Revenue and Other Income	322,784		281,117		327,011

Operating and Other Costs ¹	194,986		183,001		193,961
Depreciation, Depletion and Amortization	41,437		41,994		44,136
Freight Expense	18,423		11,603		3,809
Selling, General and Administrative Expenses ²	15,697		9,949		10,931
Loss on Extinguishment of Debt	2,468		—		—
Interest Expense ³	9,309		8,719		9,636
Total Costs	282,320		255,266		262,473
Net Income	$	40,464	$	25,851	$	64,538
Less: Net Income Attributable to CONSOL Energy, Pre-IPO and Pre-PA Mining Acquisition	—		3,995		41,182
Net Income Attributable to General and Limited Partner Ownership Interest in CONSOL Coal Resources	$	40,464	$	21,856	$	23,356
Less: General Partner Interest in Net Income	662		399		468
Less: Net Income Allocable to Preferred Units	5,553		1,851		—
Less: Distribution Effect of Preferred Conversion	173		—		—
Limited Partner Interest in Net Income	$	34,076	$	19,606	$	22,888
Less: Effect of Subordinated Distribution Suspension	—		119		—
Net Income Allocable to Limited Partner Units	$	34,076	$	19,487	$	22,888

Net Income per Limited Partner Unit - Basic	$	1.40	$	0.84	$	0.99
Net Income per Limited Partner Unit - Diluted	$	1.39	$	0.83	$	0.99

Limited Partner Units Outstanding - Basic	24,325,575		23,225,142		23,222,134
Limited Partner Units Outstanding - Diluted	24,461,373		23,402,897		23,223,045

Cash Distributions Declared per Unit ⁴
Common Unit	$	2.0500	$	2.0500	$	0.9916
Subordinated Unit	$	2.0500	$	1.5375	$	0.9916

¹Related Party of $3,503, $4,251 and $6,793 for the years ended December 31, 2017, 2016, and 2015, respectively.

²Related Party of $3,109, $3,826 and $8,926 for the years ended December 31, 2017, 2016, and 2015, respectively.

³Related Party of $746, $0 and $6,050 for the years ended December 31, 2017, 2016, and 2015, respectively.

⁴ Represents the cash distribution declared related to the period presented. See Note 23 - Subsequent Events.

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

CONSOL COAL RESOURCES LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)



	For the Years Ended December 31,
	2017		2016			2015
Net Income	$	40,464	$	25,851		$	64,538

Actuarially Determined Long-Term Liability Adjustments:
Amortization of prior service credits	—		—			(8,701		)
Recognized net actuarial (gain) loss	1,366		(93		)	1,245
OPEB Plan amendments	—		—			4,714
Other comprehensive income before reclassifications	—		911			902
Total Actuarially Determined Long-Term Liability Adjustments	1,366		818			(1,840		)

Other Comprehensive Income (Loss)	1,366		818			(1,840		)

Comprehensive Income	$	41,830	$	26,669		$	62,698

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

CONSOL COAL RESOURCES LP

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	December 31, 2017		December 31, 2016
ASSETS
Current Assets:
Cash	$	1,533	$	9,785
Trade Receivables	31,473		23,418
Other Receivables	1,970		515
Inventories	12,303		11,491
Prepaid Expenses	4,428		3,512
Total Current Assets	51,707		48,721
Property, Plant and Equipment:
Property, Plant and Equipment	910,468		876,690
Less—Accumulated Depreciation, Depletion and Amortization	483,410		442,178
Total Property, Plant and Equipment—Net	427,058		434,512
Other Assets:
Other	15,474		21,063
Total Other Assets	15,474		21,063
TOTAL ASSETS	$	494,239	$	504,296

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

CONSOL COAL RESOURCES LP

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	December 31, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	19,718		$	18,797
Accounts Payable—Related Party	3,071			1,666
Other Accrued Liabilities	44,179			44,318
Total Current Liabilities	66,968			64,781
Long-Term Debt:
Revolver, Net of Debt Issuance and Financing Fees	—			197,843
Affiliated Company Credit Agreement - Related Party	196,583			—
Capital Lease Obligations	73			146
Total Long-Term Debt	196,656			197,989
Other Liabilities:
Pneumoconiosis Benefits	3,833			2,057
Workers’ Compensation	3,404			3,090
Asset Retirement Obligations	9,615			9,346
Other	607			463
Total Other Liabilities	17,459			14,956
TOTAL LIABILITIES	281,083			277,726
Partners’ Capital:
Class A Preferred Units (No Units Outstanding at December 31, 2017; 3,956,496 Units Outstanding at December 31, 2016)	—			69,151
Common Units (15,789,106 Units Outstanding at December 31, 2017; 11,618,456 Units Outstanding at December 31, 2016)	205,974			140,967
Subordinated Units (11,611,067 Units Outstanding at December 31, 2017 and December 31, 2016)	(15,225		)	(7,631		)
General Partner Interest	11,964			12,274
Accumulated Other Comprehensive Income	10,443			11,809
Total Partners’ Capital	213,156			226,570
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	494,239		$	504,296

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

CONSOL COAL RESOURCES LP

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Dollars in thousands)



							Limited Partners
	Parent Net Investment			Class A Preferred Units			Common			Subordinated			General Partner			Accumulated Other Comprehensive Income			Total
Balance at December 31, 2014	$	174,074		$	—		$	—		$	—		$	—		$	39,209		$	213,283
Net Income Attributable to January 1, 2015 to July 6, 2015	34,134			—			—			—			—			—			$	34,134
Other Comprehensive Loss	—			—			—			—			—			(1,840		)	(1,840		)
Net Working Capital Advances to the Partnership	(26,981		)	—			—			—			—			—			(26,981		)
Assets and Liabilities Contributed/Distributed	258,276			—			—			—			—			(26,378		)	231,898
Deemed Distribution to Partnership	(355,887		)	—			28,450			314,597			12,840			—			—
Net Working Capital Advances to the Partnership	(3,430		)	—			—			—			—			—			(3,430		)
Issuance of Common Units to Public, Net of Offering Costs	—			—			148,359			—			—			—			148,359
Distribution of IPO Proceeds	—			—			(28,421		)	(314,290		)	—			—			(342,711		)
Net Income Attributable to the Partnership	7,048			—			11,444			11,444			468			—			30,404
Unitholder Distributions	—			—			(5,563		)	(5,563		)	(227		)	—			(11,353		)
Unit Based Compensation	—			—			40			—			—			—			40
Balance at December 31, 2015	$	87,234		$	—		$	154,309		$	6,188		$	13,081		$	10,991		$	271,803
Issuance of Class A Preferred Units	—			67,300			—			—			—			—			67,300
Net Income	3,995			1,851			9,806			9,800			399			—			25,851
Other Comprehensive Income	—			—			—			—			—			818			818
Net Working Capital Advances to the Partnership	(8,953		)	—			—			—			—			—			(8,953		)
Net Asset Acquired in Pennsylvania Mining Complex	(82,276		)	—			—			—			—			—			(82,276		)
Purchase Price in Excess of Net Assets Acquired	—			—			(522		)	(5,767		)	(235		)	—			(6,524		)
Unitholder Distributions	—			—			(23,811		)	(17,852		)	(971		)	—			(42,634		)
Unit Based Compensation	—			—			1,185			—			—			—			1,185
Balance at December 31, 2016	$	—		$	69,151		$	140,967		$	(7,631	)	$	12,274		$	11,809		$	226,570
Net Income	—			5,553			18,040			16,209			662			—			40,464
Unitholder Distributions	—			(5,553		)	(26,072		)	(23,803		)	(972		)	—			(56,400		)
Conversion of Preferred Units	—			(69,151		)	69,151			—			—			—			—
Unit Based Compensation	—			—			5,873			—			—			—			5,873
Units Withheld for Taxes	—			—			(1,985		)	—			—			—			(1,985		)
Actuarially Determined Long-Term Liability Adjustments	—			—			—			—			—			(1,366		)	(1,366		)
Balance at December 31, 2017	$	—		$	—		$	205,974		$	(15,225	)	$	11,964		$	10,443		$	213,156

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

CONSOL COAL RESOURCES LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)



	For the Years Ended December 31,
	2017			2016			2015
Cash Flows from Operating Activities:
Net Income	$	40,464		$	25,851		$	64,538
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	41,437			41,994			44,136
(Gain) Loss on Sale of Assets	(1,399		)	9			(61		)
Unit Based Compensation	5,873			1,185			40
Loss on Extinguishment of Debt	2,468			—			—
Other Adjustments to Net Income	688			898			777
Changes in Operating Assets:
Accounts and Notes Receivable	(9,510		)	(4,064		)	(19,389		)
Inventories	(812		)	747			1,061
Prepaid Expenses	(916		)	1,577			(186		)
Changes in Other Assets	(615		)	(3,465		)	(3,246		)
Changes in Operating Liabilities:
Accounts Payable	293			1,968			(416		)
Accounts Payable—Related Party	88			(2,644		)	3,430
Other Operating Liabilities	(5,785		)	7,010			(7,244		)
Changes in Other Liabilities	368			2,032			(6,532		)
Net Cash Provided by Operating Activities	72,642			73,098			76,908
Cash Flows from Investing Activities:
Capital Expenditures	(19,496		)	(12,704		)	(34,073		)
PA Mining Acquisition	—			(21,500		)	—
Proceeds from Sales of Assets	1,500			23			71
Net Cash Used in Investing Activities	(17,996		)	(34,181		)	(34,002		)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	(96		)	(79		)	(53		)
Payments on Related Party Long-Term Notes	—			—			(10,951		)
Proceeds from Related Party Long-Term Notes	196,583			—			16,990
Proceeds from Revolver, Net of Payments	(201,000		)	16,000			185,000
Proceeds from Issuance of Common Units, Net of Offering Costs	—			—			148,359
Distribution of Proceeds	—			—			(342,711		)
Payments for Unitholder Distributions	(56,400		)	(42,634		)	(11,353		)
Units Withheld for Taxes	(1,985		)	—			—
Debt Issuance and Financing Fees	—			—			(4,329		)
Net Change in Parent Advances	—			(8,953		)	(17,328		)
Net Cash Used In Financing Activities	(62,898		)	(35,666		)	(36,376		)
Net (Decrease) Increase in Cash	(8,252		)	3,251			6,530
Cash at Beginning of Period	9,785			6,534			4
Cash at End of Period	$	1,533		$	9,785		$	6,534

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

CONSOL 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:

On September 30, 2016, the Partnership and its wholly owned subsidiary, CONSOL Thermal Holdings, entered into a Contribution Agreement (the “Contribution Agreement”) with CNX, CPCC and Conrhein and together with CPCC, (the “Contributing Parties”), under which CONSOL Thermal Holdings acquired an undivided 6.25% of the Contributing Parties’ right, title and interest in and to the Pennsylvania Mining Complex (which represents an aggregate 5% undivided interest in and to the Pennsylvania Mining Complex)(“PA Mining Acquisition”). The PA Mining Acquisition was a transaction between entities under common control; therefore, the partnership recorded the assets and liabilities of the acquired 5% of Pennsylvania Mining Complex at their carrying amounts to CNX on the date of the transaction. The difference between CNX’s net carrying amount and the total consideration paid to CNX was recorded as a capital transaction with CNX, which resulted in a reduction in partners’ capital. Because this transaction is between entities under common control, the Partnership recast its historical consolidated financial statements to retrospectively reflect the additional 5% interest in Pennsylvania Mining Complex as if the business was owned for all periods presented; however, the consolidated financial statements are not necessarily indicative of the results of operations that would have occurred if the Partnership had owned it during the periods reported.

For the years ended December 31, 2017 2016, and 2015 the Consolidated Financial Statements include the accounts of CONSOL Operating and CONSOL Thermal Holdings, wholly owned and controlled subsidiaries.

On November 28, 2017, CONSOL Energy was separated from CNX into an independent, publicly traded coal company via a pro rata distribution of all of CONSOL Energy’s common stock to CNX’s stockholders. CONSOL Energy was originally formed as CONSOL Mining Corporation in Delaware on June 21, 2017 to hold CNX’s coal business including its interest in the Pennsylvania Mining Complex and certain related coal assets, including CNX’s ownership interest in the Partnership and our general partner, CNX’s terminal operations at the Port of Baltimore and undeveloped coal reserves located in the Northern Appalachian, Central Appalachian and Illinois basins and certain related coal assets and liabilities. As part of the separation, CONSOL Mining Corporation changed its name to CONSOL Energy Inc. and its ticker to “CEIX”, CNX changed its name to CNX Resources Corporation and its ticker to “CNX”, the Partnership changed its name to CONSOL Coal Resources LP and its ticker to “CCR” and the general partner changed its name to CONSOL Coal Resources GP LLC.

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 $1.07 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.

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.

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, 2017, 2016 and 2015.

Pension:

The personnel who operate CPCC and Conrhein’s assets were employees of CPCC and participated in certain defined benefit retirement plans administered by CNX through December 31, 2015. In connection with the separation, the sponsorship of the CONSOL Energy Inc. Employee Retirement Plan (the “Pension Plan”) was transferred to CONSOL Energy. Effective December 31, 2015, the qualified defined benefit retirement plan was frozen for all remaining participants in the plan. 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.

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 be 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 25% undivided interest in the Pennsylvania Mining Complex which assets and liabilities are held by CPCC and Conrhein. The Partnership 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, 2017 and 2016, 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:

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.

Reclassifications:

The PA Mining Acquisition was accounted for as a transaction under common control, which resulted in the prior periods being recast to reflect as if the Partnership owned 25% of Pennsylvania Mining Complex for all periods presented. Certain amounts have been reclassified to conform with the current reporting classifications with no effect on previously reported recast net income or partners’ capital.

Recent Accounting Pronouncements:

In March 2017, the Financial Accounting Standards Board (“FASB”) issued Update 2017-07 - Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The Update requires entities to (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if that subtotal is presented. Because the Partnership does not present an income from operations subtotal, that requirement is not applicable. Additionally, the Partnership’s service cost component is deemed immaterial, and therefore, the other components of net benefit cost will not be presented separately. For public entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of a fiscal year for which financial statements have not been issued. The adoption of this guidance is not expected to have an impact on the Partnership’s financial statements.

In January 2017, the FASB issued Update 2017-01 - Business Combinations (Topic 805). This update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. 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. The adoption of this new guidance will not have a material impact on the Partnership’s financial statements.

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09 “Revenue from Contracts with Customers (Topic 606)”, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (“IFRS”). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services and 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 following updates to Topic 606 were made during 2016:


•	In March 2016, the FASB updated Topic 606 by issuing ASU 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” which clarifies how an entity determines whether it is a principal or an agent for goods or services promised to a customer as well as the nature of the goods or services promised to their customers.


•	In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance obligations and licensing.

•

In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update, which was issued in response to feedback received by the FASB-IASB joint revenue recognition transition resource group (TRG), seeks to address implementation issues in the areas of collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition.


•	In December 2016, the FASB issued Updated 2016-20 - Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This update applies technical corrections or improvements specific to Update 2014-09. The technical corrections seek to address implementation issues in the areas of loan guarantee fees,

contract costs - impairment testing, contract costs - interaction of impairment testing with guidance in other topics, provisions for losses on construction-type and production-type contracts, the scope of Topic 606, disclosure of remaining performance obligations, disclosure of prior-period performance obligations, contract modifications example, contract asset versus receivable, refund liability, advertising costs, fixed-odds wagering contracts in the casino industry, and cost capitalization for advisors to private and public funds.

The new standards are effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. Management has evaluated all contracts with particular attention to the impact from contracts that contain favorable electric power price related adjustments and contracts that span multiple years that have annual fixed pricing. We adopted the new standard in 2018 using the modified retrospective approach on all contracts which were not completed as of the date of initial application and there was no material impact on the Partnership’s financial statements. Further, we expect the impact of the adoption of the new standard to be immaterial to our net income on an ongoing basis, as the majority of our revenue will still be recognized when the product is shipped from our loading facility. The following factors outline management’s position:


•	Most of our long-term contracts are for a stated range of coal at a stated rate per year, with any material price change from year-to-year being market-driven or inflationary, where no additional value is exchanged.


•	Contracts which contain favorable electric power price related adjustments also represent market-driven price adjustments wherein there is no additional value being exchanged.


•	Pricing on contracts which are variable based on contractual quality-related adjustments are industry standard practices, could be favorable or unfavorable to the Partnership, are indeterminable, and represent an immaterial portion of our overall revenue stream.


•	While we do expect to experience costs of obtaining contracts with amortization periods greater than one year, those costs would be immaterial to our net income.

In August 2016, the FASB issued Update 2016-15 - Statement of Cash Flows (Topic 230) - Classification of Certain Cash Receipts and Cash Payments. This update seeks to reduce the existing diversity in practice of the presentation and classification of specific cash flow issues. 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. The adoption of this guidance is not expected to have an impact on the Partnership’s financial statements.

In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842). This update is intended to improve financial reporting about leasing transactions. This update will require lessees to recognize all leases with terms greater than 12 months on their balance sheet as lease liabilities with a corresponding right-of-use asset. This update maintains the dual model for lease accounting, requiring leases to be classified as either operating or finance, with lease classification determined in a manner similar to existing lease guidance. The basic principle is that leases of all types convey the right to direct the use and obtain substantially all the economic benefits of an identified asset, meaning they create an asset and liability for lessees. Lessees will classify leases as either finance leases (comparable to current capital leases) or operating leases (comparable to current operating leases). Costs for a finance lease will be split between amortization and interest expense, with a single lease expense reported for operating leases. This update also will require both qualitative and quantitative disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases. For public business entities, the amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted for all entities. Management is currently evaluating the impact this guidance may have on the Partnership’s financial statements.

NOTE 2—ACQUISITIONS:

INITIAL PUBLIC AND PRIVATE PLACEMENT OFFERING:

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 IPO.

CNX Resources Corporation (formerly CONSOL Energy Inc.)

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 CNX, 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 issuance of the common and subordinated units and other ownership interests issued to CNX 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 CNX.

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 issuance of the common units to Greenlight Capital was not registered under the Securities Act. We distributed all of the proceeds from the Concurrent Private Placement to CNX.

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 CNX. The remaining 188,933 common units that the underwriters did not exercise under their option, were issued to CNX.

PNC Revolving Credit Facility

In connection with the IPO, we entered into a $400,000 senior secured revolving credit facility (the “PNC Revolving Credit Facility”) with certain lenders and PNC, as administrative agent. Obligations under the PNC Revolving Credit Facility were guaranteed by our subsidiaries (the“guarantor subsidiaries”) and were secured by substantially all of our and our subsidiaries’ assets pursuant to a security agreement and various mortgages. CNX was not a guarantor of the PNC Revolving Credit Facility.

Borrowings under the PNC Revolving Credit Facility were used by us to fund cash distributions, make capital expenditures, pay fees and expenses related to the revolving credit facility and for general partnership purposes. In connection with the completion of the IPO and our entry into the 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 CNX. On November 28, 2017, in connection with the separation, the Partnership paid all fees and other amounts outstanding under the PNC Revolving Credit Facility, terminated the PNC Revolving Credit Facility and the related loan documents and entered into the Affiliated Company Credit Agreement.

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 the revolving credit facility to make a distribution of $342,711, including $4,352 of offering and structure fees, to CNX. 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 CNX in connection with the completion of the IPO was approximately $189,916.

PA MINING ACQUISITION:

On September 30, 2016, the Partnership and its wholly owned subsidiary, CONSOL Thermal Holdings, entered into a Contribution Agreement with CNX, CPCC and Conrhein and together with CPCC, under which CONSOL Thermal Holdings acquired an undivided 6.25% of the Contributing Parties’ right, title and interest in and to the Pennsylvania Mining Complex (which represents an aggregate 5% undivided interest in and to the Pennsylvania Mining Complex), in exchange for (i) cash consideration in the amount of $21,500 and (ii) the Partnership’s issuance of 3,956,496 Class A Preferred Units representing limited partner interests in the Partnership at an issue price of $17.01 per Class A Preferred Unit (the “Class A Preferred Unit

Issue Price”), or an aggregate $67,300 in equity consideration. The Class A Preferred Unit Issue Price was calculated as the volume-weighted average trading price of the Partnership’s common units over the trailing 15-day trading period ending on September 29, 2016 (or $14.79), plus a 15% premium. The PA Mining Acquisition was consummated on September 30, 2016. Our general partner elected not to contribute capital to retain their 2% interest. As of December 31, 2017 our general partner’s ownership interest in the partnership was 1.7%. Following the PA Mining Acquisition and including interests it held previously, CONSOL Thermal holds an aggregate 25% undivided interest in and to the Pennsylvania Mining Complex. On October 2, 2017 the 3,956,496 Class A Preferred Units were converted to common units on a one-for-one basis, in accordance with our Partnership agreement.

The PA Mining Acquisition was a transaction between entities under common control; therefore, the Partnership recorded the assets and liabilities of the acquired 5% undivided interest in the Pennsylvania Mining Complex at their carrying amounts to CNX on the date of the transaction. The difference between CNX’s net carrying amount and the total consideration paid to CNX was recorded as a capital transaction with CNX, which resulted in a reduction in partners’ capital. The $67,300 in preferred equity consideration was a non-cash transaction, which impacted the investing and financing activities of the Partnership, by $6,524 of excess consideration paid over the net carrying amount and $60,776 of carrying amount paid from equity consideration.

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, we allocate our net income to our limited partners and our general partner in accordance with the terms of our Partnership Agreement. We also allocate any earnings in excess of distributions to our limited partners and our general partner in accordance with the terms of our Partnership Agreement. We 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, as set forth in the Partnership Agreement. Net income attributable to the PA Mining Acquisition for periods prior to September 30, 2016 was not allocated to the limited partners for purposes of calculating net income per limited partner unit.

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 or convertible preferred units, 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		For the Year Ended			For the Year Ended
	December 31, 2017		December 31, 2016			December 31, 2015
Net Income Attributable to General and Limited Partner Ownership Interest in CONSOL Coal Resources	$	40,464	$	25,851		$	64,538
Less: Net (Loss) Income Attributable to CONSOL Energy, Pre-IPO	—		—			34,134
Less: Net Income Attributable to CONSOL Energy, Pre-PA Mining Acquisition	—		3,995			7,048
Less: General Partner Interest in Net Income	662		399			468
Less: Net Income Allocable to Class A Preferred Units	5,553		1,851			—
Less: Distribution Effect of Preferred Unit Conversion	173		—			—
Less: Effect of Subordinated Distribution Suspension	—		119			—
Net Income Allocable to Limited Partner Units	$	34,076	$	19,487		$	22,888

Limited Partner Interest in Net Income - Common Units	$	18,040	$	9,806		$	11,444
Less: Distribution Effect of Preferred Unit Conversion	85		—			—
Effect of Subordinated Distribution Suspension - Common Units	—		2,917			—
Net Income Allocable to Common Units	$	17,955	$	12,723		$	11,444

Limited Partner Interest in Net Income - Subordinated Units	$	16,209	$	9,800		$	11,444
Less: Distribution Effect of Preferred Unit Conversion	88					—
Effect of Subordinated Distribution Suspension - Subordinated Units	—		(3,036		)	—
Net Income Allocable to Subordinated Units	$	16,121	$	6,764		$	11,444

Weighted Average Limited Partner Units Outstanding - Basic
Common Units	12,714,508		11,614,075			11,611,067
Subordinated Units	11,611,067		11,611,067			11,611,067
Total	24,325,575		23,225,142			23,222,134

Weighted Average Limited Partner Units Outstanding - Diluted
Common Units	12,850,306		11,791,830			11,611,978
Subordinated Units	11,611,067		11,611,067			11,611,067
Total	24,461,373		23,402,897			23,223,045

Net Income Per Limited Partner Unit - Basic
Common Units	$	1.41	$	1.10		$	0.99
Subordinated Units	$	1.39	$	0.58		$	0.99

Net Income Per Limited Partner Unit -Diluted
Common Units	$	1.40	$	1.08		$	0.99
Subordinated Units	$	1.39	$	0.58		$	0.99

The outstanding Class A Preferred Units were converted on a one-to-one basis into common units on October 2, 2017, under the terms of the Partnership Agreement. As a result, the Partnership issued an aggregate of 3,956,496 Common Units to CNX and canceled the Class A Preferred Units. Following the conversion of the Class A Preferred Units into Common Units, no Class A Preferred Units are outstanding. The effect of preferred unit conversion resulted in the preferred units receiving a common distribution on November 15, 2017 in the amount of $0.5125 per unit versus the stated 11% per annum previously paid on the Class A Preferred. For the calculation of diluted net income per limited partner unit, the effect of conversion of the

3,956,496 Class A Preferred Units is antidilutive and is excluded from the calculation for the year ended December 31, 2016. No preferred units were available for the year ended December 31, 2015. There were no phantom units excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive for the year ended December 31, 2017.

NOTE 4—OTHER INCOME:



	For the Years Ended December 31,
	2017		2016			2015
Purchased coal sales	$	3,290	$	1,439		$	—
Coal contract buyout	2,477		1,572			—
Gain (loss) on sale of assets	1,399		(9		)	61
Right of way sales	2		31			608
Other	280		86			272
Total Miscellaneous Other Income	$	7,448	$	3,119		$	941

NOTE 5—INTEREST EXPENSE:



	For the Years Ended December 31,
	2017			2016			2015
Revolver interest	$	8,912		$	9,022		$	3,928
Interest on notes - related party	746			—			6,050
Capitalized interest	(361		)	(315		)	(348		)
Interest on other payables, net	12			12			6
Total Interest Expense	$	9,309		$	8,719		$	9,636

NOTE 6—INVENTORIES:



	December 31, 2017		December 31, 2016
Coal	$	2,853	$	1,950
Supplies	9,450		9,541
Total Inventories	$	12,303	$	11,491

Inventories are stated at the lower of cost or net realizable value. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion and amortization, 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.

NOTE 7—PROPERTY, PLANT AND EQUIPMENT:



	December 31, 2017		December 31, 2016
Coal and other plant and equipment	$	607,314	$	576,917
Coal properties and surface lands	122,377		121,241
Airshafts	95,566		92,938
Mine development	81,538		81,538
Coal advance mining royalties	3,673		4,056
Total property, plant and equipment	910,468		876,690
Less: Accumulated depreciation, depletion and amortization	483,410		442,178
Total Net Property, Plant and Equipment	$	427,058	$	434,512

As of December 31, 2017 and 2016, property, plant and equipment includes gross assets under capital lease of $625 and $631, respectively. Accumulated amortization for capital leases was $473 and $398 at December 31, 2017 and 2016, respectively. Amortization expense for assets under capital leases approximated $95, $78, and $53 for the years ended December 31, 2017, 2016, and 2015, respectively, and is included in Depreciation, Depletion and Amortization in the accompanying Consolidated Statements of Operations.

NOTE 8—OTHER ACCRUED LIABILITIES:



	December 31, 2017		December 31, 2016
Subsidence liability	$	22,430	$	26,887
Lease buyout	5,658		—
Accrued payroll and benefits	3,219		4,052
Equipment lease rental	2,906		2,442
Accrued other taxes	1,399		2,504
Goods received, not invoiced	1,057		952
Litigation	670		2,507
Other	4,166		2,731
Current portion of long-term liabilities:
Workers' compensation	1,381		1,380
Asset retirement obligations	881		591
Pneumoconiosis benefits	195		56
Long-term disability	140		128
Capital leases	77		88
Total Other Accrued Liabilities	$	44,179	$	44,318

NOTE 9—LONG-TERM DEBT:



	December 31, 2017		December 31, 2016
Affiliated Company Credit Agreement (4.25% interest rate at December 31, 2017)	$	196,583	$	—

Revolver, carrying amount	$	—	$	201,000
Less: Debt issuance and financing fees	—		3,157
Revolver, net	$	—	$	197,843

Total Long-Term Debt	$	196,583	$	197,843

Affiliated Company Credit Agreement

On November 28, 2017, the Credit Parties entered into the Affiliated Company Credit Agreement by and among the Credit Parties, CONSOL Energy, as lender and administrative agent, and PNC. The Affiliated Company Credit Agreement provides for a revolving credit facility in an aggregate principal amount of up to $275,000 to be provided by CONSOL Energy, as lender. In connection with the completion of the separation and the Partnership’s entry into the Affiliated Company Credit Agreement, the Partnership made an initial draw of $200,583, the net proceeds of which were used to repay the PNC Revolving Credit Facility, to provide working capital for the Partnership following the separation and for other general corporate purposes. Additional drawings under the Affiliated Company Credit Agreement are available for general partnership purposes. The Affiliated Company Credit Agreement matures on February 27, 2023. The collateral obligations under the Affiliated Company Credit Agreement generally mirror the PNC Revolving Credit Facility, including the list of entities that will act as guarantors thereunder. The obligations under the Affiliated Company Credit Agreement are guaranteed by the Partnership’s subsidiaries and secured by substantially all of the assets of the Partnership and its subsidiaries pursuant to the security agreement and various mortgages.

As of December 31, 2017, the Partnership had $196,583 of borrowings outstanding under the Affiliated Company Credit Agreement, leaving $78,417 of unused capacity. Interest on outstanding borrowings under the Affiliated Company Credit Agreement at December 31, 2017 was accrued at a rate of 4.25%.

The Affiliated Company Credit Agreement contains certain covenants and conditions that, among other things, limit the Partnership’s ability to: (i) incur or guarantee additional debt; (ii) make cash distributions (subject to certain limited exceptions); 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; (iii) incur certain liens or permit them to exist; (iv) 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; (v) enter into certain types of transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer, sell or otherwise dispose of assets. The Partnership is also subject to covenants that require the Partnership to maintain certain financial ratios. For example, the Partnership is obligated to maintain at the end of each fiscal quarter (a) maximum first lien gross leverage ratio of 2.75 to 1.00 and (b) a maximum total net leverage ratio of 3.25 to 1.00, each of which will be calculated on a consolidated basis for the Partnership and its restricted subsidiaries at the end of each fiscal quarter. At December 31, 2017, first lien gross leverage ratio was 1.95 to 1.00 and the total net leverage ratio was 1.94 to 1.00.

PNC Revolving Credit Facility

Until November 28, 2017, obligations under our $400,000 senior secured revolving credit facility with certain lenders and PNC, as administrative agent (the “PNC Revolving Credit Facility”), were guaranteed by our subsidiaries and were secured by substantially all of our and our subsidiaries’ assets pursuant to a security agreement and various mortgages. CNX was not a guarantor of our obligations under the revolving credit facility. On November 28, 2017, in connection with the separation, the Partnership paid all fees and other amounts outstanding under the PNC Revolving Credit Facility and terminated the PNC Revolving Credit Facility and the related loan documents.

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


•	The highest of (i) PNC’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% depending on the total leverage ratio; or


•	the LIBOR rate plus a margin ranging from 2.50% to 3.50% depending on the total leverage ratio.

At December 31, 2016, the revolving credit facility had $201,000 of borrowings outstanding, leaving $199,000 unused capacity. Interest on outstanding borrowings under the revolving credit facility as of December 31, 2016 was accrued at 3.99% based on a LIBOR rate of 0.74%, plus a margin of 3.25%.

The PNC Revolving Credit Facility was originally scheduled to mature on July 7, 2020 and required compliance with conditions precedent that must be satisfied prior to any borrowing as well as ongoing compliance with certain affirmative and negative covenants. The PNC Revolving Credit Facility required that the Partnership maintain a minimum interest coverage ratio of at least 3.00 to 1.00, which was calculated as the ratio of trailing 12 months Adjusted EBITDA, as defined in the credit agreement, to cash interest expense of the Partnership, measured quarterly. The Partnership was also required to maintain a maximum total leverage ratio not greater than 3.50 to 1.00, (or 4.00 to 1.00 for two fiscal quarters after consummation of a material acquisition) which was calculated as the ratio of total consolidated indebtedness to trailing 12 months Adjusted EBITDA, as defined in the credit agreement, measured quarterly.

NOTE 10—LEASES:

We use various leased facilities and equipment in our 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, 2017 are as follows:



	Capital Leases		Operating Leases
2018	$	81	$	17,948
2019	57		7,556
2020	21		5,271
2021	—		5,069
2022	—		2,614
Thereafter	—		2,559
Total minimum lease payments	$	159	$	41,017
Less amount representing interest	9
Present value of minimum lease payments	150
Less amount due in one year	77
Total Long-Term Capital Lease Obligations	$	73

Rental expense related to operating leases approximated $16,766, $14,578 and $13,490 during the years ended December 31, 2017, 2016 and 2015, respectively.

NOTE 11—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, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Affiliated Company Credit Agreement - Related Party	$	196,583	$	196,583	$	—	$	—
Revolver	$	—	$	—	$	201,000	$	201,000

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 12—ASSET RETIREMENT OBLIGATIONS:



	December 31, 2017			December 31, 2016
Balance at beginning of period	$	9,937		$	10,412
Accretion expense	774			727
Payments	(209		)	(149		)
Revisions in estimated cash flows	(6		)	(1,053		)
Balance at end of period	$	10,496		$	9,937

NOTE 13— 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 CPCC (the “OPEB Plans”). In conjunction with the IPO, on July 7, 2015 the OPEB liability and related accumulated other comprehensive income was retained by CNX, and the Partnership had no OPEB obligation as of such date. As of December 31, 2015, there was no benefit obligation or related accumulated other comprehensive income included in the Partnership’s financial statements. For the years ended December 31, 2017 and December 31, 2016, there were no amounts included in the Partnership’s financial statements.

The components of net periodic benefit costs are as follows:



	Other Postretirement Benefits
	For the Year Ended December 31, 2015
Interest cost	$	58
Amortization of prior service credits	(8,703		)
Recognized net actuarial loss	1,304
Net periodic benefit cost	$	(7,341	)

NOTE 14—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. 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,
	2017			2016			2017			2016
Change in benefit obligation:
Benefit obligation at beginning of period	$	2,113		$	1,977		$	4,385		$	4,291
State administrative fees and insurance bond premiums	—			—			243			207
Service cost	1,131			803			1,225			1,299
Interest cost	72			72			130			132
Actuarial loss (gain)	780			(686		)	196			9
Benefits and fees paid	(68		)	(53		)	(1,394		)	(1,553		)
Benefit obligation at end of period	$	4,028		$	2,113		$	4,785		$	4,385

Current assets	$	—		$	—		$	—		$	85
Current liabilities	(195		)	(56		)	(1,381		)	(1,380		)
Noncurrent liabilities	(3,833		)	(2,057		)	(3,404		)	(3,090		)
Net obligation recognized	$	(4,028	)	$	(2,113	)	$	(4,785	)	$	(4,385	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain	$	7,187		$	8,102		$	3,165		$	3,394
Net amount recognized	$	7,187		$	8,102		$	3,165		$	3,394

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,
	2017			2016			2015			2017			2016			2015
Service cost	$	1,131		$	803		$	255		$	1,225		$	1,299		$	1,656
Interest cost	72			72			65			130			132			146
Recognized net actuarial gain	(135		)	(83		)	(71		)	(33		)	(21		)	(1		)
State administrative fees and insurance bond premiums	—			—			—			243			207			425
Net periodic benefit cost	$	1,068		$	792		$	249		$	1,565		$	1,617		$	2,226

Amounts that are currently included in accumulated other comprehensive income are $21 and $5 for CWP benefits and workers’ compensation benefits, respectively, that are expected to be recognized in 2018 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,
	2017		2016		2015		2017		2016		2015
Benefit obligations	3.75	%	4.40	%	4.60	%	3.57	%	4.05	%	4.26	%
Net periodic cost (benefit)	4.40	%	4.60	%	4.21	%	4.05	%	4.26	%	3.84	%

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	$	(54	)	$	57
Workers’ compensation costs (decrease) increase	$	(18	)	$	19

Cash Flows:

The Partnership does not intend to make contributions to the CWP or Workers’ Compensation plans in 2018. 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
2018	$	195	$	1,437	$	1,381	$	56
2019	156		1,525		1,467		58
2020	169		1,601		1,542		59
2021	193		1,619		1,559		60
2022	232		1,720		1,658		62
Year 2023-2027	2,061		5,175		4,841		334

NOTE 15—OTHER BENEFIT PLANS:

Pension:

The Partnership is contractually obligated to fund 25% of CPCC’s portion of employees, which provide mining services to the Partnership, that participate in the CONSOL Energy Inc. Employee Retirement Plan (the “Plan”). In connection with the separation, the sponsorship of the CONSOL Energy Inc. Employee Retirement Plan (the “Pension Plan”) was transferred to CONSOL Energy. The Pension Plan is a non-contributory defined benefit retirement plan covering substantially all full time non-represented employees. Effective December 31, 2015, the Plan was frozen for all remaining participants in the Plan. The benefits for the Plan are based primarily on years of service and employees’ pay. The costs of these benefits during the years ended December 31, 2017, 2016 and 2015 were $884, $884 and $884, 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 25% of CPCC’s portion of CNX’s investment plan through August 31, 2017 and 25% of CPCC’s portion of the CPCC’s investment plan (the “CPCC 401k plan”) from September 1, 2017 through December 31, 2017. Eligible employees of CPCC began participation in the CPCC 401k plan on September 1, 2017, which was the inception date of the CPCC 401k Plan. Both the CNX and the CPCC 401k plans are available to most employees and include company matching of 6% of eligible compensation contributed by eligible employees of CPCC. Total payments and costs were $2,389, $2,014 and $3,195 for the years ended December 31, 2017, 2016 and 2015, 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, CNX 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 6% beginning January 1, 2016 and

1% to 4% for 2015 of eligible compensation for eligible employees (as defined by the Plan). For the year ended December 31, 2016, $2,271 was accrued as a discretionary contribution under this plan and was paid into employees accounts in the first quarter of 2017. There were no such discretionary contributions made for the years ended December 31, 2017 and 2015, respectively. These costs are reflected in Operating and Other Costs in the Consolidated Statements of Operations and recorded in Accounts Payable on the Consolidated Balance Sheet.

Long-Term Disability:

The Partnership is contractually obligated for its portion of 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, 2017			December 31, 2016			December 31, 2015
Benefit costs	$	41		$	120		$	138
Discount rate assumption used to determine net periodic benefit costs	3.43		%	3.71		%	3.18		%

Long-Term Disability related liabilities are included in Other Liabilities-Other and Other Accrued Liabilities on the Consolidated Balance Sheets and amounted to $494 and $330 at December 31, 2017 and 2016, respectively.

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION:

As of December 31, 2017, 2016 and 2015, the Partnership purchased goods and services related to capital projects in the amount of $878, $759 and $1,282, respectively, that are included in accounts payable.

For the years ended December 31, 2017, 2016 and 2015, the Partnership paid interest expense, net of capitalized interest, of $7,864, $7,734 and $8,520, 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 CNX and considered a deemed contribution in the amount of $229,495.

•CNX contributed stream credit assets to the Partnership in the amount of $8,131.

•OPEB liabilities were retained by CNX and treated as a deemed contribution in the amount of $3,134.


•	As of December 31, 2015 and 2014, there were capital equipment contributions of $21,945 and $5,324 between the Partnership and CNX that are included in equity.

NOTE 17—CONCENTRATION OF CREDIT RISK:

The Partnership primarily markets thermal coal principally to electric utilities in the eastern United States. Substantially all revenues were generated from sales based in the United States for the years ended December 31, 2017, 2016 and 2015. Less than 1% of the revenues were generated from sales based in Canada for the years ended December 31, 2016 and 2015. We have contractual relationships with certain coal United States-based exporters who distribute coal to international markets. For the years ended December 31, 2017, 2016 and 2015 approximately 31%, 16% and 19% of our coal revenues were derived from these United States-based exporters, in which our coal was intended to be shipped to Asia, Europe, South America, and Africa.

For the year ended December 31, 2017, coal sales to the following customers individually exceeded 10% of our revenues: Duke Energy and XCoal Energy & Resources.

For the year ended December 31, 2016, coal sales to the following customers individually exceeded 10% of our revenues: Duke Energy and GenOn Energy Management.

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.

NOTE 18—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 its 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. 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.

At December 31, 2017, the Partnership was 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 $74,196. The instruments are comprised of $301 of letters of credit expiring in the next three years, $64,319 of environmental surety bonds expiring within the next three years, and $9,576 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 19—RECEIVABLES FINANCING AGREEMENT

On November 30, 2017, (i) CONSOL Marine Terminals LLC, formerly known as CNX Marine Terminals LLC, as an originator of receivables, (ii) CPCC, as an originator of receivables and as initial servicer of the receivables for itself and the other Originators, each a wholly owned subsidiary of CONSOL Energy, and (iii) the SPV, as buyer, entered into the Purchase and Sale Agreement. Concurrently, (i) CONSOL Thermal Holdings, as sub-originator, and (ii) CPCC, as buyer and as initial servicer of the receivables for itself and CONSOL Thermal Holdings, entered into the Sub-Originator PSA. In addition, on that date, the SPV entered into the Receivables Financing Agreement by and among (i) the SPV, as borrower, (ii) CPCC, as initial servicer, (iii) PNC, as administrative agent, LC Bank and lender, and (iv) the additional persons from time to time party thereto as lenders. Together, the Purchase and Sale Agreement, the Sub-Originator PSA and the Receivables Financing Agreement establish the primary terms and conditions of the Securitization.

Pursuant to the Securitization, (i) CONSOL Thermal Holdings will sell current and future trade receivables to CPCC and (ii) the Originators will sell and/or contribute current and future trade receivables (including receivables sold to CPCC by CONSOL Thermal Holdings) to the SPV and the SPV will, in turn, pledge its interests in the receivables to PNC, which will either make loans or issue letters of credit on behalf of the SPV. The maximum amount of advances and letters of credit outstanding under the Securitization may not exceed $100,000. Loans under the Securitization will accrue interest at a reserve-adjusted LMIR rate equal to the one-month Eurodollar rate. Loans and letters of credit under the Securitization also will accrue a program fee and participation fee, respectively, equal to 4.00% per annum. In addition, the SPV paid certain structuring fees to PNC Capital Markets LLC and will pay other customary fees to the lenders, including a fee on unused commitments.

As of December 31, 2017, the Partnership, through CONSOL Thermal Holdings, sold $31,447 of trade receivables to CPCC. The Partnership has agreed to pay CPCC a fee based upon market rates for similar services to continue servicing the sold receivables. Costs associated with the receivables facility totaled $77 for the year ended December 31, 2017. These costs have been recorded as financing fees which are included in Operating and Other Costs in the Consolidated Statements of Operations. The Partnership has not derecognized the receivables due to its continued involvement in the collections efforts.

NOTE 20—RELATED PARTY:

CONSOL Energy

The Consolidated Statements of Operations include expense allocations for certain corporate functions historically performed by CONSOL Energy or CNX, 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 receivables/payables 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 CNX. In connection with PA Mining Acquisition described in Note 2, on September 30, 2016, the then General Partner and the Partnership entered into the First Amended and Restated Omnibus Agreement (the “Amended Omnibus Agreement”) with CNX and certain of its subsidiaries. Under the Amended Omnibus Agreement, CNX would indemnify the Partnership for certain liabilities, including those relating to:


•	all tax liabilities attributable to the assets contributed to the Partnership in connection with the PA Mining Acquisition (the “First Drop Down Assets”) arising prior to the closing of the PA Mining Acquisition or otherwise related to the Contributing Parties’ contribution of the First Drop Down Assets to the Partnership in connection with the PA Mining Acquisition; and

•

certain operational and title matters related to the First Drop Down Assets, including the failure to have (i) the ability to operate under any governmental license, permit or approval or (ii) such valid title to the First Drop Down Assets, in each case, that is necessary for the Partnership to own or operate the First Drop Down Assets in substantially the same manner as owned or operated by the Contributing Parties prior to the Acquisition.

The Partnership would indemnify CNX for certain liabilities relating to the First Drop Down Assets, including those relating to:


•	the use, ownership or operation of the First Drop Down Assets; and


•	the Partnership’s operation of the First Drop Down Assets under permits and/or bonds, letters of credit, guarantees, deposits and other pre-payments held by CNX.

The Amended Omnibus Agreement amended the Partnership’s obligations to CNX with respect to the payment of an annual administrative support fee and reimbursement for the provision of certain management and operating services provided by CNX, in each case to reflect structural changes in how those services are provided to the Partnership by CNX.

On November 28, 2017, in connection with the separation, CONSOL Coal Resources GP LLC, the Partnership, CNX, CONSOL Energy and certain of its subsidiaries entered into the First Amendment (the “First Amendment to Omnibus Agreement”) to the First Amended and Restated Omnibus Agreement, dated September 30, 2016, by and among CNX, the General Partner, and the Partnership to, among other things:


•	add CONSOL Energy as a party to the omnibus agreement;


•	eliminate the right-of-first offer to the Partnership for the 75% of the Pennsylvania Mining Complex not owned by the Partnership;


•	effect an assignment of all of CNX’s rights and obligations under the omnibus agreement to CONSOL Energy and remove CNX as a party to and, except with respect to CNX’s obligations under Article II of the omnibus agreement,

eliminate all of CNX’s obligations under, the omnibus agreement, as amended by the First Amendment to Omnibus Agreement; and


•	make certain adjustments to the indemnification obligations of the parties.

Charges for services from CONSOL Energy include the following:



	For the Years Ended December 31,
	2017		2016		2015
Operating and Other Costs	$	3,503	$	4,251	$	6,793
Selling, General and Administrative Expenses	3,109		3,826		8,926
Total Services from CONSOL Energy	$	6,612	$	8,077	$	15,719

Additionally, the Consolidated Statements of Operations includes interest expense of $746 resulting from the CONSOL Energy Affiliated Company Credit Agreement. Interest is calculated based upon a fixed rate, determined quarterly, depending on the total net leverage ratio. For the year ended December 31, 2017, the weighted average interest rate was 4.25%. See Note 9 - Long-Term Debt for more information.

At December 31, 2017 and December 31, 2016, the Partnership had a net payable to CONSOL Energy in the amount of $3,071 and $1,666, respectively. This payable includes reimbursements for business expenses, executive fees, stock-based compensation and other items under the omnibus agreement.

CFI Loan

CPCC had several related party long-term notes with CONSOL Financial Inc. (“CFI”), a wholly owned subsidiary of CONSOL Energy, pursuant to which CPCC was the obligor. The loan represented multiple 10-year term notes between CPCC and CFI at the applicable federal funds rates in effect upon execution, which were due at various future dates throughout the year. In conjunction with the IPO, these notes were excluded from the Partnership’s liabilities. Payments for these notes were $10,951 for the year ended December 31, 2015. Proceeds from additional notes were $16,991 for the year ended December 31, 2015. Interest Expense related to these notes was $6,050 and for the year ended December 31, 2015. These costs are included in Interest Expense in the accompanying Consolidated Statements of Operations.

NOTE 21—LONG-TERM INCENTIVE PLAN:

Under the CONSOL 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.

In March 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update on stock compensation that was intended to simplify and improve the accounting and statement of cash flow presentation for income taxes at settlement, forfeitures, and net settlements for withholding tax. The guidance is effective for public entities for fiscal years beginning after December 31, 2016. In accordance with this Update, the value of the shares withheld for employee tax withholding purposes of $1,985 for the year ended December 31, 2017 was reclassified between Net Cash Provided by Operating Activities and Net Cash Used in Financing Activities of the Consolidated Statement of Cash Flows. As permitted by this Update, the Partnership has elected to account for forfeitures of stock-based compensation as they occur. The cumulative effect of the policy election to recognize forfeitures as they occur was nominal.

The general partner has granted equity-based phantom units that vest over a period of a director’s continued service with the Partnership. 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 vesting date. The awards may accelerate upon a change in control of the Partnership. Compensation expense is recognized on a straight-line basis over the requisite service period, which is generally the vesting term. The Partnership modified certain employees’ phantom awards to eliminate the service requirement, resulting in $1,686 of incremental compensation cost for the year ended December 31, 2017. The Partnership recognized $5,873, $1,185, and $40 of compensation expense for the years ended December 31, 2017, 2016, and 2015 respectively, which is included in Selling, General and Administrative Expense in the Consolidated Statements of Operations. As of December 31, 2017, there is $3,123 of unearned compensation that will vest over a weighted average period of 1.82 years. The total fair value of restricted stock units vested during the years ended December 31, 2017 and 2016 was $4,098 and $100, respectively. There were no units vested during the year ended December 31, 2015. The following represents the nonvested phantom units and their corresponding weighted average grant date fair value:



	Number of Units		Weighted Average Grant Date Fair Value per Unit
Nonvested at December 31, 2016	381,934		$	8.80
Granted	383,478		$	18.38
Vested	(340,646	)	$	12.03
Forfeited	(23,357	)	$	14.83
Nonvested at December 31, 2017	401,409		$	14.87

NOTE 22—FINANCIAL INFORMATION FOR SUBSIDIARY GUARANTORS AND FINANCE SUBSIDIARY OF POSSIBLE FUTURE PUBLIC DEBT:

The Partnership filed a Registration Statement on Form S-3 (333-215962) on March 10, 2017, which was declared effective by the SEC on March 14, 2017, with the SEC to register the offer and sale of various securities including debt securities. The registration statement registers guarantees of debt securities by CONSOL Operating and CONSOL Thermal Holdings (“Subsidiary Guarantors”). The Subsidiary Guarantors are 100% owned by the Partnership and any guarantees by the Subsidiary Guarantors will be full and unconditional and joint and several. In addition, the registration statement also includes CONSOL Coal Finance, which was formed for the sole purpose of co-issuing future debt securities with the Partnership. CONSOL Coal Finance is wholly owned by the Partnership, has no assets or any liabilities and its activities will be limited to co-issuing debt securities and engaging in other activities incidental thereto. The Partnership does not have any other subsidiaries other than the Subsidiary Guarantors and CONSOL Coal Finance. In addition, the Partnership has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Partnership by dividend or loan other than under the Credit Agreement described in these notes. In the event that more than one of the Subsidiary Guarantors guarantee public debt securities of the Partnership in the future, those guarantees will be full and unconditional and will constitute the joint and several obligations of the Subsidiary Guarantors. None of the assets of the Partnership, the Subsidiary Guarantors or CONSOL Coal Finance represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.

NOTE 23—SUBSEQUENT EVENTS:

On January 25, 2018, the Board of Directors of our general partner declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2017 of $0.5125 per common and subordinated unit. The cash distribution will be paid on February 15, 2018 to the unitholders of record at the close of business on February 8, 2018.

SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED):



	Three Months Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017
Coal Revenue	$	79,112	$	75,927	$	69,811	$	72,063
Freight Revenue	3,070		4,441		5,451		5,461
Other Income	1,098		2,104		3,002		1,244
Total Revenue	83,280		82,472		78,264		78,768
Operating and Other Costs	49,883		50,232		52,160		42,711
Depreciation, Depletion and Amortization	10,521		10,277		10,352		10,287
Freight Expense	3,070		4,441		5,451		5,461
Selling, General and Administrative Expenses	3,283		3,652		4,283		4,479
Loss on Extinguishment of Debt	—		—		—		2,468
Interest Expense	2,457		2,396		2,404		2,052
Total Expense	69,214		70,998		74,650		67,458
Net Income	$	14,066	$	11,474	$	3,614	$	11,310
Net Income per Limited Partner Unit
Basic	$	0.51	$	0.40	$	0.07	$	0.42
Diluted	$	0.50	$	0.40	$	0.07	$	0.42



	Three Months Ended
	March 31, 2016			June 30, 2016		September 30, 2016		December 31, 2016
Coal Revenue	$	56,541		$	62,640	$	66,922	$	80,292
Freight Revenue	3,269			2,797		2,407		3,130
Other Income	(11		)	1,780		485		865
Total Revenue	59,799			67,217		69,814		84,287
Operating and Other Costs	38,491			46,044		45,531		52,935
Depreciation, Depletion and Amortization	10,317			10,423		10,592		10,662
Freight Expense	3,269			2,797		2,407		3,130
Selling, General and Administrative Expenses	1,928			1,970		2,660		3,391
Interest Expense	1,978			2,076		2,223		2,442
Total Expense	55,983			63,310		63,413		72,560
Net Income	$	3,816		$	3,907	$	6,401	$	11,727
Net Income per Limited Partner Unit
Basic	$	0.11		$	0.11	$	0.21	$	0.41
Diluted	$	0.10		$	0.11	$	0.21	$	0.41

SUPPLEMENTAL COAL DATA (UNAUDITED):



	Thousands of Tons
	For the Year Ended December 31,
	2017		2016		2015
Proven and probable reserves at beginning of period	191,678		197,844		196,408
Purchased reserves	—		—		5,850
Transferred reserves	(1,212	)	—		—
Production	(6,527	)	(6,166	)	(5,698	)
Revisions and other changes	(72	)	—		1,284
Consolidated proven and probable reserves at end of period*	183,867		191,678		197,844

* 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, 2017, 183,867 tons of proven and probable reserves were assigned and/or accessible to our three active mines (Enlow Fork, Bailey and Harvey Mines). Of the 2017 total reserves, Enlow Fork Mine equates to 73,867 tons, Bailey Mine to 61,296 tons and Harvey Mine to 48,704 tons. On average, the reserves have a sulfur content equivalent of approximately 3.6 lbs SO₂/mmBtu, in which Enlow Fork Mine equates to 3.3 lbs SO₂/mmBtu, Bailey Mine to 4.0 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 the management of the Partnership’s general partner, including the Chief Executive Officer and Chief Financial Officer of the general partner, 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.

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, which is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Partnership’s internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and

presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2017. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (“COSO”) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2017.

This annual report on Form 10-K for the fiscal year ended December 31, 2017 does not include an attestation report of the Partnership’s independent accounting firm due to a transition period established by rules of the Securities and Exchange Commission for emerging growth companies.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, CONSOL 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 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 CONSOL Coal Resources GP LLC as of December 31, 2017. 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	61	Chief Executive Officer and Chairman of the Board
David M. Khani	54	Director and Chief Financial Officer
John Rothka	40	Chief Accounting Officer
Martha A. Wiegand	47	General Counsel and Secretary
Michael L. Greenwood	62	Director and Member of the Audit* and Conflicts Committee
Deborah J. Lackovic	45	Director
Kurt R. Salvatori	48	Director
Dan D. Sandman	69	Director and Member of Audit and Conflicts Committee
Jeffrey L. Wallace	61	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 President and Chief Operating Officer of CONSOL Energy. He has held the Chief Executive Officer position since July 11, 2017 and he assumed the responsibility of President on December 2, 2017. From December 10, 2010 to November 28, 2017, Mr. Brock served as the Chief Operating Officer - Coal of CNX. Prior to this appointment, he served as Senior Vice President-Northern Appalachia-West Virginia Operations of CNX from 2007 to 2010. From 2006 to 2007, Mr. Brock served as Vice President-Operations. Mr. Brock began his career with CNX 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 decades of service with CNX and later CONSOL Energy in positions of increasing responsibility in its coal operations provide the board of directors of our general partner with valuable experience and critical insight into our business and operations.

David M. Khani was appointed a director of our general partner effective March 16, 2015 and was appointed Chief Financial Officer of the general partner effective August 2, 2017. Since July 11, 2017, Mr. Khani has served as Executive Vice President and Chief Financial Officer of CONSOL Energy. Prior to that, Mr. Khani joined CNX on September 1, 2011 as its Vice President-Finance, and was promoted to Executive Vice President and Chief Financial Officer effective March 1, 2013, a position he held until August 2, 2017. Prior to joining CNX, 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. From May 30, 2014 until January 2018, Mr. Khani served as 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.

John Rothka was appointed Chief Accounting Officer of our general partner effective August 2, 2017. Prior to that, Mr. Rothka served as the Controller of our general partner from July 2015. Mr. Rothka was part of CNX’s Accounting Department from September 2005 to July 2015, where he served in positions of increasing responsibility, and was promoted to Senior Manager in February 2012 until July 2015. Prior to joining CNX, Mr. Rothka began his professional career at the accounting firm of Aronson LLC from September 1999 to November 2002 before joining Deloitte from November 2002 to September 2005, where he held several positions of increasing responsibilities in the audit and assurance groups.

Martha A. Wiegand was appointed General Counsel and Secretary of our general partner effective March 16, 2015. Ms. Wiegand also serves as General Counsel and Secretary of CONSOL Energy, a position that she has held since July 11, 2017 and where she is responsible for a variety of legal matters, including coal marketing and transportation, labor and employment, financing arrangements and certain corporate transactions. Prior to the separation, Ms. Wiegand was also Associate General Counsel of CNX, having joined CNX’s Legal Department in December 2008 as Senior Counsel and having been promoted to Associate General Counsel of CNX effective in 2012. Prior to joining CNX, 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.

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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.

Deborah J. Lackovic became a member of the board of directors on November 28, 2017. Ms. Lackovic currently serves as the Director of Benefits of CONSOL Energy. From January 2005 to November 28, 2017, Ms. Lackovic served in various supervisory roles of increasing responsibility within human resources at CNX (most recently as the General Manager of Compensation and Benefits, a position she held from December 2012 until being promoted to Director of Benefits in September 2017). She joined CNX’s Accounting Department in May 1996, where she served in positions of increasing responsibility and was promoted to Manager Financial Reporting in June 2002, a position she served in until December 2004. Prior to joining CNX, Ms. Lackovic worked at Deloitte from September 1994 to April 1996. We believe Ms. Lackovic’s extensive knowledge of our industry and her depth of experience managing human resources and benefit and retirement plans in the coal industry gained during her years of service with CNX and later CONSOL Energy provide the board of directors of our general partner with valuable experience.

Kurt R. Salvatori became a member of the board of directors on November 28, 2017. Mr. Salvatori currently serves as the Chief Administrative Officer of CONSOL Energy. Mr. Salvatori has served as Vice President of Administration of CONSOL Pennsylvania Coal Company since January 1, 2017. Previously, Mr. Salvatori served as Vice President of Shared Services for CNX from 2016 to January 2017, and prior to that as Vice President of Human Resources from September 2011 to June 2016. Mr. Salvatori joined CNX in April 1992 and held numerous positions at CNX and CNX Gas Corporation, including Director of Human Resources from April 2006 to September 2011, Manager of Human Resources from January 2005 to April 2006, and Supervisor of Retirement and Investment Plans from April 2002 to January 2005. We believe Mr. Salvatori brings extensive knowledge of our industry to the board of the general partner and his broad knowledge of various executive compensation, human resources, labor and employment and other administrative oversight issues specific to the coal industry gained during his years of service with CNX and later CONSOL Energy provide the board of directors of our general partner with a valuable perspective and experience.

Dan D. Sandman became a member of the board of directors on February 8, 2017. Mr. Sandman is an adjunct professor at The Ohio State University Moritz College of Law, where he has taught corporate governance law since 2007. Mr. Sandman also serves on the board of directors and audit committee of MPLX GP LLC, the general partner of MPLX LP, a publicly traded master limited partnership engaged in the gathering, processing and transportation of natural gas, liquids, oil and refined petroleum products. He has also served on the board of directors of Roppe Corporation, a privately held company, since 1987. Additionally, Mr. Sandman serves on the boards of directors of the Heinz History Center, the Carnegie Science Center, the Carnegie Hero Commission, the Pittsburgh Opera and Grove City College. From 2002 to 2007, Mr. Sandman served as vice chairman of the board of directors and chief legal & administrative officer of United States Steel, until his retirement. Prior to his career with United States Steel, Mr. Sandman held a number of legal positions, including general counsel, with Marathon Oil Company, and subsequently served as general counsel and secretary of USX Corporation, a holding company that owned Marathon Oil and United States Steel. Mr. Sandman graduated with a degree from The Ohio State University and a juris doctor degree from The Ohio State University College of Law. Mr. Sandman’s extensive strategic, corporate governance and legal experience working with publicly traded companies including energy companies and master limited partnerships, as well as his skills, knowledge and experience in the areas of transactional law, regulatory compliance, ethics and risk management matters, provide the board of directors with valuable experience.

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 was 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

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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 the CEO of the general partner is the chairman of the board of directors of the general partner.

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 the 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,

CONSOL Coal Resources LP

1000 CONSOL Energy Drive, Suite 100

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), Sandman 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.

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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, the board of directors of our general partner convenes 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 the conflicts committee, Messrs. Wallace (Chairman), Sandman 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. Accordingly, the entire board of directors of our general partner participates in the consideration of executive officer and director compensation, except that Mr. Brock abstains from consideration of his own compensation. None of the executive officers of our general partner has served as a member of the board of directors, or as a member of the compensation or similar committee, of any entity that has one or more executive officers who served on the board of directors of our general partner during 2017.

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.ccrlp.com. You may also obtain a copy by contacting Martha A. Wiegand, General Counsel and Secretary, CONSOL Coal Resources LP, 1000 CONSOL Energy Drive, Suite 100, 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 that no Forms 5 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 2017.

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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 these rules, we are permitted to provide reduced disclosure about executive compensation arrangements.

The Compensation Discussion and Analysis and Executive Compensation sections of CONSOL Energy’s Proxy 2018 Statement will include a full discussion of the compensation policies and programs in which our named executive officers participated in 2017. 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, Relationship to Our Sponsor and Employee Matters Agreement

The executive officers of our general partner are employed and compensated by our sponsor or its affiliates (other than our general partner).

For 2017, our executive officers were compensated through a combination of payments, awards and grants from our sponsor and for Mr. Brock, Ms. Ritter and Ms. Wiegand through equity awards granted under the CONSOL Coal Resources LP 2015 Long-Term Incentive Plan (the “Partnership’s LTIP”). Generally, all compensation is set and paid by our sponsor and its affiliates other than equity granted under the Partnership LTIP. The executive officers of our general partner also participate in employee benefit plans and arrangements sponsored by our sponsor and its affiliates, including plans that may be established in the future.

In 2017, CNX was our sponsor until the separation on November 28, 2017, and CONSOL Energy became our sponsor following the separation. All references in this section to “sponsor” mean CNX prior to November 28, 2017 and CONSOL Energy on or after November 28, 2017. As further discussed below, CNX and CONSOL Energy entered into an Employee Matters Agreement as part of the separation (the “EMA”) which provided the framework for how to address compensation matters in connection with the separation.

Reimbursement to our Sponsor for Compensation Paid

On July 6, 2015, we entered into an omnibus agreement with our sponsor under which we agreed to reimburse our sponsor 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. Prior to the separation and distribution of our Sponsor the executive officers of our general partner devote approximately 100% of their overall professional working time to the business and affairs of the Pennsylvania Mining Complex (on a 100% basis). As of November 28, 2017, our general partner and our Sponsor have the same executive officers. Their time will be split between our general partner and our Sponsor's business and affairs, included the business and affairs of the Pennsylvania Mining Complex. Net to our 25% undivided interest in the Pennsylvania Mining Complex, we reimburse our sponsor for approximately 25% of the total compensation related expenses (including salary, bonus, incentive compensation and other amounts) incurred by our sponsor and attributable to our executive officers’ compensation. The total reimbursable compensation related expenses attributable to each of Mr. Brock, Mr. Khani, Ms. Wiegand and Ms. Ritter for the year ended December 31, 2017 was approximately $238,214, $73,750, $80,058 and $585,301, respectively, and the total reimbursable compensation related expenses attributable to each of Mr. Brock, Ms. Ritter and Ms. Wiegand for the year ended December 31, 2016 was approximately $491,132, $188,401 and $96,558, respectively.

Summary Compensation Table

The following summarizes the total compensation earned by the named executive officers of our general partner during the years indicated, including all compensation related expenses disclosed above, which other than equity awards granted during 2016 under the Partnership’s LTIP, were paid by our sponsor:

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Name and Principal Position	Year		Salary⁽¹⁾		Bonus⁽²⁾		Stock Awards⁽³⁾		Option Awards		Non-Equity Incentive Compensation⁽⁴⁾		Change in Pension Value and Nonqualified Deferred Compensation Earnings⁽⁵⁾		All Other Compensation⁽⁶⁾		SEC Total
James A. Brock*		2017	$	419,855	$	—	$	2,138,000	$	—	$	540,042	$	417,165	$	891,572	$4,406,634
President and Chief Executive Officer		2016	$	409,654	$	—	$	2,368,779	$	—	$	533,000	$	301,970	$	45,606	$3,659,009
David M. Khani*		2017	$	530,068	$	150,000	$	3,197,692	$	—	$	612,915	$	99,402	$	29,200	$4,619,277
Chief Financial Officer		2016	$	517,188	$	—	$	3,837,558	$	1,855,103	$	725,000	$	87,749	$	51,297	$7,073,895
Martha A. Wiegand		2017	$	234,231	$	200,000	$	300,000	$	—	$	139,379	$	21,814	$	104,312	$999,736
General Counsel and Secretary
Lorraine L. Ritter		2017	$	241,351	$	—	$	291,000	$	—	$	—	$	25,180	$	953,221	$1,510,752
Former Chief Financial Officer(7)		2016	$	291,003	$	—	$	200,000	$	—	$	233,701	$	184,145	$	44,800	$953,649

* Messrs. Brock and Khani also serve as members of the board of directors of our general partner. They do not receive any additional compensation for this service.



(1)	The amounts in this column represent base salaries before compensation reduction under any CNX, CONSOL Energy or affiliated company qualified retirement and/or 401(k) savings plan in effect during 2017.
(2)	The values in this column represent discretionary cash awards paid by CONSOL Energy to Mr. Khani and Ms. Wiegand in recognition of their significant contributions to the completion of the separation.
(3)	The values set forth in this column represent (a) the aggregate grant date fair value of the service-based and performance-based restricted stock unit awards made by CNX in 2017 to Mr. Khani only prior to adjustment for the impact of the separation, (b) the phantom unit awards made by the Partnership in 2017 to Mr. Brock, Ms. Ritter and Ms. Wiegand, and (c) “one-time” spin-related service-based restricted stock awards made by CONSOL Energy to Mr. Brock, Mr. Khani and Ms. Wiegand in recognition of their significant contributions to the completion of the separation. All amounts included have been computed in accordance with FASB ASC Topic 718. The assumptions used in determining the grant date fair value of the stock awards are set forth in Note 21 to our consolidated financial statements, included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and Note 16 to the financial statements of CONSOL Energy included in its Annual Report on Form 10-K for the fiscal year ended December 31, 2017. For grants of restricted stock units, the fair value per share is equal to the closing price of CNX’s common stock on the NYSE on the date of grant for awards made by CNX, and equal to the closing price of CONSOL Energy’s common stock on the NYSE on the date of grant for awards made by CONSOL Energy. With respect to the 2017 grant by CNX of performance-based stock units (“PSUs”), the value is reported assuming the target level of performance is achieved. The value of the 2017 PSU award by CNX to Mr. Khani assuming the maximum level of performance is achieved would be $3,669,654. For phantom units granted by the Partnership, the grant date fair value is computed based upon the closing price of CONSOL Coal Resources LP units on the date of grant.
(4)	The 2017 amounts shown in this column represent cash payments made to the named executive officers under the CCR 2017 STIC.
(5)	Amounts in this column reflect the actuarial increase in the present value of each named executive officer’s benefit under the CONSOL Energy Employee Retirement Plan, the CONSOL Energy Retirement Restoration Plan, the CONSOL Energy Supplemental Retirement Plan and the CONSOL Energy New Restoration Plan between December 31, 2016 and December 31, 2017. These amounts were determined using the interest rate and mortality assumptions set forth in our consolidated financial statements, included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.
(6)	The amounts shown in this column for 2017 are derived as follows:



Category	Brock	Khani	Wiegand	Ritter
401(k) Plan Contributions (a)	$16,200	$16,200	$14,054	$11,646
Vehicle Allowance (b)	$13,000	$13,000	$4,500	$8,500
Value of accelerated equity (c)	$860,524	-	$85,758	-
Executive Health Physical (d)	$1,848	-	-	-
Separation Payment (e)	-	-	-	$933,075

(a) Annual employer matching contributions to the 401(k) plan.

(b) Vehicle allowance/Company vehicle.

(c) This column reflects the value of equity awards accelerated under the terms of CIC agreements, which treated the separation as a change in control.

(d) Executive health physical

(e) See footnote 7 below for an explanation of the payments made to Ms. Ritter in connection with her separation.

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(7)	On July 25, 2017, the board of directors of our general partner accepted the retirement of Lorraine Ritter, as the Chief Financial Officer and Chief Accounting Officer of our general partner, effective as of August 2, 2017. The board of directors of our general partner also approved a Separation of Employment and General Release Agreement with Ms. Ritter as of the same date (the “Separation Agreement”) pursuant to which Ms. Ritter agreed to waive all claims and other causes of action she has or may have against our general partner that arose at or prior to the retirement of her employment with our general partner. In consideration for the foregoing release, the Separation Agreement provided for, among other things, the following: (i) a cash payment in the amount of $933,075, (ii) continued vesting of all unvested equity grants made to Ms. Ritter under the Partnership’s LTIP (described in “Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure”) and the equity compensation plan established by CNX and (iii) payment by our general partner of all Ms. Ritter’s COBRA premiums for a period of 36 months following her retirement of employment with the general partner. On July 25, 2017, the board of directors of our general partner appointed David Khani as the Chief Financial Officer of CNX Coal Resources GP LLC, effective as of August 2, 2017. Prior to becoming the Chief Financial Officer of our general partner, Mr. Khani served as the Chief Financial Officer of CNX. Mr. Khani has also served as a director of our general partner since July 2015. With respect to Ms. Ritter’s unvested equity awards, the forfeiture provisions in the applicable award agreements related to termination of service were eliminated so that her equity will continue to vest following her separation.

Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure

General

As noted above, the executive officers of our general partner are employed and compensated by our sponsor or its affiliates (other than our general partner). Because the executive officers of our general partner are employed by our sponsor or its affiliates, compensation of the executive officers is set and paid by our sponsor and its affiliates (other than equity awards under the Partnership’s LTIP as described below). The executive officers of our general partner also participate in employee benefit plans and arrangements sponsored by our sponsor and its affiliates, including plans that may be established in the future. The board of directors of our general partner makes decisions regarding any awards granted to our executive officers under the Partnership’s LTIP.

In 2017, CNX was our sponsor until the separation on November 28, 2017, and CONSOL Energy became our sponsor following the separation. All references in this section to “sponsor” mean CNX prior to November 28, 2017 and CONSOL Energy on or after November 28, 2017. As specifically described below, the EMA provides a framework between CONSOL Energy and CNX for compensation related issues as a result of the separation.

Our sponsor provides compensation to the executive officers 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.

Equity compensation may include awards under our sponsor’s equity compensation plan or under the Partnership’s LTIP or both. Following the separation, CONSOL Energy and our general partner will continue to formulate and implement compensation programs for our executive officers to ensure that they are provided with a comprehensive and competitive compensation structure in light of the relationship between the Partnership and our new sponsor.

Elements of Compensation

The following sets forth a more detailed explanation of the elements of the compensation programs as they relate to Mr. Brock, Mr. Khani, Ms. Wiegand and Ms. Ritter (as applicable) in 2017 and 2016:

Base Salary. Base salary is set by our sponsor and 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, our sponsor considers factors including, but not limited to, the need to attract and retain talented leadership, external market data, the internal worth and value assigned to the executive’s role and responsibilities at our sponsor, and the named executive’s skills and performance.

Annual Cash Incentives. Our 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. In 2016, our named executive officers participated in our sponsor’s short-term equity incentive plan. In 2017, our sponsor designed a short-term incentive compensation plan to apply specifically to the executive officers of the general partner (which included at the time, Mr. Brock, Ms. Ritter and Ms. Wiegand). We refer to this program as the CONSOL Coal Resources LP Short Term Incentive Compensation program (the “Partnership’s STIC”). For 2017, Mr. Brock had a target bonus under the Partnership’s STIC of 65% of his annual base salary, with a potential payout up to 200% of target based on company performance metrics and Ms. Wiegand had a target bonus of 30% of her annual base salary,

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with a potential payout up to 200% of target also based on company performance metrics. Initially, the 2017 performance metrics under the Partnership’s STIC related to (1) “Coverage Ratio” meaning the partnership’s distributable cash flow over minimum common unit distributions, and (2) the percentage of the Pennsylvania Mining Complex “dropdowns,” as well as employee and contractor safety, and environmental compliance. As a result of the separation occurring in late 2017 and our executives’ focused efforts devoted to completing the separation, the opportunity to achieve any dropdowns was diminished. As a result, following the separation, CONSOL Energy’s Compensation Committee replaced the “dropdown” metric with the successful completion of the separation.

For 2017, Ms. Ritter initially had a target bonus under the Partnership’s STIC of 45% of her annual base salary, with a potential payout up to 200% of target based on company performance metrics mentioned above, but because she terminated employment prior to the end of the performance period, she was ineligible for any 2017 annual incentive award.

For 2017, Mr. Khani’s short term incentive compensation was initially established for 8 months under CNX’s annual incentive plan of senior management and for four months under the Partnership’s STIC because he began 2017 serving as the Chief Financial Officer of CNX and only became the Chief Financial Officer of our general partner on August 2, 2017. Under CNX’s 2017 annual incentive plan of senior management, Mr. Khani had a target bonus of 70% of his annual base salary, with a potential payout up to 200% of target. Following his transition as the Chief Financial Officer of our general partner, CONSOL Energy determined to measure performance based on the performance metrics under the CNX 2017 annual incentive plan of senior management for the first eight months of 2017 and based on the performance metrics outlined above for our other named executive officers for the last four months of 2017.

Long-Term Equity-Based Compensation Awards. In 2017, the Partnership issued phantom units under the Partnership’s LTIP to its executives and key employees, including Mr. Brock, Ms. Ritter and Ms. Wiegand, which vest one-third per year. For 2017, Mr. Khani was awarded CNX Restricted Stock Units (“RSUs”) that vest, one third per year and CNX Performance-Based restricted stock units (“PSUs”) that vest one-fifth per year based on the attainment of performance metrics related to relative Total Shareholder Return and Absolute Stock price because he was the Chief Financial Officer of CNX at the time of the award. Under the terms of the EMA, Mr. Khani’s RSUs and PSUs (along with all other executive equity awards other than Stock Options) were converted and adjusted into awards under the CONSOL Omnibus Performance Plan. The adjustments to Mr. Khani’s awards were completed in a manner to preserve the aggregate intrinsic value of the original CNX awards as measured immediately before and immediately after the separation. Such adjusted awards otherwise continue to be subject to the same terms and conditions that applied to the original CNX awards immediately prior to the separation.

Special Spin Awards (Cash Bonus and Equity)

On December 12, 2017, CONSOL Energy’s Compensation Committee determined to pay special one-time cash bonuses to Mr. Khani and Ms. Wiegand in recognition of their contributions in completing the separation. In addition, CONSOL Energy’s Compensation Committee made additional one-time equity awards to Mr. Brock, Mr. Khani and Ms. Wiegand of restricted stock units under CONSOL Energy’s Omnibus Performance Incentive Plan, which will vest annually in equal installments over a period of three years beginning on the first anniversary of the grant date.

Payout of Prior Long-Term CNX Equity Awards

2015-2017 PSUs Grants and Payout. In January 2015, Messrs. Brock and Khani were granted PSUs by CNX (which were converted into CONSOL Energy awards under the EMA as a result of the separation) that vest, if earned, ratably over a three-year period (January 1, 2015 through December 31, 2017) based on two metrics: return on capital employed (“ROCE”) and Relative TSR as compared to the S&P 500. As a result of the performance determination made by our sponsor’s compensation committee, our named executive officers earned the following PSUs for the 2015-2017 performance period:



Named Executive Officer	PSUs Granted 2015 (Target)	Shares of Common Stock Issued (Earned PSUs)
James A. Brock, President and Chief Executive Officer	10,315	10,315
David Khani, Chief Financial Officer	23,837	23,837

2016-2020 PSU Grants and Payout. In January 2016, Messrs. Brock and Khani were granted PSUs by CNX (which were converted into CONSOL Energy awards under the EMA as a result of the separation) that vest, if earned, ratably over a five-year period (January 1, 2016 through December 31, 2020) based on Absolute Stock Price and Relative TSR compared to the S&P 500.

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Named Executive Officer	2017 PSU Tranche (at target)	Target Payout (%)		Payout Amounts (# of shares)
James A. Brock, President and Chief Executive Officer	9,960	200	%	19,920
David Khani, Chief Financial Officer	19,920	200	%	39,840

Outstanding Equity Awards at December 31, 2017

The following sets forth all outstanding equity of our executive officers under the Partnership’s LTIP as of December 31, 2017:



	Stock Awards
Name	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($) (2)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Lorraine L. Ritter, Former Chief Financial Officer & Former Chief Accounting Officer	32,235	(1)	$504,478



(1	)	Phantom units granted on January 29, 2016 and January 31, 2017, which vest and become exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date. As described in footnote 7 to the Summary Compensation Summary Compensation Table, Ms. Ritter’s phantom units will continue to vest in accordance with the schedule under the applicable award agreements. Any forfeiture provisions were eliminated as part of her separation agreement. Also as noted in the Summary Compensation Table, vesting of all of Mr. Brock’s and Ms. Wiegand’s phantom units were accelerated in connection with the separation under their respective change in control agreements. As described below, all of Mr. Brock’s and Ms. Wiegand’s unvested equity in the Partnership vested on November 28, 2017, under the terms of their CIC Agreements.
(2	)	The market value for the phantom units was determined by multiplying the closing price for CONSOL Coal Resources common units on December 29, 2017 ($15.65) by the number of shares underlying the award.

Our executive officers have received and may continue to receive equity or equity-based awards in under our sponsor's equity compensation program. The following table provides additional information about our executive officers’ outstanding equity awards in CONSOL Energy as of December 31, 2017. Stock Options listed below reflect awards granted by CNX, which awards remained with CNX under the terms of the EMA. The EMA also required that any outstanding equity awards, including RSUs and PSUs originally granted by CNX, be converted, adjusted and issued under CONSOL Energy’s Omnibus Plan. All such awards listed below that were granted prior to the separation (whether retained by CNX or converted into CONSOL Energy common stock) reflect an adjusted number of shares subject to each such award in a manner to preserve the aggregate intrinsic value of the original CNX award as measured immediately before and immediately after the separation, subject to rounding. Such adjusted awards otherwise continue to have the same terms and conditions that applied to the original CNX awards immediately prior to the separation.

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	Option Awards						Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options Unexercisable		Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)			Market Value of Shares or Units of Stock That Have Not Vested ($) (9)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (10)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (11)
James A. Brock, Chief Executive Officer	3,593 7,331 4,752 7,310 14,345	(1) (2) (3) (4) (5)	-		68.0929 24.1551 43.7215 42.0852 31.2890	02/19/2018 02/17/2019 02/16/2020 02/23/2021 01/26/2022	25,150	(8)		$993,677	-	-
David Khani, Chief Financial Officer	8,647 88,395	(5) (6)	176,792	(6)	31.012 6.8743	01/26/2022 01/29/2026	56,055 14,296 23,837 39,840	(7) (8) (12) (13)		$2,214,733 $564,835 $941,799 $1,574,078	179,830	$	7,105,083
Martha A. Wiegand, General Counsel & Secretary	286 562 702 1,016	(2) (3) (4) (5)	-		24.1551 43.7215 42.0852 31.2890	02/16/2019 02/16/2020 02/23/2021 01/26/2022	6,706	(8	)	$264,954	-	-
Lorraine L. Ritter, Former Chief Financial Officer & Former Chief Accounting Officer	1,896 6,923 4,621 3,655 5,123	(1) (2) (3) (4) (5)	-		68.0929 24.1551 43.7215 42.0852 31.2890	02/19/2018 02/17/2019 02/16/2020 02/23/2021 01/26/2022	-			-	-	-



(1)	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.
(2)	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.
(3)	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.
(4)	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.
(5)	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.
(6)	Options granted 5/11/16 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on 1/29/17.
(7)	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.
(8)	RSU’s granted on 1/31/17 and/or 12/12/17 and vest in three equal installments (subject to rounding) beginning on the first anniversary of the grant date.
(9)	The market value for RSUs was determined by multiplying the closing market price for CONSOL Energy common stock on December 29, 2017 ($39.51) by the number of shares underlying the RSU awards.
(10)	This column shows the number of unvested PSU’s as of December 31, 2017. The performance period for the PSU’s granted in 2017 is January 2017 through December 2021, vesting one-fifth per year, and for the PSUs granted in 2016 is January 2016 through December 2020, vesting one-fifth per year and for the PSUs granted in 2015 is January 1, 2015 through December 31, 2017. The amounts presented for the 2016 PSU awards are based on achieving performance goals at a maximum level. The amounts presented for the 2017 PSU awards are based on achieving the target level. The 2016 and 2017 PSU Awards provide for a catch up payout at target for missed years if the Partnership achieves the target performance or greater at the end of a future period.
(11)	The market value for PSU’s was determined by multiplying the closing market price for CONSOL Energy common stock on December 29, 2017 ($39.51) by the number of shares underlying the PSU awards.
(12)	The performance period for the PSU Awards was January 1, 2015 through December 31, 2017. The amounts are based on actual results for the period.
(13)	The performance period for the 2017 tranche of the 2016 PSU Awards was January 1, 2017 through December 31, 2017. The amounts are based on actual results for the period.

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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 401(k) savings plan, as well as a supplemental defined benefit retirement restoration plan that provides benefits to executive officers and key employees, including Mr. Brock, Mr. Khani, Ms. Wiegand and Ms. Ritter, in excess of IRS imposed limits under the broad-based 401(k) savings plan. CONSOL Energy also provides limited executive perquisites, which are described in the footnotes to the Summary Compensation Table for 2017.

Employee Retirement Plan (the “Pension Plan”)

In connection with the separation, the sponsorship of the CONSOL Energy Inc. Employee Retirement Plan (the “Pension Plan”) was transferred to CONSOL Energy. CONSOL Energy’s Pension Plan is a non-contributory 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 as of December 31, 2015 to provide for a hard freeze of the Pension Plan for all remaining participants in the plan.

•

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. 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 limits imposed by the Code . 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

In connection with the separation, CONSOL Energy established the CONSOL Energy Supplemental Retirement Plan on November 28, 2017 with respect to the obligations assumed by CONSOL Energy related to the account balances and accrued benefits of current and former CNX coal business employees who participated in the CNX Resources Supplemental Retirement Plan (formerly known as the CONSOL Energy Supplemental Retirement Plan) prior to November 28, 2017. 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. The plan was frozen effective December 31, 2011 for current and future CONSOL employees except for certain “excepted employees”. The accrued benefits for all members in the CONSOL Energy Plan were frozen per the terms of the plan prior to the plan’s effective date of November 28, 2017.

The amount of each participant’s benefit under the plan as of age 65 (expressed as an annual amount) is equal to 50% of “final average compensation” multiplied by the “service fraction” as calculated on the earlier of the participant’s date of employment termination with CONSOL Energy or the date benefits were frozen per the terms of the plan. “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 up until the date benefits were frozen per the terms of the plan. 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

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(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 are paid in the form of a life annuity with a guaranteed term of 20 years (which is 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

In connection with the separation, CONSOL Energy established a New Restoration Plan on November 28, 2017 with respect to the obligations assumed by CONSOL Energy related to the account balances and accrued benefits of current and former CNX coal business employees who participated in the CNX Resources New Restoration Plan (formerly known as the CONSOL Energy New Restoration Plan) prior to November 28, 2017. The New Restoration Plan is 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.

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 $270,000 for 2017) 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.

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, Ms. Ritter and Ms. Wiegand 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 previously have entered into a change in control severance agreement with CONSOL Energy and our general partner, which were amended and restated on February 7, 2017. In addition, on February 7, 2017 Ms. Wiegand has entered into a change in control severance agreement with CONSOL Energy and our general partner. These agreements are referred to as the “CIC Agreements” and were in effect for the full 2017 fiscal year.

These CIC Agreements provide severance benefits to Mr. Brock, Ms. Ritter and Ms. Wiegand 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).

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


•	a lump sum cash payment equal to a multiple of base salary plus a multiple of incentive pay (the multiple, in each case, for Mr. Brock is 2.0 and for Ms. Ritter and Ms. Wiegand 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 and Ms. Wiegand 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 and Ms. Wiegand 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 and Ms. Wiegand 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, Ms. Ritter and Ms. Wiegand 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, Ms. Ritter and Ms. Wiegand 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 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 the CIC Agreements, a “change in control” generally means:

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(a) a transfer of ownership of assets or interests comprising more than seventy-five percent (75%) of the book value of the PA Mining Operations segment on CONSOL Energy’s books as of September 30, 2016 (other than to us or our subsidiaries or to other CONSOL Energy subsidiaries);

(b) CONSOL Energy fails to control, directly or indirectly, our general partner; or

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.

Under the terms of the CIC Agreements in effect during 2017 with Messrs. Brock, Ritter and Wiegand, all outstanding equity awards held by such executives vested effective as of the date of the separation, November 28, 2017, as these agreements treated the loss of control of the general partner as a change of control.

Subsequent approval of new agreements. Beginning in December of 2017 and continuing into 2018, CONSOL Energy conducted a competitive review of its compensation plans and programs including its CIC Agreements for all of its executives. As a result of such review, CONSOL entered into new Change in Control and Severance Agreements with Mr. Khani and Ms. Wiegand effective as of February 15, 2018, which are substantially similar to the above-described CIC Agreements. CONSOL Energy also entered into an individual Employment Agreement (providing for change in control and non-change of control severance entitlements for Mr. Brock) also effective February 15, 2018. These agreements supersede the prior CIC Agreements, and although they are similar in many respects differ in the following key ways:


•	Provide for additional non-CIC severance protection in the event of involuntary termination of employment absent “cause;”


•	Cash severance payment due in the event of a non-CIC involuntary termination is lump sum equal to multiple of base salary only (2x for Mr. Brock and 1x for Mr. Khani and Ms. Wiegand);


•	Cash severance payment due in the event of “involuntary termination” or “constructive termination” related to a CIC equal to multiple of base salary plus multiple of incentive pay (3x for Mr. Brock, 2.5x for Mr. Khani and 2x for Ms. Wiegand);

•

Mr. Brock’s employment agreement’s includes a specified 3-year term during which his base salary may only be increased; the agreement is renewable for successive 1-year terms unless notice of non-renewal is provided by either party within 60 days prior to the end of the calendar year; and typical other protections and obligations are recited in the agreement, including but not limited to restrictive covenants relating to non-competition, non-solicitation and confidentiality.


•	For Mr. Brock and Ms. Wiegand, the prior change of control agreements were initially entered into prior to the separation . In connection with the separation, these agreements were assigned to CONSOL Energy. The

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agreements included change of control provisions that treated the loss of control by CNX of the general Partner (by virtue of ownership of the voting securities of the general partner and the ability to elect or appoint a majority of the members of the board of directors of the general partner) as a change of control, thus making the separation a “change of control event.” However, in executing the new agreements, both Mr. Brock and Ms. Wiegand acknowledged that neither executive experienced an involuntary termination of employment that would entitle them to cash severance payments or benefits under such agreements, and further agreed that after February 15, 2018, each executive would only seek any right to severance payments or benefits under such prior agreements solely from the Partnership and/or CPCC or CONSOL Energy and not from CNX.

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. As of December 31, 2017 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 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 2017 fiscal year.



Name (1)	Fees Earned or Paid in Cash ($)	Stock Awards (1)	Option Awards	All Other Compensation	Total
Michael Greenwood	$105,000	$60,000	$0	$0	$165,000
Dan Sandman	$78,500	$60,000	$0	$0	$138,500
Jeff Wallace	$93,000	$60,000	$0	$0	$153,000

(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 CONSOL Coal Resources’ common units on the date of grant. The phantom units were granted on January 31, 2017 for Messrs. Greenwood and Wallace and February 8, 2017 for Mr. Sandman and vest in one lump sum on January 31, 2018, the first anniversary of the grant date. As of December 31, 2017, the number of phantom units held by our current non-employee directors was 3,167 for each of Messrs. Sandman, Greenwood and Wallace.

Our Long-Term Incentive Plan (Partnership LTIP)

Our general partner adopted the CONSOL 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. The board of directors of our general partner has been designated as the plan administrator. The following description reflects the terms that are included in the LTIP.

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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 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.

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Other Unit-Based Awards

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

Source of Common Units

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

Anti-Dilution Adjustments and Change in Control

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

Termination of Service

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

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 MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the beneficial ownership of common units and subordinated units of CONSOL Coal Resources LP that were outstanding at December 31, 2017 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 executive officers of our general partner as a group.

In addition, our general partner holds a 1.7% general partner interest .

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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 15,789,106 common units and 11,611,067 subordinated units outstanding at December 31, 2017.



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 and Subordinated Units Beneficially Owned
CONSOL Energy Inc. (2)	5,006,496	31.7	%	11,611,067	100.0	%	60.6	%
Greenlight Capital, Inc. (3)	5,488,438	34.8	%	—	—		20.0	%
Directors/Director Nominees/Named Executive Officers
Michael L. Greenwood	25,725	*		—	—		*
David M. Khani	13,000	*		—	—		*
John Rothka	2,320	*		—	—		*
James A. Brock	76,551	*		—	—		*
Dan D. Sandman	8,667	*		—	—		*
Jeffrey L. Wallace	15,725	*		—	—		*
Martha A. Wiegand	10,609	*		—	—		*
Kurt R. Salvatori	3,619	*		—	—		*
Deborah J. Lackovic	-	-		—	—		-
All Directors, Director Nominees and Executive Officers as a group (9 persons)	156,216	*		—	—		*



*		Less than 1%.
(1	)	Unless otherwise indicated, the address for all beneficial owners in this table is c/o CONSOL Coal Resources GP LLC, 1000 CONSOL Energy Drive, Suite 100, 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 CNX in connection with the completion of the IPO. In connection with the separation, on November 28, 2017, the common units and subordinated units held by CNX were transferred to CONSOL Energy.
(3	)	According to a Schedule 13D/A filed with the SEC on October 6, 2017 by Greenlight Capital, Inc. (“Greenlight”), DME Advisors GP, L.L.C. (“DME GP”), DME Advisors, L.P., DME Capital Management, LP and David Einhorn, (i) Greenlight has shared voting and dispositive power over 3,248,638 common units, (ii) DME GP has shared voting and dispositive power over 2,239,800 common units, (iii) DME Advisors, L.P. has shared voting and dispositive power over 719,300 common units, (iv) DME Capital Management, LP has shared voting and dispositive power over 1,520,500 common units and (v) David Einhorn has shared voting and dispositive power over 5,488,438 common units. The address for this reporting person is Greenlight Capital, Inc., 140 East 45th Street, Floor 24, New York, New York 10017.

The following table sets forth, as of December 31, 2017, 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 executive officers of our general partner as a group. The percentage of total shares is based on 27,973,281 shares outstanding as of December 31, 2017. Amounts shown below include options that are currently exercisable or that may become exercisable within 60 days of December 31, 2017 and the shares underlying deferred stock units and the shares underlying restricted stock units that will be settled within 60 days of December 31, 2017. 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.

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Name of Beneficial Owner	Total Common Stock Beneficially Owned	Percent of Total Outstanding
Directors/Director Nominees/Named Executive Officers
James A. Brock	32,763	*
Martha A. Wiegand	758	*
David M. Khani	59,536	*
Dan D. Sandman	-	*
Michael L. Greenwood	-	-
Jeffrey L. Wallace	-	-
John Rothka	23	*
Kurt R. Salvatori	3,484	*
Deborah J. Lackovic	703	*
All Directors, Director Nominees and Executive Officers as a group (9 persons)	97,267	*



*	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 the Partnership’s LTIP as of December 31, 2017.



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	401,081	(1)	$	19.03	1,531,047
Equity compensation plans not approved by security holders	—		—		—
Total	401,081		$	19.03	1,531,047

(1) Of this total, 401,081 are phantom units.

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

As of February 8, 2018, our sponsor, CONSOL Energy owns 5,006,496 common units and 11,611,067 subordinated units, representing a 60.4% limited partner interest, as well as all of our incentive distribution rights. In addition, our general partner owns a 1.7% general partner interest in us.

General

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, the board of directors of our general partner will resolve that conflict.

Although not required, we anticipate that our general partner will ask the Conflicts Committee to approve the fairness of significant transactions, such as the consideration of the acquisition of any additional interests in the Pennsylvania Mining Complex. See “ – Committees of the Board of Directors - Conflicts Committee” in Item 10.

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The board of directors of our general partner has not adopted a formal written related-person transaction approval policy. However, in the event of a potential related person transaction other than potential conflicts transactions of the type described in the paragraph above, we expect that the board of directors of our general partner would use the procedure described in “ – “Procedures for Review, Approval and Ratification of Related Person Transactions” below when reviewing, approving, or ratifying the related person transaction. For these purposes, a “related person” is a director, nominee for director, executive officer, or holder of more than 5% of our common units, or any immediate family member of a director, nominee for director or executive officer. This procedure applies to any financial transaction, arrangement or relationship or any series of similar financial transactions, arrangements or relationships in which we are a participant and in which a related person has a direct or indirect interest, other than the following:


•	payment of compensation by us to a related person for the related person’s service in the capacity or capacities that give rise to the person’s status as a related person;


•	transactions available to all employees or all unitholders on the same terms;


•	purchases from us in the ordinary course of business at the same price and on the same terms as offered to our other customers, regardless of whether the transactions are required to be reported in our filings with the SEC; and


•	transactions, which when aggregated with the amount of all other transactions between the related person and us, involve less than $120,000 in a fiscal year.

Partnership Agreement

We completed our IPO in July 2015. As part of the IPO, our general partner entered into an agreement of limited partnership with us, which outlines the various rights and obligations of our general partner with respect to the Partnership, its various classes of units, distributions and other cash payments with respect to our units and other related issues.

Concurrently with the completion of the transaction contemplated under that certain Contribution Agreement, dated September 30, 2016, among the Partnership, CONOL Thermal Holdings, CNX, CPCC and Conrhein (the “First Drop Down”), our general partner amended and restated our Partnership Agreement to, among other things, authorize and establish the terms of the Class A Preferred Units. Pursuant to the Partnership Agreement, as amended, the Class A Preferred Units ranked senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. The Class A Preferred Units had no stated maturity and were not subject to any sinking fund and were to remain outstanding indefinitely unless converted into common units at the election of either the holder of the Class A Preferred Units or us, in each case after certain requirements have been met. On October 2, 2017, all of the Class A Preferred Units were converted to common units on a one-for-one basis, in accordance with the Partnership Agreement.

On November 28, 2017, in connection with the separation, the Partnership entered into the Third Amended and Restated Agreement of Limited Partnership of the Partnership to change the name of the Partnership to “CONSOL Coal Resources LP” from “CNX Coal Resources LP” and to delete references to the Class A Preferred Units representing limited partner interests in the Partnership, all of which had been converted into common units.

Distributions and Other Cash Payments to General Partner and its Affiliates

Cash Distributions on Common Units, Subordinated Units and General Partner Interest

We generally make cash distributions of distributable cash to our unitholders pro rata of 98.3% to our limited partners (including to CONSOL Energy as the holder of 5,006,496 common units and 11,611,067 subordinated units), and 1.7% to our general partner. 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.

During 2017, we distributed approximately $30.0 million to CONSOL Energy with respect to common and subordinated units and approximately $1.0 million with respect to the general partner interest (including incentive distribution rights, all of which were held by our general partner prior to November 28, 2017).

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

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$1.0 million on the 1.7% general partner interest, and our sponsor would receive an annual distribution of approximately $34.0 million on its common units and subordinated units.

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.

Reimbursement of expenses 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. 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.

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.

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 IPO in July of 2015) of CPCC. Please read “ – Agreements With Affiliates” below.

The total amount of such reimbursed expenses was approximately $7.4 million for the year ended December 31, 2017.

Agreements with Affiliates

We entered into various agreements with our sponsor and its affiliates at the time of our July 2015 IPO. We agreed to modify certain of these agreements in connection with our First Drop Down and in connection with the separation. In addition, as part of the separation, CONSOL Energy agreed to replace CNX as our sponsor subject to certain modifications to the various agreements that we had with CNX prior to the separation.

While not the result of arm’s-length negotiations, we believe the terms of all of the agreements with CONSOL Energy and its affiliates are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

Affiliated Company Credit Agreement

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Agreement matures on February 27, 2023. The collateral obligations under the Affiliated Company Credit Agreement generally mirror the PNC Revolving Credit Facility, including the list of entities that will act as guarantors thereunder.

The obligations under Affiliated Company Credit Agreement are guaranteed by the Partnership’s subsidiaries and secured by substantially all of the assets of the Partnership and its subsidiaries pursuant to the security agreement and various mortgages.

The Affiliated Company Credit Agreement contains certain covenants and conditions that, among other things, limit the Partnership’s ability to incur or guarantee additional debt, make cash distributions (subject to certain limited exceptions), incur certain liens or permit them to exist, make particular investments and loans, enter into certain types of transactions with affiliates, merge or consolidate with another company, and transfer, sell or otherwise dispose of assets. The Partnership is also subject to covenants that require the Partnership to maintain certain financial ratios. For example, the Partnership is obligated to maintain at the end of each fiscal quarter (a) maximum first lien gross leverage ratio of 2.75 to 1.00 and (b) a maximum total net leverage ratio of 3.25 to 1.00, each of which will be calculated on a consolidated basis for the Partnership and its restricted subsidiaries at the end of each fiscal quarter.

Operating Agreement

In connection with the July 2015 IPO, CONSOL Thermal Holdings entered into an operating agreement for the Pennsylvania Mining Complex with CPCC and Conrhein. Under the operating agreement, CONSOL 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, CONSOL 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.

On September 30, 2016, in connection with the First Drop Down, CONSOL Thermal entered into a first amendment to the Operating Agreement to provide that CONSOL Thermal, as the operator under the operating agreement, will be responsible for managing and conducting the following additional operational services with respect to the Pennsylvania Mining Complex:


•	health, environmental, safety and security services, including Mine Safety and Health Administration reporting;


•	services related to the acquisition, divestiture, management and administration of the real property interests underlying the Pennsylvania Mining Complex;


•	acquiring, managing and administering all permits necessary for the operation of the Pennsylvania Mining Complex in material compliance with such permits;


•	services necessary to (i) market the production from the Pennsylvania Mining Complex and (ii) negotiate, manage and administer the contracts necessary for the operation of the Pennsylvania Mining Complex;


•	logistics relating to operation of the Pennsylvania Mining Complex; and


•	preparing, or causing to be prepared, such daily reports typically prepared by an operator of a mining complex similar to the Pennsylvania Mining Complex that are prepared in the ordinary course of business and monthly per ton reports and annual reserve reports.

On November 28, 2017, in connection with the separation, CPPCC, Conrhein, CONSOL Thermal Holdings and the

Partnership entered into the Second Amendment to the Pennsylvania Mine Complex Operating Agreement dated July 7, 2015,

as amended by the First Amendment thereto. The Second Amendment to the Pennsylvania Mine Complex Operating Agreement Amendment amended the agreement to permit the Partnership to enter into the Affiliated Company Credit Agreement and to make certain other required changes.

Pursuant to the operating agreement, CONSOL 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 CONSOL 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

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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. CONSOL 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 CONSOL Thermal Holdings’ gross negligence or willful misconduct will be borne by CONSOL Thermal Holdings, CPCC and Conrhein pro rata in relation to such person’s ownership percentage of the Pennsylvania Mining Complex. Under the operating agreement, CONSOL 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.

Under the operating agreement, CONSOL 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 $416.2 million for 2017.

Employee Services Agreement

Through our subsidiary CONSOL 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 $64.9 million to CPCC for such reimbursed expenses for the year ended December 31, 2017.

Contract Agency Agreement

Through our subsidiary CONSOL 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 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. On November 28, 2017, in

connection with the separation, CONSOL Thermal, CES and certain other parties entered into the First Amendment to Contract

Agency Agreement to amend the terms of the contract agency agreement to remove from the terms of the agreement certain

contracts and parties that pertain to operations of CNX related to natural gas sales.

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 CONSOL Thermal Holdings, we entered into a terminal throughput agreement with CONSOL Marine Terminals, LLC, 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

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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. On November 28, 2017, in connection with the separation, the Partnership and the other parties to the cooperation and safety agreement entered into an amendment to such agreement to make certain necessary changes to reflect the separation.

Water Supply and Services Agreement

We entered into a water supply and services agreement with CNX Water Assets LLC, a wholly owned subsidiary of CONSOL Energy (“CNX Water Assets”), 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. On November 28, 2017, in connection with the separation, CNX Water Assets and CONSOL

Thermal entered into an amendment to the water supply and services agreement to revise and remove certain services provided

under the agreement, revise the payment terms to require CNX Water Assets to deliver invoices no later than 30 days after the

end of each calendar month for the water supply fees incurred during the prior calendar month, to revise the arbitration provisions applicable to the agreement and to make certain other immaterial changes.

Omnibus Agreement

In connection with our July 2015 IPO, 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); and


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

On September 30, 2016, in connection with First Drop Down, we and our general partner entered into a First Amended and Restated Omnibus Agreement with CONSOL Energy, CPCC, Conrhein and certain other subsidiaries of CONSOL Energy. On

November 28, 2017, in connection with the separation, the general partner, the Partnership, CNX, CONSOL Energy and certain

of its subsidiaries entered into the First Amendment to the First Amended and Restated Omnibus Agreement to, among other

things:


•	add CONSOL Energy as a party to the existing omnibus agreement;


•	effect an assignment of all of CNX’s rights and obligations under the existing omnibus agreement to CONSOL Energy and remove CNX as a party to and, except with respect to CNX’s obligations under Article II of the agreement, eliminate all of CNX’s obligations under, the agreement, as amended; and

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•	make certain adjustments to the indemnification obligations of the parties.

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 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 services; 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. However, in connection with the First Drop Down, the First Amended Omnibus Agreement also amended our obligations to CONSOL Energy with respect to the payment of the annual administrative support fee and reimbursement for the provision of certain management and operating services provided by CONSOL, in each case to reflect structural changes in how those services are provided to us by CONSOL Energy.

We also pay CONSOL Energy an executive support fee 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.

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 in connection with our IPO in July 2015 and to the assets contributed to us in connection with the First Drop Down in September 2016;


•	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 any contributed assets in substantially the same manner as owned or operated by CONSOL Energy prior to the contribution;


•	except to the extent resulting from our breach of the operating standard in the operating agreement, CONSOL Energy’s ownership of its retained 75% 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:

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•	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 IPO completed in July of 2015 or the First Drop Down completed in September 2016. 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 in connection with the July 2015 IPO, with CONSOL Energy, CONSOL Operating and our general partner under which CONSOL Energy contributed to us all of the limited liability company interests in CONSOL Operating, which is the sole member of CONSOL Thermal Holdings. We also entered into the First Drop Down Contribution Agreement in September 2016. As a result of the contributions, CONSOL Thermal Holdings owns a 25% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania Mining Complex.

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 were not be required to file a shelf registration statement for 90 days after the closing of our IPO. As of December 31, 2017, 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 of Managing General Partner” 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.

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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, 2017. The following table presents fees billed for professional audit services rendered by E&Y in connection with its audits of the Partnership’s annual financial statements for the year ended December 31, 2017.

The fees billed to the Partnership by Ernst & Young LLP during 2017 were the following:



	2017 (E&Y Fees)		2016 (E&Y Fees)
Audit Fees	$	568,500	$	591,372
Audit-Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—
Total	$	568,500	$	591,372

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

Audit Fees

These fees for professional services were 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

These fees for assurance and related services are those reasonably related to the performance of the audit or review of Partnership’s financial statements.

Tax Fees

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

All Other Fees

These are 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

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• Broker-dealer, investment advisor 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 2017, 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(a)	Amended and Restated Certificate of Limited Partnership of CNX Coal Resources LP (Originally Formed as CONSOL Resource Partners LP), dated June 3, 2015	Filed as Exhibit 3.1(c) to the Partnership’s Amendment to Registration Statement on Form S-1/A (#333-203165) filed on June 10, 2015

3.1(b)	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of CONSOL Coal Resources LP, dated November 28, 2017	Filed Exhibit 3.1 to Form 8-K (#001-37456) on December 4, 2017)

3.2(a)	Second Amended and Restated Agreement of Limited Partnership of CNX Coal Resources LP, dated September 30, 2016	Filed as Exhibit 3.1 to Form 8-K (#001-37456) filed on October 4, 2016

3.2(b)	Third Amended and Restated Agreement of Limited Partnership of CONSOL Coal Resources LP, dated November 28, 2017	Filed Exhibit 3.2 to Form 8-K (#001-37456) on December 4, 2017

4.10	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 13, 2015

4.20	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 13, 2015

4.3	Common Unit Purchase Agreement, dated June 25, 2015, by and among CNX Coal Resources LP and each of the entities identified on Exhibit A thereto	Filed as Exhibit 10.12 to Amendment to Registration Statement on form S-1/A (#333-203165) filed on June 26, 2015

4.4	Amendment to the Common Unit Purchase Agreement, dated June 30, 2015, by and among CNX Coal Resources LP and each of the entities identified on Exhibit A thereto	Filed as Exhibit 10.2 to Form 8-K (#001-37456) filed on July 6, 2015

4.5	Registration Rights Agreement, dated September 30, 2016, by and among CNX Coal Resources LP, CONSOL Energy Inc. and such other parties that may, from time to time, become party thereto	Filed as Exhibit 4.1 to Form 8-K (#001-37456) filed on October 4, 2016

10.1	Contribution, Conveyance and Assumption Agreement, dated 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 13, 2015

10.2	First Amended and Restated Omnibus Agreement, dated September 30, 2016, by and among CONSOL Energy Inc., CNX Coal Resources GP LLC, CNX Coal Resources LP and the other parties listed on Exhibit A attached thereto	Filed as Exhibit 10.2 to Form 8-K (#001-37456) filed on October 4, 2016

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10.3	Pennsylvania Mine Complex Operating Agreement, dated 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 13, 2015

10.4	First Amendment to Pennsylvania Mine Complex Operating Agreement, dated September 30, 2016, 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 October 4, 2016

10.5	Employee Services Agreement, dated 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 13, 2015

10.6	Contract Agency Agreement, dated 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 13, 2015

10.7	Terminal and Throughput Agreement, dated 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 13, 2015

10.8	Amendment and Restatement of Master Cooperation and Safety Agreement, dated 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 13, 2015

10.9	Water Supply and Services Agreement, dated 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 13, 2015

10.10*	CNX Coal Resources LP 2015 Long-Term Incentive Plan	Filed as Exhibit 10.9 to Form 8-K (#001-37456) filed on July 13, 2015

10.11*	Form of Restricted Phantom Award Agreement under CNX Coal Resources LP 2015 Long-Term Incentive Plan	Filed as Exhibit 10.10 to Amendment to Registration Statement on Form S-1/A (#333-205639) filed on May 8, 2015

10.12	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 13, 2015

10.13	Amended and Restated Change in Control Agreement dated August 24, 2015 between CONSOL Energy Inc. and James A. Brock	Filed as Exhibit 10.11 to Form 10-Q (#001-37456) filed on November 3, 2015

10.14	Contribution Agreement, dated September 30, 2016, by and among CONSOL Energy Inc., CONSOL Pennsylvania Coal Company LLC, Conrhein Coal Company, CNX Coal Resources LP and CNX Thermal Holdings LLC	Filed as Exhibit 10.1 to Fork 8-K (#001-37456) on October 4, 2016

10.15	Amended and Restated Change in Control Severance Agreement dated February 6, 2017 between CNX Coal Resources GP LLC, CONSOL Pennsylvania Coal Company LLC, CONSOL Energy Inc. and James A. Brock	Filed as Exhibit 10.16 to Form 10-K (#001-37456) on February 8, 2017

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10.16	Amended and Restated Change in Control Severance Agreement dated February 6, 2017 between CNX Coal Resources GP LLC, CONSOL Pennsylvania Coal Company LLC, CONSOL Energy Inc.and Lorraine Ritter	Filed as Exhibit 10.16 to Form 10-K (#001-37456) on February 8, 2017

10.17	Change in Control Severance Agreement dated February 6, 2017 between CNX Coal Resources GP LLC, CONSOL Pennsylvania Coal Company LLC, CONSOL Energy Inc. and Martha Wiegand	Filed as Exhibit 10.16 to Form 10-K (#001-37456) on February 8, 2017

10.18	Form of First Amendment To Amendment and Restatement of Master Cooperation and Safety Agreement by and between CNX Thermal Holdings LLC, CONSOL Pennsylvania Coal Company LLC and Conrhein Coal Company and CNX Gas Company LLC dated July 7, 2015, dated January 7, 2016	Filed as Exhibit 10.1 to Form 10-Q (#001-37456) on October 31, 2017

10.19	Separation of Employment and General Release Agreement effective August 2, 2017 by and among CNX Coal Resources GP LLC, CONSOL Pennsylvania Coal Company LLC, CONSOL Energy Inc. and Lorraine Ritter	Filed as Exhibit 10.2 to Form 10-Q (#001-37456) on October 31, 2017

10.20	Affiliated Company Credit Agreement, dated November 28, 2017, by and among CONSOL Coal Resources LP, certain of its affiliates party thereto, CONSOL Energy Inc. and PNC Bank, National Association	Filed as Exhibit 10.1 to Form 8-K (#001-37456) on December 4, 2017

10.21	Second Amendment to the Pennsylvania Mine Complex Operating Agreement, dated November 28, 2017, by and among CONSOL Pennsylvania Coal Company LLC, Conrhein Coal Company, CONSOL Thermal Holdings LLC and CONSOL Coal Resources LP	Filed as Exhibit 10.2 to Form 8-K (#001-37456) on December 4, 2017

10.22	First Amendment to the First Amended and Restated Omnibus Agreement, dated November 28, 2017, by and among CONSOL Coal Resources LP, CONSOL Coal Resources GP LLC, CNX Resources Corporation and the other parties thereto	Filed as Exhibit 10.3 to Form 8-K (#001-37456) on December 4, 2017

10.23	First Amendment to Water Supply and Services Agreement, dated November 28, 2017, by and between CNX Water Assets LLC and CONSOL Thermal Holdings LLC	Filed as Exhibit 10.4 to Form 8-K (#001-37456) on December 4, 2017

10.24	First Amendment to Contract Agency Agreement, dated November 28, 2017, by and among CONSOL Thermal Holdings LLC, CONSOL Energy Sales Company and the other parties thereto	Filed as Exhibit 10.5 to Form 8-K (#001-37456) on December 4, 2017

10.25	Sub-Originator Sale Agreement, dated as of November 30, 2017, by and between CONSOL Thermal Holdings LLC and CONSOL Pennsylvania Coal Company LLC	Filed as Exhibit 10.6 to Form 8-K (#001-37456) on December 4, 2017

21.1	Subsidiaries of CONSOL 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

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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, 2017, furnished in XBRL).	Filed herewith

*	Compensatory plan or arrangement

Pursuant to the rules and regulations of the SEC, CONSOL 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 CONSOL 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 CONSOL Coal Resources LP’s actual state of affairs at the date hereof and should not be relied upon.

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 16, 2018



	CONSOL Coal Resources LP
	By:		CONSOL 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:		CONSOL Coal Resources GP LLC, its general partner
	By:		/s/ DAVID M. KHANI
			David M. Khani
			Chief Financial Officer (Duly Authorized Officer and Principal Financial 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 16, 2018.

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

	By:		/s/ DAVID M. KHANI
			David M. Khani
			Chief Financial Officer and Director (Duly Authorized Officer and Principal Financial Officer)

	By:		/s/ JOHN M. ROTHKA
			John M. Rothka
			Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

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

	By:		/s/ DAN D. SANDMAN
			Dan D. Sandman
			Director

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

	By:		/s/ KURT R. SALVATORI
			Kurt R. Salvatori
			Director

	By:		/s/ DEBORAH J. LACKOVIC
			Deborah J. Lackovic
			Director

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