Company Quick10K Filing
Consol Coal Resources
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$0.00 -0 $-0
10-K 2020-02-14 Annual: 2019-12-31
10-Q 2019-11-05 Quarter: 2019-09-30
10-Q 2019-08-06 Quarter: 2019-06-30
10-Q 2019-05-08 Quarter: 2019-03-31
10-K 2019-02-08 Annual: 2018-12-31
10-Q 2018-11-01 Quarter: 2018-09-30
10-Q 2018-08-02 Quarter: 2018-06-30
10-Q 2018-05-03 Quarter: 2018-03-31
10-K 2018-02-16 Annual: 2017-12-31
10-Q 2017-10-31 Quarter: 2017-09-30
10-Q 2017-08-01 Quarter: 2017-06-30
10-Q 2017-05-02 Quarter: 2017-03-31
10-K 2017-02-08 Annual: 2016-12-31
10-Q 2016-11-01 Quarter: 2016-09-30
10-Q 2016-07-29 Quarter: 2016-06-30
10-Q 2016-04-28 Quarter: 2016-03-31
10-K 2016-02-05 Annual: 2015-12-31
10-Q 2015-11-03 Quarter: 2015-09-30
10-Q 2015-07-31 Quarter: 2015-06-30
8-K 2020-02-11 Earnings, Regulation FD, Exhibits
8-K 2019-12-27 Officers
8-K 2019-11-05 Earnings, Regulation FD, Exhibits
8-K 2019-08-06 Earnings, Regulation FD, Exhibits
8-K 2019-05-08 Earnings, Regulation FD, Exhibits
8-K 2019-03-28 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2019-02-07 Earnings, Regulation FD, Exhibits
8-K 2018-11-01 Earnings, Regulation FD, Exhibits
8-K 2018-08-02 Earnings, Regulation FD, Exhibits
8-K 2018-05-03 Earnings, Regulation FD, Exhibits
8-K 2018-02-06 Earnings, Regulation FD, Exhibits
CCR 2019-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 8. Financial Statements and Supplementary Data
Note 1-Significant Accounting Policies
Note 2-Revenue:
Note 3-Net Income per Limited Partner and General Partner Interest:
Note 4-Other Income:
Note 5-Interest Expense:
Note 6-Inventories:
Note 7-Property, Plant and Equipment:
Note 8-Other Accrued Liabilities:
Note 9-Long-Term Debt:
Note 10-Leases:
Note 11-Fair Value of Financial Instruments:
Note 12-Asset Retirement Obligations:
Note 13-Coal Workers' Pneumoconiosis (Cwp) and Workers' Compensation:
Note 14-Other Benefit Plans:
Note 15-Supplemental Cash Flow Information:
Note 16-Concentration of Credit Risk:
Note 17-Commitments and Contingent Liabilities:
Note 18-Receivables Financing Agreement
Note 19-Related Party:
Note 20-Long-Term Incentive Plan:
Note 21-Financial Information for Subsidiary Guarantors and Finance Subsidiary of Possible Future Public Debt:
Note 22-Subsequent Events:
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance of General Partner
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
EX-4.4 exhibit44descriptionof.htm
EX-21.1 exhibit211-12312019.htm
EX-23.1 exhibit231-12312019.htm
EX-31.1 exhibit311-12312019.htm
EX-31.2 exhibit312-12312019.htm
EX-32.1 exhibit321-12312019.htm
EX-32.2 exhibit322-12312019.htm
EX-95 exhibit95-mshax12312019.htm

Consol Coal Resources Earnings 2019-12-31

CCR 10K Annual Report

Balance SheetIncome StatementCash Flow

Comparables ($MM TTM)
Ticker M Cap Assets Liab Rev G Profit Net Inc EBITDA EV G Margin EV/EBITDA ROA
CTRA 982 2,780 1,813 2,285 0 62 273 1,091 0% 4.0 2%
CEIX 710 2,765 2,155 1,461 0 124 335 1,253 0% 3.7 4%
METC 214 218 58 230 61 27 48 223 27% 4.6 12%
HNRG 178 513 252 331 18 9 71 341 6% 4.8 2%
FELP 96 2,387 1,845 1,089 0 -61 134 1,365 0% 10.2 -3%
CLD 6 275 642 724 0 -1,340 -1,264 -40 0% 0.0 -488%
BBL
CCR 494 269 339 0 55 105 168 0% 1.6 11%
NRP 1,219 615 307 62 133 217 467 20% 2.2 11%
ARLP 2,503 1,123 2,102 0 467 802 500 0% 0.6 19%

Document
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________________________________________
FORM 10-K
_________________________________________________________________
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
OR
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) 416-8300
(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
Trading Symbols
Name of Each Exchange On Which Registered
Common Units representing limited partner units
CCR
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    No 
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    No 
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    No 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes    No  
 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      Accelerated filer      Non-accelerated filer      Smaller Reporting Company   Emerging Growth Company  
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
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No 
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 $177,872,584 as of June 28, 2019, 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 27,632,824 common units and a 1.7% general partner interest outstanding at January 24, 2020.

DOCUMENTS INCORPORATED BY REFERENCE:
None
 




TABLE OF CONTENTS

 
 
Page
 
PART I
 
 
 
 
Item 1.
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
 
 
 
 
PART II
 
 
 
 
Item 5.
Market for Registrants Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 7.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Item 8.
Financial Statements
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
Item 9A.
Controls and Procedures
Item 9B.
Other Information
 
 
 
 
PART III
 
 
 
 
Item 10.
Directors, Executive Officers and Corporate Governance of General Partner
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13.
Certain Relationships and Related Transactions and Director Independence
Item 14.
Principal Accounting Fees and Services
 
 
 
 
PART IV
 
 
 
 
Item 15.
Exhibits and Financial Statement Schedules
 
Signatures


2



PART I

Significant Relationships and Other Important Definitions Referenced in this Annual Report

“CONSOL Coal Resources LP,” the “Partnership,” “we,” “our,” “us” and similar terms 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.”

“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.

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

“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.

“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; CONSOL Thermal Holdings owns a 25% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania Mining Complex.

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

“CPCC” refers to CONSOL Pennsylvania Coal Company LLC, a Delaware limited liability company 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 our former sponsor, 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).


3



“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 Bailey, Enlow Fork, and Harvey coal mines, coal reserves and related assets and operations, located primarily in southwestern Pennsylvania. The Pennsylvania Mining Complex is owned 75% by our sponsor and its subsidiaries and 25% by CONSOL Thermal Holdings.

“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.

“recoverable coal reserves” refer to our proven and probable coal reserves, as defined by Industry Guide 7, 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.

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

“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. On August 16, 2019, all 11,611,067 subordinated units, which were owned entirely by CONSOL Energy, were converted into common units on a one-for-one basis. As of the date of this Annual Report on Form 10-K, there are no outstanding subordinated units.







4



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 and outcomes to differ materially from results expressed in or implied by our forward-looking statements. 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;
defects in title or loss of any leasehold interests with respect to our properties;
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;
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;
adverse effect of cybersecurity threats;
failure to maintain effective internal controls over financial reporting;
recent action and the possibility of future action on trade by U.S. and foreign governments;
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.

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ITEM 1.    BUSINESS

General

We are a master limited partnership formed on March 16, 2015 to manage and further develop all of our sponsor's active coal operations in Pennsylvania. All amounts discussed in this section are in thousands, except for per unit or per ton amounts, unless otherwise indicated.

At December 31, 2019, 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-British thermal unit (“Btu”) coal that is sold primarily to electric utilities in the eastern United States. We are a leading producer of high-Btu 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 Coal Seam, which is a large contiguous formation of high-Btu coal that is ideal for high-productivity, low-cost longwall operations. As of December 31, 2019, our portion of the Pennsylvania Mining Complex included 167,341 tons of recoverable coal reserves that are sufficient to support approximately 23.5 years of production. In addition, our reserves currently exhibit thermoplastic behavior suitable for cokemaking, 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, our 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, with many of the approved permits as far out as ten years. We typically operate five longwalls and 15-17 continuous mining sections at the Pennsylvania Mining Complex. The current production capacity of our portion of the Pennsylvania Mining Complex’s five longwalls is 7.1 million 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 raw 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 clean 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 significantly increases our efficiency in meeting our customers’ transportation needs.

On July 1, 2015, our common units began trading on the New York Stock Exchange. 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, we acquired 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 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.

Since November 28, 2017, CONSOL Energy has been our sponsor. CONSOL Energy's coal business includes its 75% undivided interest in the Pennsylvania Mining Complex, terminal operations at the Port of Baltimore and undeveloped coal reserves located in the Northern Appalachian Basin, Central Appalachian Basin and Illinois Basin and certain related coal assets and liabilities. On August 16, 2019, all 11,611,067 subordinated units, which were owned entirely by our sponsor, were converted into common units on a one-for-one basis. As of December 31, 2019, CONSOL Energy holds (i) 16,811,818 of our common units, (ii) a 1.7% general partnership interest in us and (iii) all of our incentive distribution rights.

Our primary strategy for growing our business 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.

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Our principal executive offices are located at 1000 CONSOL Energy Drive, Suite 100, Canonsburg, Pennsylvania 15317-6506, and our telephone number is (724) 416-8300. 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, 2019:
a2019orgstructure.jpg

Our Relationship with CONSOL Energy

One of our principal strengths is our relationship with our sponsor, CONSOL Energy. CONSOL Energy is a leading, low-cost producer of high-quality coal, headquartered in Canonsburg, Pennsylvania. 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

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listed on the NYSE under the symbol “CEIX” and had a market capitalization of approximately $376.3 million as of December 31, 2019.

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 coal reserves are sufficient to support approximately 23.5 years of production.

Our Operations

Bailey Mine

The Bailey Mine is located in Enon, Pennsylvania. The Bailey Mine is the first mine developed at the Pennsylvania Mining Complex. As of December 31, 2019, the Partnership’s portion of the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 28,817 tons of recoverable coal reserves with an average as-received gross heat content of approximately 12,890 Btus per pound and an approximate average lb SO2/mmBtu of 4.4. Construction of the slope and initial air shaft began in 1982. The slope development reached the coal seam at a depth of approximately 600 feet and, following development of the slope bottom, commercial coal production began in 1984. Longwall mining production commenced in 1985, and the second longwall was placed into operation in 1987. In 2010, a new slope and overland belt system was commissioned, which allowed a large percentage of the Bailey Mine to be sealed off. For the years ended December 31, 2019, 2018 and 2017, our portion of the Bailey Mine produced 3,054 tons, 3,184 tons and 3,031 tons of coal, respectively. The Bailey Mine uses approximately six to seven continuous mining units to develop the mains and gate roads for its longwall panels.

Enlow Fork Mine

The Enlow Fork Mine is located directly north of the Bailey Mine. As of December 31, 2019, the Partnership’s portion of the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 81,126 tons of recoverable coal reserves with an average as-received gross heat content of approximately 12,940 Btus per pound and an approximate average lb SO2/mmBtu of 3.3. Initial underground development was started from the Bailey Mine while the Enlow Fork slope was being constructed. Once the slope bottom was developed and the slope belt became operational, seals were constructed to separate the two mines. Following development of the slope bottom, commercial coal production began in 1989. Longwall mining production commenced in 1991 with the second longwall coming online in 1992. In 2014, a new slope and overland belt system was commissioned and a substantial portion of the Enlow Fork Mine was sealed. For the years ended December 31, 2019, 2018 and 2017, our portion of the Enlow Fork Mine produced 2,511 tons, 2,469 tons and 2,295 tons of coal, respectively. The Enlow Fork Mine uses approximately six to seven continuous mining units to develop the mains and gate roads for its longwall panels.

Harvey Mine

The Harvey Mine is located directly east of the Bailey and Enlow Fork Mines. As of December 31, 2019, the Partnership’s portion of the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 57,398 tons of recoverable coal reserves with an average as-received gross heat content of approximately 12,950 Btus per pound and an approximate average lb SO2/mmBtu of 3.8. Similar to the Enlow Fork Mine, the Harvey Mine was developed off of the Bailey Mine’s slope bottom. Once the slope for the Harvey Mine was placed into operation, seals were built to separate the two mines, and the original slope was dedicated solely to the Harvey Mine, which eliminated the need to make significant capital expenditures to develop, among other things, a new slope, air shaft and portal facility. Development of the Harvey Mine began in 2009, and construction of the supporting surface facilities commenced in 2011. Longwall mining production commenced in March 2014. For the years ended December 31, 2019, 2018 and 2017, our portion of the Harvey Mine produced 1,256 tons, 1,245 tons and 1,201 tons of coal, respectively. The Harvey Mine uses approximately three continuous mining units to develop the mains and gate roads for its longwall panels. The Harvey Mine’s existing infrastructure, including its bottom development, slope belt and material handling system, has the capacity to add one incremental permanent longwall mining system with additional mine development and capital investment.
Capital Expenditures

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In 2020, the Partnership expects to invest $25,000-$30,000 in maintenance capital expenditures, which is decreased from 2019 levels due to expected reductions in equipment-related expenditures and spending on buildings and structures.

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, which contracts are administered at our direction by a wholly owned subsidiary of CONSOL Energy under a contract agency agreement, as “our contracts”. For 2020 and 2021, our contracted position, as of February 11, 2020, is at 95% and 43%, respectively, assuming an annual coal sales volume at the midpoint of our guidance range. Our contracted position includes a mix of sales to our top domestic customers and to the thermal and metallurgical export markets, 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, 2019, 2018 and 2017, approximately 88%, 68% and 68%, 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 2019 sales tons, approximately 66% were sold to U.S. electric generators, 33% were priced on export markets and 1% were sold to other domestic customers. Of the 33% of our 2019 sales tons priced on export markets, 6% were sold in the metallurgical market. In 2019, we derived greater than 70% of our total coal sales revenue from our top three customers. As of January 1, 2020, we had multiple sales agreements with these customers that expire at various times in 2020 through 2023.

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 free-on-board (“FOB”) mine prices. Most of our coal is sold 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

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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.

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 and tariffs 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.

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 power generators. 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.

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. Additionally, these laws are subject to revision and may become increasingly stringent. The ultimate effect of implementation may not be predictable, as associated regulations may still be in development or subject to public notice, extensive comment, or judicial review.


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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

Clean Air Act. The federal 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 operations through permitting and emission control requirements for the construction or modification of certain facilities. Indirectly, the CAA affects the U.S. coal industry by extensively regulating the air emissions of coal-fired electric power generating plants or other industrial facilities operated by our customers.

Coal impurities are released into the air when coal is combusted. The CAA regulates specific emissions, such as sulfur, nitrogen oxides, particulate matter, mercury and other substances. In addition to those statutes discussed herein, CAA programs such as Maximum Achievable Control Technology (“MACT”) emission limits for Hazardous Air Pollutants, the Regional Haze Program, and permitting requirements under New Source Review may directly or indirectly affect our operations. Such regulations restricting emissions from coal-fired electric generating plants or other industrial facilities could increase the costs to operate and affect demand for coal as a fuel source, therefore potentially affecting the volume of our sales. Moreover, additional environmental regulations increase the likelihood that existing coal-fired electric generating plants will be decommissioned or replaced with alternative sources of fuel and reduce the likelihood that new coal-fired plants will be built in the future. In recent years, repeal or revision to multiple regulations under the CAA has been proposed; however, the extent to which these regulations will take effect or survive future administrations is uncertain.

Mercury and Air Toxics Standards Rule. In 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. NSPS are technology-based standards that vary depending on the particular source, such as a coal-fired electric generating plant, and can have a significant influence on the cost of using coal as a fuel source. The EPA's 2012 Mercury and Air Toxics Standards rule (“MATS Rule”) established NSPS for emissions of particulate matter, sulfur dioxide (“SO2”) and nitrogen oxides (“NOX”) from coal-fired electric generating units (“EGUs”). The MATS Rule also established national emission standards for hazardous air pollutants (“NESHAP”) for coal-fired electric generating units for certain impurities such as mercury. Unlike pollutants regulated by a NSPS, pollutants regulated by a NESHAP require the MACT be used to control emissions of the pollutant. The application of a MACT standard is generally more costly than other control technology standards, and prompted the closure of some facilities. The rule was challenged and ultimately rejected by the U.S. Supreme Court on June 29, 2015 for failing to consider the costs imposed by the MATS Rule. The rule was remanded to the Court of Appeals for the D.C. Circuit (“D.C. Circuit”) to determine whether to allow the EPA to address the rule’s deficiencies or to vacate and nullify the rule. In April 2017, the D.C. Circuit granted the EPA's request to stay the case to allow the agency to fully review the rule. Nevertheless, many coal-fired electric power generators have already taken steps to comply with the MATS Rule, as such required control and operational modifications can take significant time to install and/or implement. On December 27, 2018, the EPA proposed to revise the 2016 supplemental cost finding for the MATS Rule, as well as the related risk and technology review required by the CAA. Under the proposal, the emissions standards and other requirements of the MATS Rule would remain in place while the EPA’s methodology for assessing the costs and benefits of the rule were being modified.

National Ambient Air Quality Standards. The CAA requires the EPA to set National Ambient Air Quality Standards (“NAAQS”) for six pollutants considered harmful to public health and the environment (“Criteria Pollutants”). Areas that are not in compliance with these standards are considered “non-attainment areas.” In recent years, the EPA has adopted more stringent NAAQS for these Criteria Pollutants, which could directly or indirectly impact mining operations through the designation of new non-attainment areas which could prompt local changes to permitting or emissions control requirements, as prescribed by federally mandated state implementation plans that require emission source identification and emission reduction plans. Final rules may require significant investment in emissions control technologies by our customers in the electric power generation industry, and could affect the demand for our coal. For example, in 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 was challenged in the D.C. Circuit. On April 7, 2017, the EPA advised the D.C. Circuit that it intended to reconsider the final rule and the Court subsequently stayed the litigation pending further action by the EPA. In August 2018, the EPA ultimately decided not to revisit the rule. As a result, the D.C. Circuit lifted its stay of the 2015 ozone NAAQS rule imposing the 70 ppb ambient air quality standard while EPA reviews the standards under an expedited process. On October 31, 2019, EPA published a draft policy assessment recommending that the 70 ppb ozone NAAQS be retained. The policy assessment will be followed by a proposed rule finalizing the ozone NAAQS update on or before October 1, 2020.


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Cross-State Air Pollution Rule. On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”). CSAPR regulates cross-border emissions of criteria air pollutants such as SO2 and NOX particulate matter and ozone in the District of Columbia and 27 states. CSAPR requires states to limit emissions from sources that “contribute significantly” to noncompliance with air quality standards, such as electric power generating facilities. 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 October 2016, the EPA finalized revisions to the CSAPR, known as the CSAPR Update Rule. Following litigation in the D.C. Circuit and U.S. Supreme Court, CSAPR was implemented in two phases: Phase 1 began in 2015 and Phase 2 began in 2017. On December 6, 2018, the EPA issued the CSAPR “Close-Out” Rule, a final determination that the CSAPR achieves requirements with respect to the 2008 ground-level ozone NAAQS in 20 states, and accordingly, those states will not be required to impose requirements for further reduction in transported ozone pollution. In addition, the covered states do not need to submit state implementation plans (“SIPs”) that would establish additional requirements beyond the existing CSAPR update. The “Close-Out” rule was challenged by several states and other entities in the D.C. Circuit. In a September 13, 2019 ruling, the D.C. Circuit remanded the 2016 CSAPR Update Rule to EPA, finding that rule is inconsistent with the CAA. In a subsequent October 1, 2019 ruling, the CSAPR “Close-Out” rule was vacated.

Affordable Clean Energy Rule. In August 2018, the EPA published a proposed rule, the Affordable Clean Energy (“ACE”) rule, to replace the 2015 “Carbon Pollution Standard for New Power Plants”, known as the Clean Power Plan (“CPP”). The CPP, which established separate NSPS for carbon dioxide (“CO2”) emissions for new, modified, or reconstructed power plants under the CAA, was challenged by multiple parties with its effective date ultimately being stayed by the U.S. Supreme Court. The EPA formally proposed repeal of the CPP on October 16, 2017. The CPP was formally repealed with promulgation of the final ACE rule on June 19, 2019. The ACE rule establishes greenhouse gas (“GHG”) guidelines for states to use when developing plans to limit CO2 emissions from coal-fired EGUs. The ACE rule provides that heat rate efficiency improvements are the Best System of Emission Reduction for coal-fired electric utility sources under the federal Clean Air Act. The ACE rule directs states to develop specific SIPs to implement the rule, and provides six heat rate improvement technologies that may be considered by the states to establish emission standards of performance on a plant-by-plant basis. States may also consider the remaining useful life of the EGUs, as provided by the CAA. While the ACE rule reduces regulatory burden on coal fired EGUs compared to the CPP, its ultimate effect on coal demand is unknown. Several states and public interest groups have petitioned for review of the ACE rule in the D.C. Circuit. The EPA has requested for an expedited review of the challenges, seeking a resolution in the D.C. Circuit in 2020.

    National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to taking a “major Federal action”, which encompasses agencies’ decisions on certain permitting applications that fall under federal jurisdiction. NEPA reviews require federal agencies to review the environmental impacts of their decisions, including those associated with GHG emissions and the effects of climate change. Agencies must issue either an Environmental Impact Statement or an Environmental Assessment, which may create delays in project review and authorization timeframes, or increase the cost of compliance. In June 2018, the White House Council on Environmental Quality (“CEQ”) issued an Advance Notice of Proposed Rulemaking on NEPA seeking to streamline the NEPA process, while also minimizing unnecessary litigation, cost and delay for project proponents. On June 26, 2019, CEQ published a “Draft NEPA Guidance on Consideration of Greenhouse Gas Emissions” to replace guidance previously issued in 2016. The draft guidance seeks to clarify the scope of review federal agencies should undertake when considering the effects of GHG emissions under NEPA. A final proposed rule is expected to be published in 2020. Certain federal courts have held that GHGs must be considered under NEPA prior to a federal agency taking a “major Federal action,” and any modifications to NEPA will likely be subject to legal challenge.

Laws and Regulations Governing Greenhouse Gas Emissions. Our customers' consumption of the coal we produce results in the emission of GHGs, such as CO2 and nitrous oxide. During operations, our coal mines release methane, a GHG, to promote a safe working environment for our miners underground. GHGs are believed to contribute to warming of the earth’s atmosphere and other climatic changes. As a result, global climate change initiatives and regulations intended to reduce GHG emissions have and are expected to continue to result in (i) the decreased utilization or accelerated closure of existing coal-fired EGUs, (ii) the increased utilization of alternative fuels or generating systems, and (iii) a reduction or elimination of new coal-fired power plant construction in certain countries.
Foreign governments, including the European Union and member countries, have adopted regulations governing GHG emissions. In the United States, findings published by the EPA in 2009 concluded that GHG emissions pose an endangerment to public health and the environment. These findings provided the EPA with the authority to adopt and implement regulations restricting GHG emissions under existing provisions of the CAA. For example, the EPA relied on this authority to promulgate NSPS for CO2 emissions from power plants under the ACE rule, discussed above.

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Since 2011, the EPA has required underground coal mines and certain support facilities exceeding a minimum GHG emission threshold to report emissions annually under the Mandatory Reporting Rule. These emissions are currently classified as fugitive emissions associated with coal extraction and are not currently regulated by the EPA. Previous petitions and judicial challenges seeking to compel the EPA to classify coal mines as stationary sources appropriate for regulation have been unsuccessful to date. If the EPA were to regulate coal mine methane emissions in the future, we would likely be required to install additional pollution control devices, pay fees or taxes for our emissions, or incur expenses associated with the purchase of emissions credits, in order to continue operation. Alternatively, we may need to curtail coal production. The magnitude of impact on our operations, capital expenditures, financial condition or cash flows would be dependent on the structure of any proposed regulation and the degree of emission reduction prescribed.
In the absence of sweeping federal legislation on GHG emissions in the United States, some states, governors, mayors and businesses have committed to the goals of the Paris Agreement or other broad GHG reduction initiatives. For instance, on October 3, 2019, Pennsylvania Governor Tom Wolf issued an Executive Order, “Commonwealth Leadership in Addressing Climate Change through Electric Sector Emissions Reductions,” directing the state’s Department of Environmental Protection to begin a rulemaking process that will allow Pennsylvania to join the Regional Greenhouse Gas Initiative (“RGGI”). RGGI is a mandatory cap-and- trade program among 10 northeastern states to reduce CO2 emissions from the power sector. Governor Wolf’s authority to commit the state to membership in such a consortium without the approval of lawmakers will likely be subject to legislative and legal challenges, and its ultimate effect on coal demand is presently unknown. Similar to other mandatory cap-and-trade initiatives, such as the Midwestern Regional Greenhouse Gas Reduction Accord and the Western Climate Initiative, RGGI seeks to limit CO2 emissions annually in order to achieve a prescribed long-term emissions reduction target. In all cap-and-trade scenarios, power generators are required to purchase allowances, available through auction or a secondary market, that are equal to one ton of CO2 emissions thereby increasing the cost of electric power generation. GHG and climate change initiatives, associated regulation, and cap-and-trade initiatives could result in decreased demand and decreased prices for our coal, in both domestic and international markets.
 
Clean Water Act. The federal Clean Water Act (“CWA”) and corresponding state laws affect our coal operations by regulating discharges into certain waters, primarily through permitting. CWA permits issued either by the EPA or an analogous state agency typically require regular monitoring and compliance with limitations on defined pollutants and reporting requirements. Specific to the Partnership's operations, CWA permits and corresponding state laws often require (1) treatment of discharges from coal mining properties for non-traditional pollutants, such as chlorides, sulfates, selenium and dissolved solids and (2) requirements to dispose of produced wastes at approved disposal facilities.

In order to obtain a permit for certain coal mining activities, including the construction of coal refuse areas and slurry impoundments that may result in impacts to waters of the United States, an operator may need to obtain a permit for the discharge of fill material from the Army Corps of Engineers (“ACOE”) under Section 404, as well as a corresponding permit from the state regulatory authority under Section 401 of the CWA. Alternatively, for specific categories of activities determined to have minimal effects, the Partnership may be required to obtain nationwide permits from the ACOE. All permits associated with the placement of dredge or fill material subject to minimum thresholds require appropriate mitigation. Permit holders must receive explicit authorization from ACOE before proceeding with mining activities, which could result in time or cost burdens to our operations.
Additionally, the Partnership must obtain National Pollution Discharge Elimination System (“NPDES”) permits from the appropriate state or federal permitting authority under Section 402 of the CWA. These permits establish effluent limitations for discharges to streams that are protective of water quality standards. For wastewater discharges to receiving waters that are classified as either high-quality or impaired, stringent restrictions are established to ensure anti-degradation and compliance with water quality standards. Permitting such discharges under NPDES could increase the cost, time, and difficulty of complying with permit requirements, and may warrant costly treatment that could affect our operations.
Under the CWA, citizens may sue permit holders for alleged discharges of pollutants not explicitly limited by NPDES permits, or, citizens may sue to enforce NPDES permit requirements. Beginning in 2012, multiple citizen suits have been filed alleging violations of numeric and narrative water quality standards that broadly prohibit effects to aquatic life. The suits seek penalties and injunctive relief that could limit future discharges or impose expensive treatment technologies. While the outcome of these suits cannot be predicted, court rulings could result in additional treatment expenses that could affect our operations. See Item 3, “Legal Proceedings,” regarding certain actions pertaining to our operations.

In June 2015, the EPA issued a rule to clarify which waterways are subject to federal jurisdiction under the CWA, known as the Clean Water Rule. This rule was quickly challenged and nationwide implementation was blocked by a federal appeals court. The Clean Water Rule would impose additional permitting obligations on the Partnership's operations by increasing the

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number of waterbodies subject to CWA permitting and other regulations. On February 28, 2017, President Trump issued an executive order prompting the EPA and ACOE to consider replacing the blocked Clean Water Rule. On December 11, 2018, the EPA and the ACOE proposed a new regulation to determine which waterbodies are subject to federal jurisdiction. A final rule repealing the 2015 definition of “Waters of the United States” (“WOTUS”) became effective on December 23, 2019. The repeal resets a consistent, nationwide regulatory standard to the previous pre-2015 regulations. A replacement rule that redefines WOTUS to comport with the text of the CWA is expected to be finalized in 2020.

On November 3, 2015, the EPA published the final Effluent Limitations Guidelines and Standards (“ELG”) rule, 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. On September 13, 2017, the EPA finalized a rule postponing for two years certain applicability dates for specific waste streams subject to the effluent limitations. On November 22, 2019, the EPA published its proposed revisions to the stringent limitations and standards included in the 2015 final ELG rule, while establishing a voluntary incentive program which provides power plants until December 31, 2028, to implement changes.

Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (“SMCRA”) establishes minimum extraction, environmental, reclamation, and closure standards for mining activities. While SMCRA is a comprehensive statute, it does not supersede other major statutes such as the Clean Air Act, Clean Water Act, Endangered Species Act and other statutes discussed herein. Operators must obtain SMCRA permits and permit renewals from the U.S. Office of Surface Mining (“OSM”) or from the applicable state agency where states have been granted regulatory primacy by demonstrating that the state’s regulatory program is at least as stringent as the federal program. Our active operations are located in states which have achieved primary jurisdiction for enforcement of SMCRA, with oversight from OSM. The timing of permit issuance is largely at the discretion of the regulatory authorities and is related to the size and complexity of the operation seeking approval. Timing of permit issuance can also be influenced by public engagement in the permitting process, such as through comment, hearings, or legal interventions which could affect our operations. In addition, mining permits can be delayed, refused, or revoked if any entity under common ownership or control have unabated permit violations, including the mining and compliance history of officers, directors, and principal owners of the entity seeking permit approval.
Under federal and state laws, including SMCRA, we are required to obtain surety bonds or other acceptable security to secure payment of our long-term obligations, including mine closure and reclamation, mine water treatment, federal and state workers’ compensation costs, coal leases, or other miscellaneous obligations. Surety bonds are typically renewable on a yearly basis and it is possible that surety-bond issuers may refuse to renew bonds or may demand additional collateral therefor. In recent years, surety bond costs have increased, the market terms of surety bonds have generally become less favorable, and the number of companies willing to issue surety bonds has decreased. Any failure to maintain, or our inability to acquire, surety bonds required by state and federal laws or the related collateral required by bond issuers, could have a material adverse effect on our ability to produce coal, adversely affecting our business, financial condition, liquidity, results of operations and cash flows. As of December 31, 2019, we posted an aggregated $89 million in surety bonds for reclamation purposes, as well as approximately $11 million in surety bonds, cash, and letters of credit to secure other obligations including workers compensation, coal lease, and other obligations.

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 lands mined, closed, or abandoned before SMCRA's adoption in 1977, and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. 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. We recognized expense related to Abandoned Mine Reclamation Fund fees of approximately $1 million for the year ended December 31, 2019.

Endangered Species Act. The federal Endangered Species Act (“ESA”) and other related federal and state statutes protect species that have been classified as endangered or threatened with possible extinction, or other protective designations. Protection of these species could prohibit or delay authorization of mining activities or may place additional restrictions on our operations related to timbering, construction, vegetation, or water discharges. A number of species indigenous to our operating areas are protected under the ESA or other related laws and regulations; however, we do not believe the ESA would materially or adversely affect our mining operations under current approved mining plans. If more stringent or protective measures were required, or if additional critical habitat areas were designated, our operations could be exposed to additional requirements and expense, or delayed approval timeframes. In August 2018, the Department of the Interior issued three proposed rules intended to update and streamline the ESA as it relates to: (i) factors for the listing, delisting, or reclassifying of species, and the designation of critical habitat and (ii) the blanket extension of prohibitions for endangered species to threatened species. These rules, which became effective on September 26, 2019, are subject to challenge from several states and environmental groups.

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Comprehensive Environmental Response, Compensation, and Liability Act. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) imposes remediation requirements related to actual or threatened releases of hazardous substances into the environment. Under CERCLA or related state laws, joint and several liability may be imposed on generators of hazardous waste, site owners, waste transporters or others regardless of fault associated with the original disposal activity. Although the EPA excludes most wastes generated during coal mining and processing from hazardous waste laws, such wastes may contain hazardous substances that are governed by CERCLA if released to the environment. Our current operations, operations of our predecessors, or sites to which we have sent waste materials could be subject to liability under CERCLA.
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, transportation, and disposal of certain wastes created throughout the coal mining process. Facilities where certain regulated wastes have been treated, stored or disposed of are subject to RCRA and may receive corrective action orders for instances of non-compliance or in the event a hazardous substance is released to the environment. Many waste streams created throughout the mining process are excluded from the regulatory definition of hazardous waste, and coal operations authorized under SMCRA are exempt from RCRA permitting requirements. RCRA is particularly important in the coal industry because it regulates coal combustion residuals - byproducts of coal combustion. In April 2015, the EPA published regulations under RCRA for the disposal of coal combustion residuals from electric utilities and independent power producers (the “coal combustion residuals rule”). Importantly, coal combustion residuals are regulated under RCRA as “non-hazardous” waste and avoid the stricter, costlier regulations under RCRA's “hazardous” waste rules. In 2018, the EPA promulgated the first of a two-part rulemaking amending the national minimum criteria for existing and new coal combustion residuals impoundments. The EPA released its second rulemaking proposal on December 19, 2019, to establish a federal permitting program for states and territories that do not have an approved permitting program for the disposal of coal combustion residuals in surface impoundments and landfills under RCRA. The coal combustion residuals rule imposes new requirements at existing coal combustion residuals impoundments and landfills that would generally increase the cost of coal combustion residuals management. The combined effect of the coal combustion residuals rule and ELG regulations (discussed above) has compelled power generating companies to close existing ash ponds and may force the closure of certain older existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.

Other Environmental Regulations. We are required to comply with other state, federal and local environmental laws in addition to those discussed above. These laws include, for example, the Safe Drinking Water Act, the Emergency Planning and Community Right to Know Act, the Toxic Release Inventory, and the rules governing the use and storage of explosives regulated by the U.S. Bureau of Alcohol, Tobacco, and Firearms and the Department of Homeland Security.

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 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 September 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. MSHA has not issued a final rule regarding these proposed rules.

Since March 2015, all underground coal mine operations have been required by MSHA to equip continuous mining machines (except full-face continuous mining machines) with proximity detection systems. The proximity detection system

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strengthens protection for miners by reducing the potential of pinning, crushing and striking hazards that result in life-threatening injuries and death.

Since August 1, 2014, we have been subject to additional rules designed to lower miners’ exposure to respirable coal mine dust. Accordingly, we have been required to take full shift dust samples from the designated occupations and areas 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 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 (coal miners who show evidence of the development of black lung disease).

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 coal, at a 2018 rate 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. On January 1, 2019, the excise tax levels reverted to pre-2008 levels, at $0.50 per ton for deep mined coal and $0.25 per ton for surface-mined coal. In December 2019, Congress restored the 2018 rates (of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal), effective through December 31, 2020.

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

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, 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, 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, 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

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CONSOL Energy or its subsidiaries and are subject to the employee services agreement. As of December 31, 2019, CONSOL Energy employed approximately 1,594 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.

Emerging Growth Company and Smaller Reporting Company Status

Under the Jumpstart Our Business Startups Act (“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;
our limited partner interests held by non-affiliates have a market value of more than $700 million; 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, is subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

Additionally, under Rule 12b-2 of the Exchange Act, the Partnership also qualifies as a “smaller reporting company” because its public float as of the last business day of the Partnership’s most recently completed second fiscal quarter was less than $250 million. For as long as the Partnership remains a “smaller reporting company,” we may take advantage of certain exemptions from the SEC’s reporting requirements that are otherwise applicable to public companies that are not smaller reporting 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. These documents 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.

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ITEM 1A.    RISK FACTORS
You should carefully consider the following risks and other information in this Annual Report on Form 10-K in evaluating us and our common units. The risk factors generally have been separated into three groups: risks related to our business, risks inherent to an investment in us and tax risks.
Any of the following risks could materially and adversely affect our financial condition, results of operations, cash flows or ability to make cash distributions. Our operations could be affected by various risks, many of which are beyond our control. Based on current information, we believe that the following list identifies the most significant risk factors that could affect our financial condition, results of operations, cash flows or ability to make cash distributions. There may be additional risks and uncertainties that adversely affect our financial condition, results of operations, cash flows or ability to make cash distributions in the future that are not presently known, are not currently believed to be material, or are not identified below, because they are common to all businesses. Past financial performance may not be a reliable indicator of future performance and historical trends should not be used to anticipate results or trends in future periods. For more information, see “Forward-Looking Statements.”

Risks Related to Our Business

We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution, or any distribution at all, to our common unitholders.

In order to support the payment of the minimum quarterly distribution of $0.5125 per common unit per quarter, or $2.05 per common unit on an annualized basis, we must generate distributable cash flow of approximately $14,405 per quarter, or approximately $57,619 per year, based on the number of common units and the general partner interest outstanding as of December 31, 2019.

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;
other business risks affecting our cash levels;
overall domestic and global economic and industry conditions, including the market price of, supply of and demand for domestic and foreign coal;
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, 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.

In addition, we may not generate sufficient distributable cash flow to pay our quarterly distribution to our common unitholders at the current distribution level, or at all, following the establishment of cash reserves and payment of expenses,

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including payments to our general partner, and as a result, future distributions to our common unitholders may be reduced, suspended or eliminated.

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 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. 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 maintain 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. Additionally, our estimates of recoverable coal reserves may be materially

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and adversely affected in future fiscal periods by the SEC’s recent rule amendments revising property disclosure requirements for publicly traded mining companies. We will be required to comply with these new rules in 2021.

Defects may exist in our chain of title for our undeveloped recoverable coal reserves where we have not done a thorough chain of title examination. We may incur additional costs and delays to mine coal because we have to acquire additional property rights to perfect our title to coal rights. If we fail to acquire additional property rights to perfect our title to coal rights, we may have to reduce our estimated recoverable coal reserves.

Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine certain of our recoverable coal reserves has in the past been, and may again in the future be, adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations, which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional coal reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. As a result, our results of operations, business and financial condition may be materially adversely affected.

Our inability to acquire or develop 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 and surface land needed to ensure the reserves are economically recoverable to replace the reserves we produce. If we fail to acquire, gain access to 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, cash flows and ability to make cash distributions to our unitholders.

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. 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.


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Decreases in demand for electricity and changes in coal consumption patterns of 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. or international electric power generators would likely impact our business over the long term. According to the U.S. Energy Information Administration, in 2019, the domestic electric power sector accounted for approximately 91% of total U.S. coal consumption. In 2019, the Pennsylvania Mining Complex sold approximately 66% 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 economy and financial markets in the U.S. or in international markets;
overall demand for electricity;
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.

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. 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 power generators. 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.

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. 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.

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

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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.

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. 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 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.

A significant portion of our production is sold in international markets, which exposes us to additional risks and uncertainties.

For the fiscal years ended December 31, 2019, 2018 and 2017, approximately 35%, 29% and 31%, respectively, of our annual coal revenue was derived from customers who exported our coal outside the United States. Exports to Asia represent the majority of those sales. We believe that international markets will continue to account for a significant percentage of our revenue as we seek international expansion opportunities. Our international markets are subject to a number of material risks, including, but not limited to:

changes in a specific country's or region's political, economic or other conditions;
changes in U.S. government policy with respect to these foreign countries may inhibit export of our products and limit potential customers’ access to U.S. dollars in a country or region in which those potential customers are located;
we may experience difficulties in enforcing our legal contracts or the collecting of foreign accounts receivable in a timely manner and we may be forced to write off these receivables;
tariffs and other barriers may make our products less cost competitive or slow the ability of our customers to pay us for the coal that we sell overseas;
potentially adverse tax consequences to our customers may damage our cost competitiveness;
customs, import/export and other regulations of the countries in which our international customers are located may adversely affect our business;
currency fluctuations may make our coal less cost competitive, affecting overseas demand for our coal, or may indirectly expose us to currency fluctuation risks; and
geopolitical uncertainty or turmoil, including terrorism, war and natural disasters.

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Our sales are also affected by general economic conditions in our international markets. A prolonged economic downturn in international markets could have a material adverse effect on our business. Negative developments in one or more countries or regions in which our coal is exported could result in a reduction in demand for our coal, the cancellation or delay of orders already placed, difficulties in producing and delivering our products, difficulty in collecting receivables or a higher cost of doing business, any of which could negatively impact our business, financial condition, cash flows and results of operations. In addition, we may be exposed to legal risks under the laws of the countries outside the U.S. in which we do business, as well as the laws of the U.S. governing our business activities in those other countries, such as the U.S. Foreign Corrupt Practices Act.

We intend, if possible, to offset any potential adverse impact from various international risks (for example, tariffs) that may be imposed by governments in the countries in which one or more of our end users are located by reallocating our customer base to other countries or to the domestic U.S. markets.

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 or death to persons, damage to property and equipment and other potential legal or other liabilities. 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, either of which could materially and adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

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, 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.

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.


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Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and failure to obtain adequate insurance coverages could both have a material adverse effect on our business and results of operations.

Federal and state laws require us to obtain surety bonds or post letters of credit to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. The costs of surety bonds have fluctuated in recent years while the market terms of such bonds have generally become less favorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. In addition, federal and state regulators are considering making financial assurance requirements with respect to mine closure and reclamation more stringent. Because we are required by federal and state law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. Additionally, coal and other mining companies are increasingly struggling to obtain adequate insurance coverage for their business and operations. Our failure to obtain adequate insurance coverages could have a material adverse effect on our business and results of operations.

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 mining operations are conducted at a single mining complex located in the Northern Appalachian Basin in southwestern Pennsylvania and northern West Virginia. 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 and ability to make cash distributions to our unitholders.

Any significant downtime of our major pieces of mining equipment, including our preparation plant, or any inability to obtain equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs, 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. 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 or the cancellation of our supply contracts under which we obtain equipment could limit our ability to obtain these supplies or equipment.


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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.

Additionally, 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. 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.

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, 2019, approximately 88% 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.

We have customer concentration, so the loss of, or significant reduction in, purchases by our largest coal customers could adversely affect our business, financial condition, results of operations and cash flows.

We are exposed to risks associated with an increasingly concentrated customer base both domestically and globally. We derive a significant portion of our revenues from three domestic customers, each of which accounted for over 10% of our total coal sales revenue and aggregated approximately 70% of our coal sales revenue in fiscal year 2019. Domestic customer concentration has increased from fiscal year 2018. While the majority of our production is directed toward our established base of domestic power plant customers, many of which are secured through annual or multi-year sales contracts, we also have continued to diversify our portfolio by placing a growing portion of our production in the thermal and crossover metallurgical markets. We have a multi-year contract for the sale of coal to an exporter that began in the second quarter of 2018 and will extend through the second quarter of 2020.

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. 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.


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Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to collect payments from our customers for coal sold and delivered could be impaired if our customers' creditworthiness declines or if they fail to honor their contracts. Because our sales are concentrated to a few material customers, if the creditworthiness of a significant customer declines or the customer significantly delays payments to us, our business, cash flow and financial condition could be materially and adversely affected. Furthermore, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation or if we terminate a relationship with a significant customer due to credit risks, our revenue could decrease materially and we may have to reduce production at our mines until our customers’ contractual obligations are honored or we are able to replace a significant customer.

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 consistency. 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.

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


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A low ESG or sustainability score could result in the exclusion of our securities from consideration by certain investment funds and a negative perception of us by certain investors.

Certain organizations that provide corporate governance and other corporate risk information to investors and stockholders have developed scores and ratings to evaluate companies and investment funds based upon environmental, social and governance (“ESG”) or “sustainability” metrics. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders. Indeed, many investment funds focus on positive ESG business practices and sustainability scores when making investments. In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Companies in the energy industry generally, and in particular those focused on coal, natural gas or petroleum extraction and refining, often perform less well under ESG assessments compared to companies in other industries. Consequently, a low ESG or sustainability score could result in our securities, both debt and equity, from being excluded from the portfolios of certain investment funds and investors. As such, this could restrict our access to capital to fund our continuing operations and growth opportunities.

New or existing tariffs and other trade measures could adversely affect our results of operations, financial position, cash flows, and ability to make cash distributions.

New or existing tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows, either directly or indirectly through various adverse impacts on our significant customers. During the last several years, the Trump Administration imposed tariffs on steel and aluminum and a broad range of other products imported into the U.S. In response to the tariffs imposed by the U.S., the European Union, Canada, Mexico and China have announced tariffs on U.S. goods and services. Although some of these tariffs have been rescinded or suspended, these tariffs, along with any additional tariffs or trade restrictions that may be implemented by the U.S. or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal and metallurgical coal, limits on trade with the United States or other potentially adverse economic outcomes. Additionally, we sell coal into the thermal and metallurgical export markets. Accordingly, our international sales may also be impacted by the tariffs and other restrictions on trade between the U.S. and other countries. While tariffs and other retaliatory trade measures imposed by other countries on U.S. goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position, cash flows and ability to make cash distributions.

We may be unsuccessful in finding suitable acquisition targets or 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. However, our ability to grow our business through acquisitions may be limited by both our ability to identify appropriate acquisition candidates and our financial resources, including our available cash and borrowing capacity. Additionally, 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

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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.

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, including our failure to meet certain financial ratios included in such 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 $180,925 as of December 31, 2019, comprised of funds drawn under our Affiliated Company Credit Agreement, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $1,809. 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.

If we do not maintain effective internal controls over financial reporting, we could fail to accurately report our financial results.

During the course of the preparation of our financial statements, we evaluate our internal controls to identify and correct deficiencies in our internal controls over financial reporting. If we fail to maintain an effective system of disclosure controls or internal control over financial reporting, including satisfaction of the requirements of the Sarbanes-Oxley Act, we may not be able to accurately or timely report on our financial results or adequately identify and reduce fraud. As a result, the financial condition of our business could be adversely affected, current and potential future unitholders could lose confidence in us and/or our reported financial results, which may cause a negative effect on the trading price of our common units, and we could be exposed to litigation or regulatory proceedings, which may be costly or divert management's attention.


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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 and transporters.

Substantially all of our recoverable 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, while we may have to coordinate our mining with such oil and natural gas drillers and transporters, our mining activities will have priority over any oil and natural gas drillers and transporters with respect to the land covered by our permit. Oil and natural gas drillers and transporters may be subject to laws and regulations that are enforced by regulators that do not have jurisdiction over our activities. Any conflict between our rights and the enforcement actions by any regulator of oil or natural gas-specific rights that conflict with our rights to mine could result in additional cost and possible delays to mining.

For recoverable coal reserves outside of our permits, we engage in discussions with drilling and transport 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 could likewise make mining through those wells uneconomical, thereby effectively causing a loss of significant portions of our recoverable coal reserves, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

Our ability to operate our business effectively could be impaired if CONSOL Energy fails to attract and retain qualified 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 qualified personnel necessary to conduct our business. Efficient coal mining using modern techniques and equipment requires qualified 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 qualified 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 qualified 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.





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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, 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 cyberattacks than other targets in the United States. Deliberate attacks on our assets, or security breaches in our systems or infrastructure, 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. Similarly, our vendors or service providers could be the subject of such attacks or breaches that result in the risks of corruption or loss of our proprietary and sensitive data and/or the other disruptions as described above. In addition to existing risks, the adoption of new technologies may also increase our exposure to data breaches or our ability to detect and remediate effects of a breach. 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.

Regulation to address climate change (particularly greenhouse gas emissions) and uncertainty regarding such regulation may increase our operating costs, reduce the value of our coal assets and adversely impact the market for coal.

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 GHGs such as carbon dioxide and methane). Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide 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 and/or have elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative in the northeastern U.S. Any significant legislative changes at the international, national, state or local levels could significantly affect our ability to produce and sell our coal and develop our reserves, could increase the cost of the production and sale of coal and could materially reduce the value of our coal and recoverable coal reserves.

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. In

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addition, there have also been efforts in recent years affecting the investment community, including investment advisers, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities, encouraging the consideration of ESG practices of companies in a manner that negatively affects coal companies 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. These efforts, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-coal fuel sources, including natural gas and/or alternative energy sources, could cause coal prices and sales of our coal to materially decline and could cause our costs to increase. Further, climate change itself may cause more extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our services and increase our costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Furthermore, adoption of comprehensive legislation or regulation focusing on climate change or GHG emission reductions for the United States or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired plants, may make it more costly to operate coal-fired electric power generation plants and make coal less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, especially if such regulation or legislation makes our coal more expensive as a result of increased compliance, operating and maintenance costs. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal consumed by electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our 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. Although we cannot predict the ultimate impact of any legislation or regulation it is likely that any future laws, regulations or other policies aimed at reducing GHG emissions will negatively impact demand for our coal and could also negatively affect the value of our reserves and other assets.

We may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. For instance, our sponsor has been named as a defendant in litigation brought by the City of Baltimore seeking to hold our sponsor and other energy companies liable for the effects of climate change caused by the release of GHGs. The outcome of this litigation is uncertain, and we could incur substantial legal costs associated with defending this and similar lawsuits in the future. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these other lawsuits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

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, asset retirement obligations and restoration of mining properties after mining is completed and the protection of hydrologic, biologic and cultural resources. 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, our operational production schedules and competitive position. In addition, there is the possibility that we could incur substantial short and long-term liabilities as a result of violations under

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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 cause us to incur significant additional costs that could adversely affect our operating results, financial condition, cash flows and ability to make cash distributions.

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.

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. 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.

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. In addition, 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,” for which long-term water treatment may be required. 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 that are designed, constructed and inspected in accordance with stringent environmental and safety standards and are subjected 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. 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.

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. In support of our permit applications, we prepare and present data relating to the potential impact or effect that the proposed mining activity may have on the environment. 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. In recent years, as the requirements for mining permits have become more stringent, permit applications and regulatory agency permit decisions have been subject to extensive litigation by third parties, including environmental organizations. Challenges to permits are costly and may cause substantial operational delays, thereby adversely affecting our production, cash flows and profitability. 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. Section 404 permits have also been subject to a series of legal challenges, resulting in increased costs and operational delays. The slow pace with which the government issues permits needed for new operations and/or for on-going operations to continue mining continues to have significant negative effects and could materially and adversely affect our business.

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.


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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 asset retirement 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 and 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 final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total asset retirement obligations, which are based upon permit requirements and our experience, were approximately $11,755 at December 31, 2019. The amounts recorded are dependent upon a number of variables, including the estimated future expenditures, estimated mine lives, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient, 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 asset retirement obligations (“full cost bonding”). West Virginia is not a full cost bonding state. West Virginia has an alternative bond system for coal mine asset retirement obligations which consists of (i) individual site bonds posted by the permittee that are less than the full estimated asset retirement obligations 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. However, 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 asset retirement obligations. However, the costs of surety bonds have fluctuated in recent years and the market terms of such bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. In addition, federal and state regulators are considering making financial assurance requirements with respect to mine closure and asset retirement obligations more stringent. 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. Furthermore, because we are required by state and federal law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.

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.

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 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 incentive distributions;
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
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.

Our general partner and its affiliates, including CONSOL Energy, may engage in businesses that compete with us.

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, does 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.

Our Partnership Agreement requires that we distribute all of our available cash, if any, 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), if any, 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, cash distributions, if any, to our unitholders will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, if any, to our unitholders, 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 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

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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.

Our Partnership Agreement replaces our general partner’s fiduciary duties to holders of our units with contractual standards governing its duties.

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. However, the general partner is still subject to the implied contractual covenant of good faith and fair dealing, under which 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. Nevertheless, as a result of the elimination of fiduciary standards, 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 generally acts 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 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 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. Additionally, 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

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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 are determined by our general partner in its sole discretion, and fees due to our general partner and its affiliates for services provided are substantial and 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 are required to reimburse CONSOL Energy for the provision of certain administrative support services to us. Under our employee services agreement, we are 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 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. 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, 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 its 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 60.8% of our total outstanding common units on an aggregate basis. This will give CONSOL Energy the ability to prevent the removal of our general partner.

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 19.9% 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.


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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 maintain or 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;
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 16,811,818 common units. 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 on the NYSE or on any other trading market that may develop for our units.

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


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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 unitholders 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. As of December 31, 2019, our general partner owns approximately 60.8% 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) and therefore is not be able to exercise the call right as of such date.

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

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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 shareholders of 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 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,

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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. 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 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 take various accounting and reporting positions. The IRS may adopt or assert 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.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties

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and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

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.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, without regard to any deduction allowable for depreciation, amortization, or depletion but only, as set forth in proposed regulations, to the extent such depreciation, amortization or depletion is not capitalized into the cost of goods sold with respect to our inventory. If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

Tax-exempt entities 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), 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 taxable to those unitholders as unrelated business taxable income. With respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction) subject to the interim guidance issued by the Internal Revenue Service pending the issuance of applicable Treasury Regulations. As a result, for years, beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.

Non-U.S. unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. persons generally are taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business. Because we generate income that is effectively connected with a United States trade or business, distributions to non-U.S. unitholders will be deemed to be subject to withholding at the highest applicable effective tax rate, and each non-U.S. unitholder will be required to file U.S. federal income tax returns and pay tax on its allocable share of such effectively connected income. In addition, the Tax Cuts and Jobs Act of 2017 imposes a

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withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a United States trade or business. The IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships: however, proposed regulations issues in 2019 would end this suspension if finalized in their current form. If you are 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. 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 business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We 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.


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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 and 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 material properties. See “Business – Our Operations” in Item 1 of this Annual Report on Form 10-K for a description of our properties, incorporated herein by this reference. Our principal executive offices are located at 1000 CONSOL Energy Drive, Suite 100, Canonsburg, Pennsylvania 15317-6506.

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ccrmapjpegfilea08.jpgRecoverable Coal Reserves

The estimates of our recoverable coal reserves are estimated internally using the face positions of the Pennsylvania Mining Complex’s longwall mines as of December 31, 2019 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 recoverable coal reserves are proven and probable reserves 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, updated mine plans, 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 recoverable coal reserves is restricted to the exploration 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

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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 estimations 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 Coal Seam, estimates for proven reserves are based on points of observation that are equal to or less than 3,000 feet apart, 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 recoverable coal 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 recoverable 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, some of our reserves exhibit thermoplastic behavior suitable for cokemaking, which enables us, if market dynamics are favorable, to capture greater margins from selling this 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 recoverable coal reserves are commercially marketable.

The amount of coal we assign to a mining complex generally is sufficient to support mining through the duration of the applicable current mining permit. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured. In addition, mines may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible. Accessible reserves are recoverable coal 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 recoverable coal reserves which are either owned or leased. The leases have terms extending up to several 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, 2019:
 
 
 
 
 
 
 
Recoverable Coal Reserves (As-Received) (2,3,4)
 
 
 
 
 
As Received Heat Value (1) (Btu/lb)
 
 
Tons in Thousands
Mine/Reserve
Preparation Facility Location
Reserve Class
Coal Seam
Average Mining Height (feet)
Typical
Range
Owned (%)
Leased (%)
12/31/2019
12/31/2018
Bailey
Enon, PA
Assigned Operating
Pittsburgh
7.5
12,900
12,600 - 13,170
59
%
41
%
19,333

15,561

 
 
Accessible
Pittsburgh
7.5
12,890
12,820 - 13,110
43
%
57
%
9,484

25,271

Enlow Fork
Enon, PA
Assigned Operating
Pittsburgh
7.4
13,050
12,660 - 13,260
99
%
1
%
18,174

20,506

 
 
Accessible
Pittsburgh
7.6
12,910
12,460 - 13,340
74
%
26
%
62,952

62,901

Harvey
Enon, PA
Assigned Operating
Pittsburgh
6.9
13,060
12,850 - 13,230
90
%
10
%
10,295

10,910

 
 
Accessible
Pittsburgh
7.7
12,930
12,720 - 13,070
92
%
8
%
47,103

39,476

Total Assigned Operating and Accessible
 






167,341

174,625


(1) ) The heat values (gross calorific values) shown for reserves are based on the forecasted quality for each mine/reserve class, assuming that the coal is washed to an extent consistent with normal full-capacity operation of each mine’s/complex’s

45



preparation plant. 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.

(2) Recoverable coal reserves are estimated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This estimate 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) Because the continuity of the Pittsburgh coal seam is well known, and due to the minimal difference in the degree of assurance between observations points, recoverable reserves in this table represent the aggregation of proven and probable reserves that can be reasonably recovered considering all mining and preparation losses involved in producing a saleable product using existing mining methods under current law.

(4) Recoverable coal reserves incorporate losses for dilution and mining recovery based upon a 99% longwall mining recovery, a continuous mining recovery typically ranging from 25% to 40%, and a 95% preparation plant efficiency within the life of mine plan. Recoverable coal reserves are assessed using forward-looking prices derived from our forward contracts, various coal indices such as API 2, and other observable forward market indicators such as natural gas and electric power forward pricing to determine the reserves were economical.
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 17 “Commitments and Contingent Liabilities,” in the Notes to the 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.

46



PART II
ITEM 5.    MARKET FOR REGISTRANTS 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.

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 January 24, 2020, the number of registered holders of our common units was approximately nine. The Fourth Quarter 2019 cash distribution of $0.5125 per common unit was declared on January 24, 2020 to holders of record as of February 10, 2020 and will be paid on February 14, 2020.

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

Neither our sponsor nor the Partnership repurchased any of the Partnership's common units during the Fourth Quarter 2019.

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, if any, 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 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

47



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.


48



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 discussed in this section are in thousands, except for per unit or per ton amounts, unless otherwise indicated.

Overview

We are a master limited partnership formed in 2015 to manage and further develop all of our sponsor's active coal operations in Pennsylvania. Our primary strategy for growing our business 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, 2019, 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 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 Coal Seam, which is a large contiguous formation of high-Btu coal that is ideal for high-productivity, low-cost longwall operations. As of December 31, 2019, the Partnership’s portion of the Pennsylvania Mining Complex included 167,341 tons of recoverable coal reserves that are sufficient to support approximately 23.5 years of production. In addition, our reserves currently exhibit thermoplastic behavior suitable for cokemaking, 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.

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.


49


These non-GAAP financial measures should not be considered an alternative to total costs, total coal revenue, 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 and the way we calculate them 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.

Reconciliation of Non-GAAP Financial Measures

We evaluate our cost of coal sold and cash cost of coal sold on an aggregate basis. 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 includes items such as direct operating costs, royalty and production taxes, direct administration, and depreciation, depletion and amortization costs on production assets. Our costs exclude any indirect costs such as selling, general and administrative costs, freight expenses, interest expenses, depreciation, depletion and amortization costs on non-production assets 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.

The following table presents a reconciliation of cost of coal sold and 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.

 
Years Ended December 31,
 
2019
 
2018
Total Costs
$
287,377

 
$
290,609

Freight Expense
(4,917
)
 
(10,893
)
Selling, General and Administrative Expenses
(12,874
)
 
(13,931
)
Interest Expense, Net
(6,604
)
 
(6,667
)
Other Costs (Non-Production)
(5,650
)
 
(11,534
)
Depreciation, Depletion and Amortization (Non-Production)
(2,130
)
 
(2,166
)
Cost of Coal Sold
$
255,202

 
$
245,418

Depreciation, Depletion and Amortization (Production)
(43,677
)
 
(42,576
)
Cash Cost of Coal Sold
$
211,525

 
$
202,842


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.

The following table presents a reconciliation of average cash margin per ton to coal revenue, the most directly comparable GAAP financial measure, on a historical basis for each of the periods indicated.

50


 
Years Ended December 31,
 
2019
 
2018
Total Coal Revenue
$
322,132

 
$
341,073

Operating and Other Costs
217,175

 
214,376

Less: Other Costs (Non-Production)
(5,650
)
 
(11,534
)
Cash Cost of Coal Sold
211,525

 
202,842

Add: Depreciation, Depletion and Amortization
45,807

 
44,742

Less: Depreciation, Depletion and Amortization (Non-Production)
(2,130
)
 
(2,166
)
Cost of Coal Sold
$
255,202

 
$
245,418

Total Tons Sold
6,829

 
6,920

Average Revenue per Ton Sold
$
47.17

 
$
49.28

Average Cash Cost of Coal Sold per Ton
30.97

 
29.29

Add: Depreciation, Depletion and Amortization Costs per Ton Sold
6.40

 
6.17

Average Cost of Coal Sold per Ton
37.37

 
35.46

Average Margin per Ton Sold
9.80

 
13.82

Add: Depreciation, Depletion and Amortization Costs per Ton Sold
6.40

 
6.17

Average Cash Margin per Ton Sold
$
16.20

 
$
19.99


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


51


 
Years Ended December 31,
 
2019
 
2018
Net Income
$
45,551

 
$
66,566

Plus:
 
 
 
Interest Expense, Net
6,604

 
6,667

Depreciation, Depletion and Amortization
45,807

 
44,742

Unit-Based Compensation
1,409

 
1,842

Adjusted EBITDA
$
99,371

 
$
119,817

Less:
 
 
 
Cash Interest
7,473

 
7,217

Estimated Maintenance Capital Expenditures
35,911

 
35,949

Distributable Cash Flow
$
55,987

 
$
76,651

 
 
 
 
Net Cash Provided by Operating Activities
$
81,125

 
$
125,379

Plus:
 
 
 
Interest Expense, Net
6,604

 
6,667

Other, Including Working Capital
11,642

 
(12,229
)
Adjusted EBITDA
$
99,371

 
$
119,817

Less:
 
 
 
Cash Interest
7,473

 
7,217

Estimated Maintenance Capital Expenditures
35,911

 
35,949

Distributable Cash Flow
$
55,987

 
$
76,651

Minimum Distributions
$
57,619

 
$
57,392

Distribution Coverage Ratio
1.0

 
1.3





52



Results of Operations

Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Total net income was $45,551 for the year ended December 31, 2019 compared to $66,566 for the year ended December 31, 2018. 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,
 
2019
 
2018
 
Variance
Revenue:
 
Coal Revenue
$
322,132

 
$
341,073

 
$
(18,941
)
Freight Revenue
4,917

 
10,893

 
(5,976
)
Other Income
5,879

 
5,209

 
670

Total Revenue and Other Income
332,928

 
357,175

 
(24,247
)
Cost of Coal Sold:
 
 
 
 
 
Operating Costs
211,525

 
202,842

 
8,683

Depreciation, Depletion and Amortization
43,677

 
42,576

 
1,101

Total Cost of Coal Sold
255,202

 
245,418

 
9,784

Other Costs:
 
 
 
 
 
Other Costs
5,650

 
11,534

 
(5,884
)
Depreciation, Depletion and Amortization
2,130

 
2,166

 
(36
)
Total Other Costs
7,780

 
13,700

 
(5,920
)
Freight Expense
4,917

 
10,893

 
(5,976
)
Selling, General and Administrative Expenses
12,874

 
13,931

 
(1,057
)
Interest Expense, Net
6,604

 
6,667

 
(63
)
Total Costs
287,377

 
290,609

 
(3,232
)
Net Income
$
45,551

 
$
66,566

 
$
(21,015
)
Adjusted EBITDA
$
99,371

 
$
119,817

 
$
(20,446
)
Distributable Cash Flow
$
55,987

 
$
76,651

 
$
(20,664
)
Distribution Coverage Ratio
1.0

 
1.3

 
(0.3
)




53



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
 
2019
 
2018
 
Variance
Bailey
 
3,054

 
3,184

 
(130
)
Enlow Fork
 
2,511

 
2,469

 
42

Harvey
 
1,256

 
1,245

 
11

Total
 
6,821

 
6,898

 
(77
)

Coal production was 6,821 tons for the year ended December 31, 2019 compared to 6,898 tons for the year ended December 31, 2018. The Partnership’s coal production decreased slightly, mainly due to reduced production at the Bailey mine resulting from one additional longwall move and other operational delays. This was partially offset by increased production at the Enlow Fork mine, as geological conditions improved throughout the first half of 2019 compared to the year-ago period. The Harvey mine set an individual production record in 2019, exceeding its previous record set in 2018, and marking its third consecutive record-setting year.
Coal Operations

Coal revenue and cost components on a per unit basis for the years ended December 31, 2019 and 2018 are detailed 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,
 
2019
 
2018
 
Variance
Total Tons Sold
6,829

 
6,920

 
(91
)
Average Revenue per Ton Sold
$
47.17

 
$
49.28

 
$
(2.11
)
 
 
 
 
 
 
Average Cash Cost of Coal Sold per Ton (1)
$
30.97

 
$
29.29

 
$
1.68

Depreciation, Depletion and Amortization per Ton Sold (Non-Cash Cost)
6.40

 
6.17

 
0.23

Average Cost of Coal Sold per Ton
$
37.37

 
$
35.46

 
$
1.91

Average Margin per Ton Sold (1)
$
9.80

 
$
13.82

 
$
(4.02
)
Add: Depreciation, Depletion and Amortization Costs per Ton Sold
6.40

 
6.17

 
0.23

Average Cash Margin per Ton Sold (1)
$
16.20

 
$
19.99

 
$
(3.79
)
(1) Average cash cost of coal sold per ton, average margin per ton sold and average cash margin per ton sold are each 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 $322,132 for the year ended December 31, 2019 compared to $341,073 for the year ended December 31, 2018. The $18,941 decrease was primarily attributable to a $2.11 per ton lower average sales price per ton sold in the 2019 period, mainly driven by lower domestic netback contract pricing compared to the year-ago period, as well as a slight decrease in tons sold. This decrease was partially offset by an increase in prices the Partnership received for its export coal.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers for which we contractually provide transportation services. Freight revenue is completely offset in freight expense. Freight revenue and freight expense were both $4,917 for the year ended December 31, 2019 compared to $10,893 for the year ended December 31, 2018. The $5,976 decrease was due to decreased shipments to customers where we were contractually obligated to provide transportation services.


54



Other income is comprised of income generated by the Partnership relating to non-coal producing activities. Other income remained materially consistent in the period-to-period comparison.

Cost of Coal Sold

Cost of coal sold is comprised of operating costs related to produced tons sold, along with changes in both volumes and carrying values of coal inventory. 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 on production assets. Total cost of coal sold was $255,202 for the year ended December 31, 2019, or $9,784 higher than the $245,418 for the year ended December 31, 2018. Total costs per ton sold were $37.37 per ton for the year ended December 31, 2019 compared to $35.46 per ton for the year ended December 31, 2018. The increase in the total cost of coal sold was primarily driven by additional equipment rebuilds and longwall overhauls due to the timing of longwall moves and panel development. The Partnership also faced atypical challenges during 2019, including a roof fall and equipment breakdowns, which resulted in higher mine maintenance and project expenses. In addition, subsidence expense increased in the year-to-year comparison due to the timing and nature of properties undermined.

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 $5,920 for the year ended December 31, 2019 compared to the year ended December 31, 2018. The decrease was primarily attributable to additional costs incurred in the year-ago period related to externally purchased coal to blend and resell, discretionary employee benefit expense and demurrage charges.

Selling, General and Administrative Expense

Selling, General and Administrative expenses were $12,874 for the year ended December 31, 2019 compared to $13,931 for the year ended December 31, 2018. The $1,057 decrease was primarily related to lower short-term incentive compensation during 2019 compared to 2018.

Interest Expense

Interest expense, which primarily relates to obligations under our Affiliated Company Credit Agreement, remained materially consistent in the year-to-year comparison.

Adjusted EBITDA

Adjusted EBITDA was $99,371 for the year ended December 31, 2019 compared to $119,817 for the year ended December 31, 2018. The $20,446 decrease was primarily a result of a $3.79 decrease in the average cash margin per ton sold, coupled with 91 fewer tons sold during the year, which equated to a $27,624 decrease in Adjusted EBITDA. This was partially offset by lower non-production related costs as discussed above.

Distributable Cash Flow

Distributable cash flow was $55,987 for the year ended December 31, 2019 compared to $76,651 for the year ended December 31, 2018. The $20,664 decrease was primarily attributable to a $20,446 decrease in Adjusted EBITDA as discussed above.

Capital Resources and Liquidity

Liquidity and Financing Arrangements

Our ongoing sources of liquidity include cash generated from operations, borrowings under our Affiliated Company Credit Agreement, and, if necessary, the ability to issue additional equity or debt securities (either directly or indirectly). 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. The Partnership filed a universal shelf registration on Form S-3 (333-215962) on March 10, 2017, 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. Absent further action, this universal registration statement expires in March 2020.


55



We believe our strong contracted position, consistent cost control measures and liquidity will allow us to fund our 2020 capital and operating expenses. As further described below, we experienced longer delays in collections of accounts receivable in 2019. If these delays continue or become longer, we may have less cash flow from operations. As we move into 2020, we will continue to monitor the creditworthiness of our customers.

We started a capital construction project on the coarse refuse disposal area project in 2017, which is expected to continue through 2021. Our 2020 capital needs, including the coarse refuse disposal area project, are expected to be between $25,000 to $30,000, which is decreased from 2019 levels due to expected reductions in equipment-related expenditures and spending on building and structures.

We expect to generate adequate cash flows and liquidity to meet reasonable increases in the cost of supplies that are passed on from our suppliers. We will also continue to seek alternate sources of supplies and replacement material to offset any unexpected increase in the cost of supplies.

Uncertainty in the financial markets brings additional potential risks to the Partnership. These risks include declines in the Partnership's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact the Partnership's collection of trade receivables. As a result, the Partnership regularly monitors the creditworthiness of its customers and counterparties and manages credit exposure through payment terms, credit limits, prepayments and security. Given the state of the current global coal market, as well as the impact of trade tariffs, the Partnership has experienced slowing of collections within its customer group. The Partnership does not believe that this represents an abnormal business risk, and expects this trend to reverse in 2020 given the passage of the 'Phase I' trade agreement with China.

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 24, 2020, the Board of Directors of our general partner declared a cash distribution of $0.5125 per unit for the quarter ended December 31, 2019 to the limited partner unitholders and the holder of the general partner interest. The cash distribution will be paid on February 14, 2020 to the unitholders of record at the close of business on February 10, 2020.

Affiliated Company Credit Agreement

On November 28, 2017, the Partnership and the other Credit Parties entered into the Affiliated Company Credit Agreement by and among the Credit Parties, CONSOL Energy, as lender and administrative agent, and PNC, as collateral agent. On March 28, 2019, the Affiliated Company Credit Agreement was amended to extend the maturity date from February 27, 2023 to December 28, 2024. 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 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 amounts outstanding under the Partnership's prior credit facility. Additional drawings under the Affiliated Company Credit Agreement are available for general partnership purposes. 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, 2019, the Partnership had $180,925 of borrowings outstanding under the Affiliated Company Credit Agreement, leaving $94,075 of unused capacity. Interest on outstanding borrowings under the Affiliated Company Credit Agreement at December 31, 2019 was accrued at a rate of 4.00%.

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.

56



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, 2019, the Partnership was in compliance with its debt covenants with a first lien gross leverage ratio at 1.84 to 1.00 and a total net leverage ratio at 1.83 to 1.00.

Receivables Financing Agreement

On November 30, 2017, (i) CONSOL 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”), 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 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”). On August 30, 2018, the Securitization was amended, among other things, to extend the scheduled termination date to August 30, 2021.

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 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, ranging from 2.00% to 2.50% per annum, depending on the total net leverage ratio of CONSOL Energy. 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 agreements comprising the Securitization contain 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 certain 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, 2019, the Partnership, through CONSOL Thermal Holdings, sold $33,294 of trade receivables to CPCC. The Partnership has not derecognized the receivables due to its continued involvement in the collections efforts.
Cash Flows
 
For the Years Ended December 31,
 
2019
 
2018
 
Variance
Cash flows provided by operating activities
$
81,125

 
$
125,379

 
$
(44,254
)
Cash used in investing activities
$
(37,171
)
 
$
(30,973
)
 
$
(6,198
)
Cash used in financing activities
$
(44,414
)
 
$
(94,936
)
 
$
50,522


57




Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018:

Cash provided by operating activities decreased $44,254 in the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to a $21,015 decrease in net income, a slowing of customer collections in 2019 compared to an acceleration of customer collections in 2018, and other working capital changes that occurred throughout both periods.

Cash flows used in investing activities increased $6,198 in the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily as a result of increased capital expenditures of $6,034, mainly due to an increase in airshaft construction projects, belt system related expenditures, purchases of land and equipment, and rebuilds of owned equipment. The table below represents various items for which cash was used for investing activities during the years ended December 31, 2019 and December 31, 2018.
 
For the Years Ended December 31,
 
2019
 
2018
 
Variance
Building and Infrastructure
$
16,223

 
$
11,196

 
$
5,027

Equipment Purchases and Rebuilds
10,671

 
9,437

 
1,234

Refuse Storage Area
7,931

 
8,572

 
(641
)
Other
2,352

 
1,938

 
414

Total Capital Expenditures
$
37,177

 
$
31,143

 
$
6,034


Cash flows used in financing activities decreased $50,522 in the year ended December 31, 2019 compared to the year ended December 31, 2018. The decrease in cash used in financing activities was primarily due to lower discretionary payments made under the Affiliated Company Credit Agreement. Net proceeds received under the Affiliated Company Credit Agreement were $17,925 in the year ended December 31, 2019, compared to net payments of $33,583 in the year ended December 31, 2018.
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 (Significant Accounting Policies) of the audited consolidated financial statements included elsewhere in this report for a complete listing of our accounting policies.

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 primarily relate to the reclamation of land upon mine closure, the treatment of mine water discharge where necessary, and the plugging of gas wells acquired for mining purposes. Changes in the assumptions used to calculate the liabilities can have a significant effect on the asset retirement obligations. 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

58



necessary. Estimates of our total asset retirement obligations, which are based upon permit requirements and our engineering expertise related to these requirements, including the current portion, were $11,755 at December 31, 2019 and $10,977 at December 31, 2018. 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.

Recoverable 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 recoverable coal 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:

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 recoverable coal 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 recoverable coal reserves will likely vary from estimates, and these variances may be material.

59



ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
Page
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the Years Ended December 31, 2019 and 2018
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019 and 2018
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2019 and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019 and 2018
Notes to the Consolidated Financial Statements


60



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, 2019 and 2018, and the related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, 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 14, 2020


61



CONSOL COAL RESOURCES LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit data)


 
For the Years Ended December 31,
 
2019
 
2018
Coal Revenue
$
322,132

 
$
341,073

Freight Revenue
4,917

 
10,893

Other Income
5,879

 
5,209

Total Revenue and Other Income
332,928

 
357,175

 
 
 
 
Operating and Other Costs 1 
217,175

 
214,376

Depreciation, Depletion and Amortization
45,807

 
44,742

Freight Expense
4,917

 
10,893

Selling, General and Administrative Expenses 2
12,874

 
13,931

Interest Expense, Net 3
6,604

 
6,667

Total Costs
287,377

 
290,609

Net Income
$
45,551

 
$
66,566

 
 
 
 
Less: General Partner Interest in Net Income
768

 
1,127

Limited Partner Interest in Net Income
$
44,783

 
$
65,439

 
 
 
 
Net Income per Limited Partner Unit - Basic
$
1.62

 
$
2.38

Net Income per Limited Partner Unit - Diluted
$
1.62

 
$
2.37

 
 
 
 
Limited Partner Units Outstanding - Basic
27,622,032

 
27,511,804

Limited Partner Units Outstanding - Diluted
27,659,790

 
27,611,924

 
 
 
 
Cash Distributions Declared per Unit 4
$
2.05

 
$
2.05


1 Related Party of $3,219 and $2,918 for the years ended December 31, 2019 and 2018, respectively.
2 Related Party of $8,309 and $8,300 for the years ended December 31, 2019 and 2018, respectively.
3 Related Party of $