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, 20182019
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, PA15317-6506
(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 | 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 o☐Nox☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o☐Nox☒
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. Yesx☒ No o☐
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). Yesx☒ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (check one):
Large accelerated filer o☐Accelerated filerx☒ Non-accelerated filer o☐ Smaller Reporting Company x ☒Emerging Growth Company x☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act x☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐No x☒
The aggregate value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $161,736,496$177,872,584 as of June 30, 2018,28, 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 15,911,21127,632,824 common units, 11,611,067 subordinated units and a 1.7% general partner interest outstanding at January 25, 2019.24, 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 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 | |
| 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.” Prior to November 28, 2017, we were called CNX Coal Resources LP and our common units traded on the New York Stock Exchange under the ticker “CNXC”.
“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; following the PA Mining Acquisition, CONSOL Thermal Holdings owns a 25% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania Mining Complex.
“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).
“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. From the closing of the PA Mining Acquisition in September 2016 until November 28, 2017, theThe Pennsylvania Mining Complex wasis owned 75% by our former sponsor and its subsidiaries and 25% by CONSOL Thermal Holdings. In connection with the separation, our former sponsor's undivided interest in the Pennsylvania Mining Complex was transferred to CONSOL Energy.
“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. In connection with the completion of the IPO, we issuedOn August 16, 2019, all 11,611,067 subordinated units, to our former sponsor. In connection with the separation and the Affiliated Company Credit Agreement, allwhich 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 were transferred directly to CONSOL Energy.units.
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. |
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 are displayed in thousands.amounts, unless otherwise indicated.
At December 31, 2018,2019, 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 No. 8 Coal Seam, which is a large contiguous formation of uniform, high-Btu coal that is ideal for high-productivity, low-cost longwall operations. As of December 31, 2018,2019, our portion of the Pennsylvania Mining Complex included 174,625167,341 tons of recoverable coal reserves with an average gross heat content of approximately 12,907 Btus per pound and approximately 3.6 pounds of sulfur dioxide (“SO2”) per million British thermal units (“lb SO2/mmBtu”). Based on our current production capacity, these reservesthat are sufficient to support approximately 2523.5 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.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 7,1257.1 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 under the ticker symbol “CNXC”.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, our former sponsor contributed to the Partnershipwe 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 from our former sponsor 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.
Our primary strategy for growing our business and increasing distributions to our unitholders is to increase operating efficiencies to maximize realizations and make acquisitions that increase our distributable cash flow. The primary component of our growth strategy is based upon our expectation of future divestitures by CONSOL Energy to us of portions of its retained 75% undivided interest in the Pennsylvania Mining Complex.
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, 2018:2019:
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 and its former parent and predecessors have been mining coal, primarily in the Appalachian Basin, since 1864. CONSOL Energy deploys an organic growth strategy focused on efficiently developing its resource base. CONSOL Energy’s premium coal grades are sold to electricity generators, steel makers, coke producers and industrial consumers, both domestically and internationally. CONSOL Energy is
listed on the NYSE under the symbol “CEIX” and had a market capitalization of approximately $870.1$376.3 million as of December 31, 2018.2019.
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 2523.5 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, 2018,2019, the Partnership’s portion of the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 40,83228,817 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 4.1.4.4. 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 2017 and 2016,2017, our portion of the Bailey Mine produced 3,054 tons, 3,184 tons 3,031 tons and 3,0143,031 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, 2018,2019, the Partnership’s portion of the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 83,40781,126 tons of recoverable coal reserves with an average as-received gross heat content of approximately 12,93512,940 Btus per pound and an approximate average lb SO2/mmBtu of 3.2.3.3. 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 2017 and 2016,2017, our portion of the Enlow Fork Mine produced 2,511 tons, 2,469 tons 2,295 tons and 2,4092,295 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, 2018,2019, the Partnership’s portion of the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 50,38657,398 tons of recoverable coal reserves with an average as-received gross heat content of approximately 12,87312,950 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 2017 and 2016,2017, our portion of the Harvey Mine produced 1,256 tons, 1,245 tons 1,201 tons and 7431,201 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
In 2019,2020, the Partnership expects to invest $34,000-$25,000-$38,00030,000 in maintenance capital expenditures, which is increaseddecreased from 20182019 levels due to additional expected capitalreductions in equipment-related expenditures related to airshaft construction projects, as well as additional belt system 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, and which contracts are administered at our direction by a wholly owned subsidiary of CONSOL Energy administers under thea contract agency agreement, at our direction as “our contracts”. We are greater than 95% contracted for 2019, 53% contracted forFor 2020 and 28%2021, our contracted for 2021,position, as of February 11, 2020, is at 95% and 43%, respectively, assuming an annual production ratecoal sales volume at the midpoint of approximately 6,750 tons. With our planned coal production in 2019 largely sold out, our focus now has shifted to maximizing realizations for any additional production and booking additional sales for contract years 2020 and 2021.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, and 2016, approximately 68%88%, 68% and 80%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 20182019 sales tons, approximately 68%66% were sold to U.S. electric generators, 29%33% were priced on export markets and 3%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 2018,2019, we derived greater than 10%70% of our total coal sales revenue from our top three
customers. As of January 1, 2019,2020, we had sixmultiple sales agreements with these customers that expire at various times in 2019, 2020 and 2021.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
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.
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 burned and thecombusted. The CAA regulates specific emissions, such as sulfur,nitrogen oxides, particulate matter, mercury and mercury. Theseother 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 could 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— including plants the Partnership sells coal to—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. EPA’sThe EPA's 2012 Mercury and Air Toxics Standards rule (“MATS Rule”) established NSPS for coal-fired electric generating units foremissions of particulate matter, (“PM”), 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 ana NSPS, pollutants regulated by a NESHAP require the maximum achievable control technology (“MACT”)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, andRule. The rule was remanded the case 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 28,27, 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 emissionemissions 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”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,Criteria Pollutants, which could directly or indirectly impact mining operations through the identificationdesignation 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. The primary NAAQS set the permissible level of a particular criteria pollutantFinal rules may require significant investment in emissions control technologies by our customers in the ambient air. Inelectric 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)(“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.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.
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 (“PM2.5”) and ozone by requiring
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.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. Implementation ofIn October 2016, the EPA finalized revisions to the CSAPR, is being accomplishedknown 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. In September 2016,On December 6, 2018, the EPA finalized revisionsissued the CSAPR “Close-Out” Rule, a final determination that the CSAPR achieves requirements with respect to the CSAPR. As of May 2017, this2008 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 limits summertime NOX emissions from power plants in 22was challenged by several states and other entities in the eastern United States, which may have an impact on how coal-fired electric-generating units are utilized in this region.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 Power PlanEnergy Rule. On September 20, 2013,In August 2018, the EPA issuedpublished a new proposal,proposed rule, the Affordable Clean Energy (“ACE”) rule, to replace the 2015 “Carbon Pollution Standard for New Power Plants”, to establishknown as the Clean Power Plan (“CPP”). The CPP, which established separate NSPS for carbon dioxide (“CO2”) emissions for natural gas-fired turbines and coal-fired units. This rulenew, modified, or reconstructed power plants under the CAA, was finalized in late 2015, immediately challenged by multiple parties and in August 2017 waswith its effective date ultimately being stayed by the D.C. Circuit to allow the Trump Administration's EPA to review the rule.
National Environmental Policy Act. The National Environmental Policy Act (“NEPA”). 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 ourcertain permitting applications and adoption of land management actions. When we propose activities that fall under federal jurisdiction, we are subjectjurisdiction. NEPA reviews require federal agencies to NEPA reviews,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 April 2017, pursuant to executive order,June 2018, the White House Council on Environmental Quality (“CEQ”) — the federal agency charged with overseeing implementation of NEPA — withdrew its “Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews.” This guidance previously directed agencies to consider proposed actions’ effects on climate change (including GHG emission), and may have created additional delays and costs in the NEPA review process for the energy industry that are now no longer in place. Additionally, pursuant to Executive Order 13807 issued in August 2017, the CEQ has issued an Advance Notice of Proposed Rulemaking on NEPA that seeksseeking 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 CEQ’sdraft guidance seeks to clarify the scope of review federal agencies should undertake when considering the effects of GHG emissions under NEPA. A final proposed revisions to NEPA have yetrule is expected to be updated, though the comment period for the rulemaking closed August 2018. Nevertheless, certain Federalpublished in 2020. Certain federal courts have held that GHGs must be considered under NEPA prior to a federal agency taking a “major Federal action.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.
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 and other oil and gas 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”) and/orunder Section 404, as well as a dischargecorresponding permit from the state regulatory authority under the state counterpart toSection 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 early 2009, EPA took a number2012, multiple citizen suits have been filed alleging violations of initiativesnumeric and narrative water quality standards that have resulted in delaysbroadly prohibit effects to aquatic life. The suits seek penalties and obstruction of the issuance of such permits for surface mining operations in the Appalachian states, including Pennsylvania where the Pennsylvania Mining Complex is located. Increased oversight of delegated state programmatic authority, coupled with individual permit review and additional requirements imposed by EPA, has resulted in delays in the review and issuance of permits. In addition, the Spill Prevention, Control and Countermeasure (“SPCC”) requirements of the CWA apply to all our operations that use or produce oil and require the implementation of plans to address any spills and the installation of secondary containment around all storage tanks. These requirements under the CWA and SPCC may cause us to incur significant additional costsinjunctive relief that could adverselylimit 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 operating results, financial condition and cash flows.operations. See Item 3, “Legal Proceedings,” regarding certain actions pertaining to our operations.
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 new proposal would lessen the number of waterbodies subjectrepeal 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 as comparedis expected to the Clean Water Rule.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. The applicability date ofOn November 22, 2019, the stricter effluent limits isEPA published its proposed revisions to the subject of on-going litigation. Nevertheless,stringent limitations and standards included in the combined effect of the Coal Combustion Residuals (“CCR”)2015 final ELG rule, (discussed below) and ELG regulations has compelled power generating companies to close existing ash ponds and may force the closure of certain older existing coal burningwhile establishing a voluntary incentive program which provides power plants that cannot comply with the new standards.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 operational minesmining activities. While SMCRA is a comprehensive statute, it does not supersede other major statutes such as well as reclamation standards for reclaiming post-operational, mined land. Thethe 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 responsible for issuing permits applying these standards to individual mining operations. However, states that operate federally approved state programs may impose standards whichat least as stringent as the federal program. Our active operations are more stringent than the requirements of SMCRA and OSM’s regulations and in many instances have done so. The Pennsylvania Mining Complex is located in states which have achieved primary jurisdiction for enforcement of SMCRA, 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 approvedcomment, 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 programs. 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 unreclaimed and abandoned mine lands mined, closed, or abandoned before 1977.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 (“ESA”). The federal ESA and other related federal and state statutes protect species that have been classified as endangered or threatened with possible extinction.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 vegetation.water discharges. A number of species indigenous to our operating areas are protected under the ESA;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.
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 Comprehensive Environmental Response, CompensationSafe Drinking Water Act, the Emergency Planning and LiabilityCommunity 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 (“SCSR”) devices underground;
the purchase and installation of electronic communication and personal tracking devices underground;
the purchase and installation of proximity detection devices on continuous miner machines;
the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;
the purchase of new fire resistant conveyor belting underground;
additional training and testing that creates the need to hire additional employees;
more stringent rock dusting requirements; and
the purchase of personal dust monitors for collecting respirable dust samples from certain miners.
On 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.
strengthens protection for miners by reducing the potential of pinning, crushing and striking hazards that result in accidents involving life-threatening injuries and death. The final rule became effective March 15, 2015 and included a phased in schedule for newly manufactured and in-service equipment.
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 in 2018 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 back 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 capped at 2% of the coal's selling price.and up to $0.55 per ton for surface-mined coal), effective through December 31, 2020.
The Patient Protection and Affordable Care Act (“PPACA”) made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner’s work. Second, it changed the law so that black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner’s death. 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 producingcoal-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
CONSOL Energy or its subsidiaries and are subject to the employee services agreement. As of December 31, 2018,2019, CONSOL Energy employed approximately 1,5721,594 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 (large accelerated filer);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, will beis 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, andSEC. 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 and subordinated unitholders.
In order to support the payment of the minimum quarterly distribution of $0.5125 per common and subordinated unit per quarter, or $2.05 per common and subordinated unit on an annualized basis, we must generate distributable cash flow of approximately $14,348$14,405 per quarter, or approximately $57,392$57,619 per year, based on the number of common units, subordinated units and the general partner interest outstanding as of December 31, 2018.2019.
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,
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 and increasing distributions to our unitholders is to increase operating efficiencies to maximize realizations and make acquisitions that increase our distributable cash flow. The primary component of our growth strategy is based upon our expectation of future divestitures by CONSOL Energy to us of portions of its currently retained 75% undivided interest in the Pennsylvania Mining Complex. CONSOL Energy is under no obligation to sell us additional undivided interests in the Pennsylvania Mining Complex and we are under no obligation to purchase additional undivided interests in the Pennsylvania Mining Complex from CONSOL Energy. We may never purchase additional undivided interests in the Pennsylvania Mining Complex for several reasons, including the following:
CONSOL Energy may choose not to sell any portion of its undivided interests in the Pennsylvania Mining Complex;
we may not make offers to buy any additional interests in the Pennsylvania Mining Complex;
we and CONSOL Energy may be unable to agree to terms acceptable to both parties;
we may be unable to obtain financing to purchase additional undivided interests in the Pennsylvania Mining Complex on acceptable terms or at all; or
we may be prohibited by the terms of our debt agreements (including the Affiliated Company Credit Agreement) or other contracts from purchasing additional undivided interests in the Pennsylvania Mining Complex, and CONSOL Energy may be prohibited by the terms of its debt agreements or other contracts from selling all or any portion of it. If we or CONSOL Energy must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of CONSOL Energy’s undivided interests in the Pennsylvania Mining Complex, we or CONSOL Energy may be unable to do so in a timely manner or at all.
We can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of CONSOL Energy’s retained 75% undivided interest in the Pennsylvania Mining Complex. If CONSOL Energy reduces its ownership interest in us, it may be less willing to sell to us additional undivided interests in the Pennsylvania Mining Complex. 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 increasemaintain 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
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 thatand 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 flows.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.
Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.
Our business is closely linked to domestic demand for electricity, and any changes in coal consumption by U.S. or international electric power generators would likely impact our business over the long term. According to the U.S. Energy Information Administration, (EIA), in 2018,2019, the domestic electric power sector accounted for approximately 92%91% of total U.S. coal consumption. In 2018,2019, the Pennsylvania Mining Complex sold approximately 68%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 U.S. 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
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.
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.
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.
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, 20182019, approximately 68%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 derivedare 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 from which we generated an aggregate ofand aggregated approximately 57%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. Additionally,
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 theirour customers' creditworthiness declines or if they fail to honor their contracts with us. Ifcontracts. Because our sales are concentrated to a few material customers, if the creditworthiness of our customersa 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 willcould decrease materially and we may have to reduce production at our mines until our customers’ contractual obligations are honored. Our inabilityhonored or we are able to collect payment from counterparties to our sales contracts may havereplace a materially adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.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 consist.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 or raise the level of our future cash distributions over the long term. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional units or other equity securities. Using cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control.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.
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. Recently,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. The newAlthough 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
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 $163,000$180,925 as of December 31, 2018,2019, 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 $1,630.$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 stockholdersunitholders could lose confidence in us and/or our reported financial results, which may cause a negative effect on the trading price of our common stock,units, and we could be exposed to litigation or regulatory proceedings, which may be costly or divert management's attention.
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.
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 skilledqualified 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 skilledqualified personnel necessary to conduct our business. Efficient coal mining using modern techniques and equipment requires skilledqualified 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 skilledqualified 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 skilledqualified labor in the future, our labor and overall productivity or costs could be materially adversely affected. In the future, we may utilize a greater number of external contractors for portions of our operations. The costs of these contractors have historically been higher than that of our employed laborers. If CONSOL Energy’s labor and contractor prices increase, or if it experiences materially increased health and benefit costs with respect to its employees, our results of operations could be materially adversely affected.
None of CONSOL Energy’s employees who conduct mining operations at the Pennsylvania Mining Complex are currently represented by a labor union or covered under a collective bargaining agreement, although many employers in our industry have employees who belong to a union. It is possible that our employees who conduct mining operations at the Pennsylvania Mining Complex may join or seek recognition to form a labor union, or CONSOL Energy may be required to become a labor agreement signatory. If some or all of the employees who conduct mining operations at the Pennsylvania Mining Complex were to become unionized, it could adversely affect productivity, increase labor costs and increase the risk of work stoppages at our mines. If a work stoppage were to occur, it could interfere with operations at the Pennsylvania Mining Complex and have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions. In addition, the mere fact that a portion of CONSOL Energy’s labor force could be unionized may harm our reputation in the eyes of some investors and thereby negatively affect our common unit price.
We do not have any officers or employees and rely on officers of our general partner and employees of CONSOL Energy.
We are managed and operated by the board of directors and executive officers of our general partner. Our general partner has no field-level employees that conduct mining operations and relies on the employees of CONSOL Energy to conduct mining activities. CONSOL Energy conducts businesses and activities of its own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to both our general partner and to CONSOL Energy. If our general partner and the officers and employees of CONSOL Energy do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.
We are a holding company with no independent operations or assets. Distributions to our unitholders are dependent on cash flow generated by our subsidiaries.
We have a holding company structure, meaning the sole source of our earnings and cash flow consists exclusively of the earnings of and cash distributions from our direct and indirect subsidiaries. All of our operations are conducted, and all of our assets are owned, by our direct and indirect subsidiaries. Consequently, our cash flow and our ability to meet our obligations or to pay cash distributions to our unitholders will depend upon the cash flows of our subsidiaries and the payment of funds by our subsidiaries to us in the form of distributions or otherwise. The ability of our subsidiaries to make any payments to us will
depend on their earnings, the terms of their indebtedness and legal restrictions applicable to them. In particular, the terms of our Affiliated Company Credit Agreement place limitations on the ability of our subsidiaries to pay distributions to us, and thus on our ability to pay distributions to our unitholders. In the event that we do not receive distributions from our subsidiaries, we may be unable to make cash distributions to our unitholders.
Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.
We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber attackscyberattacks than other targets in the United States. Deliberate attacks on our assets, or security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. 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, and reduce the value of our coal assets.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 greenhouse gases (“GHGs”)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. While climate change legislation in the U.S. is unlikely in the next several years, numerousNumerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other statesboundaries 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
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 environmental, social and governance (ESG)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.
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.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, reclamationasset 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
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. Recent EPA rulemakingRulemaking 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.
The Federal Coal Mine Safety and Health Act and Mine Improvement and New Emergency Response Act impose stringent health and safety standards on mining operations. Regulations that have been adopted are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures and other matters. Most states in which we operate have programs for mine safety and health regulation and enforcement. The various requirements mandated by law or regulation can place restrictions on our methods of operations, and potentially lead to penalties for the violation of such requirements, creating a significant effect on operating costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shutdown based on safety considerations. If an incident were to occur at one of our coal mines, it could be shut down for an extended period of time and our reputation with our customers could be materially damaged.
We have reclamation, mine closing obligations and gas well pluggingasset 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 reclamation, mine-closing and degasification and well plugging liabilities,asset retirement obligations, which are based upon permit requirements and our experience, were approximately $10,977$11,755 at December 31, 2018.2019. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs,expenditures, estimated proved reserves,mine lives, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient, or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected. Most states where we operate require us to post bonds for the full cost of coal mine reclamation (fullasset retirement obligations (“full cost bonding)bonding”). West Virginia is not a full cost bonding state. West Virginia has an alternative bond system (ABS) for coal mine reclamationasset retirement obligations which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamationasset 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 reclamationasset 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 reclamationasset 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:
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 a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;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, willdoes 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, our required 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 or increase our per unit distribution level. There are no other limitations in our Partnership Agreement on our ability to issue additional partnership interests, including partnership interests ranking senior to our common units as to distributions or in
liquidation or that have special voting rights and other rights, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional partnership interests. The incurrence of additional commercial bank borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.
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 intendsgenerally 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 common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that 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
committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Cost and expense reimbursements, which will beare determined by our general partner in its sole discretion, and fees due to our general partner and its affiliates for services provided will beare substantial and will reduce our distributable cash flow.
Under our Partnership Agreement, we are required to reimburse our general partner and its affiliates for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner and its affiliates in connection with managing and operating our business and affairs (including expenses allocated to our general partner by its affiliates). Except to the extent specified under our omnibus agreement and the other agreements described under “Certain Relationships and Related Party Transactions—Agreementswith Affiliates,” our general partner determines the amount of these expenses. Under the terms of the omnibus agreement we will beare required to reimburse CONSOL Energy for the provision of certain administrative support services to us. Under our employee services agreement, we
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 61.0%60.8% of our total outstanding common units and subordinated units on an aggregate basis. This will give CONSOL Energy the ability to prevent the removal of our general partner.
The restrictions in our Partnership Agreement applicable to holders of 20% or more of any class of our outstanding partnership interests do not apply to Greenlight Capital.
Unitholders’ voting rights are restricted by the Partnership Agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons or groups who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. In connection with the Concurrent Private Placement, our general partner waived this provision with respect to Greenlight Capital. As a result of this waiver, the common units purchased by Greenlight Capital in the Concurrent Private Placement are generally considered to be outstanding under our Partnership Agreement and will be entitled to vote on any matter on which the common unitholders are otherwise entitled to vote. Greenlight Capital owns 34.5%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.
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 5,174,45416,811,818 common units and 11,611,067 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. In addition, Greenlight Capital holds 5,488,438 common units, per public filings. We also agreed to provide CONSOL Energy and Greenlight Capital with certain registration rights under applicable securities laws. The sale of these units described above in the public or private markets could have an adverse impact on the price of the common units on the NYSE or on any other trading market that may develop.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.
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. OurAs of December 31, 2019, our general partner owns approximately 32.5%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). At the end of the subordination period, our general partner will own approximately 61.0% of our
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to the common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the Partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our Partnership Agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the Partnership are not counted for purposes of determining whether a distribution is permitted.
CONSOL Energy, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or our common unitholders. The exercise of this election could result in lower distributions to our common unitholders in certain situations.
CONSOL Energy has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters and the amount of such distribution did not exceed the adjusted operating surplus for such quarter, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If CONSOL Energy elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to CONSOL Energy will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in such two quarters. We anticipate that CONSOL Energy would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that CONSOL Energy could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units and general partner interests in connection with resetting the target distribution levels. Additionally, CONSOL Energy has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as CONSOL Energy relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled.
Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption.
As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption. “Eligible holders” are limited partners whose (or whose owners’) (i) U.S. federal income
tax status or lack of proof of U.S. federal income tax status does not have and is not reasonably likely to have, as determined by our general partner, a material adverse effect on the maximum applicable rates that can be charged to customers by us or our subsidiaries and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to create, as determined by our general partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest. The aggregate redemption price for redeemable interests will be an amount equal to the current market price (the date of determination of which will be the date fixed for redemption) of limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these
purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not an eligible holder will not be entitled to voting rights.
Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which limits our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.
Our Partnership Agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine. In addition, our Partnership Agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, are not subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to 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 a maximum of 21%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to a unitholder. In addition,
changes in current state law may subject us to additional entity-level taxation by individual states. Because of state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce our distributable cash flow. Therefore, if we were treated as a corporation for U.S. federal income tax purposes, or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our units.
Our unitholders’ allocated share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the U.S. federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. We intend to furnish to each unitholder within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his or her share of our income, gains, losses and deductions for our preceding taxable year. In preparing this information, we will take various accounting and reporting positions. The IRS may adopt 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
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 and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be 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 taxablesubject to them. DistributionsUnited 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. personsunitholders will be reduced bydeemed to be subject to withholding taxes at the highest applicable effective tax rate, and each non-U.S. personunitholder will be required to file U.S. federal income tax returns and pay tax on its allocable share of our taxablesuch effectively connected income. In addition, the Tax Cuts and Jobs Act of 2017 imposes a
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 tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our units.
We will treat each purchaser of units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
Because we cannot match transferors and transferees of units and because of other reasons, we adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations, promulgated under the Internal Revenue Code of 1986 (the “Code”) referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. Our tax counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from a sale of units and could have a negative impact on the value of our units or result in audit adjustments to your tax returns.
We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first 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.
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 significantmaterial 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.
Recoverable Coal Reserves
The estimates of our recoverable coal reserves are calculatedestimated internally using the face positions of the Pennsylvania Mining Complex’s longwall mines as of December 31, 20182019 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”“Proven (Measured) Reserves” and “probable (indicated) reserves,“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) |
| • | “Probable (Indicated) Reserves.” Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and |
measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
Spacing of points of observation for confidence levels in our reserve calculationsestimations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). Our estimates for proven reserves have the highest degree of geologic assurance. Because of the well-known continuity of the Pittsburgh No. 8 Coal Seam, estimates for proven reserves are based on points of observation that are equal to or less than 3,000 feet 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 currently exhibit thermoplastic behavior suitable for cokemaking, which enables us, if market dynamics are favorable, to capture greater margins from selling ourthis 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. For the years ended December 31, 2018, 2017 and 2016, our portion of the Pennsylvania Mining Complex sold approximately 0.4 million tons, 0.4 million tons and 0.5 million tons of coal, respectively, in the metallurgical market.
The amount of coal we assign to a mining complex generally is sufficient to support mining through the duration of the applicable current mining permit. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured. In addition, mines may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible. Accessible reserves are 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, 2018 (tons in thousands):2019:
As Received Heat Value (1) (Btu/lb) | Recoverable Coal Reserves (2)(3) | ||||||||||||||||||
| Mine | Reserve Class | Average Seam Thickness (feet) | Typical | Range | As Received lb SO2 / mmBtu | Owned (%) | Leased (%) | Total (tons) | |||||||||||
| Bailey: | Assigned | 7.4 | 12,940 | 12,810 - 13,040 | 3.7 | 41 | % | 59 | % | 15,561 | |||||||||
| Accessible | 7.5 | 12,860 | 12,670 - 13,140 | 4.3 | 65 | % | 35 | % | 25,271 | ||||||||||
| Enlow Fork: | Assigned | 7.5 | 13,010 | 12,850 - 13,190 | 2.9 | 95 | % | 5 | % | 20,506 | |||||||||
| Accessible | 7.6 | 12,910 | 12,650 - 13,150 | 3.3 | 74 | % | 26 | % | 62,901 | ||||||||||
| Harvey: | Assigned | 6.9 | 13,030 | 12,900 - 13,200 | 3.0 | 93 | % | 7 | % | 10,910 | |||||||||
| Accessible | 7.7 | 12,830 | 12,790 - 13,190 | 4.0 | 99 | % | 1 | % | 39,476 | ||||||||||
| Total | 174,625 | ||||||||||||||||||
| 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 Assigned Operating reserves are based on the 2018 actual quality and five-year 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
preparation plant. Actual quality is based on laboratory analysis of samples collected from coal shipments delivered in 2018. Forecasted quality is derived from exploration sample analysis results, which have been adjusted to account for anticipated moisture and for the effects of mining and coal preparation. The heat values (gross calorific values) shown for Accessible Reserves are on an as received basis (dry values obtained from drill hole analyses, adjusted for moisture) and are prorated by the associated Assigned Operating product values to account for similar mining and processing methods.
(2) Recoverable coal reserves are calculatedestimated based on proposed mine plans in the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculationestimate 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) TheBecause 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 decreased 9.2 million tonsincorporate losses for dilution and mining recovery based upon a 99% longwall mining recovery, a continuous mining recovery typically ranging from December 31, 201725% to December 31, 2018, as40%, and a result95% preparation plant efficiency within the life of producing 6.9 million tons for the year ended December 31, 2018, as well as a reduction of 2.3 million tons from a re-evaluation and reallocation of recoverablemine plan. Recoverable coal reserves amongare 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 three mines at the Pennsylvania Mining Complex.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.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS AND RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Partnership’s common units have been listed on the New York Stock Exchange (NYSE) since July 1, 2015 and trade under the symbol “CCR”. Prior to that, the Partnership’s equity securities were not listed on any exchange or traded on any public trading market.
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 25, 2019,24, 2020, the number of registered holders of our common units was approximately nine. The Fourth Quarter 20182019 cash distribution of $0.5125 per common and subordinated unit was declared on January 24, 20192020 to holders of record as of February 7, 201910, 2020 and will be paid on February 15, 2019.14, 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
| (a) | (b) | (c) | (d) | |||||||
| Period | Total Number of Units Purchased (1) | Average Price Paid per Unit | Total Number of Units Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Units that May Yet be Purchased Under the Plans or Programs (in thousands) (2) | ||||||
| October 1, 2018 - October 31, 2018 | 90,422 | $ | 18.73 | 90,422 | $ | 21,921 | ||||
| November 1, 2018 - November 30, 2018 | — | $ | — | — | $ | 21,921 | ||||
| December 1, 2018 - December 31, 2018 | — | $ | — | — | $ | 21,921 | ||||
| Total | 90,422 | $ | 18.73 | |||||||
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 and subordinated units of $0.5125 per unit per quarter, or $2.05 per unit on an annualized basis, to the extent the Partnership has sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general
partner. The Partnership Agreement requires that all available cash that is deemed to be “Operating Surplus” under the terms of the Partnership Agreement be distributed, however, there is no guarantee that the Partnership will pay the minimum quarterly distribution on those units in any quarter. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity.”
General Partner Interest
Initially, our general partner was entitled to 2% of all quarterly distributions from inception that we made prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% general partner interest in these distributions was reduced as a result of issuing additional limited partner interests in the form of Class A Preferred Units and our general partner did not contribute a proportionate amount of capital to maintain a 2% general partner interest. This resulted in our general partner now having a 1.7% general partner interest. As of the date of this Annual Report on Form 10-K, there are no outstanding Class A Preferred Units.
Incentive Distribution Rights
CONSOL Energy currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48%, of the available cash we distribute from operating surplus in excess of $0.5894 per unit per quarter.
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| 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 are displayed in thousands.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 and increasing distributions to our unitholders is to increase operating efficiencies to maximize realizations and make acquisitions that increase our distributable cash flow. The primary component of our growth strategy is based upon our expectation of future divestitures by CONSOL Energy to us of portions of its retained 75% undivided interest in the Pennsylvania Mining Complex. At December 31, 2018,2019, 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 No. 8 Coal Seam, which is a large contiguous formation of uniform, high-Btu coal that is ideal for high-productivity, low-cost longwall operations. As of December 31, 2018,2019, the Partnership’s portion of the Pennsylvania Mining Complex included 174,625167,341 tons of recoverable coal reserves with an average gross heat content of approximately 12,907 Btus per pound and approximately 3.6 pounds sulfur dioxide per million British thermal units (“lb SO2/mmBtu”). Based on our current production capacity, these reservesthat are sufficient to support approximately 2523.5 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.
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 a cost per tonan aggregate basis. Our cost of coal sold per ton represents our costs of coal sold divided by the tons of coal we sell. We define cost of coal sold as operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The cost of coal sold per ton includes items such as direct operating costs, royalty and production taxes, direct administration, and depreciation, depletion and amortization costs 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 (in thousands).indicated.
| Years Ended December 31, | Years Ended December 31, | |||||||||||||
| 2018 | 2017 | 2019 | 2018 | |||||||||||
| Total Costs | $ | 290,609 | $ | 282,320 | $ | 287,377 | $ | 290,609 | ||||||
| Freight Expense | (10,893 | ) | (18,423 | ) | (4,917 | ) | (10,893 | ) | ||||||
| Selling, General and Administrative Expenses | (13,931 | ) | (15,697 | ) | (12,874 | ) | (13,931 | ) | ||||||
| Loss on Extinguishment of Debt | — | (2,468 | ) | |||||||||||
| Interest Expense, Net | (6,667 | ) | (9,309 | ) | (6,604 | ) | (6,667 | ) | ||||||
| Other Costs (Non-Production) | (11,534 | ) | (5,714 | ) | (5,650 | ) | (11,534 | ) | ||||||
| Depreciation, Depletion and Amortization (Non-Production) | (2,166 | ) | (2,187 | ) | (2,130 | ) | (2,166 | ) | ||||||
| Cost of Coal Sold | $ | 245,418 | $ | 228,522 | $ | 255,202 | $ | 245,418 | ||||||
| Depreciation, Depletion and Amortization (Production) | (42,576 | ) | (39,250 | ) | (43,677 | ) | (42,576 | ) | ||||||
| Cash Cost of Coal Sold | $ | 202,842 | $ | 189,272 | $ | 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 (in thousands, except for per ton information).indicated.
| Years Ended December 31, | Years Ended December 31, | |||||||||||||
| 2018 | 2017 | 2019 | 2018 | |||||||||||
| Total Coal Revenue | $ | 341,073 | $ | 296,913 | $ | 322,132 | $ | 341,073 | ||||||
| Operating and Other Costs | 214,376 | 194,986 | 217,175 | 214,376 | ||||||||||
| Less: Other Costs (Non-Production) | (11,534 | ) | (5,714 | ) | (5,650 | ) | (11,534 | ) | ||||||
| Cash Cost of Coal Sold | 202,842 | 189,272 | 211,525 | 202,842 | ||||||||||
| Add: Depreciation, Depletion and Amortization | 44,742 | 41,437 | 45,807 | 44,742 | ||||||||||
| Less: Depreciation, Depletion and Amortization (Non-Production) | (2,166 | ) | (2,187 | ) | (2,130 | ) | (2,166 | ) | ||||||
| Cost of Coal Sold | $ | 245,418 | $ | 228,522 | $ | 255,202 | $ | 245,418 | ||||||
| Total Tons Sold | 6,920 | 6,523 | 6,829 | 6,920 | ||||||||||
| Average Revenue per Ton Sold | $ | 49.28 | $ | 45.52 | $ | 47.17 | $ | 49.28 | ||||||
| Average Cash Cost per Ton Sold | 29.29 | 29.02 | ||||||||||||
| Average Cash Cost of Coal Sold per Ton | 30.97 | 29.29 | ||||||||||||
| Add: Depreciation, Depletion and Amortization Costs per Ton Sold | 6.17 | 6.01 | 6.40 | 6.17 | ||||||||||
| Average Cost per Ton Sold | 35.46 | 35.03 | ||||||||||||
| Average Cost of Coal Sold per Ton | 37.37 | 35.46 | ||||||||||||
| Average Margin per Ton Sold | 13.82 | 10.49 | 9.80 | 13.82 | ||||||||||
| Add: Depreciation, Depletion and Amortization Costs per Ton Sold | 6.17 | 6.01 | 6.40 | 6.17 | ||||||||||
| Average Cash Margin per Ton Sold | $ | 19.99 | $ | 16.50 | $ | 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 (loss) before net interest expense, depreciation, depletion and amortization, as adjusted for (ii) certain non-cash items, such as Unit-Based Compensation, less net cash interest paid and estimated maintenance capital expenditures, which is defined as those forecasted average capital expenditures required to maintain, over the long-term, the operating capacity of our capital assets. These estimated capital expenditures do not reflect the actual cash capital incurred in the period presented. Distributable cash flow will not reflect changes in working capital balances. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. We define distribution coverage ratio as a ratio of the distributable cash flow to the 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 (in thousands).indicated.
| Years Ended December 31, | Years Ended December 31, | |||||||||||||
| 2018 | 2017 | 2019 | 2018 | |||||||||||
| Net Income | $ | 66,566 | $ | 40,464 | $ | 45,551 | $ | 66,566 | ||||||
| Plus: | ||||||||||||||
| Interest Expense, Net | 6,667 | 9,309 | 6,604 | 6,667 | ||||||||||
| Depreciation, Depletion and Amortization | 44,742 | 41,437 | 45,807 | 44,742 | ||||||||||
| Loss on Extinguishment of Debt | — | 2,468 | ||||||||||||
| Unit-Based Compensation | 1,842 | 5,873 | 1,409 | 1,842 | ||||||||||
| Adjusted EBITDA | $ | 119,817 | $ | 99,551 | $ | 99,371 | $ | 119,817 | ||||||
| Less: | ||||||||||||||
| Cash Interest | 7,217 | 8,224 | 7,473 | 7,217 | ||||||||||
Distributions to Preferred Units1 | — | 5,553 | ||||||||||||
| Estimated Maintenance Capital Expenditures | 35,949 | 35,764 | 35,911 | 35,949 | ||||||||||
| Distributable Cash Flow | $ | 76,651 | $ | 50,010 | $ | 55,987 | $ | 76,651 | ||||||
| Net Cash Provided by Operating Activities | $ | 125,379 | $ | 72,642 | $ | 81,125 | $ | 125,379 | ||||||
| Plus: | ||||||||||||||
| Interest Expense, Net | 6,667 | 9,309 | 6,604 | 6,667 | ||||||||||
| Other, Including Working Capital | (12,229 | ) | 17,600 | 11,642 | (12,229 | ) | ||||||||
| Adjusted EBITDA | $ | 119,817 | $ | 99,551 | $ | 99,371 | $ | 119,817 | ||||||
| Less: | ||||||||||||||
| Cash Interest | 7,217 | 8,224 | 7,473 | 7,217 | ||||||||||
Distributions to Preferred Units1 | — | 5,553 | ||||||||||||
| Estimated Maintenance Capital Expenditures | 35,949 | 35,764 | 35,911 | 35,949 | ||||||||||
| Distributable Cash Flow | $ | 76,651 | $ | 50,010 | $ | 55,987 | $ | 76,651 | ||||||
| Minimum Quarterly Distributions | $ | 57,392 | $ | 50,982 | ||||||||||
| Minimum Distributions | $ | 57,619 | $ | 57,392 | ||||||||||
| Distribution Coverage Ratio | 1.3 | 1.0 | 1.0 | 1.3 | ||||||||||
52
Results of Operations
Year Ended December 31, 20182019 Compared to the Year Ended December 31, 20172018
Total net income was $45,551 for the year ended December 31, 2019 compared to $66,566 for the year ended December 31, 2018 compared to $40,464 for the year ended December 31, 2017.2018. 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 | For the Years Ended | |||||||||||||||||||||
| December 31, | December 31, | |||||||||||||||||||||
| 2018 | 2017 | Variance | 2019 | 2018 | Variance | |||||||||||||||||
| Revenue: | (in thousands) | |||||||||||||||||||||
| Coal Revenue | $ | 341,073 | $ | 296,913 | $ | 44,160 | $ | 322,132 | $ | 341,073 | $ | (18,941 | ) | |||||||||
| Freight Revenue | 10,893 | 18,423 | (7,530 | ) | 4,917 | 10,893 | (5,976 | ) | ||||||||||||||
| Other Income | 5,209 | 7,448 | (2,239 | ) | 5,879 | 5,209 | 670 | |||||||||||||||
| Total Revenue and Other Income | 357,175 | 322,784 | 34,391 | 332,928 | 357,175 | (24,247 | ) | |||||||||||||||
| Cost of Coal Sold: | ||||||||||||||||||||||
| Operating Costs | 202,842 | 189,272 | 13,570 | 211,525 | 202,842 | 8,683 | ||||||||||||||||
| Depreciation, Depletion and Amortization | 42,576 | 39,250 | 3,326 | 43,677 | 42,576 | 1,101 | ||||||||||||||||
| Total Cost of Coal Sold | 245,418 | 228,522 | 16,896 | 255,202 | 245,418 | 9,784 | ||||||||||||||||
| Other Costs: | ||||||||||||||||||||||
| Other Costs | 11,534 | 5,714 | 5,820 | 5,650 | 11,534 | (5,884 | ) | |||||||||||||||
| Depreciation, Depletion and Amortization | 2,166 | 2,187 | (21 | ) | 2,130 | 2,166 | (36 | ) | ||||||||||||||
| Total Other Costs | 13,700 | 7,901 | 5,799 | 7,780 | 13,700 | (5,920 | ) | |||||||||||||||
| Freight Expense | 10,893 | 18,423 | (7,530 | ) | 4,917 | 10,893 | (5,976 | ) | ||||||||||||||
| Selling, General and Administrative Expenses | 13,931 | 15,697 | (1,766 | ) | 12,874 | 13,931 | (1,057 | ) | ||||||||||||||
| Loss on Extinguishment of Debt | — | 2,468 | (2,468 | ) | ||||||||||||||||||
| Interest Expense | 6,667 | 9,309 | (2,642 | ) | ||||||||||||||||||
| Interest Expense, Net | 6,604 | 6,667 | (63 | ) | ||||||||||||||||||
| Total Costs | 290,609 | 282,320 | 8,289 | 287,377 | 290,609 | (3,232 | ) | |||||||||||||||
| Net Income | $ | 66,566 | $ | 40,464 | $ | 26,102 | $ | 45,551 | $ | 66,566 | $ | (21,015 | ) | |||||||||
| Adjusted EBITDA | $ | 119,817 | $ | 99,551 | $ | 20,266 | $ | 99,371 | $ | 119,817 | $ | (20,446 | ) | |||||||||
| Distributable Cash Flow | $ | 76,651 | $ | 50,010 | $ | 26,641 | $ | 55,987 | $ | 76,651 | $ | (20,664 | ) | |||||||||
| Distribution Coverage Ratio | 1.3 | 1.0 | 0.3 | 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, | Years Ended December 31, | |||||||||||||||||
| Mine | 2018 | 2017 | Variance | 2019 | 2018 | Variance | ||||||||||||
| (in thousands) | ||||||||||||||||||
| Bailey | 3,184 | 3,031 | 153 | 3,054 | 3,184 | (130 | ) | |||||||||||
| Enlow Fork | 2,469 | 2,295 | 174 | 2,511 | 2,469 | 42 | ||||||||||||
| Harvey | 1,245 | 1,201 | 44 | 1,256 | 1,245 | 11 | ||||||||||||
| Total | 6,898 | 6,527 | 371 | 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 compared to 6,527 tons for the year ended December 31, 2017.2018. 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 371 tons, primarily to satisfy increased demand for our products in the domestic and export markets, as well as a result of improved productivity, initial benefits from automation projects and improved geological conditionsproduction at the Enlow Fork mine.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, 20182019 and 20172018 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, | For the Years Ended December 31, | |||||||||||||||||||||
| 2018 | 2017 | Variance | 2019 | 2018 | Variance | |||||||||||||||||
| Total Tons Sold (in thousands) | 6,920 | 6,523 | 397 | |||||||||||||||||||
| Total Tons Sold | 6,829 | 6,920 | (91 | ) | ||||||||||||||||||
| Average Revenue per Ton Sold | $ | 49.28 | $ | 45.52 | $ | 3.76 | $ | 47.17 | $ | 49.28 | $ | (2.11 | ) | |||||||||
| Average Cash Cost per Ton Sold | $ | 29.29 | $ | 29.02 | $ | 0.27 | ||||||||||||||||
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) | 6.17 | 6.01 | 0.16 | 6.40 | 6.17 | 0.23 | ||||||||||||||||
| Total Costs per Ton Sold | $ | 35.46 | $ | 35.03 | $ | 0.43 | ||||||||||||||||
| Average Cost of Coal Sold per Ton | $ | 37.37 | $ | 35.46 | $ | 1.91 | ||||||||||||||||
| Average Margin per Ton Sold | $ | 13.82 | $ | 10.49 | $ | 3.33 | $ | 9.80 | $ | 13.82 | $ | (4.02 | ) | |||||||||
| Add: Depreciation, Depletion and Amortization Costs per Ton Sold | 6.17 | 6.01 | 0.16 | 6.40 | 6.17 | 0.23 | ||||||||||||||||
| Average Cash Margin per Ton Sold (1) | $ | 19.99 | $ | 16.50 | $ | 3.49 | $ | 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 issold 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 compared to $296,913 for the year ended December 31, 2017.2018. The $44,160 increase$18,941 decrease was primarily attributable to a 397 ton increase in tons sold and a $3.76$2.11 per ton higher average sales price. The increase in tons sold was driven by increased demand from our domestic customers, largely due to higher burn. The higherlower average sales price per ton sold in the 20182019 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 primarilypartially offset by an increase in prices the result of higher realizations on our netback contracts due to strong power prices and an increased demand in the international thermal and crossover metallurgical coal markets that we serve. 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 compared to $18,423 for the year ended December 31, 2017.2018. The $7,530$5,976 decrease was due to decreased shipments to customers where we were contractually obligated to provide transportation services.
Other income is comprised of income generated by the Partnership notrelating to non-coal producing activities. Other income remained materially consistent in the ordinary course of business. Other income was $5,209 for the year ended December 31, 2018 compared to $7,448 for the year ended December 31, 2017. The $2,239 decrease was primarily due to a $2,390 decrease in coal contract buyouts and a $1,403 gain that occurred during the year ended December 31, 2017 in relation to an agreement to avoid mining approximately 85 acres of reserves. These decreases were offset, in part, by an increase of $1,498 in sales of externally purchased coal to blend and resell.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, or $16,896 higher than the $228,5222018. Total costs per ton sold were $37.37 per ton for the year ended December 31, 2017. Total costs per ton sold were2019 compared to $35.46 per ton for the year ended December 31, 2018 compared to $35.03 per ton for the year ended December 31, 2017.2018. The increase in the total cost of coal sold was primarily driven by an increaseadditional 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 production-related costs, as more coal was mined to meet market demand. The increasehigher mine maintenance and project expenses. In addition, subsidence expense increased in the average cost per ton sold was the result of additional royalty and production taxesyear-to-year comparison due to a $3.76 per ton higher average sales price. In addition, since the fourth quartertiming and nature of 2017, we have seen modest inflation in the cost of supplies that contain steel and other commodities for which prices are strengthening, as well as in the cost of contract labor. We have been able to successfully offset these inflationary pressures through productivity gains, initial benefits from our automation investments, and a reduction in lease expense.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 increased $5,799decreased $5,920 for the year ended December 31, 20182019 compared to the year ended December 31, 2017.2018. The increasedecrease was primarily attributable to an increaseadditional costs incurred in current year coststhe year-ago period related to discretionary employee benefit expense, demurrage charges and externally purchased coal to blend and resell. This increase was partially offset by a decrease in severance costs due to organizational restructuring that occurred during the year ended December 31, 2017.resell, discretionary employee benefit expense and demurrage charges.
Selling, General and Administrative Expense
Selling, generalGeneral and administrativeAdministrative expenses were $12,874 for the year ended December 31, 2018 decreased $1,766 primarily due2019 compared to a decrease in long-term incentive compensation recognized in relation to award modifications due to organizational restructuring in the year ended December 31, 2017.
Interest Expense
Interest expense, which primarily relates to obligations under our Affiliated Company Credit Agreement. ForAgreement, remained materially consistent in the year-to-year comparison.
Adjusted EBITDA
Adjusted EBITDA was $99,371 for the year ended December 31, 2017, $9,309 of interest expense was incurred, primarily on the PNC Revolving Credit Facility. The PNC Revolving Credit Facility was refinanced through the Affiliated Company Credit Agreement on November 28, 2017. The decrease was primarily attributable2019 compared to a lower average daily balance outstanding under the Affiliated Company Credit Agreement than had been drawn on the PNC Revolving Credit facility in the previous year. For a detailed explanation of our liquidity and financing arrangements, please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity.”
Distributable Cash Flow
Distributable cash flow was $55,987 for the year ended December 31, 2017. The $20,266 increase was a result of a $3.76 per ton increase in the average sales price, offset in part by a $0.27 per ton increase in the cash cost of coal sold, resulting in a $24,151 increase in Adjusted EBITDA. In addition, an increase of 397 sales tons resulted in an increase of $6,550 in Adjusted EBITDA. The remaining variance is primarily due2019 compared to various changes as discussed above, such as contract buyouts, award modifications, and severance costs during the year ended December 31, 2017, coupled with discretionary employee benefit expense and demurrage charges during the year ended December 31, 2018 and various other transactions throughout both periods, none of which are individually material.
Capital Resources and Liquidity
Liquidity and Financing Arrangements
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 expect that theexperienced longer delays in collections of accounts receivable in 2019. If these delays continue or become longer, we may have less cash flow generated from operationsoperations. As we move into 2020, we will continue to exceedmonitor the creditworthiness of our maintenancecustomers.
We started a capital requirements and we will have adequate access to capital to fund any incremental growth-related capital needs. We startedconstruction project on the coarse refuse disposal area project in 2017, which is expected to continue through 2021. Our 20192020 capital needs, including the coarse refuse disposal area project, are expected to be between $34,000$25,000 to $38,000,$30,000, which is increaseddecreased from 20182019 levels due to additional expected maintenance capitalreductions in equipment-related expenditures related to airshaft construction projects, as well as additional belt system 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, 2019,2020, the Board of Directors of our general partner declared a cash distribution of $0.5125 per unit for the yearquarter ended December 31, 20182019 to the limited partner unitholders and the holder of the general partner interest. The cash distribution will be paid on February 15, 201914, 2020 to the unitholders of record at the close of business on February 7, 2019.10, 2020.
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 completion of the separation and the Partnership’s entry into the Affiliated Company Credit Agreement, the Partnership made an initial draw of $200,583, the net proceeds of which were used to repay the PNC Revolving Credit Facility.amounts outstanding under the Partnership's prior credit facility. Additional drawings under the Affiliated Company Credit Agreement are available for general partnership purposes. The Affiliated Company Credit Agreement matures on February 27, 2023. The collateral obligations under the Affiliated Company Credit Agreement generally mirror the PNC Revolving Credit Facility, including the list of entities that act as guarantors thereunder. The obligations under the Affiliated Company Credit Agreement are guaranteed by the Partnership’s subsidiaries and secured by substantially all of the assets of the Partnership and its subsidiaries pursuant to the security agreement and various mortgages.
Interest on outstanding obligations under our Affiliated Company Credit Agreement accrues at a fixed rate ranging from 3.75% to 4.75% depending on the total net leverage ratio. The unused portion of our Affiliated Company Credit Agreement is subject to a commitment fee of 0.50% per annum.
As of December 31, 2018,2019, the Partnership had $163,000$180,925 of borrowings outstanding under the Affiliated Company Credit Agreement, leaving $112,000$94,075 of unused capacity. Interest on outstanding borrowings under the Affiliated Company Credit Agreement at December 31, 20182019 was accrued at a rate of 3.75%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.
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, 2018,2019, the Partnership was in compliance with its debt covenants with a first lien gross leverage ratio was 1.40at 1.84 to 1.00 and thea total net leverage ratio was 1.39at 1.83 to 1.00.
Receivables Financing Agreement
On November 30, 2017, (i) CONSOL Marine Terminals LLC, formerly known as CNX Marine Terminals LLC, as an originator of receivables, (ii) CPCC, as an originator of receivables and as initial servicer of the receivables for itself and the other originators (collectively, the “Originators”), each a wholly owned subsidiary of CONSOL Energy, and (iii) CONSOL Funding LLC (the “SPV”), 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, 2018,2019, the Partnership, through CONSOL Thermal Holdings, sold $21,871$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, | ||||||||||||||||||||||
| 2018 | 2017 | Variance | For the Years Ended December 31, | |||||||||||||||||||
| (in thousands) | 2019 | 2018 | Variance | |||||||||||||||||||
| Cash flows provided by operating activities | $ | 125,379 | $ | 72,642 | $ | 52,737 | $ | 81,125 | $ | 125,379 | $ | (44,254 | ) | |||||||||
| Cash used in investing activities | $ | (30,973 | ) | $ | (17,996 | ) | $ | (12,977 | ) | $ | (37,171 | ) | $ | (30,973 | ) | $ | (6,198 | ) | ||||
| Cash used in financing activities | $ | (94,936 | ) | $ | (62,898 | ) | $ | (32,038 | ) | $ | (44,414 | ) | $ | (94,936 | ) | $ | 50,522 | |||||
Year Ended December 31, 20182019 Compared to the Year Ended December 31, 2017:2018:
Cash flows provided by operating activities increased $52,737decreased $44,254 in the year ended December 31, 20182019 compared to the year ended December 31, 20172018, primarily due to an increasea $21,015 decrease in net income, a slowing of customer collections in 2019 compared to an acceleration of customer collections in 2018, and a change inother working capital.capital changes that occurred throughout both periods.
Cash flows used in investing activities increased $12,977$6,198 in the year ended December 31, 20182019 compared to the year ended December 31, 20172018, primarily as a result of increased capital expenditures of $11,647 and a decrease in proceeds from the sale of assets of $1,330. The$6,034, mainly due to an increase in capitalairshaft construction projects, belt system related expenditures, is due topurchases 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 following items:
years ended December 31, 2019 and December 31, 2018.
| For the Years Ended December 31, | ||||||||||||||||||||||
| 2018 | 2017 | Variance | For the Years Ended December 31, | |||||||||||||||||||
| (in thousands) | 2019 | 2018 | Variance | |||||||||||||||||||
| Building and Infrastructure | $ | 11,196 | $ | 8,166 | $ | 3,030 | $ | 16,223 | $ | 11,196 | $ | 5,027 | ||||||||||
| Equipment Purchases and Rebuilds | 9,437 | 2,185 | 7,252 | 10,671 | 9,437 | 1,234 | ||||||||||||||||
| Refuse Storage Area | 8,572 | 8,002 | 570 | 7,931 | 8,572 | (641 | ) | |||||||||||||||
| Other | 1,938 | 1,143 | 795 | 2,352 | 1,938 | 414 | ||||||||||||||||
| Total Capital Expenditures | $ | 31,143 | $ | 19,496 | $ | 11,647 | $ | 37,177 | $ | 31,143 | $ | 6,034 | ||||||||||
Cash flows used in financing activities increased $32,038decreased $50,522 in the year ended December 31, 20182019 compared to the year ended December 31, 2017.2018. The increasedecrease in cash used in financing activities was primarily due to $33,583 in netlower discretionary payments made inunder the current year onAffiliated Company Credit Agreement. Net proceeds received under the Affiliated Company Credit Agreement were $17,925 in the year ended December 31, 2019, compared to the prior year $4,417 in net payments on long-term debt.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 are primarily relatedrelate to the closure of the mines and gas wells and the reclamation of land upon exhaustionmine closure, the treatment of coal reserves.mine water discharge where necessary, and the plugging of gas wells acquired for mining purposes. Changes in the variablesassumptions used to calculate the liabilities can have a significant effect on the mine closing and reclamation liabilities.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
necessary. Estimates of our total reclamation, mine-closing and gas well closing liabilities,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 and $10,496 at December 31, 2017.2018. 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, | |
| Consolidated Statements of Comprehensive Income for the Years Ended December 31, | |
| Consolidated Balance Sheets at December 31, | |
| Consolidated Statements of Partners’ Capital for the Years Ended December 31, | |
| Consolidated Statements of Cash Flows for the Years Ended December 31, | |
| 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, 20182019 and 2017,2018, 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, 2018,2019, and the related notes (collectively referred to as the “financial“consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2019 and 2018, and 2017, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2018,2019, 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 8, 201914, 2020
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CONSOL COAL RESOURCES LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit data)
| For the Years Ended December 31, | For the Years Ended December 31, | |||||||||||||
| 2018 | 2017 | 2019 | 2018 | |||||||||||
| Coal Revenue | $ | 341,073 | $ | 296,913 | $ | 322,132 | $ | 341,073 | ||||||
| Freight Revenue | 10,893 | 18,423 | 4,917 | 10,893 | ||||||||||
| Other Income | 5,209 | 7,448 | 5,879 | 5,209 | ||||||||||
| Total Revenue and Other Income | 357,175 | 322,784 | 332,928 | 357,175 | ||||||||||
Operating and Other Costs 1 | 214,376 | 194,986 | 217,175 | 214,376 | ||||||||||
| Depreciation, Depletion and Amortization | 44,742 | 41,437 | 45,807 | 44,742 | ||||||||||
| Freight Expense | 10,893 | 18,423 | 4,917 | 10,893 | ||||||||||
Selling, General and Administrative Expenses 2 | 13,931 | 15,697 | 12,874 | 13,931 | ||||||||||
| Loss on Extinguishment of Debt | — | 2,468 | ||||||||||||
Interest Expense, Net 3 | 6,667 | 9,309 | 6,604 | 6,667 | ||||||||||
| Total Costs | 290,609 | 282,320 | 287,377 | 290,609 | ||||||||||
| Net Income | $ | 66,566 | $ | 40,464 | $ | 45,551 | $ | 66,566 | ||||||
| Less: General Partner Interest in Net Income | 1,127 | 662 | 768 | 1,127 | ||||||||||
| Less: Net Income Allocable to Class A Preferred Units | — | 5,553 | ||||||||||||
| Less: Distribution Effect of Preferred Unit Conversion | — | 173 | ||||||||||||
| Limited Partner Interest in Net Income | $ | 65,439 | $ | 34,076 | $ | 44,783 | $ | 65,439 | ||||||
| Net Income per Limited Partner Unit - Basic | $ | 2.38 | $ | 1.40 | $ | 1.62 | $ | 2.38 | ||||||
| Net Income per Limited Partner Unit - Diluted | $ | 2.37 | $ | 1.39 | $ | 1.62 | $ | 2.37 | ||||||
| Limited Partner Units Outstanding - Basic | 27,511,804 | 24,325,575 | 27,622,032 | 27,511,804 | ||||||||||
| Limited Partner Units Outstanding - Diluted | 27,611,924 | 24,461,373 | 27,659,790 | 27,611,924 | ||||||||||
Cash Distributions Declared per Unit 4 | $ | 2.05 | $ | 2.05 | ||||||||||
| Common Unit | $ | 2.05 | $ | 2.05 | ||||||||||
| Subordinated Unit | $ | 2.05 | $ | 2.05 | ||||||||||
1 Related Party of $2,918$3,219 and $3,503$2,918for the years ended December 31, 2019 and 2018, and 2017, respectively.
2 Related Party of $8,300$8,309 and $3,109$8,300 for the years ended December 31, 2019 and 2018, and 2017, respectively.
3 Related Party of $6,667$6,221 and $746$6,667 for the years ended December 31, 2019 and 2018, and 2017, respectively.
4 Represents the cash distribution declared related to the period presented. See Note 22 - Subsequent Events.
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOL COAL RESOURCES LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
| For the Years Ended December 31, | For the Years Ended December 31, | |||||||||||||
| 2018 | 2017 | 2019 | 2018 | |||||||||||
| Net Income | $ | 66,566 | $ | 40,464 | $ | 45,551 | $ | 66,566 | ||||||
| Actuarially Determined Long-Term Liability Adjustments: | ||||||||||||||
| Recognized Net Actuarial (Gain) Loss | (8 | ) | 1,366 | |||||||||||
| Other Comprehensive Income Before Reclassifications | 1,485 | — | ||||||||||||
| Recognized Net Actuarial Loss (Gain) | 15 | (8 | ) | |||||||||||
| Other Comprehensive (Loss) Income Before Reclassifications | (1,356 | ) | 1,485 | |||||||||||
| Total Actuarially Determined Long-Term Liability Adjustments | 1,477 | 1,366 | (1,341 | ) | 1,477 | |||||||||
| Other Comprehensive Income | 1,477 | 1,366 | ||||||||||||
| Other Comprehensive (Loss) Income | (1,341 | ) | 1,477 | |||||||||||
| Comprehensive Income | $ | 68,043 | $ | 41,830 | $ | 44,210 | $ | 68,043 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOL COAL RESOURCES LP
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
| December 31, 2018 | December 31, 2017 | December 31, 2019 | December 31, 2018 | |||||||||||
| ASSETS | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash | $ | 1,003 | $ | 1,533 | $ | 543 | $ | 1,003 | ||||||
| Trade Receivables | 21,871 | 31,473 | ||||||||||||
| Trade Receivables, net of allowance | 32,769 | 21,871 | ||||||||||||
| Other Receivables | 1,068 | 1,970 | 1,572 | 1,068 | ||||||||||
| Inventories | 11,066 | 12,303 | 12,653 | 11,066 | ||||||||||
| Prepaid Expenses | 5,096 | 4,428 | 5,746 | 5,096 | ||||||||||
| Total Current Assets | 40,104 | 51,707 | 53,283 | 40,104 | ||||||||||
| Property, Plant and Equipment: | ||||||||||||||
| Property, Plant and Equipment | 946,298 | 910,468 | 984,898 | 946,298 | ||||||||||
| Less—Accumulated Depreciation, Depletion and Amortization | 526,747 | 483,410 | 571,238 | 526,747 | ||||||||||
| Total Property, Plant and Equipment—Net | 419,551 | 427,058 | 413,660 | 419,551 | ||||||||||
| Other Assets: | ||||||||||||||
| Right of Use Asset—Operating Leases | 15,695 | — | ||||||||||||
| Other Assets | 14,908 | 15,474 | 13,456 | 14,908 | ||||||||||
| Total Other Assets | 29,151 | 14,908 | ||||||||||||
| TOTAL ASSETS | $ | 474,563 | $ | 494,239 | $ | 496,094 | $ | 474,563 | ||||||
| December 31, 2018 | December 31, 2017 | ||||||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities: | |||||||
| Accounts Payable | $ | 24,834 | $ | 19,718 | |||
Accounts Payable—Related Party | 3,831 | 3,071 | |||||
| Other Accrued Liabilities | 35,419 | 44,179 | |||||
| Total Current Liabilities | 64,084 | 66,968 | |||||
| Long-Term Debt: | |||||||
Affiliated Company Credit Agreement—Related Party | 163,000 | 196,583 | |||||
| Capital Lease Obligations | 5,067 | 73 | |||||
| Total Long-Term Debt | 168,067 | 196,656 | |||||
| Other Liabilities: | |||||||
| Pneumoconiosis Benefits | 4,260 | 3,833 | |||||
Workers’ Compensation | 3,119 | 3,404 | |||||
| Asset Retirement Obligations | 9,775 | 9,615 | |||||
| Other | 518 | 607 | |||||
| Total Other Liabilities | 17,672 | 17,459 | |||||
| TOTAL LIABILITIES | 249,823 | 281,083 | |||||
Partners’ Capital: | |||||||
| Common Units (15,911,211 Units Outstanding at December 31, 2018; 15,789,106 Units Outstanding at December 31, 2017) | 212,122 | 205,974 | |||||
| Subordinated Units (11,611,067 Units Outstanding at December 31, 2018 and December 31, 2017) | (11,421 | ) | (15,225 | ) | |||
| General Partner Interest | 12,119 | 11,964 | |||||
| Accumulated Other Comprehensive Income | 11,920 | 10,443 | |||||
Total Partners’ Capital | 224,740 | 213,156 | |||||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL | $ | 474,563 | $ | 494,239 | |||
The accompanying notes are an integral part of these consolidated financial statements.
| Limited Partners | |||||||||||||||||||||||
| Class A Preferred Units | Common | Subordinated | General Partner | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||
| Balance at December 31, 2016 | $ | 69,151 | $ | 140,967 | $ | (7,631 | ) | $ | 12,274 | $ | 11,809 | $ | 226,570 | ||||||||||
| Net Income | 5,553 | 18,040 | 16,209 | 662 | — | 40,464 | |||||||||||||||||
| Unitholder Distributions | (5,553 | ) | (26,072 | ) | (23,803 | ) | (972 | ) | — | (56,400 | ) | ||||||||||||
| Conversion of Preferred Units | (69,151 | ) | 69,151 | — | — | — | — | ||||||||||||||||
| Unit-Based Compensation | — | 5,873 | — | — | — | 5,873 | |||||||||||||||||
| Units Withheld for Taxes | — | (1,985 | ) | — | — | — | (1,985 | ) | |||||||||||||||
| Actuarially Determined Long-Term Liability Adjustments | — | — | — | — | (1,366 | ) | (1,366 | ) | |||||||||||||||
| Balance at December 31, 2017 | $ | — | $ | 205,974 | $ | (15,225 | ) | $ | 11,964 | $ | 10,443 | $ | 213,156 | ||||||||||
| Net Income | — | 37,832 | 27,607 | 1,127 | — | 66,566 | |||||||||||||||||
| Unitholder Distributions | — | (32,614 | ) | (23,803 | ) | (972 | ) | — | (57,389 | ) | |||||||||||||
| Unit-Based Compensation | — | 1,842 | — | — | — | 1,842 | |||||||||||||||||
| Units Withheld for Taxes | — | (912 | ) | — | — | — | (912 | ) | |||||||||||||||
| Actuarially Determined Long-Term Liability Adjustments | — | — | — | — | 1,477 | 1,477 | |||||||||||||||||
| Balance at December 31, 2018 | $ | — | $ | 212,122 | $ | (11,421 | ) | $ | 12,119 | $ | 11,920 | $ | 224,740 | ||||||||||
| December 31, 2019 | December 31, 2018 | ||||||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities: | |||||||
| Accounts Payable | $ | 22,805 | $ | 24,834 | |||
Accounts Payable—Related Party | 1,419 | 3,831 | |||||
| Current Portion of Long-Term Debt | 5,252 | 3,503 | |||||
| Other Accrued Liabilities | 39,455 | 31,916 | |||||
| Total Current Liabilities | 68,931 | 64,084 | |||||
| Long-Term Debt: | |||||||
Affiliated Company Credit Agreement—Related Party | 180,925 | 163,000 | |||||
| Finance Lease Obligations | 1,645 | 5,067 | |||||
| Total Long-Term Debt | 182,570 | 168,067 | |||||
| Other Liabilities: | |||||||
| Pneumoconiosis Benefits | 6,028 | 4,260 | |||||
Workers’ Compensation | 3,611 | 3,119 | |||||
| Asset Retirement Obligations | 10,801 | 9,775 | |||||
| Operating Lease Liability | 11,507 | — | |||||
| Other | 785 | 518 | |||||
| Total Other Liabilities | 32,732 | 17,672 | |||||
| TOTAL LIABILITIES | 284,233 | 249,823 | |||||
Partners’ Capital: | |||||||
| Common Units (27,632,824 Units Outstanding at December 31, 2019; 15,911,211 Units Outstanding at December 31, 2018) | 189,367 | 212,122 | |||||
| Subordinated Units (No Units Outstanding at December 31, 2019; 11,611,067 Units Outstanding at December 31, 2018) | — | (11,421 | ) | ||||
| General Partner Interest | 11,915 | 12,119 | |||||
| Accumulated Other Comprehensive Income | 10,579 | 11,920 | |||||
Total Partners’ Capital | 211,861 | 224,740 | |||||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL | $ | 496,094 | $ | 474,563 | |||
The accompanying notes are an integral part of these consolidated financial statements.
65
CONSOL COAL RESOURCES LP
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(Dollars in thousands)
| Limited Partners | |||||||||||||||||||
| Common | Subordinated | General Partner | Accumulated Other Comprehensive Income (Loss) | Total | |||||||||||||||
| Balance at December 31, 2017 | $ | 205,974 | $ | (15,225 | ) | $ | 11,964 | $ | 10,443 | $ | 213,156 | ||||||||
| Net Income | 37,832 | 27,607 | 1,127 | — | 66,566 | ||||||||||||||
| Unitholder Distributions | (32,614 | ) | (23,803 | ) | (972 | ) | — | (57,389 | ) | ||||||||||
| Unit-Based Compensation | 1,842 | — | — | — | 1,842 | ||||||||||||||
| Units Withheld for Taxes | (912 | ) | — | — | — | (912 | ) | ||||||||||||
| Actuarially Determined Long-Term Liability Adjustments | — | — | — | 1,477 | 1,477 | ||||||||||||||
| Balance at December 31, 2018 | $ | 212,122 | $ | (11,421 | ) | $ | 12,119 | $ | 11,920 | $ | 224,740 | ||||||||
| Net Income | 32,552 | 12,231 | 768 | — | 45,551 | ||||||||||||||
| Unitholder Distributions | (38,794 | ) | (17,852 | ) | (972 | ) | — | (57,618 | ) | ||||||||||
| Conversion of Subordinated Units to Common Units | (17,042 | ) | 17,042 | — | — | — | |||||||||||||
| Unit-Based Compensation | 1,409 | — | — | — | 1,409 | ||||||||||||||
| Units Withheld for Taxes | (880 | ) | — | — | — | (880 | ) | ||||||||||||
| Actuarially Determined Long-Term Liability Adjustments | — | — | — | (1,341 | ) | (1,341 | ) | ||||||||||||
| Balance at December 31, 2019 | $ | 189,367 | $ | — | $ | 11,915 | $ | 10,579 | $ | 211,861 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOL COAL RESOURCES LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
| For the Years Ended December 31, | For the Years Ended December 31, | |||||||||||||
| 2018 | 2017 | 2019 | 2018 | |||||||||||
| Cash Flows from Operating Activities: | ||||||||||||||
| Net Income | $ | 66,566 | $ | 40,464 | $ | 45,551 | $ | 66,566 | ||||||
| Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities: | ||||||||||||||
| Depreciation, Depletion and Amortization | 44,742 | 41,437 | 45,807 | 44,742 | ||||||||||
| Loss (Gain) on Sale of Assets | 34 | (1,399 | ) | |||||||||||
| Loss on Sale of Assets | 49 | 34 | ||||||||||||
| Unit-Based Compensation | 1,842 | 5,873 | 1,409 | 1,842 | ||||||||||
| Loss on Extinguishment of Debt | — | 2,468 | ||||||||||||
| Other Adjustments to Net Income | — | 688 | ||||||||||||
| Changes in Operating Assets: | ||||||||||||||
| Accounts and Notes Receivable | 10,504 | (9,510 | ) | |||||||||||
| Trade and Other Receivables | (11,393 | ) | 10,504 | |||||||||||
| Inventories | 1,237 | (812 | ) | (1,587 | ) | 1,237 | ||||||||
| Prepaid Expenses | (668 | ) | (916 | ) | (650 | ) | (668 | ) | ||||||
| Changes in Other Assets | 741 | (615 | ) | 1,452 | 741 | |||||||||
| Changes in Operating Liabilities: | ||||||||||||||
| Accounts Payable | 4,990 | 293 | (1,389 | ) | 4,990 | |||||||||
Accounts Payable—Related Party | 760 | 88 | (2,412 | ) | 760 | |||||||||
| Other Operating Liabilities | (6,528 | ) | (5,785 | ) | 3,351 | (6,528 | ) | |||||||
| Changes in Other Liabilities | 1,159 | 368 | 937 | 1,159 | ||||||||||
| Net Cash Provided by Operating Activities | 125,379 | 72,642 | 81,125 | 125,379 | ||||||||||
| Cash Flows from Investing Activities: | ||||||||||||||
| Capital Expenditures | (31,143 | ) | (19,496 | ) | (37,177 | ) | (31,143 | ) | ||||||
| Proceeds from Sales of Assets | 170 | 1,500 | 6 | 170 | ||||||||||
| Net Cash Used in Investing Activities | (30,973 | ) | (17,996 | ) | (37,171 | ) | (30,973 | ) | ||||||
| Cash Flows from Financing Activities: | ||||||||||||||
| Payments on Capitalized Leases | (3,052 | ) | (96 | ) | ||||||||||
| Net (Payments on) Proceeds from Related Party Long-Term Notes | (33,583 | ) | 196,583 | |||||||||||
| Net Payments on Revolver | — | (201,000 | ) | |||||||||||
| Payments on Finance Leases | (3,841 | ) | (3,052 | ) | ||||||||||
| Net Proceeds from (Payments on) Related Party Long-Term Notes | 17,925 | (33,583 | ) | |||||||||||
| Payments for Unitholder Distributions | (57,389 | ) | (56,400 | ) | (57,618 | ) | (57,389 | ) | ||||||
| Units Withheld for Taxes | (912 | ) | (1,985 | ) | (880 | ) | (912 | ) | ||||||
| Net Cash Used In Financing Activities | (94,936 | ) | (62,898 | ) | (44,414 | ) | (94,936 | ) | ||||||
| Net Decrease in Cash | (530 | ) | (8,252 | ) | (460 | ) | (530 | ) | ||||||
| Cash at Beginning of Period | 1,533 | 9,785 | 1,003 | 1,533 | ||||||||||
| Cash at End of Period | $ | 1,003 | $ | 1,533 | $ | 543 | $ | 1,003 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOL COAL RESOURCES LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands)thousands, except per unit data)
NOTE 1—SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies is included below. These, together with the other notes to the consolidated financial statements, are an integral part of the Consolidated Financial Statements.
Basis of Consolidation and Presentation:
For the years ended December 31, 20182019 and 2017,2018, the Consolidated Financial Statements include the accounts of CONSOL Operating and CONSOL Thermal Holdings, wholly owned and controlled subsidiaries.
Jumpstart Our Business Startups Act (“JOBS Act”):
Under the JOBS Act, for as long as the Partnership remains an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from the SEC’s reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of itsour system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and seeking unitholder approval of any golden parachute payments not previously approved. We may take advantage of these reporting exemptions until we are no longer an emerging growth company.
The Partnership will remain an emerging growth company for up to five years, although we will lose that status sooner if:
we have more than $1.07 billion of revenues in a fiscal year;
limited partner interests held by non-affiliates have a market value of more than $700 million (large accelerated filer);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, will be 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 qualifies as a “smaller reporting company” because the value of its limited partner interests held by non-affiliates as of the end of its most recently completed second fiscal quarter was less than $250 million. For as long as the Partnership remains a smaller reporting company, it 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.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant
estimates included in the preparation of the consolidated financial statements are related to coal workers’ pneumoconiosis, workers’ compensation, asset retirement obligations, contingencies and recoverable coal reserve values.
Cash:
Cash includes cash on hand and on deposit with banking institutions.
Trade Receivables and Allowance for Doubtful Accounts:
Trade receivables are recorded at the invoiced amount and do not bear interest. We reserveTrade credit is extended based upon evaluations of each customer's ability to perform its obligations, which is assessed regularly. An allowance for specificdoubtful accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on termsupon an aging of sale, credit statuscustomer accounts and a review for collectibility of customers and various other circumstances. We regularly review collectability and establish or adjust the allowance as necessary using the specific identification method. Account balancesaccounts. Amounts are chargedwritten off against the allowance after all meansin the period in which the receivable is deemed uncollectible. The allowance for doubtful accounts was $525 as of collection have been exhausted and the potentialDecember 31, 2019. NaN allowance for recovery is considered remote. Theredoubtful accounts was recorded as of December 31, 2018. In addition, there were no reserves for uncollectible trade amounts in the periods presented.material financing receivables with a contractual maturity greater than one year at December 31, 2019 or 2018.
Inventories:
Inventories are stated at the lower of cost or net realizable value. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, depreciation, depletion and amortization, operating overhead and other related costs. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in our coal operations.
Property, Plant and Equipment:
Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs, which do not extend the useful lives of existing plant and equipment, are expensed as incurred.
Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.
Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities.
Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced, so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material effect from changes in estimates is disclosed in the period in which the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.
Coal reserves are either owned in fee or controlled by lease. The duration of the leases vary; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable coal reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered real property interests.
Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production using the units-of-production method. Depletion of leased coal interests is computed using the units-of-production method over recoverable coal reserves.
Advance mining royalties and leased coal interests are evaluated periodically, or at a minimum once a year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates.
When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized in Other Income in the Consolidated Statements of Operations.
Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:
| Years | |
| Buildings and improvements | 10 to 45 |
| Machinery and equipment | 3 to 25 |
| Leasehold improvements | Life of Lease |
Costs to obtain coal lands are capitalized based on the cost at acquisition and are amortized using the units-of-production method over all estimated recoverable coal reserve tons assigned and accessible to the mine. Recoverable coal reserves are calculated on a clean coal ton equivalent, which excludes non-recoverable coal reserves and anticipated preparation plant processing refuse. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum, once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material effect from changes in estimates is disclosed in the period the change occurs.
Impairment of Long-lived Assets:
Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to its estimated fair value, which is usually measured based on an estimate of future discounted cash flows. There were no indicators of impairment and therefore, no impairment losses were recognized during the years ended December 31, 20182019 and 2017.2018.
Pneumoconiosis Benefits and Workers’ Compensation:
The Partnership is required by federal and state statutes to provide our portion of benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers’ pneumoconiosis (“CWP”). The Partnership is also required by various state statutes to provide our portion of workers’ compensation benefits for employees who sustain employment relatedemployment-related physical injuries or some types of occupational disease. Workers’ compensation benefits include compensation for their disability, medical costs and, on some occasions, the cost of rehabilitation. The provisions for our portion of estimated benefits are determined on an actuarial basis for the Partnership’s dedicated contract labor provided under a service agreement with CONSOL Energy.
Asset Retirement Obligations:
Mine closing reclamation costs, perpetual water care costs and other costs associated with dismantling and removing facilities are accrued using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation to 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 costsobligations is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized asset retirement costobligation is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines.asset. Accretion is included in Depreciation, Depletion and Amortization on the Consolidated Statements of Operations. Asset retirement obligations primarily relate to the closure of mines which includes treatment of water and the reclamation of land upon exhaustion of coal reserves.
Accrued mine closing costs, perpetual care costs and reclamation costs and other costs of dismantling and removing facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.
Subsidence:
Subsidence occurs when there is damage of the ground surface due to the removal of underlying coal. Areas affected may include, although not be limited to, streams, property, roads, pipelines and other land and surface structures. Total estimated subsidence claims are recognized in the period when the related coal has been extracted and are included in Operating and Other Costs on the Consolidated Statements of Operations and Other Accrued Liabilities on the Consolidated Balance Sheets. On occasion, we prepay the estimated damages prior to undermining the property, in return for release of liability. Prepayments are included as assets and either recognized as Prepaid Expenses or in Other Assets on the Consolidated Balance Sheets, if the payment is made less than or greater than one year, respectively, prior to undermining the property.
Income Taxes:
The Partnership’s assets and liabilities are comprised of a 25% undivided interest in the Pennsylvania Mining Complex, which assets and liabilities are held by CPCC and Conrhein. The Partnership does not share in the separate income tax consequences attributable to the owners of CPCC and Conrhein. Accordingly, no provision for federal or state income taxes has been recorded. As of December 31, 20182019 and 2017,2018, the Partnership had no liability reported for unrecognized tax benefits and had not incurred interest and penalties related to income taxes. The Partnership’s operations are treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of taxable income. Therefore, the Partnership has excluded income taxes from these financial statements.
Revenue Recognition:
Revenues are generally recognized when title passes to the customers and the price is fixed and determinable. Generally, title passes when coal is loaded at the central preparation facility and, on occasion, at terminal locations or other customer destinations. Our coal contract revenue per ton is fixed and determinable and adjusted for nominal quality adjustments. Some coal contracts also contain positive electric power price-related adjustments in addition to a fixed base-price per ton. None of the Partnership's coal contracts allow for retroactive adjustments to pricing after title to the coal has passed. See Note 2 - Revenue for more information.
Freight Revenue and Expense:
Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.
Contingencies:
The Partnership, from time to time, is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.
Recent Accounting Pronouncements:
In 2016,August 2018, the Financial Accounting Standards Board (“FASB”) issued a new lease accounting standard, which requires lessees to put most leases on their balance sheets, but recognize the expenses in their income statements in a manner similar to current practice. The new standard states that a lessee will recognize a lease liability for the obligation to make lease payments and a right-of-use asset for the right to use the underlying asset for the lease term. Expenses related to leases determined to be operating leases will be recognized on a straight-line basis, while those determined to be financing leases will be recognized following a front-loaded expense profile in which interest and amortization are presented separately in the income statement. The following updates to this guidance were made in 2018:
capitalizing implementation costs incurred to develop or obtain internal-use software. These changes will be effective for fiscal years beginning after December 15, 2018,2019, including interim periods within those fiscal years. The Partnership will adopt ASC 842 in 2019 using the transition option, “Comparatives Under 840 Option,” established by ASU 2018-11, Leases (Topic 842), Targeted Improvements (ASU 2018-11). As most of our leases doManagement does not provide an implicit rate, we will takeexpect this update to have a portfolio approach of applying our incremental borrowing rate basedmaterial impact on the information available at adoption date to calculate the present value of lease payments over the lease term. We will elect the package of practical expedients permitted under the transition guidance within the new standard, which allows us (1) to not reassess whether any expired or existing contracts are or contain leases, (2) to not reassess the lease classification for any expired or existing leases and (3) to not reassess initial costs for any existing leases. We will also elect the practical expedient to not evaluate land easements that existed or expired before the entity’s adoption of Topic 842 and the practical expedient to not separate lease and non-lease components, that is, to account lease and non-lease components in a contract as a single lease component for all classes of underlying assets. Further, we will make an accounting policy election to keep leases with an initial term of 12 months or less off the balance sheet. We will recognize those lease payments in the Consolidated Statements of Operations over the lease term. Based on our lease portfolio, we anticipate recognizing an initial lease liability and related right-of-use asset on our balance sheet of approximately $15,000 to $25,000.Partnership's financial statements.
In August 2018, the FASB issued ASU 2018-14 - Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) to improve the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by GAAP. The amendments modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. These changes will be effective for fiscal years ending after December 15, 2020, including interim periods within those fiscal years. Management is currently evaluating the impact this guidance may have on the Partnership's financial statements.
In August 2018, the FASB issued ASU 2018-13 - Fair Value Measurement (Topic 820) to improve the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by GAAP. The amendments modify the disclosure requirements on fair value measurements, including the consideration of costs and benefits. These changes will be effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Management is currently evaluating the impact this guidance may have on the Partnership's financial statements.
In June 2016, the FASB issued ASU 2016-13 - Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this, the amendments in this ASU replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. In May 2019, the FASB updated Topic 326 by issuing ASU 2019-05, Financial Instruments-Credit Losses (Topic 326): Targeted Transition Relief, which provides entities that have certain instruments within the scope of Subtopic 326-20, Financial Instruments-Credit Losses - Measured at Amortized Cost, with an option to irrevocably elect the fair value option in Subtopic 825-10, Financial Instruments-Overall, applied on an instrument-by-instrument basis for eligible instruments, upon adoption of Topic 326. The amendments in this ASUthese updates will be applied using a modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 20192022 and interim periods within those annual periods. Early adoption is permitted under this guidance. Management is currently evaluating the overall impact the implementation of this guidance will have on the Partnership's financial statements. The Partnership's exposure to credit losses is concentrated on trade and other receivables arising from contractual agreements. Additional disclosures will be required to describe the nature and amount of the Partnership's credit losses, including the significant assumptions and judgments required to value the losses, and the accounting policy elections taken. The Partnership is implementing processes and controls to review the credit losses for fiscal years beginning after December 15, 2018appropriate accounting treatment in the context of the standards and interim periods within those annual periods. Management doesto generate disclosures required under the standards, which the Partnership expects to disclose in its Quarterly Report on Form 10-Q for the first quarter of 2020. As of the filing date of this Form 10-K, based on the Partnership's historical collection efforts, current industry trends in the markets the Partnership serves and the financial health of the Partnership's counterparties, the expected credit losses recognized upon adoption of this guidance are not expect this updateexpected to have a material impact on the Partnership's financial statements.
Reclassifications:
Certain amounts in prior periods have been reclassified to conform with the report classifications of the current period, including the reclassification of the Current Portion of Long-Term Debt, previously included in Other Accrued Liabilities on the Consolidated Balance Sheets. These reclassifications had no effect on previously reported Total Current Liabilities and are not material to the prior year presentation.
NOTE 2—REVENUE:
The following table disaggregates our revenue by major source to depict howfrom contracts with customers for the nature, amount, timingyears ended December 31, 2019 and uncertainty of the Partnership's revenues and cash flows are affected by economic factors:December 31, 2018:
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | ||||||
| Coal Revenue | $ | 322,132 | $ | 341,073 | |||
| Freight Revenue | 4,917 | 10,893 | |||||
| Total Revenue from Contracts with Customers | $ | 327,049 | $ | 351,966 | |||
| Year Ended December 31, 2018 | |||
| Coal Revenue | $ | 341,073 | |
| Freight Revenue | 10,893 | ||
| Total Revenue from Contracts with Customers | $ | 351,966 | |
The estimated transaction price from each of our contracts is based on the total amount of consideration to which we expect to be entitled under the contract. Included in the transaction price for certain coal supply contracts is the impact of variable consideration, including quality price adjustments, handling services, per ton price fluctuations based on certain coal sales price indices and anticipated payments in lieu of shipments. The estimated transaction price for each contract is allocated to our performance obligations based on relative standalone selling prices determined at contract inception.
Coal Revenue
Revenues are recognized when title passes to the customers and the price is fixed and determinable. Generally, title passes when coal is loaded at the central preparation facility and, on occasion, at terminal locations or other customer destinations. Our coal contract revenue per ton is fixed and determinable and adjusted for nominal quality adjustments. Some coal contracts also
contain positive electric power price-related adjustments in addition to a fixed base-price per ton. None of the Partnership's coal contracts allow for retroactive adjustments to pricing after title to the coal has passed.
Some of our contracts span multiple years and have annual pricing modification provisions, based upon market-driven or inflationary adjustments, where no additional value is exchanged. Also, some of our contracts contain favorable electric power price relatedprice-related adjustments, which represent market-driven price adjustments, wherein there is no additional value being exchanged. Management believes that the invoice price is the most appropriate rate at which to recognize revenue.
While we do, from time to time, experience costs of obtaining coal customer contracts with amortization periods greater than one year, those costs would behave been immaterial to our net income. As of and for the yearyears ended December 31, 2019 and December 31, 2018, we do not have any capitalized costs to obtain customer contracts on our balance sheet nor have we recognized any amortization of previously existing capitalized costs of obtaining customer contracts. Further, the Partnership has not recognized any revenue in the current period from performance obligations satisfied (or partially satisfied) in previous periods.
Freight Revenue
Some of our coal contracts require that we sell our coal at locations other than our central preparation plant. The cost to transport our coal to the ultimate sales point is passed through to our customers and we recognize the freight revenue equal to the transportation cost when title of the coal passes to the customer.
Contract Balances
Contract assets are recorded asseparately from trade receivables and reported separately in the Partnership's Consolidated Balance Sheet from other contract assetsand are reclassified to trade receivables as title passes to the customer and the Partnership's right to consideration becomes unconditional. Payments for coal shipments are typically due within two to four weeks of the invoice date. The Partnership
typically does not have material contract assets that are stated separately from trade receivables as the Partnership's performance obligations are satisfied as control of the goods or services passes to the customer, thereby granting the Partnership an unconditional right to receive consideration. Contract liabilities relate to consideration received in advance of the satisfaction of the Partnership's performance obligations. Contract liabilities are recognized as revenue at the point in time when control of the good or service passes to the customer.
NOTE 3—NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST:
The Partnership allocates net income among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income to our limited partners and our general partner in accordance with the terms of our Partnership Agreement. We also allocate any earnings in excess of distributions to our limited partners and our general partner in accordance with the terms of our Partnership Agreement. We allocate any distributions in excess of earnings for the period to our general partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the incentive distribution rights, as set forth in the Partnership Agreement.
Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.
On August 16, 2019, all 11,611,067 subordinated units were converted into common units on a 1-for-one basis. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2019. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests. Upon payment of the cash distribution for the second quarter of 2019, the financial requirements for the conversion of all subordinated units were satisfied.
The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated partner units (in thousands, except for per unit information):units:
| For the Year Ended | For the Year Ended | |||||||
| December 31, 2019 | December 31, 2018 | |||||||
| Net Income | $ | 45,551 | $ | 66,566 | ||||
| Less: General Partner Interest in Net Income | 768 | 1,127 | ||||||
| Net Income Allocable to Limited Partner Units | $ | 44,783 | $ | 65,439 | ||||
| Limited Partner Interest in Net Income - Common Units | $ | 32,552 | $ | 37,832 | ||||
| Limited Partner Interest in Net Income - Subordinated Units | 12,231 | 27,607 | ||||||
| Limited Partner Interest in Net Income - Basic & Diluted | $ | 44,783 | $ | 65,439 | ||||
| Weighted Average Limited Partner Units Outstanding - Basic | 27,622,032 | 27,511,804 | ||||||
| Weighted Average Limited Partner Units Outstanding - Diluted | 27,659,790 | 27,611,924 | ||||||
| Net Income Per Limited Partner Unit - Basic | ||||||||
| Common Units | $ | 1.62 | $ | 2.38 | ||||
| Subordinated Units | $ | 1.05 | $ | 2.38 | ||||
| Net Income Per Limited Partner Unit - Basic | $ | 1.62 | $ | 2.38 | ||||
| Net Income Per Limited Partner Unit - Diluted | ||||||||
| Common Units | $ | 1.62 | $ | 2.36 | ||||
| Subordinated Units | $ | 1.05 | $ | 2.38 | ||||
| Net Income Per Limited Partner Unit - Diluted | $ | 1.62 | $ | 2.37 | ||||
| For the Year Ended | For the Year Ended | |||||||
| December 31, 2018 | December 31, 2017 | |||||||
| Net Income | $ | 66,566 | $ | 40,464 | ||||
| Less: General Partner Interest in Net Income | 1,127 | 662 | ||||||
| Less: Net Income Allocable to Class A Preferred Units | — | 5,553 | ||||||
| Less: Distribution Effect of Preferred Unit Conversion | — | 173 | ||||||
| Net Income Allocable to Limited Partner Units | $ | 65,439 | $ | 34,076 | ||||
| Limited Partner Interest in Net Income - Common Units | $ | 37,832 | $ | 18,040 | ||||
| Less: Distribution Effect of Preferred Unit Conversion | — | 85 | ||||||
| Net Income Allocable to Common Units | $ | 37,832 | $ | 17,955 | ||||
| Limited Partner Interest in Net Income - Subordinated Units | $ | 27,607 | $ | 16,209 | ||||
| Less: Distribution Effect of Preferred Unit Conversion | — | 88 | ||||||
| Net Income Allocable to Subordinated Units | $ | 27,607 | $ | 16,121 | ||||
| Weighted Average Limited Partner Units Outstanding - Basic | ||||||||
| Common Units | 15,900,737 | 12,714,508 | ||||||
| Subordinated Units | 11,611,067 | 11,611,067 | ||||||
| Total | 27,511,804 | 24,325,575 | ||||||
| Weighted Average Limited Partner Units Outstanding - Diluted | ||||||||
| Common Units | 16,000,857 | 12,850,306 | ||||||
| Subordinated Units | 11,611,067 | 11,611,067 | ||||||
| Total | 27,611,924 | 24,461,373 | ||||||
| Net Income Per Limited Partner Unit - Basic | ||||||||
| Common Units | $ | 2.38 | $ | 1.41 | ||||
| Subordinated Units | $ | 2.38 | $ | 1.39 | ||||
| Net Income Per Limited Partner Unit - Diluted | ||||||||
| Common Units | $ | 2.36 | $ | 1.40 | ||||
| Subordinated Units | $ | 2.38 | $ | 1.39 | ||||
NOTE 4—OTHER INCOME:
| For the Years Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| Purchased Coal Sales | $ | 3,096 | $ | 4,788 | |||
| Coal Contract Buyout | 2,490 | 87 | |||||
| Property Easement and Option Income | 268 | 295 | |||||
| Loss on Sale of Assets | (49 | ) | (34 | ) | |||
| Other | 74 | 73 | |||||
| Total Other Income | $ | 5,879 | $ | 5,209 | |||
74
| For the Years Ended December 31, | |||||||
| 2018 | 2017 | ||||||
| Purchased Coal Sales | $ | 4,788 | $ | 3,290 | |||
| Property Easement and Option Income | 295 | — | |||||
| Coal Contract Buyout | 87 | 2,477 | |||||
| (Loss) Gain on Sale of Assets | (34 | ) | 1,399 | ||||
| Other | 73 | 282 | |||||
| Total Other Income | $ | 5,209 | $ | 7,448 | |||
NOTE 5—INTEREST EXPENSE:
* Excludes current portion of Finance Lease Obligations of $3,809 and $3,503 at December 31, 2019 and December 31, 2018, respectively.
We use various leased facilities and equipment in our operations. Future minimumOn January 1, 2019, the Partnership adopted Accounting Standards Codification (“ASC”) Topic 842 using the transition option, “Comparatives Under 840 Option,” established by ASU 2018-11, Leases (Topic 842), Targeted Improvements. As allowed under this guidance, the Partnership elected not to recast the comparative periods presented when transitioning to ASC 842. As most of the Partnership's leases do not provide an implicit rate, the Partnership has taken a portfolio approach of applying its incremental borrowing rate based on the information available at the adoption date to calculate the present value of lease payments over the lease term. The Partnership has elected the package of practical expedients permitted under capitalthe transition guidance within the standard, which allows the Partnership (1) to not reassess whether any expired or existing contracts are or contain leases, (2) to not reassess the lease classification for any expired or existing leases, and (3) to not reassess initial direct costs for any existing leases. The Partnership has also elected the practical expedient to not evaluate land easements that existed or expired before its adoption of Topic 842 and the practical expedient to not separate lease and non-lease components; that is, to account lease and non-lease components in a contract as a single lease component for all classes of underlying assets. Further, the Partnership made an accounting policy election to keep leases with an initial term of twelve months or less off the Consolidated Balance Sheets. The Partnership will recognize those lease payments in the Consolidated Statements of Operations over the lease term. For the year ended December 31, 2019, these short term lease expenses were not material to the Partnership's financial statements.
Rental expense related to2019, the Partnership had no additional significant operating or finance leases approximated $11,323 and $16,766 during the years ended December 31, 2018 and 2017, respectively.that had not yet commenced.
For the year ended December 31, 2018, we derived greater than 10% of our total coal sales revenue from three customers. For the year ended December 31, 2017, we derived greater than 10% of our total coal sales revenue from two customers.
CONSOL EnergyOmnibus Agreement
Article II of the omnibus agreement, eliminate all of our former sponsor’s obligations under the omnibus agreement and make certain adjustments to the indemnification obligations of the parties.
Charges for services from CONSOL Energy include the following:
At December 31, 2018 and December 31, 2017, the Partnership had a net payable to CONSOL Energy in the amount of $3,831 and $3,071, respectively. This payable includes reimbursements for business expenses, executive fees, stock-based compensation and other items under the omnibus agreement.Repurchase Program
David M. KhaniMiteshkumar B. Thakkar was appointed a director of our general partner effective March 16, 2015 and was appointed Chief Financial Officer of the general partner effective August 2, 2017. Since July 11, 2017, Mr. Khani has served as Executive Vice President and Chief Financial Officer of CONSOL Energy. Prior to that, Mr. Khani joined CNX on September 1, 2011 as its Vice President-Finance, and was promoted to Executive Vice President and Chief Financial Officer effective March 1, 2013, a
position he held until August 2, 2017. Prior to joining CNX, Mr. Khani was with FBR Capital Markets & Co. (“FBR”), an investment banking and advisory firm and held the following positions: Director of Research from February 2007 through October 2010, and then Co-Director of Research from November 2010 through August 2011. Prior to that time he served as the Managing Director and Co-Head of FBR’s Energy and Natural Resources Group. From May 30, 2014 until January 2018, Mr. Khani served as a director and the Chief Financial Officer of the general partner of CONE Midstream Partners LP. We believe Mr. Khani’s energy industry and financial experience providesby the board of directors of our general partner with valuable experienceas the General Partner's interim Chief Financial Officer, effective as of January 1, 2020. Mr. Thakkar has served as Director of Finance and Investor Relations of both CONSOL Energy and the Partnership since November 2017 and as Director of Finance and Investor Relations of the Partnership since May 2015. He previously served in our financialvarious roles in the equity research department of FBR Capital markets
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities (collectively, “Insiders”) to file with the SEC initial reports of ownership and reports of changes in ownership of such equity securities. Insiders are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of forms furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that the Insiders complied with all filing requirements under Rule 16(a) with respect to transactions in our equity securities during 2018, except for: (i) a late filing on Form 4 for one transaction related to vesting of an equity award for each of Messrs. Wallace, Greenwood and Sandman, which was one day late due to administrative error and (ii) a late filing on Form 4 by CONSOL Energy related to the purchase of CCR common units, which was one day late due to administrative error.
| For the Years Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| Interest on Affiliated Company Credit Agreement—Related Party | $ | 7,892 | $ | 7,709 | |||
| Interest on Finance Leases | 361 | 451 | |||||
| Capitalized Interest | (1,671 | ) | (1,508 | ) | |||
| Interest on Other Payables, Net | 22 | 15 | |||||
| Total Interest Expense | $ | 6,604 | $ | 6,667 | |||
| For the Years Ended December 31, | |||||||
| 2018 | 2017 | ||||||
| Interest on Notes - Related Party | $ | 7,709 | $ | 746 | |||
| Interest on Capitalized Leases | 451 | — | |||||
| Revolver Interest | — | 8,912 | |||||
| Capitalized Interest | (1,508 | ) | (361 | ) | |||
| Interest on Other Payables, Net | 15 | 12 | |||||
| Total Interest Expense | $ | 6,667 | $ | 9,309 | |||
NOTE 6—INVENTORIES:
| December 31, 2019 | December 31, 2018 | ||||||
| Coal | $ | 621 | $ | 1,160 | |||
| Supplies | 12,032 | 9,906 | |||||
| Total Inventories | $ | 12,653 | $ | 11,066 | |||
| December 31, 2018 | December 31, 2017 | ||||||
| Coal | $ | 1,160 | $ | 2,853 | |||
| Supplies | 9,906 | 9,450 | |||||
| Total Inventories | $ | 11,066 | $ | 12,303 | |||
NOTE 7—PROPERTY, PLANT AND EQUIPMENT:
| December 31, 2019 | December 31, 2018 | ||||||
| Coal and Other Plant and Equipment | $ | 666,560 | $ | 636,105 | |||
| Coal Properties and Surface Lands | 126,294 | 122,679 | |||||
| Airshafts | 106,750 | 102,275 | |||||
| Mine Development | 81,538 | 81,538 | |||||
| Coal Advance Mining Royalties | 3,756 | 3,701 | |||||
| Total Property, Plant and Equipment | 984,898 | 946,298 | |||||
| Less: Accumulated Depreciation, Depletion and Amortization | 571,238 | 526,747 | |||||
| Total Property, Plant and Equipment, Net | $ | 413,660 | $ | 419,551 | |||
| December 31, 2018 | December 31, 2017 | ||||||
| Coal and Other Plant and Equipment | $ | 636,105 | $ | 607,314 | |||
| Coal Properties and Surface Lands | 122,679 | 122,377 | |||||
| Airshafts | 102,275 | 95,566 | |||||
| Mine Development | 81,538 | 81,538 | |||||
| Coal Advance Mining Royalties | 3,701 | 3,673 | |||||
| Total Property, Plant and Equipment | 946,298 | 910,468 | |||||
| Less: Accumulated Depreciation, Depletion and Amortization | 526,747 | 483,410 | |||||
| Total Net Property, Plant and Equipment | $ | 419,551 | $ | 427,058 | |||
Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable coal reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered real property interests.
As of December 31, 20182019 and 2017,2018, property, plant and equipment includes gross assets under capitalfinance lease of $11,919$12,596 and $625,$11,919, respectively. Accumulated amortization for capitalfinance leases was $3,529$7,351 and $473$3,529 at December 31, 20182019 and 2017,2018, respectively. Amortization expense for assets under capitalfinance leases approximated $3,227$3,870 and $95$3,227 for the years ended December 31, 20182019 and 20172018 respectively, and is included in Depreciation, Depletion and Amortization in the accompanying Consolidated Statements of Operations.
75
NOTE 8—OTHER ACCRUED LIABILITIES:
| December 31, 2019 | December 31, 2018 | ||||||
| Subsidence Liability | $ | 22,661 | $ | 20,883 | |||
| Accrued Payroll and Benefits | 4,460 | 2,693 | |||||
| Accrued Interest (Related Party) | 2,541 | 1,767 | |||||
| Accrued Other Taxes | 921 | 1,071 | |||||
| Equipment Lease Rental | — | 515 | |||||
| Other | 1,383 | 1,925 | |||||
| Current Portion of Long-Term Liabilities: | |||||||
| Operating Lease Liability | 4,753 | — | |||||
| Workers' Compensation | 1,423 | 1,554 | |||||
| Asset Retirement Obligations | 954 | 1,202 | |||||
| Pneumoconiosis Benefits | 201 | 165 | |||||
| Long-Term Disability | 158 | 141 | |||||
| Total Other Accrued Liabilities | $ | 39,455 | $ | 31,916 | |||
| December 31, 2018 | December 31, 2017 | ||||||
| Subsidence Liability | $ | 20,883 | $ | 22,430 | |||
| Accrued Payroll and Benefits | 2,693 | 3,219 | |||||
| Accrued Interest (Related Party) | 1,767 | 824 | |||||
| Accrued Other Taxes | 1,071 | 1,399 | |||||
| Equipment Lease Rental | 515 | 2,906 | |||||
| Longwall Equipment Buyout | — | 5,658 | |||||
| Other | 1,925 | 5,069 | |||||
| Current Portion of Long-Term Liabilities: | |||||||
| Capital Leases | 3,503 | 77 | |||||
| Workers' Compensation | 1,554 | 1,381 | |||||
| Asset Retirement Obligations | 1,202 | 881 | |||||
| Pneumoconiosis Benefits | 165 | 195 | |||||
| Long-Term Disability | 141 | 140 | |||||
| Total Other Accrued Liabilities | $ | 35,419 | $ | 44,179 | |||
NOTE 9—LONG-TERM DEBT:
| December 31, 2019 | December 31, 2018 | ||||||
| Affiliated Company Credit Agreement (4.00% and 3.75% interest rate at December 31, 2019 and December 31, 2018, respectively) | $ | 180,925 | $ | 163,000 | |||
| Other Asset-Backed Financing Maturing in December 2020, 5.96% Weighted Average Interest Rate at December 31, 2019 | 1,443 | — | |||||
| 182,368 | 163,000 | ||||||
| Less: Amounts Due in One Year* | 1,443 | — | |||||
| Long-Term Debt | $ | 180,925 | $ | 163,000 | |||
| December 31, 2018 | December 31, 2017 | ||||||
| Affiliated Company Credit Agreement (3.75% interest rate at December 31, 2018) | $ | 163,000 | $ | 196,583 | |||
| Total Long-Term Debt | $ | 163,000 | $ | 196,583 | |||
* Excludes current portion of Finance Lease Obligations of $3,809 and $3,503 at December 31, 2019 and December 31, 2018, respectively.
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. 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 completion of the separation and the Partnership’s entry into the Affiliated Company Credit Agreement, the Partnership made an initial draw of $200,583, the net proceeds of which were used to repay the PNC Revolving Credit Facility.amounts outstanding under the Partnership's prior credit facility. Additional drawings under the Affiliated Company Credit Agreement are available for general partnership purposes. The Affiliated Company Credit Agreement matures on February 27, 2023. The collateral obligations under the Affiliated Company Credit Agreement generally mirror the PNC Revolving Credit Facility, including the list of entities that act as guarantors thereunder. The obligations under the Affiliated Company Credit Agreement are guaranteed by the Partnership’s subsidiaries and secured by substantially all of the assets of the Partnership and its subsidiaries pursuant to the security agreement and various mortgages.
Interest on outstanding obligations under our Affiliated Company Credit Agreement accrues at a fixed rate ranging from 3.75% to 4.75%, depending on the total net leverage ratio. The unused portion of our Affiliated Company Credit Agreement is subject to a commitment fee of 0.50% per annum.
The Partnership had available capacity under the Affiliated Company Credit Agreement of $112,000$94,075 and $78,417$112,000 as of December 31, 20182019 and 2017, respectively. Interest on outstanding borrowings under the Affiliated Company Credit Agreement was accrued at a rate of 3.75% and 4.25% as of December 31, 2018, and 2017, respectively.
The Affiliated Company Credit Agreement contains certain covenants and conditions that, among other things, limit the Partnership’s ability to: (i) incur or guarantee additional debt; (ii) make cash distributions (subject to certain limited exceptions); provided that we will be able to make cash distributions of available cash to partners so long as no event of default
is continuing or would result therefrom; (iii) incur certain liens or permit them to exist; (iv) make particular investments and loans; provided that we will be able to increase our ownership percentage of our undivided interest in the Pennsylvania Mining Complex and make investments in the Pennsylvania Mining Complex in accordance with our ratable ownership; (v) enter into certain types of transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer, sell or otherwise dispose of assets. The Partnership is also subject to covenants that require the Partnership to maintain certain financial ratios.
For example, the Partnership is obligated to maintain at the end of each fiscal quarter (a) 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, 2018,2019, the Partnership was in compliance with its debt covenants with thea first lien gross leverage ratio was 1.40of 1.84 to 1.00 and thea total net leverage ratio was 1.39of 1.83 to 1.00.
During the year ended December 31, 2019, the Partnership entered into an asset-backed financing arrangement related to certain equipment. The equipment, which has an approximate value of $1,443, fully collateralizes the loan.
NOTE 10—LEASES:
Based on the Partnership's lease portfolio, the standard had a material impact on the Partnership’s Consolidated Balance Sheets, but did not have a significant impact on the Partnership’s consolidated net earnings and cash flows. The most significant impact was the recognition of Right of Use (“ROU”) assets and lease liabilities for operating leases, while the accounting for finance leases remained substantially unchanged. The Partnership's bank covenants were not affected by this update. The Partnership recorded operating lease ROU assets and offsetting operating lease liabilities of approximately $20 million as of January 1, 2019, primarily related to mining equipment, based on the present value of the future lease payments on the date of adoption.
The Partnership determines if an arrangement is an operating or finance lease at inception of the applicable lease. For leases where the Partnership is the lessee, ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent an obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. As most of the Partnership’s leases do not provide an implicit interest rate, the Partnership uses its incremental borrowing rate based on the information available on the commencement date in determining the present value of lease payments. The ROU asset also consists of any prepaid lease payments, lease incentives received, and costs which will be incurred in exiting a lease. The lease terms used to calculate the ROU asset and related lease liability include options to extend or terminate the lease when it is reasonably certain that the Partnership will exercise that option. Lease expense for operating leases is recognized on a straight-line basis over the lease term as an operating expense while the expense for finance leases is recognized as depreciation expense and interest expense using the interest method of recognition.
The Partnership has operating leases for mining or other equipment used in operations and office space. Many leases include one or more options to renew, some of which include options to extend the leases, and some leases include options to terminate or buy out the leases within a set period of time. In some of the Partnership’s lease agreements, the rental payments are adjusted periodically to reflect actual charges incurred for inflation and/or changes in other indexes. Many of our operating lease payments for mining equipment contain a variable component which is calculated based upon production metrics such as
feet of advance or raw tonnage mined. While most of our leases contain clauses regarding the general condition of the equipment upon lease termination, they do not contain residual value guarantees.
For the year ended December 31, 2019, the components of operating lease expense were as follows:
| Fixed Operating Lease Expense | $ | 6,180 | |
| Variable Operating Lease Expense | 2,861 | ||
| Total Operating Lease Expense | $ | 9,041 | |
Supplemental cash flow information related to the Partnership’s operating leases for the year ended December 31, 2019 was as follows:
| Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities | $ | 6,130 | |
| ROU Assets Obtained in Exchange for Operating Lease Obligations | $ | — | |
The following table presents the lease balances within the Consolidated Balance Sheets, weighted average lease term, and weighted average discount rates related to the Partnership’s operating leases as of December 31, 2019:
| Lease Assets and Liabilities | Classification | Amount | ||
| Assets: | ||||
| Operating Lease ROU Assets | Other Assets | $ | 15,695 | |
| Liabilities: | ||||
| Current: | ||||
| Operating Lease Liabilities | Other Accrued Liabilities | $ | 4,753 | |
| Long-Term: | ||||
| Operating Lease Liabilities | Operating Lease Liabilities | $ | 11,507 | |
| Total Operating Lease Liabilities | $ | 16,260 | ||
| Weighted Average Remaining Lease Term (in Years) | 3.46 | |||
| Weighted Average Discount Rate | 6.2 | % | ||
The Partnership also enters into finance leases for mining equipment and automobiles. Assets arising from finance leases are included in Property, Plant and Equipment—Net and the liabilities are included in Current Portion of Long-Term Debt and Long-Term Debt in the Partnership's Consolidated Balance Sheets.
For the year ended December 31, 2019, the components of finance lease expense were as follows:
| Amortization of Right of Use Assets | $ | 3,870 | |
| Interest Expense | $ | 361 | |
The following table presents the weighted average lease term and weighted average discount rates related to the Partnership’s finance leases as of December 31, 2019:
| Weighted Average Remaining Lease Term (in Years) | 1.67 | |
| Weighted Average Discount Rate | 4.65 | % |
The following table presents the future maturities of the Partnership’s operating and finance lease liabilities, together with the present value of the net minimum capital lease payments, asat December 31, 2019:
| Finance Leases | Operating Leases | |||||
| 2020 | $ | 3,979 | $ | 5,722 | ||
| 2021 | 1,213 | 5,483 | ||||
| 2022 | 173 | 3,030 | ||||
| 2023 | 179 | 1,314 | ||||
| 2024 | 138 | 1,211 | ||||
| Thereafter | — | 1,730 | ||||
| Total minimum lease payments | $ | 5,682 | $ | 18,490 | ||
| Less amount representing interest | 228 | 2,230 | ||||
| Present value of minimum lease payments | $ | 5,454 | $ | 16,260 | ||
As of December 31, 2018 are as follows:
| Capital Leases | Operating Leases | ||||||
| 2019 | $ | 3,840 | $ | 5,657 | |||
| 2020 | 4,178 | 5,271 | |||||
| 2021 | 1,052 | 5,068 | |||||
| 2022 | 12 | 2,614 | |||||
| 2023 | 9 | 899 | |||||
| Thereafter | — | 1,661 | |||||
| Total Minimum Lease Payments | $ | 9,091 | $ | 21,170 | |||
| Less Amount Representing Interest | 521 | ||||||
| Present Value of Minimum Lease Payments | 8,570 | ||||||
| Less Amount Due in One Year | 3,503 | ||||||
| Total Long-Term Capital Lease Obligations | $ | 5,067 | |||||
NOTE 11—FAIR VALUE OF FINANCIAL INSTRUMENTS:
The Partnership determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including LIBOR-based discount rates), while unobservable inputs reflect the Partnership’s own assumptions of what market participants would use.
The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below.
Level One - Quoted prices for identical instruments in active markets.
Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including LIBOR-based discount rates.
Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity. The significant unobservable inputs used in the fair value measurement of the Partnership’s third party guarantees are the credit risk of the third party and the third party surety bond markets.
In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.
The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:
Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
| December 31, 2019 | December 31, 2018 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
| Affiliated Company Credit Agreement - Related Party | $ | 180,925 | $ | 180,925 | $ | 163,000 | $ | 163,000 | |||||||
| December 31, 2018 | December 31, 2017 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
| Affiliated Company Credit Agreement - Related Party | $ | 163,000 | $ | 163,000 | $ | 196,583 | $ | 196,583 | |||||||
The Partnership’s debt obligations are valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.
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NOTE 12—ASSET RETIREMENT OBLIGATIONS:
| December 31, 2019 | December 31, 2018 | ||||||
| Balance at Beginning of Period | $ | 10,977 | $ | 10,496 | |||
| Accretion Expense | 906 | 813 | |||||
| Payments | (496 | ) | (50 | ) | |||
| Revisions in Estimated Cash Flows | 368 | (282 | ) | ||||
| Balance at End of Period | $ | 11,755 | $ | 10,977 | |||
| December 31, 2018 | December 31, 2017 | ||||||
| Balance at Beginning of Period | $ | 10,496 | $ | 9,937 | |||
| Accretion Expense | 813 | 774 | |||||
| Payments | (50 | ) | (209 | ) | |||
| Revisions in Estimated Cash Flows | (282 | ) | (6 | ) | |||
| Balance at End of Period | $ | 10,977 | $ | 10,496 | |||
NOTE 13—COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION:
The Partnership is contractually obligated for our portion of medical and disability benefits to CPCC employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. Conrhein has no current or former employees. The Partnership is also responsible under various state statutes for our portion of pneumoconiosis benefits. The calculation of our portion of the actuarial present value of the estimated pneumoconiosis obligation is based on an annual actuarial study by external actuaries and uses assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates which are derived from actual experience and outside sources. Actuarial gains or losses can result from discount rate changes, differences in incident rates and severity of claims filed as compared to original assumptions.
The Partnership is also contractually required to compensate individuals who sustain employment relatedemployment-related physical injuries or some types of occupational diseases and, on some occasions, for our portion of costs of their rehabilitation. Workers’ compensation lawsprograms will also compensate survivors of workers who suffer employment-related deaths. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. The Partnership primarily provides for our portion of these claims through a self-insurance program. The Partnership recognizes an actuarial present value for our portion of the estimated workers’ compensation obligation calculated by independent actuaries. The calculation is based on claims filed and an estimate of claims incurred, but not yet reported, as well as various assumptions. The assumptions include discount rate, future healthcare trend rate, benefit duration and recurrence of injuries. Actuarial gains associated with workers’ compensation have resulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident rates than our assumptions.
| CWP | Workers’ Compensation | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||||||
| Change in Benefit Obligation: | ||||||||||||||||
| Benefit Obligation at Beginning of Period | $ | 4,425 | $ | 4,028 | $ | 4,522 | $ | 4,785 | ||||||||
| State Administrative Fees and Insurance Bond Premiums | — | — | 201 | 90 | ||||||||||||
| Service Cost | 801 | 1,489 | 1,395 | 1,464 | ||||||||||||
| Interest Cost | 194 | 144 | 165 | 139 | ||||||||||||
| Actuarial Loss (Gain) | 990 | (1,050 | ) | 77 | (355 | ) | ||||||||||
| Benefits and Fees Paid | (181 | ) | (186 | ) | (1,430 | ) | (1,601 | ) | ||||||||
| Benefit Obligation at End of Period | $ | 6,229 | $ | 4,425 | $ | 4,930 | $ | 4,522 | ||||||||
| Funded Status: | ||||||||||||||||
| Current Assets | $ | — | $ | — | $ | 104 | $ | 151 | ||||||||
| Current Liabilities | (201 | ) | (165 | ) | (1,423 | ) | (1,554 | ) | ||||||||
| Noncurrent Liabilities | (6,028 | ) | (4,260 | ) | (3,611 | ) | (3,119 | ) | ||||||||
| Net Obligation Recognized | $ | (6,229 | ) | $ | (4,425 | ) | $ | (4,930 | ) | $ | (4,522 | ) | ||||
| Amounts Recognized in Accumulated Other Comprehensive Income Consist of: | ||||||||||||||||
| Net Actuarial Gain | $ | 7,250 | $ | 8,215 | $ | 3,389 | $ | 3,515 | ||||||||
| Net Amount Recognized | $ | 7,250 | $ | 8,215 | $ | 3,389 | $ | 3,515 | ||||||||
| CWP | Workers’ Compensation | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||||||
| Change in Benefit Obligation: | ||||||||||||||||
| Benefit Obligation at Beginning of Period | $ | 4,028 | $ | 2,113 | $ | 4,785 | $ | 4,385 | ||||||||
| State Administrative Fees and Insurance Bond Premiums | — | — | 90 | 243 | ||||||||||||
| Service Cost | 1,489 | 1,131 | 1,464 | 1,225 | ||||||||||||
| Interest Cost | 144 | 72 | 139 | 130 | ||||||||||||
| Actuarial (Gain) Loss | (1,050 | ) | 780 | (355 | ) | 196 | ||||||||||
| Benefits and Fees Paid | (186 | ) | (68 | ) | (1,601 | ) | (1,394 | ) | ||||||||
| Benefit Obligation at End of Period | $ | 4,425 | $ | 4,028 | $ | 4,522 | $ | 4,785 | ||||||||
| Current Assets | $ | — | $ | — | $ | 151 | $ | — | ||||||||
| Current Liabilities | (165 | ) | (195 | ) | (1,554 | ) | (1,381 | ) | ||||||||
| Noncurrent Liabilities | (4,260 | ) | (3,833 | ) | (3,119 | ) | (3,404 | ) | ||||||||
| Net Obligation Recognized | $ | (4,425 | ) | $ | (4,028 | ) | $ | (4,522 | ) | $ | (4,785 | ) | ||||
| Amounts Recognized in Accumulated Other Comprehensive Income Consist of: | ||||||||||||||||
| Net Actuarial Gain | $ | 8,215 | $ | 7,187 | $ | 3,515 | $ | 3,165 | ||||||||
| Net Amount Recognized | $ | 8,215 | $ | 7,187 | $ | 3,515 | $ | 3,165 | ||||||||
The components of the net periodic benefit cost are as follows:
| CWP | Workers’ Compensation | ||||||||||||||
| For the Years Ended December 31, | For the Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2019 | 2018 | ||||||||||||
| Service Cost | $ | 801 | $ | 1,489 | $ | 1,395 | $ | 1,464 | |||||||
| Interest Cost | 194 | 144 | 165 | 139 | |||||||||||
| Recognized Net Actuarial Loss (Gain) | 25 | (21 | ) | (50 | ) | (4 | ) | ||||||||
| State Administrative Fees and Insurance Bond Premiums | — | — | 201 | 90 | |||||||||||
| Net Periodic Benefit Cost | $ | 1,020 | $ | 1,612 | $ | 1,711 | $ | 1,689 | |||||||
| CWP | Workers’ Compensation | ||||||||||||||
| For the Years Ended December 31, | For the Years Ended December 31, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Service Cost | $ | 1,489 | $ | 1,131 | $ | 1,464 | $ | 1,225 | |||||||
| Interest Cost | 144 | 72 | 139 | 130 | |||||||||||
| Recognized Net Actuarial Gain | (21 | ) | (135 | ) | (4 | ) | (33 | ) | |||||||
| State Administrative Fees and Insurance Bond Premiums | — | — | 90 | 243 | |||||||||||
| Net Periodic Benefit Cost | $ | 1,612 | $ | 1,068 | $ | 1,689 | $ | 1,565 | |||||||
Amounts that are currently included in accumulated other comprehensive (loss) income are $(25)$(163) and $49$34 for CWP benefits and workers’ compensationWorkers’ Compensation benefits, respectively, that are expected to be recognized in 20192020 net periodic benefit costs:
Assumptions:
The weighted-average discount rates used to determine benefit obligations and net periodic cost (benefit)benefit costs are as follows:
| CWP | Workers’ Compensation | |||||||||||
| For the Years Ended | For the Years Ended | |||||||||||
| December 31, | December 31, | |||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||
| Benefit Obligations | 3.41 | % | 4.42 | % | 3.25 | % | 4.26 | % | ||||
| Net Periodic Benefit Costs | 4.42 | % | 3.75 | % | 4.26 | % | 3.57 | % | ||||
| CWP | Workers’ Compensation | |||||||||||
| For the Years Ended | For the Years Ended | |||||||||||
| December 31, | December 31, | |||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||
| Benefit Obligations | 4.42 | % | 3.75 | % | 4.26 | % | 3.57 | % | ||||
| Net Periodic Cost (Benefit) | 3.75 | % | 4.40 | % | 3.57 | % | 4.05 | % | ||||
Assumed discount rates have a significant effect on the amounts reported for both CWP benefits and Workers’ Compensation costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:
| 0.25 Percentage Point Increase | 0.25 Percentage Point Decrease | |||||||
| CWP Costs (Decrease) Increase | $ | (47 | ) | $ | 50 | |||
| Workers’ Compensation Costs (Decrease) Increase | $ | (23 | ) | $ | 24 | |||
| 0.25 Percentage Point Increase | 0.25 Percentage Point Decrease | |||||||
| CWP Costs (Decrease) Increase | $ | (82 | ) | $ | 88 | |||
| Workers’ Compensation Costs Increase (Decrease) | $ | 38 | $ | (40 | ) | |||
Cash Flows:
The Partnership does not intend to make contributions to the CWP or Workers’ Compensation plans in 2019.2020. We intend to pay benefit claims as they become due.
The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:
Workers’ Compensation | ||||||||||||||||
| CWP | Total | Actuarial | Other | |||||||||||||
| Benefits | Benefits | Benefits | Benefits | |||||||||||||
| 2020 | $ | 201 | $ | 1,497 | $ | 1,319 | $ | 178 | ||||||||
| 2021 | 225 | 1,661 | 1,479 | 182 | ||||||||||||
| 2022 | 257 | 1,765 | 1,578 | 187 | ||||||||||||
| 2023 | 276 | 1,868 | 1,677 | 191 | ||||||||||||
| 2024 | 301 | 1,931 | 1,735 | 196 | ||||||||||||
| Year 2025-2029 | 2,070 | 10,762 | 9,706 | 1,056 | ||||||||||||
Workers’ Compensation | ||||||||||||||||
| CWP | Total | Actuarial | Other | |||||||||||||
| Benefits | Benefits | Benefits | Benefits | |||||||||||||
| 2019 | $ | 165 | $ | 1,659 | $ | 1,403 | $ | 256 | ||||||||
| 2020 | 139 | 2,404 | 2,142 | 262 | ||||||||||||
| 2021 | 153 | 2,431 | 2,162 | 269 | ||||||||||||
| 2022 | 172 | 2,460 | 2,185 | 275 | ||||||||||||
| 2023 | 200 | 2,495 | 2,213 | 282 | ||||||||||||
| Year 2024-2028 | 1,606 | 13,103 | 11,582 | 1,521 | ||||||||||||
NOTE 14—OTHER BENEFIT PLANS:
Pension:
The Partnership is contractually obligated to fund 25% of CPCC’s portion of employees, which provide mining services to the Partnership, that participate in the CONSOL Energy Inc. Employee Retirement Plan (the “Plan”). In connection with the separation, the sponsorship of the CONSOL Energy Inc. Employee Retirement Plan (the “Pension Plan”) was transferred to CONSOL Energy. The Pension Plan is a non-contributory defined benefit retirement plan covering substantially all full-time non-represented employees. Effective December 31, 2015, the Plan was frozen for all remaining participants in the Plan. The benefits for the Plan are based primarily on years of service and employees’ pay. The costs of these benefits during the years ended December 31, 20182019 and 20172018 were $258 and $884,$258, respectively. These costs are reflected in Operating and Other Costs in the Consolidated Statements of Operations.
Investment Plan:
The Partnership is contractually obligated to fund 25% of CPCC’s portion of our former sponsor’s investment plan through August 31, 2017 and 25% of CPCC’s portion of the CPCC’s investment plan (the “CPCC 401k plan”) beginning September 1, 2017. Eligible employees of CPCC began participation in the CPCC 401k plan on September 1, 2017, which was the inception date of the CPCC 401k Plan. Effective December 31, 2019, the CPCC 401k Plan was amended to change its sponsor from CONSOL Pennsylvania Coal Company to CONSOL Energy Inc., and the plan's name was changed from the CONSOL Pennsylvania Coal Company Investment Plan to the CONSOL Energy Inc. Investment Plan (the “CEIX 401k Plan”). Both the 401k plan of our former sponsor and the CPCCCEIX 401k plansPlans are available to most employees and include company matching of 6% of eligible compensation contributed by eligible employees of CPCC. Total payments and costs were $4,795$2,389 and $2,389$4,795 for the years ended December 31, 20182019 and 2017,2018, respectively. These costs are reflected in Operating and Other Costs in the Consolidated Statements of Operations.
The CEIX 401k Plan also provides for discretionary contributions ranging from 1% to 6% of eligible compensation for eligible employees (as defined by the CEIX 401k Plan). For the year ended December 31, 2018, $2,330 was accrued as a discretionary contribution under this plan and was paid into employees accounts in the first quarter of 2019. There were no0 such discretionary contributions made for the year ended December 31, 2017.2019. These costs are reflected in Operating and Other Costs in the Consolidated Statements of Operations and recorded in Accounts Payable on the Consolidated Balance Sheet.Sheets.
Long-Term Disability:
The Partnership is contractually obligated for its portion of a Long-Term Disability Plan available to all eligible full-time salaried employees of CPCC. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.
| For the Years Ended | |||||||
| December 31, 2019 | December 31, 2018 | ||||||
| Net periodic benefit costs | $ | 143 | $ | 119 | |||
| Discount rate assumption used to determine net periodic benefit costs | 3.97 | % | 3.22 | % | |||
| For the Years Ended | |||||||
| December 31, 2018 | December 31, 2017 | ||||||
| Benefit costs | $ | 119 | $ | 41 | |||
| Discount rate assumption used to determine net periodic benefit costs | 3.22 | % | 3.43 | % | |||
Long-Term Disability-related liabilities are included in Other Liabilities-Other and Other Accrued Liabilities on the Consolidated Balance Sheets and amounted to $413$705 and $494$413 at December 31, 20182019 and 2017,2018, respectively.
NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION:
As of December 31, 20182019 and 2017,2018, the Partnership purchased goods and services related to capital projects in the amount of $838 and $467, and $878, respectively, thatwhich are included in accounts payable.payable and the current portion of long-term debt on the Consolidated Balance Sheets.
During the year ended December 31, 2019, the Partnership entered into non-cash finance lease arrangements of $717. During the year ended December 31, 2018, the Partnership terminated two2 operating leases on its longwall shields, and refinanced these as capitalfinance leases in the amount of $11,495.
For the years ended December 31, 20182019 and 2017,2018, the Partnership paid interest expense, net of capitalized interest, of $5,709$5,802 and $7,864,$5,709, respectively.
NOTE 16—CONCENTRATION OF CREDIT RISK:
The Partnership primarily markets thermal coal principally to electric utilities in the eastern United States. Substantially all revenues were generated from sales based in the United States for the years ended December 31, 2019 and 2018. Less than 2% of the Partnership's revenues were generated from sales based in Canada for the year ended December 31, 2019. During the years ended December 31, 2019 and 2018, three customers each accounted for over 10% of the Partnership's total coal sales revenue, aggregating approximately 70% and 2017. We have57%, respectively, of our sales. Additionally, two of the Partnership's customers had outstanding balances each in excess of 10% of the total trade receivables balance as of December 31, 2019 and 2018.
The Partnership has contractual relationships with certain coal exporters who distribute coal to international markets. For the years ended December 31, 2019 and 2018, approximately 35% and 2017, approximately 29% and 31%, respectively, of ourthe Partnership's coal revenues were derived from these exporters, in which ourits coal was intended to be shipped to Europe, Asia, Europe, South America and Africa.
NOTE 17—COMMITMENTS AND CONTINGENT LIABILITIES:
The Partnership is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes and other claims and actions arising out of the normal course of its business. We accrue the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. Our current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of the Partnership. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of the Partnership; however, such amounts cannot be reasonably estimated.
At December 31, 2018,2019, the Partnership was contractually obligated to CONSOL Energy for financial guarantees and letters of credit to certain third parties which were issued by CONSOL Energy on behalf of the Partnership. The maximum potential total of future payments that we could be required to make under these instruments is $83,324.$99,451. The instruments are
comprised of $301$1,937 of letters of credit expiring in the next three years, $73,569$88,895 of environmental surety bonds expiring within the next three years and $9,454$8,619 of employee-related and other surety bonds expiring within the next three years. Employee-related financial guarantees have primarily been provided to support various state workers’ compensation and federal black lung self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Other guarantees have been extended to support
insurance policies, legal matters, full and timely payments of mining equipment leases, and various other items necessary in the normal course of business. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. The Partnership’s management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on the financial condition of the Partnership.
NOTE 18—RECEIVABLES FINANCING AGREEMENT
On November 30, 2017, (i) CONSOL Marine Terminals LLC, formerly known as CNX Marine Terminals LLC, as an originator of receivables, (ii) CPCC, as an originator of receivables and as initial servicer of the receivables for itself and the other originators (collectively, the “Originators”), each a wholly owned subsidiary of CONSOL Energy, and (iii) CONSOL Funding LLC (the “SPV”), 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- OriginatorSub-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 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. The SPV’s assets and credit are not available to satisfy the debts and obligations owed to the creditors of CONSOL Energy, CONSOL Thermal Holdings or any of the Originators. CONSOL Thermal Holdings, the Originators and CPCC as servicer are independently liable for their own customary representations, warranties, covenants and indemnities. In addition, CONSOL Energy has guaranteed the performance of the obligations of CONSOL Thermal Holdings, the Originators and CPCC as servicer, and will guarantee the obligations of any additional originators or successor servicer that may become party to the Securitization. However, neither CONSOL Energy nor its affiliates will guarantee collectability of receivables or the creditworthiness of obligors thereunder.
The Securitization contains various customary representations and warranties, covenants and default provisions which provide for the termination and acceleration of the commitments and loans under the Securitization in circumstances including, but not limited to, failure to make payments when due, breach of representation, warranty or covenant, certain insolvency events or failure to maintain the security interest in the trade receivables, and defaults under other material indebtedness.
As of December 31, 2019 and 2018, respectively, the Partnership, through CONSOL Thermal Holdings, had sold $33,294 and $21,871 of trade receivables to CPCC. The Partnership has not derecognized the receivables due to its continued involvement in the collections efforts.
NOTE 19—RELATED PARTY:
The Partnership prioris a party to the separation, entered into several agreementsOmnibus Agreement, dated September 30, 2016, as amended on November 28, 2017, with our sponsor and certain of its affiliates, including an omnibus agreement. On September 30, 2016,subsidiaries. Under the Omnibus Agreement, we are obligated to make certain payments to, and reimburse, CONSOL Energy for the provision of certain services in connection with our operations.
Charges for services from CONSOL Energy under the First Drop Down, weOmnibus Agreement include the following:
| For the Years Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| Operating and Other Costs | $ | 3,219 | $ | 2,918 | |||
| Selling, General and Administrative Expenses | 8,309 | 8,300 | |||||
| Total Services from CONSOL Energy | $ | 11,528 | $ | 11,218 | |||
At December 31, 2019 and December 31, 2018, the Partnership had a net payable to CONSOL Energy in the amount of $1,419 and $3,831, respectively. This payable includes reimbursements for business expenses, executive fees, stock-based compensation and other parties toitems under the omnibus agreement entered into a First Amended and Restated Omnibus Agreement. On November 28, 2017,
Affiliated Company Credit Agreement
As described in connection with the separation, the general partner,Note 9, the Partnership our former sponsor, CONSOL Energy and certain of its subsidiaries entered into the First Amendment to the First Amended and Restated Omnibus Agreement to add CONSOL Energy asis also a party to the omnibus agreement, eliminate the right-of-first offer to the Partnership for the 75% of the Pennsylvania Mining Complex not owned by the Partnership, effect an assignment of all our former sponsor’s rights and obligations toAffiliated Company Credit Agreement with CONSOL Energy and remove our former sponsor as a party to the agreement and, except with respect to our former sponsor’s obligations underEnergy.
| For the Years Ended December 31, | |||||||
| 2018 | 2017 | ||||||
| Operating and Other Costs | $ | 2,918 | $ | 3,503 | |||
| Selling, General and Administrative Expenses | 8,300 | 3,109 | |||||
| Total Services from CONSOL Energy | $ | 11,218 | $ | 6,612 | |||
For the year ended December 31, 2019 and 2018, $7,892 and $7,709, respectively, of interest was incurred under the Affiliated Company Credit Agreement, of which $6,667 is included in Interest Expense in the Consolidated Statements of Operations$1,671 and $1,042, respectively, was capitalized and included in Property, Plant and Equipment on the Consolidated Balance Sheets. For the year ended December 31, 2017, $746 of interest was incurred under the Affiliated Company Credit Agreement and is included in Interest Expense in the Consolidated Statements of Operations. Interest is calculated based upon a fixed rate, determined quarterly, depending on the total net leverage ratio. For the years ended December 31, 20182019 and 2017,2018, the average interest rate was 3.97%3.85% and 4.25%3.97%, respectively. See Note 9 - Long-Term Debt for more information.
In July 2018,May 2019, CONSOL Energy's Board of Directors approved an expansion of itsthe stock, unit and debt repurchase program. The program expansion allowspreviously allowed CONSOL Energy to use up to $25 million of the program to purchase CONSOL Coal Resources LP'sthe Partnership's outstanding common units in the open market. The repurchase program does not obligate CONSOL Energy to repurchase any dollar amount or number of common units and CONSOL Energy's Board of Directors may modify, suspend or discontinue its authorizationapproved changing the termination date of the program at any time.from June 30, 2019 to June 30, 2020. Also, in accordance with CONSOL Energy’s credit facility covenants, the total amount that can be used for repurchases of the Partnership's outstanding common units was raised to $50 million. During the yearyears ended December 31, 2019 and 2018, 26,297 and 167,958 common units were repurchased at an average price of $14.05 and $18.33 per unit.unit, respectively.
Conversion of Subordinated Units
In August 2019, upon payment of the cash distribution with respect to the quarter ended June 30, 2019, the financial requirements for the conversion of all the Partnership's subordinated units were satisfied. As a result, all 11,611,067 subordinated units, owned entirely by CONSOL Energy Inc., were converted into common units on a 1-for-one basis. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.
NOTE 20—LONG-TERM INCENTIVE PLAN:
Under the CONSOL Coal Resources LP 2015 Long-Term Incentive Plan (the “LTIP”), our general partner may issue long-term equity-based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards are intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. We are responsible for the cost of awards granted under the LTIP and all determinations with respect to awards to be made under the LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator.
The LTIP limits the number of units that may be delivered pursuant to vested awards to 2,300,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards. The Partnership recognizes forfeitures as they occur.
The general partner has granted equity-based phantom units that vest over a period of a recipient’s continued service with the Partnership. The phantom units will be paid in common units or an amount of cash equal to the fair market value of a unit based on the vesting date. The awards may accelerate upon a change in control of the Partnership. Compensation expense is recognized on a straight-line basis over the requisite service period, which is generally the vesting term. The Partnership modified certain employees’ phantom awards to eliminate the service requirement, resulting in $40recognized $1,409 and $1,686 of incremental compensation cost for the years ended December 31, 2018 and 2017, respectively. The Partnership recognized $1,842 and $5,873 of compensation expense for the years ended December 31, 20182019 and 2017,2018, respectively, which is included in Selling, General and Administrative Expense in the Consolidated Statements of Operations. As of December 31, 2018,2019, there is $1,305$121 of unearned compensation that will vest over a weighted average period of 1.030.09 years. The total fair value of phantom units vested during the years ended December 31, 2019 and 2018 was $2,906 and 2017 was $2,508, and $4,098, respectively. The following represents the
nonvested phantom units and their corresponding weighted average grant date fair value:
| Number of Units | Weighted Average Grant Date Fair Value per Unit | |||||
| Nonvested at December 31, 2018 | 223,676 | $ | 15.67 | |||
| Granted | 17,190 | $ | 17.45 | |||
| Vested | (158,554 | ) | $ | 13.41 | ||
| Forfeited | (3,967 | ) | $ | 18.95 | ||
| Nonvested at December 31, 2019 | 78,345 | $ | 18.62 | |||
| Number of Units | Weighted Average Grant Date Fair Value per Unit | |||||
| Nonvested at December 31, 2017 | 401,409 | $ | 14.87 | |||
| Granted | 18,807 | $ | 15.95 | |||
| Vested | (179,281 | ) | $ | 13.99 | ||
| Forfeited | (17,259 | ) | $ | 14.81 | ||
| Nonvested at December 31, 2018 | 223,676 | $ | 15.67 | |||
NOTE 21—FINANCIAL INFORMATION FOR SUBSIDIARY GUARANTORS AND FINANCE SUBSIDIARY OF POSSIBLE FUTURE PUBLIC DEBT:
The Partnership filed a Registration Statement on Form S-3 (333-215962)(Reg. No. 333-215962) with the SEC on March 10, 2017, which was declared effective by the SEC on March 14, 2017, to register the offer and sale of various securities, including debt securities. The registration statement registers guarantees of debt securities by CONSOL Operating and CONSOL Thermal Holdings (“Subsidiary Guarantors”). The Subsidiary Guarantors are 100% owned by the Partnership and any guarantees by the Subsidiary Guarantors will be full and unconditional and joint and several. In addition, the registration statement also includes CONSOL Coal Finance, which was formed for the sole purpose of co-issuing future debt securities with the Partnership. CONSOL Coal Finance is wholly owned by the Partnership, has no assets or any liabilities and its activities will be limited to co-issuing debt securities and engaging in other activities incidental thereto. The Partnership does not have any other subsidiaries other than the Subsidiary Guarantors and CONSOL Coal Finance. In addition, the Partnership has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Partnership by dividend or loan other than under the Affiliated Company Credit Agreement described in these notes. In the event that more than one of the Subsidiary Guarantors guarantee public debt securities of the Partnership in the future, those guarantees will be full and unconditional and will constitute the joint and several obligations of the Subsidiary Guarantors. None of the assets of the Partnership, the Subsidiary Guarantors or CONSOL Coal Finance represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.
NOTE 22—SUBSEQUENT EVENTS:
On January 24, 2019,2020, the Board of Directors of our general partner declared a cash distribution of $0.5125 per unit for the quarter ended December 31, 20182019 to the limited partner unitholders and the holder of the general partner interest. The cash distribution will be paid on February 15, 201914, 2020 to the unitholders of record at the close of business on February 7, 2019.10, 2020.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of the management of the Partnership’s general partner, including the Chief Executive Officer and Interim Chief Financial Officer of the general partner, an evaluation of the effectiveness of our disclosure controls and procedures pursuant to Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), was conducted as of the end of the period covered by this report. Based upon this evaluation, the Chief
Executive Officer and Interim Chief Financial Officer of the Partnership’s general partner have concluded that the Partnership’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Management’s Report on Internal Control over Financial Reporting
The management of the Partnership’s general partner is responsible for establishing and maintaining adequate internal control over financial reporting, which is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Partnership’s internal control over financial reporting includes policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2018.2019. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (“COSO”) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2018.2019.
This annual report on Form 10-K for the fiscal year ended December 31, 20182019 does not include an attestation report of the Partnership’s independent accounting firm due to a transition period established by rules of the Securities and Exchange Commission for emerging growth companies.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
During 2018, the Partnership began implementing an enterprise resource planning system, which is expected to improve the efficiency of certain financial and related transactional processes. During the first half of fiscal year 2019, the Partnership completed the implementation of certain processes, and revised and updated the related controls. These changes did not materially affect the Partnership's internal control over financial reporting.
It should be noted that any system of controls, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events.
ITEM 9B. OTHER INFORMATION
None.
87
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF GENERAL PARTNER
We are managed and operated by the directors and executive officers of our general partner, CONSOL Coal Resources GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. CONSOL Energy owns all of the membership interests in our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Our unitholders are not entitled to nominate candidates for, or elect the directors of our general partner’s board of directors or to directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.
Our general partner has seven directors of which three, Messrs. Greenwood, Sandman and Wallace, have been determined by our board to be independent as defined under the independence standards established by the New York Stock Exchange (“NYSE”) and the Exchange Act. NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the board of directors of its general partner.
The following table presents information for the board of directors and executive officers of CONSOL Coal Resources GP LLC as of December 31, 2018.January 24, 2020. In evaluating director candidates, CONSOL Energy will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of our board of directors to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board of directors of our general partner to fulfill their duties. Directors hold office until their successors have been appointed or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors.
| Name | Age | Position with Our General Partner | ||
| James A. Brock | Chairman of the Board and Chief Executive Officer | |||
| John M. Rothka | Chief Accounting Officer | |||
| Martha A. Wiegand | Director and General Counsel and Secretary | |||
| Michael L. Greenwood | Director and Member of the Audit* and Conflicts Committee | |||
| Deborah J. Lackovic | Director | |||
| Kurt R. Salvatori | Director | |||
| Dan D. Sandman | Director and Member of Audit and Conflicts Committee | |||
| Jeffrey L. Wallace | Director and Member of Audit and Conflicts* Committees | |||
*Indicates Chair of Committee
James A. Brock was appointed Chief Executive Officer and a director of our general partner effective March 16, 2015. Mr. Brock also serves as President and Chief Operating Officer of CONSOL Energy. He has held the Chief Executive Officer position at CONSOL Energy since July 11, 2017 and he assumed the responsibility of President of CONSOL Energy on December 2, 2017. From December 10, 2010 to November 28, 2017, Mr. Brock served as the Chief Operating Officer - Coal of CNX.CNX Resources Corporation (“CNX”). Prior to this appointment, he served as Senior Vice President-Northern Appalachia-West Virginia Operations of CNX from 2007 to 2010. From 2006 to 2007, Mr. Brock served as Vice President-Operations. Mr. Brock began his career with CNX in 1979 at the Matthews Mine and since then has served at various locations in many positions including Section Foreman, Mine Longwall Coordinator, General Mine Foreman and Superintendent. Since 2018, Mr. Brock has served on the board of directors of each of the National Coal Council and the American Coalition for Clean Coal Electricity. We believe Mr. Brock’s extensive knowledge of our industry and our operations gained during his decades of service with CNX and later CONSOL Energy in positions of increasing responsibility in its coal operations provide the board of directors of our general partner with valuable experience and critical insight into our business and operations.
(now part of B. Riley FBR, Inc.) from May 2007 through May 2015 where he provided equity research coverage for companies in the metals and investor relations matters.mining sector starting as an intern and moving up to VP, analyst from July 2011 to May 2015. Prior to his work at FBR, he served in various roles at Reliance Engineering Associates (P) Limited from September 2002 through June 2006, moving up to a manager leading project planning and controls for various petrochemical and telecom-related projects. Mr. Thakkar holds a Bachelors of Engineering (Mechanical) degree from the Maharaja Sayajirao University of Baroda and a Masters in Business Administration degree from Texas A&M University.
John M. Rothka was appointed Chief Accounting Officer of our general partner effective August 2, 2017. Prior to that, Mr. Rothka served as the Controller of our general partner from July 2015. Mr. Rothka was part of CNX’s Accounting Department from September 2005 to July 2015, where he served in positions of increasing responsibility, and was promoted to Senior Manager in February 2012, which position he held until July 2015. Prior to joining CNX, Mr. Rothka began his professional career at the accounting firm of Aronson LLC from September 1999 to November 2002 before joining Deloitte from November 2002 to September 2005, where he held several positions of increasing responsibilities in the audit and assurance groups.
Martha A. Wiegand was appointed General Counsel and Secretary of our general partner effective March 16, 2015.2015 and was appointed to the board of directors of our general partner effective as of January 2, 2020 to fill the vacancy resulting from the resignation of a prior director. Ms. Wiegand also serves as General Counsel and Secretary of CONSOL Energy, a position that she has held since July 11, 2017 and where she is responsible for a variety of legal matters, including coal marketing and transportation, labor and employment, financing arrangements and certain corporate transactions. Prior to the separation,November 2017, Ms. Wiegand was also Associate General Counsel of our former sponsor,CNX, having joined its Legal Department in December 2008 as Senior Counsel and having been promoted to Associate General Counsel effective in 2012. Prior thereto, Ms. Wiegand worked for approximately 10 years for several large Pittsburgh-based law firms, where she handled financing and corporate transactions for clients in the banking and energy industries, among others. She is licensed to practice law in Pennsylvania and New Jersey and a member of the American Bar Association, the Pennsylvania Bar Association and the Energy & Mineral Law Foundation.
Michael L. Greenwood became a member of the board of directors of our general partner on July 1, 2015. Mr. Greenwood is Managing Director of Carnegie Capital LLC (2004 - present), a private financial advisory firm providing corporate and private equity clients investment banking assistance with acquisitions, divestitures and debt and equity capital fundings. From 2002 to 2004, Mr. Greenwood was Vice President-Finance and Treasurer of Energy Transfer Partners, L.P., a diversified energy company, and Chief Financial Officer and Treasurer of its predecessor, Heritage Propane Partners, L.P. From 1994 to 2002, he was Chief Financial Officer and Treasurer of Alliance Resource Partners, L.P., a producer and marketer of coal to major utilities. Prior to his career at Alliance Resource Partners, Mr. Greenwood held a number of financial positions in the energy industry with Mapco Inc., Penn Central Corporation and The Williams Companies. Additionally, Mr. Greenwood previously served on the boards of Hiland Partners, LP, Libra Natural Resources plc, Global Power Equipment Group Inc., Hiland Holdings GP and International Resource Partners GP. He also serves as a trustee of the Oklahoma State University Foundation and as a director of the OSU Research Foundation. Mr. Greenwood’s previous experience with public master limited partnerships and the coal industry, as well as his expertise in financial matters, provide him with the necessary skills to be a member of the board of directors of our general partner.
Deborah J. Lackovic became a member of the board of directors of our general partner on November 28, 2017. Ms. Lackovic currently serves as the Director of Benefits of CONSOL Energy. From January 2005 to November 28, 2017, Ms. Lackovic served in various supervisory roles of increasing responsibility within human resources at CNX (most recently as the General Manager of Compensation and Benefits, a position she held from December 2012 until being promoted to Director of Benefits in September 2017). She joined CNX’s Accounting Department in May 1996, where she served in positions of increasing responsibility and was promoted to Manager Financial Reporting in June 2002, a position she served in until December 2004. Prior to joining CNX, Ms. Lackovic worked at Deloitte from September 1994 to April 1996. We believe Ms. Lackovic’s extensive knowledge of our industry and her depth of experience managing human resources and benefit and retirement plans in the coal industry gained during her years of service with CNX and later CONSOL Energy provide the board of directors of our general partner with valuable experience.
Kurt R. Salvatori became a member of the board of directors of our general partner on November 28, 2017. Mr. Salvatori currently serves as the Chief Administrative Officer of CONSOL Energy, a position he has held since July 11, 2017. Mr. Salvatori has served as Vice President of Administration of CONSOL Pennsylvania Coal Company since January 1, 2017. Previously, Mr. Salvatori served as Vice President of Shared Services for CNX from 2016 to January 2017, and prior to that as Vice President of Human Resources from September 2011 to June 2016. Mr. Salvatori joined CNX in April 1992 and held numerous positions at CNX and CNX Gas Corporation, including Director of Human Resources from April 2006 to September 2011, Manager of Human Resources from January 2005 to April 2006, and Supervisor of Retirement and Investment Plans
from April 2002 to January 2005. We believe Mr. Salvatori brings extensive knowledge of our industry to the board of the
general partner and his broad knowledge of various executive compensation, human resources, labor and employment and other administrative oversight issues specific to the coal industry gained during his years of service with CNX and later CONSOL Energy provide the board of directors of our general partner with a valuable perspective and experience.
Dan D. Sandman became a member of the board of directors of our general partner on February 8, 2017. Mr. Sandman is an adjunct professor at The Ohio State University Moritz College of Law, where he has taught corporate governance law since 2007. Mr. Sandman also serves on the board of directors as lead independent director and audit committee member of MPLX GP LLC, the general partner of MPLX LP, a publicly traded master limited partnership engaged in the gathering, processing and transportation of natural gas, liquids, oil and refined petroleum products. He has also served on the board of directors of Roppe Corporation, a privately held company, since 1987. Additionally, Mr. Sandman serves on the boards of directors of the Carnegie Science Center, the Carnegie Hero Fund Commission and Grove City College. From 2002 to 2007, Mr. Sandman served as vice chairman of the board of directors and chief legal & administrative officer of United States Steel, until his retirement. Prior to his career with United States Steel, Mr. Sandman held a number of legal positions, including general counsel, with Marathon Oil Company, and subsequently served as general counsel and secretary of USX Corporation, a holding company that owned Marathon Oil and United States Steel. Mr. Sandman graduated with a bachelor's degree from The Ohio State University and a juris doctor degree from The Ohio State University College of Law. Mr. Sandman’s extensive strategic, corporate governance and legal experience working with publicly traded companies including energy companies and master limited partnerships, as well as his skills, knowledge and experience in the areas of transactional law, regulatory compliance, ethics and risk management matters, provide the board of directors with valuable experience.
Jeffrey L. Wallace became a member of the board of directors of our general partner on July 1, 2015. Mr. Wallace was the Vice President of Fuel Services (2006 to 2015) of Southern Company Generation, the generation subsidiary of The Southern Company, an electric utility serving 4.2 million customers in the southeast United States, with more than 40,000 megawatts of generating capacity. In that role, Mr. Wallace was responsible for managing the $7 billion annual fuel planning, procurement and delivery program for 85 power plants. Prior to that position, he was Vice President of Planning and Utility Relations at Georgia Power, a Southern Company subsidiary. He joined the company in 1978, working in accounting and budgeting, resource management and customer service, among other areas, since that time. Mr. Wallace is a graduate of the University of Georgia with degree in accounting and he earned his MBA in finance from Georgia State University. He also has an Executive MBA from Harvard Business School. Mr. Wallace has served on the boards of directors of the Boy Scouts of America (Atlanta Area Council), the South Fulton Chamber of Commerce, the American Coal Council, the National Coal Council and the Rail Energy Transportation Advisory Committee to the Surface Transportation Board. Mr. Wallace’s experience with electric utilities and the coal industry, as well as his expertise in financial matters, provide him with the necessary skills to be a member of the board of directors of our general partner.
Board Leadership Structure
The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or appointed by CONSOL Energy. Currently, the CEO of the general partner is the chairman of the board of directors of the general partner.
Board Role in Risk Oversight
Our corporate governance guidelines provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by the audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.
Meetings of Non-Management Directors and Communications with Directors
At least annually, all of the independent directors of our general partner meet in executive session without management participation or participation by non-independent directors. Mr. Greenwood, as the Chairman of the audit committee, serves as the presiding director for such executive sessions. The presiding director may be contacted by mail or courier service:
Presiding Director of the Board of Directors,
C/O Martha A. Wiegand, General Counsel and Secretary,
CONSOL Coal Resources LP
1000 CONSOL Energy Drive, Suite 100
Canonsburg, PA 15317
Committees of the Board of Directors
The board of directors of our general partner has one standing committee: an audit committee. The conflicts committee is convened on an as needed basis. NYSE does not require a publicly traded limited partnership like us to establish a compensation or a nominating and corporate governance committee. Accordingly, the functions typically handled by such committees are addressed by the full board of directors of our general partner.
Audit Committee
Our general partner is required by NYSE to have an audit committee of at least three members and all of the audit committee members must meet the independence and experience requirements established by NYSE and the Exchange Act.
The audit committee consists of Messrs. Greenwood (Chairman), Sandman and Wallace. Each member of the audit committee satisfies the independence requirements established by NYSE and the Exchange Act and is financially literate. In addition, the board of directors of our general partner has determined that Mr. Greenwood and Mr. Wallace each member of the audit committee qualifies as an “audit committee financial expert” as such term is defined under the SEC’s regulations. This designation is a disclosure requirement of the SEC related to each audit committee member's experience and understanding with respect to certain accounting and auditing matters. The designation does not impose upon the audit committee members any duties, obligations or liabilities that are greater than those generally imposed on them as members of the audit committee and the board of directors of our general partner. As audit committee financial experts, each memberAll members of the audit committee also hashave the accounting or related financial management expertise required by NYSE rules.
The audit committee of the board of directors of our general partner assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (iii) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.
Conflicts Committee
From time to time, on an as-needed basis, the board of directors of our general partner convenes a conflicts committee under our Partnership Agreement, to review specific matters that may involve conflicts of interest in accordance with the terms of our Partnership Agreement. The board of directors of our general partner will determine whether to refer a matter to the conflicts committee on a case-by-case basis. The members of the conflicts committee, Messrs. Wallace (Chairman), Sandman and Greenwood, are not officers or employees of our general partner or directors, officers or employees of its affiliates (including CONSOL Energy), and meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Our Partnership Agreement provides that the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our long-term incentive plan. If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Code of Conduct and Code of Ethics
Our general partner has adopted a code of business conduct and ethics applicable to all of its directors, officers, employees and other personnel and to our subsidiaries, as well as to suppliers, vendors, agents, contractors and consultants. The code of business conduct and ethics, along with our corporate governance guidelines and audit committee charter, are posted on our website, www.ccrlp.com. You may also obtain a copy by contacting Martha A. Wiegand, General Counsel and Secretary, CONSOL Coal Resources LP, 1000 CONSOL Energy Drive, Suite 100, Canonsburg PA 15317. We intend to satisfy our disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of business conduct and ethics by posting such information on our website.
ITEM 11. EXECUTIVE COMPENSATION
Compensation of Our Officers and Directors
We are currently considered an emerging growth company and a smaller reporting company for purposes of the SEC’s executive compensation disclosure rules. In accordance with these rules, we are permitted to provide reduced disclosure about executive compensation arrangements.
The Compensation Discussion and Analysis and Executive Compensation sections of CONSOL Energy’s Proxy 20192020 Statement will include a full discussion of the compensation policies and programs in which our named executive officers participated in 2018.2019. CONSOL Energy’s Proxy Statement will be available upon its filing on the SEC’s website at http://www.sec.gov and on CONSOL Energy’s website at http://www.consolenergy.com.
Executive Compensation, Relationship to Our Sponsor
During 2018,2019, the executive officers of our general partner were employed and compensated entirely by our sponsor or its affiliates (other than our general partner).
As discussed further below, such compensation included base salaries, annual incentive awards and equity grants from our sponsor. The executive officers of our general partner also participate in employee benefit plans and arrangements maintained by our sponsor and its affiliates, including plans that may be established in the future.
Reimbursement to our Sponsor for Compensation Paid
We are a party to an omnibus agreement with our sponsor under which we agreed to reimburse our sponsor on a monthly basis for compensation related expenses (including salary, bonus, incentive compensation and other amounts) attributable to the portion of an executive’s compensation that is allocable to our general partner. Prior to the separation and distribution of our sponsor the executive officers of our general partner devoted approximately 100% of their overall professional working time to the business and affairs of the Pennsylvania Mining Complex (on a 100% basis). Since the separation ourOur general partner and our sponsor have had the same executive officers. Their time is split between our general partner's and our sponsor's business and affairs, including the business and affairs of the Pennsylvania Mining Complex. As a result of our 25% undivided interest in the Pennsylvania Mining Complex, we reimburse our sponsor for approximately 25% of the total compensation related expenses (including salary, bonus, incentive compensation and other amounts) incurred by our sponsor and attributable to our executive officers’ compensation. The total reimbursable compensation related expenses attributable to each of Mr. Brock, Ms. Wiegand, and Mr. Khani and Ms. Wiegand for the year ended December 31, 20182019 was approximately $295,301, $285,870$558,308, $161,964 and $109,219,
$317,411, respectively, and the total reimbursable compensation related expenses attributable to each of Mr. Brock, Ms. Wiegand, and Mr. Khani and Ms. Wiegand for the year ended December 31, 20172018 was approximately $238,214, $73,750$295,301, $109,219, and $80,858,$285,870, respectively.
Summary Compensation Table
The following summarizes the total compensation earned by the named executive officers of our general partner during 20182019 and other years indicated, including all compensation related expenses disclosed above, which were paid entirely by our sponsor (or an affiliate of our sponsor):. Mr. Khani resigned from the Partnership on December 31, 2019 and is no longer an employee of our general partner. While he is required to appear in the summary compensation table, and certain discrete other tables, he was not eligible for payments under many of our sponsor's plans resulting in payouts with respect to the 2019 fiscal year. In addition, Mr. Khani forfeited any equity awards unvested as of December 31, 2019 as a result of his resignation.
Name and Principal Position | Year | Salary(1) | Bonus(2) | Stock Awards(3) | Option Awards | Non-Equity Incentive Compensation(4) | Change in Pension Value and Nonqualified Deferred Compensation Earnings(5) | All Other Compensation(6) | SEC Total | Year | Salary(1) | Bonus(2) | Stock Awards(3) | Option Awards | Non-Equity Incentive Compensation | Change in Pension Value and Nonqualified Deferred Compensation Earnings(4) | All Other Compensation(5) | SEC Total | |||||||||||||||||||||||||||||||||||||||||||
| James A. Brock* | 2018 | $ | 641,163 | $ | — | $ | 2,438,915 | $ | — | $ | 1,430,000 | $ | — | $ | 46,000 | $4,556,078 | 2019 | $ | 803,231 | $ | 1,199,813 | $ | 3,773,887 | $ | — | $ | — | $ | 733,841 | $ | 39,600 | $6,550,372 | |||||||||||||||||||||||||||||
| President and Chief Executive Officer | 2017 | $ | 419,855 | $ | — | $ | 2,138,000 | $ | — | $ | 540,042 | $ | 417,165 | $ | 891,572 | $4,406,634 | 2018 | $ | 641,163 | $ | — | $ | 2,438,915 | $ | — | $ | 1,430,000 | $ | — | $ | 46,000 | $4,556,078 | |||||||||||||||||||||||||||||
| David M. Khani* | 2018 | $ | 530,566 | $ | — | $ | 2,770,188 | $ | — | $ | 739,078 | $ | 52,599 | $ | 52,814 | $4,145,245 | |||||||||||||||||||||||||||||||||||||||||||||
Chief Financial Officer | 2017 | $ | 530,068 | $ | 150,000 | $ | 3,197,692 | $ | — | $ | 612,915 | $ | 99,402 | $ | 29,200 | $4,619,277 | |||||||||||||||||||||||||||||||||||||||||||||
| Martha A. Wiegand | 2018 | $ | 297,500 | $ | — | $ | 133,980 | $ | — | $ | 300,000 | $ | 18,866 | $ | 47,788 | $798,134 | 2019 | $ | 347,855 | $ | 196,875 | $ | 433,371 | $ | — | $ | — | $ | 42,756 | $ | 31,143 | $1,052,000 | |||||||||||||||||||||||||||||
| General Counsel and Secretary | 2017 | $ | 234,231 | $ | 200,000 | $ | 300,000 | $ | — | $ | 139,379 | $ | 21,814 | $ | 104,312 | $999,736 | 2018 | $ | 297,500 | $ | — | $ | 133,980 | $ | — | $ | 300,000 | $ | 18,866 | $ | 47,788 | $798,134 | |||||||||||||||||||||||||||||
| David M. Khani* | 2019 | $ | 530,566 | $ | — | $ | 2,167,009 | $ | — | $ | — | $ | — | $ | 36,873 | $2,734,448 | |||||||||||||||||||||||||||||||||||||||||||||
Former Chief Financial Officer | 2018 | $ | 530,566 | $ | — | $ | 2,770,188 | $ | — | $ | 739,078 | $ | 52,599 | $ | 52,814 | $4,145,245 | |||||||||||||||||||||||||||||||||||||||||||||
* Messrs. Brock and Khani also serve as members of the board of directors of our general partner. They do not receive any additional compensation for this service.
| (1) | The amounts in this column represent base salaries before compensation reduction under any CONSOL Energy or affiliated company qualified retirement and/or 401(k) savings plan in effect during |
| (2) | The amounts in this column represent annual incentive awards |
| (3) | The values set forth in this column represent the aggregate grant date fair value of the service-based and performance-based restricted stock unit awards made by CONSOL Energy to each of our named executive officers during 2018. All amounts included have been computed in accordance with FASB ASC Topic 718. The assumptions used in determining the grant date fair value of the stock awards are set forth in Note 20 to our consolidated financial statements, included in this Annual Report on Form 10-K for the fiscal year ended December 31, |
| (4) | |
Amounts in this column reflect the actuarial increase in the present value of each named executive officer’s benefit under the CONSOL Energy Employee Retirement Plan, the CONSOL Energy Retirement Restoration Plan, the CONSOL Energy Supplemental Retirement Plan and the CONSOL Energy New Restoration Plan between December 31, | |
| The amounts shown in this column for | |
| Category | Brock | Khani | Wiegand | Brock | Wiegand | Khani |
| 401(k) Plan Contributions (a) | $16,500 | $16,800 | ||||
| Vehicle Allowance (b) | $13,000 | $13,000 | ||||
| Executive Health Physical (c) | $0 | $1,656 | $1,788 | $3,549 | $1,343 | $1,733 |
| Business and Country Club Dues (d) | $0 | $5,158 | $0 | $5,000 | $0 | $5,340 |
| Discretionary Contribution to 401(k) (e) | $16,500 | |||||
| Spousal Travel (e) | $1,251 | $0 | ||||
(a) Annual employer matching contributions to the 401(k) plan
(b) Vehicle allowance/Company vehicle
(c) Executive health physical
(d) Business and Country Club Dues
(e) Discretionary Contribution made by CONSOL under its 401(k) plan
Spousal Travel
Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure
General
As noted above, during 2018,2019, the named executive officers of our general partner are employed and compensated by our sponsor or its affiliates (other than our general partner). Because the executive officers of our general partner are employed by
our sponsor or its affiliates, compensation of the executive officers is set and paid by our sponsor and its affiliates. The executive officers of our general partner also participate in employee benefit plans and arrangements sponsored by our sponsor and its affiliates, including plans that may be established in the future.
Our sponsor provides compensation to the executive officers in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefits plans and arrangements, including broad-based and supplemental defined contribution and defined benefit retirement plans.
Elements of Compensation
The following sets forth a more detailed explanation of the elements of the compensation programs as they relate to Mr. Brock, Mr. Khani, and Ms. Wiegand in 20182019 and 2017:2018:
Base Salary. Base salary is set by our sponsor and is designed to provide a competitive fixed rate of pay recognizing employees’ different levels of responsibility and performance. In setting an executive’s base salary, our sponsor considers factors including, but not limited to, the need to attract and retain talented leadership, external market data, the internal worth and value assigned to the executive’s role and responsibilities at our sponsor, and the named executive’s skills and performance.
Annual Cash Incentives. Our sponsor’s annual cash incentive program (STIC) provides participants with an opportunity to earn performance based annual cash bonus awards. Target annual bonus levels are established at the beginning of each year and are based on a percentage of the executive’s base salary as described in the chart below. In 2018,2019, our sponsor designed a short-term incentive arrangement (the “2018“2019 “STIC”) under which an annual cash incentive award would be earned subject to the sponsor’s successful achievement of performance goals related to Operating Margin and Free Cash Flow, equally weighted, but subject to modification influenced by each executive officer’s contribution towards achieving environmental and safety initiatives. 20182019 STIC awards include a threshold, target and maximum performance levels. If actual performance against the threshold level of performance is not achieved, then no cash payment will be made. The maximum performance possible (for outstanding performance) is 200%.
Long-Term Equity-Based Compensation Award. Our sponsor’s long-term equity-based compensation program (LTIC) for 20182019 included equity awards for each of our executive officers to be delivered in the form of 60% performance-based restricted stock units (PSUs) and 40% service-based restricted stock units (RSUs). The PSUs vest ratably over a period of three years, but only to the extent that pre-established performance metrics related to relative total stockholder return and free cash flow are achieved. The PSUs include threshold, target and maximum performance levels. If actual performance against the threshold level of performance is not achieved, then no payout will be made. The maximum performance possible (for outstanding performance) is 200% of target performance. The RSUs also vest ratably over a period of three years. Target long-term levels for the 20182019 long-term equity awards are established at the beginning of each year and are based on a percentage of the executive’s base salary as described in the chart below.
For 2018,2019, our executive officers had the following targets for the STIC and LTIC:
| Name of Executive | Base Salary | Target 2018 STIC | Target 2018 LTIC | Base Salary | Target 2019 STIC | Target 2019 LTIC |
| Mr. Brock | $650,000 | 110% | 350% | $810,000 | 150% | 430% |
| Ms. Wiegand | $350,000 | 60% | 114% | |||
| Mr. Khani | $530,566 | 70% | 487% | $530,566 | 70% | 377% |
| Ms. Wiegand | $300,000 | 50% | 42% | |||
Payout of Prior Long-Term Equity Awards
2016-2020 PSU Grants and Payout. In January 2016, Messrs. Brock and Khani were granted PSUs by our former sponsor (which were converted into CONSOL Energy awards under the employee matters agreement executed as part of the separation) that vest, if earned, ratably over a five-year period (January 1, 2016 through December 31, 2020) based on Absolute Stock Price and Relative TSR compared to the S&P 500.
| Named Executive Officer | 2018 PSU Tranche (at target) | Target Payout (%) | Payout Amounts (# of shares) | |
| James A. Brock, President and Chief Executive Officer | 9,960 | 200 | % | 19,920 |
| David Khani, Chief Financial Officer | 19,920 | 200 | % | 39,840 |
| Named Executive Officer | 2018 PSU Tranche (at target) and 2017 PSU Tranche 50% lookback at target) | Target Payout (%) | Payout Amounts (# of shares) | 2019 PSU Tranche (at target) | Target Payout (%) | Payout Amounts (# of shares) | ||
| David Khani, Chief Financial Officer | 12,063 | 134 | % | 16,164 | ||||
| 6,031 | 100 | % | 6,031 | |||||
| James A. Brock, President and Chief Executive Officer | 9,960 | 135.5 | % | 13,496 | ||||
2018 - 2020 PSU Grants and Payout. In February 2018, Messrs. Brock and Khani and Ms. Wiegand were granted PSUs by CONSOL Energy that vest, if earned, ratably over a three-year period (January 1, 2018 through December 31, 2020) based on Free Cash Flow and Relative TSR compared to the Metals and Mining Index. Mr. Khani forfeited any equity awards unvested as of December 31, 2019 as a result of his resignation.
| Named Executive Officer | 2018 PSU Tranche (at target) | Target Payout (%) | Payout Amounts (# of shares) | 2019 PSU Tranche (at target) | Target Payout (%) | Payout Amounts (# of shares) | ||||||
| James A. Brock, President and Chief Executive Officer | 14,361 | 200 | % | 28,722 | 14,361 | 49 | % | 7,038 | ||||
| David Khani, Chief Financial Officer | 16,312 | 200 | % | 32,624 | ||||||||
| Martha Wiegand, General Counsel | 788 | 200 | % | 1,576 | 788 | 49 | % | 387 | ||||
2019 - 2021 PSU Grants and Payout. In February 2019, Messrs. Brock and Khani were granted PSUs by CONSOL Energy that vest, if earned, ratably over a three-year period (January 1, 2019 through December 31, 2021) based on Free Cash Flow and Relative TSR compared to the Metals and Mining Index. Mr. Khani forfeited any equity awards unvested as of December 31, 2019 as a result of his resignation.
| Named Executive Officer | 2020 PSU Tranche (at target) | Target Payout (%) | Payout Amounts (# of shares) | |||
| James A. Brock, President and Chief Executive Officer | 20,284 | — | % | — | ||
CONSOL Energy Outstanding Equity Awards at December 31, 20182019
Our executive officers received and continue to receive equity or equity-based awards under our sponsor's equity compensation program. Our named executive officers did not receive any grants of awards under the CNX Coal Resources LP 2015 Long-Term Incentive Plan in 2018. The following table provides additional information about our executive officers’ outstanding equity awards in CONSOL Energy as of December 31, 2018.2019.
| Option Awards | Stock Awards | Option Awards | Stock Awards | |||||||||||||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options (#) Exercisable | Number of Securities Underlying Unexercised Options Unexercisable | Option Exercise Price ($) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($) (3) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (8) | Number of Securities Underlying Unexercised Options (#) Exercisable | Number of Securities Underlying Unexercised Options Unexercisable | Option Exercise Price ($) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($) (1) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (7) | ||||||||||||||||||||||||
James A. Brock, Chief Executive Officer | 45,491 28,722 19,920 | (9) (5) (7) | $1,442,520 $910,775 $631,633 | 68,566 (10) | $ | 2,174,228 | 68,104 7,038 13,496 | (2) (3) (4) | $988,189 $102,121 $195,827 | 64,897 (5) | $ | 941,655 | ||||||||||||||||||||||||||||
| David Khani, Chief Financial Officer | 69,996 14,296 39,840 18,094 32,624 | (1) (2) (7) (6) (5) | $2,219,573 $453,326 $1,263,326 $573,761 $1,034,507 | 160,555 (4) | $ | 5,091,199 | ||||||||||||||||||||||||||||||||||
| Martha A. Wiegand, General Counsel & Secretary | 6,049 1,576 | (9) (5) | $191,814 $49,975 | 1,579 (11) | $ | 50,071 | 7,948 387 | (2) (3) | $115,325 $5,615 | 5,451 (6) | $ | 79,094 | ||||||||||||||||||||||||||||
| (1) | |
| The market value for the RSUs was determined by multiplying the closing market price for CONSOL Energy common stock on December 31, | |
| (2) | This represents RSUs granted on December 12, 2017, February 6, 2018 and February 7, 2019 vest in three equal installments (subject to rounding) beginning on the first anniversary of the grant date. |
| (3) | The performance period for the 2019 tranche of the 2018 PSU awards was January 1, 2019 through December 31, 2019. The amounts are based on actual results for the period. |
| (4) | The performance period for the 2019 tranche of the 2016 PSU awards was January 1, 2019 through December 31, 2019. The amounts are based on actual results for the period. |
| (5) | This column shows the number of unvested PSUs as of December 31, |
| This column shows the number of unvested PSUs as of December 31, 2019. The performance period for the PSUs granted in 2018 | |
| (7) | |
| The market value for the PSUs was determined by multiplying the closing market price for CONSOL Energy common stock on December 31, | |
Retirement, Health, Welfare and Additional Benefits. CONSOL Energy employees are eligible to participate in a variety of employee benefit plans and programs, subject to the terms and eligibility requirements of those plans, which include a broad-based 401(k) savings plan, as well as a supplemental defined benefit retirement restoration plan that provides benefits to executive officers and key employees, including Mr. Brock, Ms. Wiegand, and Mr. Khani and Ms. Wiegand, in excess of IRS imposed limits under the broad-based 401(k) savings plan. CONSOL Energy also provides limited executive perquisites, which are described in the footnotes to the Summary Compensation Table for 2018.2019.
Employee Retirement Plan (the “Pension Plan”)
CONSOL Energy maintains a pension plan that is a non-contributory defined benefit plan that pays retirement benefits based on years of service and compensation. The sponsorship of this plan was transferred from our former sponsor to CONSOL Energy in connection with the separation. It is a qualified plan, meaning that it is subject to a variety of IRS rules. These rules contain various requirements on coverage, funding, vesting and the amount of compensation that can be taken into account in calculating benefits. The Pension Plan has a fairly broad application across CONSOL Energy’s employee population and forms a part of the general retirement benefit program available to employees.
| • | Eligibility: The Pension Plan covers employees of CONSOL Energy and affiliated participating companies that are classified as regular, full-time employees or that complete 1,000 hours of service during a specified twelve-month period. The Pension Plan was amended as of December 31, 2015 to provide for a hard freeze of the Pension Plan for all remaining participants in the plan. |
| • | Form of Payment: The portion of accrued pension benefits earned under the Pension Plan as of December 31, 2005 may be, upon the election of the participant, paid in the form of a lump-sum payment except in the case of an incapacity retirement. Pension benefits earned after January 1, 2006 are payable in the form of a single life annuity, 50% joint and survivor annuity, 75% joint and survivor annuity or 100% joint and survivor annuity. |
| • | Calculation of Benefits: Pension benefits are based on an employee’s years of service and average monthly pay during the employee’s five highest-paid years. Average monthly pay for this purpose excludes compensation in excess of limits imposed by the Code. Prior to January 1, 2006, pension benefits were calculated based on the average monthly pay during the employee’s three highest-paid years and included annual amounts payable under CONSOL Energy’s STIC, again excluding compensation in excess of limits imposed by the Code. |
| • | Categories: The Pension Plan provides for various categories of retirement, including normal retirement, early retirement, separation retirement, and incapacity retirement, based upon years of service, age and certain other factors. |
Supplemental Retirement Plan
CONSOL Energy established the CONSOL Energy Supplemental Retirement Plan on November 28, 2017 with respect to certain obligations it assumed related to current and former CNX coal business employees who participated in our former sponsor's supplemental retirement plan prior to November 28, 2017. The CONSOL Energy Supplemental Retirement Plan was designed primarily for the purpose of providing benefits for a select group of management and highly compensated employees of CONSOL Energy and its subsidiaries and is intended to qualify as a “top hat” plan under the Employee Retirement Income Security Act of 1974, as amended. The plan was frozen effective December 31, 2011 for current and future employees except for certain “excepted employees”. The accrued benefits for all members in the CONSOL Energy Supplemental Retirement Plan were frozen per the terms of the plan prior to the plan’s effective date of November 28, 2017.
The amount of each participant’s benefit under the plan as of age 65 (expressed as an annual amount) is equal to 50% of “final average compensation” multiplied by the “service fraction” as calculated on the earlier of the participant’s date of employment termination with CONSOL Energy or the date benefits were frozen per the terms of the plan. “Final average compensation” means the average of a participant’s five highest consecutive annual compensation amounts (annual base salary plus amounts received under the STIC) while employed by CONSOL Energy or its subsidiaries up until the date benefits were frozen per the terms of the plan. The “service fraction” means a fraction with a numerator equal to a participant’s number of years of service and with a denominator of 20. The service fraction can never exceed one.
The benefit described above will be reduced by a participant’s age 65 vested benefits (including benefits which have been paid or are payable in the future (converted to an annual amount)) under: (i) the Pension Plan; (ii) the Restoration Plan; and (iii) any other plan or arrangement providing retirement-type benefits, to the extent service under such arrangement is credited under the Supplemental Retirement Plan.
No benefit will be vested under the Supplemental Retirement Plan until a participant has five years of service with CONSOL Energy or its participating subsidiaries while the participant meets the eligibility standards in the plan.
Benefits under the Supplemental Retirement Plan are paid in the form of a life annuity with a guaranteed term of 20 years (which is the actuarial equivalent of a single life annuity) commencing in the month following the later to occur of: (a) the end of the month following the month in which the participant turns age 50 or (b) the end of the month following the month in which the employment termination of a participant occurs. In the event the benefits commence prior to the participant’s normal retirement age, the benefit will be actuarially reduced as necessary (using assumptions specified in the Pension Plan).
New Restoration Plan
CONSOL Energy also established a New Restoration Plan on November 28, 2017 with respect to the obligations it assumed related to current and former CNX coal business employees who participated in our former sponsor's restoration plan (formerly known as the CONSOL Energy New Restoration Plan) prior to November 28, 2017. The New Restoration Plan is designed primarily for the purpose of providing benefits for a select group of management and highly compensated employees of CONSOL Energy and its subsidiaries and is intended to qualify as a “top hat” plan under the Employee Retirement Income Security Act of 1974, as amended.
The CONSOL Energy Compensation Committee has reserved the right to terminate a participant’s participation in the New Restoration Plan at any time. Additionally, if a participant’s employment is terminated or if a participant no longer meets the New Restoration Plan’s basic eligibility standards, the participant’s participation in New Restoration Plan (and such person’s right to accrue any benefits thereunder) will terminate automatically with no further action required.
Eligibility for benefits under the New Restoration Plan is determined each calendar year (the “Award Period”). Participants whose sum of annual base pay as of December 31 and amounts received under the STIC or other annual incentive program earned for services rendered by the participant during the Award Period exceed the compensation limits imposed by section 401(a)(17) of the Code (up to $275,000$280,000 for 2018)2019) are eligible for benefits under the New Restoration Plan for the Award
Period. The amount of each eligible participant’s benefit under the plan is equal to 9% times annual base salary as of December 31 including amounts received under the STIC or other annual incentive program earned for services rendered by the participant during the Award Period less 6% times the lesser of annual base salary as of December 31 or the compensation limit imposed by the Code for the Award Period.
Benefits under the New Restoration Plan will be paid in the form of two hundred forty (240) equal monthly installments, with each installment equal to the value of the participant’s account at commencement divided by two hundred forty (240). Benefits shall commence in the month immediately following the later to occur of: (i) the month in which the participant turns age 60 or (ii) the month containing the six-month anniversary date of the participant’s separation from service.
Severance and Change in Control Programs. CONSOL Energy has entered into change in control severance agreements with each of Mr. Brock, Mr. Khani and Ms. Wiegand which are described below.
Agreements between Our Executive Officers and CONSOL Energy
Our general partner’s officers have not entered into any agreements with us or our general partner or with CONSOL Energy specifically in relation to their services with us and our general partner. However, in relation to their employment with CONSOL Energy, each of Mr. Khani and Ms. Wiegand have entered into a severance and change in control (“CIC”) agreement with CONSOL Energy that became effective February 15, 2018. In addition, Mr. Brock entered into an individual employment agreement with CONSOL Energy that also became effective February 15, 2018. These agreements were developed and approved by CONSOL Energy in connection with a competitive review the company conducted relating to its overall compensation plans and programs. Generally, these agreements supersede the terms and conditions that were established by CIC agreements in place during 2017.
The agreement for Ms. Wiegand provideprovides for both (i) non-CIC cash severance and (ii) CIC cash severance exclusively upon a termination of employment absent “cause,” subject to the following requirements. In the case of a “CIC scenario,” the agreement is “double trigger” and each executive is only entitled to cash severance if, following, or in connection with, a CIC the executive’s employment is terminated by CONSOL Energy absent “cause” or if the executive resigns due to constructive or good reason termination within ninety (90) day prior to the CIC or within two (2) years following the CIC. The agreements do not include any gross up feature arising from the excise tax payable on an excess parachute payment.
Under these agreements, Mr. Khani andthe agreement, Ms. Wiegand would be entitled to receive:
•a lump sum cash payment equal to a 1x multiple of base salary in a non-CIC involuntary termination of employment absent “cause”;
•a lump sum cash payment equal to a multiple of base salary plus a multiple of annual incentive pay) in an involuntary termination of employment or constructive (or good reason) termination related to a CIC absent “cause” (2.5x for Mr. Khani and 2x(2x for Ms. Wiegand);
•a prorated payment of the executive’s annual incentive compensation for the year in which the termination occurs;
•accelerated vesting of any outstanding long-term incentive compensation upon the 2nd trigger related to a CIC termination event; provided, however, that any outstanding performance-based awards shall be settled at the greater or target or actual performance (if ascertainable at the CIC) and prorated for service to the date of the CIC;
•continued healthcare for eighteen (18) months;
•outplacement assistance in the form of a cash payment equal to $25,000;
•a cash payment equal to the total amount the executive would have received under the CONSOL Energy 401(k) plan assuming he or she continued employment for a period of eighteen (18) months; and
•a pension enhancement in the form a cash payment equivalent to the difference between the present value of the executive’s accrued benefit at his or her actual termination date under CONSOL Energy’s qualified defined benefit plan and the present value of the accrued benefit the executive would have received assuming he or she continued employment for eighteen (18) months.
The agreementsagreement also containcontains confidentiality, non-competition and non-solicitation obligations pursuant to which Mr. Khani and Ms. Wiegand havehas agreed not to compete with the business for two (2) years, or to solicit customers or employees for one (1) year following a termination of employment.
No payment or benefits are provided under these agreements unless the executive executes, and does not revoke, a written release of any and all claims (other than entitlements under the terms of the agreements or which may not be released under applicable law).
For purposes of these agreements, the following definitions apply:
“Cause” is defined as a determination by a majority of the board of directors of CONSOL Energy that the executive has
(a)engaged in gross negligence in the performance of his or her duties;
(b)been convicted of a plea of guilty or nolo contendere to a felony or any misdemeanor involving fraud, theft or embezzlement;
(c)failed or refused to perform his or her duties and responsibilities with the company (with an opportunity to cure);
(d)breached a material restrictive covenant relating to non-competition, non-solicitation or confidentiality;
(e)willfully violated any material provision of the company’s code of conduct; or
(f)willfully engaged in conduct demonstrably and materially injurious to the company.
“Change in control” generally means:
(a)an individual, entity or group acquires beneficial ownership of more than twenty-five (25) percent of the total fair market value of the common stock of the company or combined voting power of the company;
(b)the board composition is modified so less than a majority of the board pre-CIC remains in control;
(c)the consummation of or reorganization, merger or consolidation of the company or other business combination involving the sale of all or substantially all of the assets of the company; or
(d)a complete liquidation of the company.
“Constructive” or “good reason” termination” means:
(a)a material adverse change in position or material diminution in duties and responsibilities;
(b)a material reduction in base salary (excluding generally a reduction applicable to all executive officers); or
(c)the relocation of the executive’s principal work location that increases his or her commute by fifty (50) or more miles.
The individual employment agreement between Mr. Brock and CONSOL Energy, which also became effective on February 15, 2018, provides for a three (3) year initial term of employment automatically renewed for additional one (1) year periods unless either party provides advance written notice within sixty (60) days of the end of the term. Similar to the severance and CIC agreements discussed immediately above for Mr. Khani and Ms. Wiegand, the employment agreement provides for double trigger change in control cash severance equal to a three times (3x) multiple of his base salary plus a three times (3x) multiple of his annual incentive compensation, but only in the event of the executive’s involuntary termination of employment (including resignation following constructive or good reason termination) absent “cause.” In addition, the agreement provides for non CIC cash severance payable in lump sum form to Mr. Brock equal to two times (2x) his base salary only and payable exclusively in the event of an involuntary termination of employment absent “cause.” The agreement includes customary restrictive covenants during employment and post termination relating to confidentiality, non-competition and non-solicitation and requires the executive to sign an appropriate release of claims identical to the provisions discussed above, and the agreement supersedes any agreement previously in place during 2017 (or earlier) that was adopted by CONSOL or any predecessor company. The employment agreement does not include any gross up feature arising from the excise tax payable on an excess parachute payment.
Compensation of Our Directors
The officers or employees of our general partner or of our sponsor who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner or of our sponsor, or “non-employee directors,” receive cash and equity-based compensation for their services as directors. We directly pay all compensation earned by our non-employee directors for their services to us. As of December 31, 20182019 the non-employee director compensation program consists of the following:
an annual retainer of $60,000 (payable in quarterly installments);
an additional annual retainer of $20,000 (payable in quarterly installments) for service as chair of the audit committee;
an additional payment of $1,000 for service as chair of the conflicts committee, if convened, per transaction;
$5,000 per member for conflicts committee service if convened, per transaction; and
an annual equity-based award (phantom units) granted under the Partnership's LTIP (described below), having a value as of the grant date of approximately $100,000 and vesting on the first anniversary of the grant date.
Non-employee directors also receive reimbursement for out-of-pocket expenses they incur in connection with attending meetings of the board of directors or its committees. Each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.
The following table sets forth the compensation earned by our directors for the 20182019 fiscal year.
| Name (1) | Fees Earned or Paid in Cash ($) | Stock Awards (1) | Option Awards | All Other Compensation | Total | |||||
| Michael Greenwood | $80,000 | $100,000 | $0 | $0 | $180,000 | |||||
| Dan Sandman | $60,000 | $100,000 | $0 | $0 | $160,000 | |||||
| Jeff Wallace | $60,000 | $100,000 | $0 | $0 | $160,000 | |||||
(1) The values set forth in this column reflect awards of phantom units under the Partnership LTIP, and are based on the aggregate grant date fair value of the awards computed in accordance with FASB ASC Topic 718 (disregarding the impact of estimated forfeitures related to service-based vesting conditions). For phantom units, the grant date fair value is computed based upon the closing price of the Partnership’s units on the date of grant. The phantom units were granted on February 6, 20187, 2019 and vested in one lump sum on February 6, 2019,7, 2020, the first anniversary of the grant date. As of December 31, 2018,2019, the number of phantom units held by our current non-employee directors was 6,2695,730 for each of Messrs. Sandman, Greenwood and Wallace.
Our Long-Term Incentive Plan (LTIP)
Our general partner adopted the CONSOL Coal Resources LP 2015 Long-Term Incentive Plan (the “LTIP”) under which our general partner may issue long-term equity based awards in our Partnership to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards are intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. All determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. The board of directors of our general partner has been designated as the plan administrator. The following description reflects the terms that are included in the LTIP.
General
The LTIP provides for the grant, from time to time at the discretion of the board of directors of our general partner or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards in our Partnership. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP limits the number of units that may be delivered pursuant to vested awards to 2,300,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, withheld to satisfy exercise prices or tax withholding
obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.
Restricted Units and Phantom Units
A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the plan administrator, cash equal to the fair market value of a common unit. The plan administrator of the LTIP may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the plan administrator may determine are appropriate, including the period over which restricted units or phantom units will vest. The plan administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.
Distributions made by us to our unitholders with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.
Distribution Equivalent Rights
The plan administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.
Unit Options and Unit Appreciation Rights
The LTIP also permits the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the plan administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.
Unit Awards
Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the plan administrator of the LTIP may establish.
Profits Interest Units
Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the plan administrator, may consist of profits interest units. The plan administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.
Other Unit-Based Awards
The LTIP also permits the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of another unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, another unit-based award may be paid in cash and/or in units (including restricted units) or any combination thereof as the plan administrator of the LTIP may determine.
Source of Common Units
Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.
Anti-Dilution Adjustments and Change in Control
If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the plan administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the plan administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the plan administrator of the LTIP shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles,
the plan administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the plan administrator deems appropriate to reflect the applicable transaction or event.
Termination of Service
The consequences of the termination of a grantee’s membership on the board of directors of our general partner or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.
Amendment or Termination of Long-Term Incentive Plan
The plan administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The plan administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Internal Revenue Code.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
The following table sets forth the beneficial ownership of common units and subordinated units of CONSOL Coal Resources LP that were outstanding at January 25, 201924, 2020 and held by:
each unitholder known by us to beneficially hold 5% or more of our outstanding units;
each director or director nominee of our general partner;
each executive officer of our general partner; and
all of the directors, director nominees and executive officers of our general partner as a group.
In addition, our general partner holds a 1.7% general partner interest .
Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the following table have sole voting and sole investment power with respect to all units beneficially owned by them, subject to community property laws where applicable. The percentage of units beneficially owned is based on a total of 15,911,21127,632,824 common units and 11,611,067 subordinated units outstanding at January 25, 2019.
24, 2020.
| Name of Beneficial Owner (1) | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | Subordinated Units Beneficially Owned | Percentage of Subordinated Units Beneficially Owned | Percentage of Total Common and Subordinated Units Beneficially Owned | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | ||||||||||||||
| CONSOL Energy Inc. (2) | 5,174,454 | 32.5 | % | 11,611,067 | 100.0 | % | 61.0 | % | 16,811,818 | 60.8 | % | ||||||||||
| Greenlight Capital, Inc. (3) | 5,488,438 | 34.5 | % | — | — | 19.9 | % | 5,488,438 | 19.9 | % | |||||||||||
| Directors/Director Nominees and Executive Officers | |||||||||||||||||||||
| Michael L. Greenwood | 31,994 | (4) | * | — | — | * | 37,724 | (4) | * | ||||||||||||
| David M. Khani | 13,000 | * | — | — | * | ||||||||||||||||
| Miteshkumar B. Thakkar | 4,900 | (5) | * | ||||||||||||||||||
| John M. Rothka | 4,413 | (5) | * | — | — | * | 4,321 | (6) | * | ||||||||||||
| James A. Brock | 76,551 | * | — | — | * | 76,551 | * | ||||||||||||||
| Dan D. Sandman | 14,936 | (6) | * | — | — | * | 20,666 | (7) | * | ||||||||||||
| Jeffrey L. Wallace | 21,994 | (7) | * | — | — | * | 27,724 | (8) | * | ||||||||||||
| Martha A. Wiegand | 10,609 | * | — | — | * | 10,609 | * | ||||||||||||||
| Kurt R. Salvatori | 3,619 | * | — | — | * | 1,809 | * | ||||||||||||||
| Deborah J. Lackovic | - | - | — | — | - | - | - | ||||||||||||||
All Directors, Director Nominees and Executive Officers as a group (9 persons) | 177,116 | (8) | 1.1 | % | — | — | * | 184,304 | (9) | 0.7 | % | ||||||||||