UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20162019 or
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| ¨ | 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: 1-31465
NATURAL RESOURCE PARTNERS L.P.
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| NATURAL RESOURCE PARTNERS L.P. |
| (Exact name of registrant as specified in its charter) | |
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| Delaware | | 35-2164875 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification Number) |
| No.) |
1201 Louisiana Street, Suite 3400 Houston, Texas 77002 (Address of principal executive offices) (Zip Code) (713) 751-7507 |
(Registrant’s telephone number, including area code) |
Registrant's telephone number, including area code (713) 751-7507
Securities registered pursuant to Section 12(b) of the Act:
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| | | | |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
Common Units representing limited partnershippartner interests | | NRP | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitionsdefinition of "accelerated filer", "large accelerated filer," "accelerated filer" and, "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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¨ Large Accelerated Filer
| x Accelerated Filer
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| Accelerated Filer | ý |
| Non-accelerated Filer | ¨ |
| Smaller Reporting Company | ¨ |
| Emerging Growth Company | ¨ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes ¨ No ý
The aggregate market value of the common units held by non-affiliates of the registrant on June 30, 2016,28, 2019, was $119.7$318 million based on a closing price on that date of $14.35$35.46 per unit as reported on the New York Stock Exchange.
As of February 24, 2017, there were 12,232,006 common units outstanding.
Documents incorporated by reference: None.
TABLE OF CONTENTS
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
Statements included in this Annual Report on Form 10-K may constitute forward-looking statements. All statements, other than statements of historical facts, included herein or incorporated herein by reference are "forward-looking statements." In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding:
our business strategy;
our liquidity and access to capital and financing sources;
our ability to service our debt and make distributions to our limited partners;
our financial strategy;
prices of and demand for coal, trona and soda ash, construction aggregates, frac sand and other natural resources;
estimated revenues, expenses and results of operations;
the amount, nature and timing of capital expenditures;
projected production levels by our lessees and VantaCore Partners LLC ("VantaCore");
lessees; Ciner Wyoming LLC’s ("Ciner Wyoming"Wyoming's") trona mining and soda ash refinery operations;
distributions from our soda ash joint venture; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and
global and U.S. economic conditions.
These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.
You should not put undue reliance on any forward-looking statements. See
"Item"Item 1A. Risk Factors"Factors" in this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to differ.
PART I
As used in this Part I, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes.notes due 2025 (the "2025 Senior Notes").
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Partnership Structure and Management
We are a publicly traded Delaware limited partnership formed in 2002. We own, operate, manage and lease a diversified portfolio of mineral properties in the United States, including interests in coal and other natural resources and own a non-controlling 49% interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining and soda ash construction aggregates and other natural resources. production business.
Our business is organized into threetwo operating segments:
Coal Royalty and Other—consists primarily of coal royalty properties and coal relatedcoal-related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty properties, aggregates royalty properties, oil and gas royalty properties and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the WesternNorthern Powder River Basin in the United States. Our aggregates and industrial minerals and aggregates properties are located in a number ofvarious states across the United States. OurStates, our oil and gas royalty assets are primarily located in Louisiana.Louisiana and our timber assets are primarily located in West Virginia.
Soda Ash—consists of our 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining operation and soda ash refineryproduction business located in the Green River Basin of Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business.
VantaCore—consists of our construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
Our Corporate and Financing segment includes functional corporate departments that do not earn revenues. Costs incurred by these departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other corporate-level activity not specifically allocated to a segment.
Our operations are conducted through Opco and our operating assets are owned by our subsidiaries. NRP (GP) LP, our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations and the Board of Directors and officers of GP Natural Resource Partners LLC make decisions on our behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Subject to the Investor Rights Agreement with Adena Minerals, LLC ("Adena Minerals") and the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with The Blackstone Group L.P.Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree"), Mr. Robertson, Jr. is entitled to nominate eleven directors toappoint the members of the Board of Directors of GP Natural Resource Partners LLC. Mr. RobertsonLLC and has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, andappoint one director to Blackstone.
The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited Partnership andor Quintana Minerals Corporation, which are companies controlled by Mr. Robertson, and theyJr. These officers allocate varying percentages of their time to managing our operations. Neither our general partner, GP Natural Resource Partners LLC, nor any of their affiliates receive any management fee or other compensation in connection with the management of our business, but they are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.
We have regional offices through which we conduct our operations, the largest of which is located at 5260 Irwin Road, Huntington, West Virginia 25705 and the telephone number is (304) 522-5757. Our principal executive office is located at 1201 Louisiana Street, Suite 3400, Houston, Texas 77002 and our telephone number is (713) 751-7507.
2017 Recapitalization Transactions
On March 2, 2017, we completed a series of transactions in order to strengthen our balance sheet, enhance our liquidity and ultimately reposition the partnership for long-term growth, including:
the issuance of $250 million of a new class of 12.0% preferred units representing limited partner interests in NRP, together with warrants to purchase common units, to Blackstone and GoldenTree;
the exchange of $241 million of our 9.125% Senior Notes due 2018 (the "2018 Notes") for $241 million of a new series of 10.500% Senior Notes due 2022 (the "2022 Notes"), and the sale of $105 million of additional 2022 Notes in exchange for cash proceeds; and
the extension of Opco’s revolving credit facility to April 2020, with commitments thereunder reduced to $180 million.
We used a portion of the proceeds from these transactions to repay Opco’s revolving credit facility in full and pay all fees and expenses associated with the transactions described above. We will also use a portion of the proceeds to redeem the remaining 2018 Notes. On March 3, 2017, we delivered a notice of partial redemption for $90.0 million of our outstanding 2018 Notes at a redemption price of 104.563%, plus accrued and unpaid interest to the redemption date. This partial redemption of the 2018 Notes is expected to occur on April 3, 2017. We will redeem all of the remaining 2018 Notes within 60 days after October 1, 2017 at the then-applicable price and pay all accrued and unpaid interest thereon. For more information on these transactions, including the terms of the preferred units, warrants and 2022 Notes, see "Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—2017 Recapitalization Transactions."
2016 Asset Sales
Prior to completion of the recapitalization transactions discussed above, we had been pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments and scheduled debt principal payments. As part of this plan, we sold assets during the year ended December 31, 2016, for total gross proceeds of $181.0 million that consisted of the following:
1)Oil and gas working interest in the Williston Basin for $116.1 million gross sales proceeds. Our exit from the non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on our coal royalty, soda ash and construction aggregates business segments.
2)Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $36.4 million gross sales proceeds.
3)Aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds.
4)Mineral reserves in multiple sale transactions for cumulative $17.3 million of gross sales proceeds. These amounts primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas royalty interests. Additional asset sales during the year included sales of land and plant and equipment for $1.2 million of gross proceeds.
Segment and Geographic Information
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| | | | | | | | | | | | | | | | |
| | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Total |
| 2016 | | | | | | | | |
| Revenues | | $ | 239,183 |
| | $ | 40,061 |
| | $ | 120,815 |
| | $ | 400,059 |
|
| Percentage of total | | 60 | % | | 10 | % | | 30 | % | | |
| 2015 | | | | | | | | |
| Revenues | | $ | 250,717 |
| | $ | 49,918 |
| | $ | 139,013 |
| | $ | 439,648 |
|
| Percentage of total | | 57 | % | | 11 | % | | 32 | % | | |
| 2014 | | | | | | | | |
| Revenues | | $ | 267,451 |
| | $ | 41,416 |
| | $ | 42,051 |
| | $ | 350,918 |
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| Percentage of total | | 76 | % | | 12 | % | | 12 | % | | |
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| (In thousands) | | Amount | | % of Total |
| Coal Royalty and Other | | $ | 216,846 |
| | 82% |
| Soda Ash | | 47,089 |
| | 18% |
| Total | | $ | 263,935 |
| | 100% |
Coal Royalty and Other Segment
We do not operate anyOur coal mines, butreserves are primarily located in the Appalachia Basin, the Illinois Basin and the Northern Powder River Basin in the United States. We lease our reserves to experienced mine operators under long-term leases. Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms. Leases include the right to renegotiate royalties and minimum payments for the additional terms. We also own and manage coal-related transportation and processing assets in the Illinois Basin that generate additional revenues generally based on throughput or rents. As described in the "—Other Coal Royalty and Other Segment Assets" section below, we also own oil and gas, industrial minerals and aggregates reserves that generate a portion of the Coal Royalty and Other segment revenues.
Under our standard royalty lease, we grant the operators the right to mine and sell our reserves in exchange for royalty payments. A typical lease haspayments based on the greater of a five- to ten-year base term, with the lessee having an option to extend the lease for additional terms. Leases may include the right to renegotiate rents and royalties for the extended term. We also own and manage coal related infrastructure assets that generate additional revenues in the Illinois Basin. In addition, we own aggregates and industrial mineral reserves located in a number of states across the country. We derive a small percentage of our aggregatesthe sale price or fixed royalty per ton of minerals mined and industrial mineral revenues by leasing our owned reserves to third party operators who mine and sell the reserves in exchange for royalty payments.
Under our standard lease, lesseessold. Lessees calculate royalty payments due to us and are required to report tons of minerals removedmined and sold as well as the sales prices of the extracted minerals. Therefore, to a great extent, amounts reported as royalty revenuerevenues are based upon the reports of our lessees. We periodically audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify that the information that our lessees have submitted to us is accurate. Our audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to us and the actual results from each property.
In addition to their royalty obligations, our lessees are often subject to pre-established minimum quarterly or annual payments. These minimum rentalspayments, which reflect amounts we are entitled to receive even if no mining activity occurredoccurs during the period. Minimum rentalspayments are usually credited against future royalties that are earned as minerals are produced. In certain leases, the lessee is time limited on the period available for recouping minimum payments and such time is unlimited on other leases.
Because we do not operate any coal mines, our coal royalty business does not bear ordinary operating costs and has limited direct exposure to environmental, permitting and labor risks. Our lessees, as operators, are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. In addition, the lessees generally bear all labor-related risks, including retiree health care legacy costs, black lung benefits and workers’ compensation costs associated with operating the mines on our coal and aggregates properties. We typically pay property taxes on our properties, which are largely reimbursed by our lessees pursuant to the terms of the various lease agreements.
Coal ProductionReserves and ReservesProduction Information
The following table presents coal production for the year ended December 31, 2016 and coal reserves information as of December 31, 20162019 for the properties that we ownedown by major coal region:
| | | | | Production | Proven and Probable Reserves (1) | | Proven and Probable Reserves (1) |
| | | Underground | | Surface | | Total | |
| | | (Tons in thousands) | |
| Appalachia: | | | | | | | | | |
| (Tons in thousands) | | | Underground | | Surface | | Total |
| Appalachia Basin | | | | | | | |
| Northern | | 2,312 |
| | 297,896 |
| | — |
| | 297,896 |
| | 301,742 |
| | 3,031 |
| | 304,773 |
|
| Central | | 13,222 |
| | 749,328 |
| | 240,293 |
| | 989,621 |
| | 720,378 |
| | 242,379 |
| | 962,757 |
|
| Southern | | 2,776 |
| | 73,148 |
| | 17,018 |
| | 90,166 |
| | 57,881 |
| | 19,794 |
| | 77,675 |
|
| Total Appalachia | | 18,310 |
|
| 1,120,372 |
|
| 257,311 |
|
| 1,377,683 |
| |
| Total Appalachia Basin | | | 1,080,001 |
|
| 265,204 |
|
| 1,345,205 |
|
| Illinois Basin | | 8,116 |
| | 302,626 |
| | 5,307 |
| | 307,933 |
| | 299,818 |
| | 5,074 |
| | 304,892 |
|
| Northern Powder River Basin | | 3,781 |
| | — |
| | 34,738 |
| | 34,738 |
| | — |
| | 163,555 |
| | 163,555 |
|
| Gulf Coast | | 0.4 |
| | — |
| | 1,957 |
| | 1,957 |
| | — |
| | 1,957 |
| | 1,957 |
|
| Total | | 30,207 |
|
| 1,422,998 |
|
| 299,313 |
|
| 1,722,311 |
| | 1,379,819 |
|
| 435,790 |
|
| 1,815,609 |
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| (1) | In excess of 95%90% of the reserves presented in this table are currently leased to third parties. |
The following table presents the sulfur content, the typical qualitytype of our coal reserves and the type of coal by major coal region as of December 31, 2016:2019:
| | | | | | | Sulfur Content | | Typical Quality (1) | | Type of Coal | | Type of Coal | | |
| | | Compliance Coal (2) | | Low (<1.0%) | | Medium (1.0% to 1.5%) | | High (>1.5%) | | Total | | Heat Content (Btu per pound) | | Sulfur (%) | | Steam | | Met (3) | |
| | | (Tons in thousands) | | | | | | (Tons in thousands) | |
| Appalachia | | | | | | | | | | | | | | | | | | | |
| (Tons in thousands) | | | Thermal | | Metallurgical (1) | | Total |
| Appalachia Basin | | | | | | | |
| Northern | | 32,807 |
| | 32,807 |
| | 905 |
| | 264,184 |
| | 297,896 |
| | 12,854 |
| | 2.76 |
| | 265,089 |
| | 32,807 |
| | 243,939 |
| | 60,834 |
| | 304,773 |
|
| Central | | 490,556 |
| | 688,924 |
| | 254,223 |
| | 46,473 |
| | 989,620 |
| | 13,258 |
| | 0.90 |
| | 567,359 |
| | 422,262 |
| | 545,949 |
| | 416,808 |
| | 962,757 |
|
| Southern | | 60,284 |
| | 69,973 |
| | 16,617 |
| | 3,577 |
| | 90,167 |
| | 13,380 |
| | 0.83 |
| | 66,893 |
| | 23,273 |
| | 58,554 |
| | 19,121 |
| | 77,675 |
|
| Total Appalachia | | 583,647 |
|
| 791,704 |
|
| 271,745 |
|
| 314,234 |
|
| 1,377,683 |
| | 13,178 |
| | 1.30 |
| | 899,341 |
|
| 478,342 |
| |
| Total Appalachia Basin | | | 848,442 |
| | 496,763 |
| | 1,345,205 |
|
| Illinois Basin | | — |
| | — |
| | 2,155 |
| | 305,778 |
| | 307,933 |
| | 11,472 |
| | 3.29 |
| | 307,933 |
| | — |
| | 304,892 |
| | — |
| | 304,892 |
|
| Northern Powder River Basin | | — |
| | 34,738 |
| | — |
| | — |
| | 34,738 |
| | 8,800 |
| | 0.65 |
| | 34,738 |
| | — |
| | 163,555 |
| | — |
| | 163,555 |
|
| Gulf Coast | | 82 |
| | 1,957 |
| | — |
| | — |
| | 1,957 |
| | 6,964 |
| | 0.69 |
| | 1,875 |
| | 82 |
| | 1,875 |
| | 82 |
| | 1,957 |
|
| Total | | 583,729 |
|
| 828,399 |
|
| 273,900 |
|
| 620,012 |
|
| 1,722,311 |
| | | | | | 1,243,887 |
|
| 478,424 |
| | 1,318,764 |
| | 496,845 |
| | 1,815,609 |
|
| |
| (1) | For purposes of this table, we have defined metallurgical coal reserves as reserves located in seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the metallurgical category can also be used as thermal coal. |
The following table presents the sulfur content and the typical quality of our coal reserves by major coal region as of December 31, 2019:
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| | | | | | | | | | | | | | | | | | | | | |
| | | | | Sulfur Content | | Typical Quality (1) |
| (Tons in thousands) | | Compliance Coal (2) | | Low (<1.0%) | | Medium (1.0% to 1.5%) | | High (>1.5%) | | Total | | Heat Content (Btu per pound) | | Sulfur (%) |
| Appalachia Basin | | | | | | | | | | | | | | |
| Northern | | 46,307 |
| | 46,507 |
| | 1,002 |
| | 257,264 |
| | 304,773 |
| | 12,977 |
| | 2.61 |
|
| Central | | 443,313 |
| | 677,143 |
| | 239,230 |
| | 46,384 |
| | 962,757 |
| | 13,238 |
| | 0.91 |
|
| Southern | | 43,382 |
| | 47,905 |
| | 27,180 |
| | 2,590 |
| | 77,675 |
| | 13,405 |
| | 0.96 |
|
| Total Appalachia Basin | | 533,002 |
|
| 771,555 |
|
| 267,412 |
|
| 306,238 |
|
| 1,345,205 |
| | 13,189 |
| | 1.30 |
|
| Illinois Basin | | — |
| | — |
| | 2,152 |
| | 302,740 |
| | 304,892 |
| | 11,476 |
| | 3.29 |
|
| Northern Powder River Basin | | — |
| | 163,555 |
| | — |
| | — |
| | 163,555 |
| | 8,800 |
| | 0.65 |
|
| Gulf Coast | | 82 |
| | 1,957 |
| | — |
| | — |
| | 1,957 |
| | 6,964 |
| | 0.69 |
|
| Total | | 533,084 |
|
| 937,067 |
|
| 269,564 |
|
| 608,978 |
|
| 1,815,609 |
| | | | |
| |
| (1) | Unless otherwise indicated, the coal quality information in this Annual Report and on the Form 10-K is reported on an as-received basis with an assumed moisture of 6% for AppalachianAppalachia Basin reserves, and site specific moisture values for Illinois (typically 12% moisture) and Northern Powder River Basin (typically 25%) moisture). |
| |
| (2) | Compliance coal, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu and meets the sulfur dioxide emission standards imposed by Phase II of the Clean Air Act without blending with other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal. |
| |
(3) | For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the metallurgical category can also be used as steam coal. In 2016, approximately 37% of our coal royalty revenues and approximately 35% of the related production from metallurgical coal. In prior years metallurgical coal royalty revenues accounted for a greater portion of total revenue when compared to the proportion of total production. In 2016, pricing for metallurgical coal was comparable to thermal coal pricing. |
The following table presents the type of coal sales volumes by major coal region for the year ended December 31, 2019:
|
| | | | | | | | | |
| | | Type of Coal | | |
| (Tons in thousands) | | Thermal | | Metallurgical | | Total |
| Appalachia Basin | | | | | | |
| Northern | | 2,781 |
| | 679 |
| | 3,460 |
|
| Central | | 3,117 |
| | 10,260 |
| | 13,377 |
|
| Southern | | 470 |
| | 1,200 |
| | 1,670 |
|
| Total Appalachia Basin | | 6,368 |
| | 12,139 |
| | 18,507 |
|
| Illinois Basin | | 2,201 |
| | — |
| | 2,201 |
|
| Northern Powder River Basin | | 3,036 |
| | — |
| | 3,036 |
|
| Total | | 11,605 |
| | 12,139 |
| | 23,744 |
|
Methodologies Used in Mineral Reserve Estimation
All of the reserves reported above are recoverable provedproven or probable reserves as determined byin accordance with the SEC’s Industry Guide 7 and are estimated by our internal geologists or independent third-party consultants. Significant internally generated reserve engineers.studies are reviewed by independent third-party consultants. The technologies and economic data used by our internal reserve engineers in the estimation of our provedproven or probable reserves include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine and coal quality, cross sections, statistical analysis and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. In addition, the SEC has adopted new rules to modernize the property disclosure requirements for registrants with significant mining activities, which we will be required to begin to comply with for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ending December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures. The new rules require that reserve estimates that are reported be based on technical reports prepared using extensive mine-specific geological and engineering data, as well as market and cost assumptions. As a royalty company, we may not have access to much of the information that is required to prepare the technical reports used to determine reserves under the new rules without unreasonable burden or expense. Accordingly, the amount of coal and other minerals that we are allowed to report under the new rules beginning with the year ending December 31, 2021 may differ materially from the reserves reported above. See "Item"Item 1A. Risk Factors—Risks Related to Our Business—Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves. In addition, compliance with new SEC rules that will become effective beginning in 2021 could result in material adjustments to the quantities of reserves we are allowed to report."
Major Coal Producing Properties
The following istable provides a summary of our majorsignificant coal producingroyalty properties inby sales volumes for 2019 and is followed by additional information for each region:property:
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| | | | | | | | |
| Region | | Property/Lease Name | | Operator(s) | | Coal Type | | 2019 Sales Volumes (Millions of Tons) |
| Appalachia Basin | | | | | | | | |
| Northern | | Hibbs Run | | Murray Energy Corporation | | Thermal | | 2.0 |
| Northern | | Mettiki Coal | | Alliance Resource Partners | | Met/Thermal | | 0.8 |
| Central | | Contura-CAPP (VA) | | Contura Energy, Inc. | | Met | | 3.8 |
| Central | | Coal Mountain | | CM Energy Properties, LP | | Met | | 1.3 |
| Central | | Aracoma | | Contura Energy, Inc. | | Met | | 1.2 |
| Central | | Elk Creek | | Ramaco Resources, Inc. | | Met | | 1.1 |
| Central | | Lynch | | Blackjewel, LLC; InMet, LLC | | Met/Thermal | | 0.9 |
| Southern | | Oak Grove | | Murray Metallurgical Coal Holdings LLC | | Met | | 1.2 |
| Illinois Basin | | Macoupin | | Foresight Energy LP | | Thermal | | 1.6 |
| Illinois Basin | | Williamson | | Foresight Energy LP | | Thermal | | 0.3 |
| Illinois Basin | | Hillsboro | | Foresight Energy LP | | Thermal | | 0.2 |
| Northern Powder River Basin | | Western Energy | | Rosebud Mining, LLC | | Thermal | | 3.0 |
Appalachia—
Appalachia Basin—Northern Appalachia
Hibbs Run. The Hibbs Run property is located in Marion County, West Virginia. In 2016,2019, approximately 1.52.0 million tons were producedsold from this thermal property. We lease this property to Ohio Valley Resources, Inc., a subsidiary of Murray Energy Corporation. Coal from this property is produced from longwall mines.mines and shipped by rail to utility customers. The royalty rate for this property is a low fixed rate per ton and has a significant effect on the weighted average per ton revenue for the region. The coal from this property is shipped by rail to utility customers.
Area F.Mettiki Coal. Area FThe Mettiki Coal property is located in RandolphTucker and UpshurGrant Counties, West Virginia. In 2016,2019, approximately 0.40.8 million metallurgical and thermal tons were producedsold from this property. We lease this property to Carter Roag Coal Company, a subsidiary of United Coal Company, LLC (owned by Metinvest).Alliance Resource Partners. Production comes from the Pleasant Hill Sewell Seam deepthis mine and is trucked to Carter Roag’s preparation plant situated at Star Bridge, West Virginia. The coal produced from this propertyvia a longwall operation. Coal is shipped viaby truck to a local utility customer and by train to metallurgical customers. NRP pays an override royalty equal to the CSX railroadroyalty received from Mettiki to Baltimore and then by ocean vessel to Metinvest's steel mills inWestern Pocahontas Properties Limited Partnership per the Ukraine.terms of the deed.
The map below shows the location of our major properties in Northern Appalachia:
Appalachia—
Appalachia Basin—Central Appalachia
Contura-CAP.Contura-CAPP (VA). The Contura-CAPContura-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2016,2019, approximately 3.23.8 million tons were producedsold from this property.property, substantially all of which was metallurgical coal. We lease this property to subsidiaries of Contura Energy, Inc.Inc ("Contura Energy"). Production comes from both underground room and pillar and surface mines and is trucked to one of two preparation plants. Coal is shipped via both the CSX and Norfolk Southern railroads to utility and metallurgical customers.
Dingess-Rum.Coal Mountain. The Dingess-RumCoal Mountain property is located in Wyoming County, West Virginia. In 2019, approximately 1.3 million tons of metallurgical coal were sold from this property. We lease this property to CM Energy Properties, LP. Metallurgical coal is produced from a multi-seam surface mine and coal is transported by truck to a preparation plant on the property. Coal is shipped via the Norfolk Southern railroad to both domestic and export metallurgical customers.
Aracoma. The Aracoma property is located in Logan Clay and Nicholas Counties,County, West Virginia. This property is leased to subsidiaries of Alpha Natural Resources, Inc. and Blackhawk Mining, LLC. In 2016, approximately 2.1Approximately 1.2 million tons were produced from the property. Both steam andof coal, substantially all of which is metallurgical coal, arewere sold in 2019 from this property. We lease this property to a subsidiary of Contura Energy. Coal is produced from underground and surface mines and is transported by belt or truck to the preparation plantsplant on the property. Coal is shipped via the CSX railroad to utility customersexport metallurgical customers.
Elk Creek. The Elk Creek property is located in Logan and Wyoming Counties, West Virginia. In 2019, approximately 1.1 million tons were sold from this property. We lease this property to variousRamaco Resources, Inc. Metallurgical coal is produced from surface and underground mines and is transported by belt and truck to a preparation plant on the property. Coal is shipped via the CSX railroad to both domestic and export metallurgical customers.
Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky.Kentucky and Wise County, Virginia. In 2016,2019, approximately 1.70.9 million tons were producedsold from this property. ThisBlackjewel, LLC ("Blackjewel") operated this property is leaseduntil it filed for bankruptcy in the third quarter of 2019. InMet, LLC obtained lease rights to a subsidiarysubstantial portion of Revelation Energy, LLC.this property through the Blackjewel bankruptcy process and is currently operating on this lease. Production comes from both underground room and pillar and surface mines. This property has the ability to ship coal on both the CSX and Norfolk Southern railroads.
Pinnacle. The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. In 2016, approximately 1.3 million tons of metallurgical coal were produced from our reserves on this property. We also own an overriding royalty interest on coal produced from the reserves that we do not own at this property, from which we derive additional revenues. We lease the property to a subsidiary of Seneca Resources, LLC. Production comes from a longwall mine and is transported by beltline to a preparation plant and is then shipped via railroad and barge to both domestic and export customers.
Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. In 2016, approximately 1.3 million tons were produced from this property. We lease the property to a subsidiary of Arch Coal, Inc. Production comes from underground mines and is transported primarily by beltline to a preparation plant on adjacent property and shipped on the Norfolk Southern or CSX railroads to utilitiesutility and pulverized coal injection customers.
Kingston. The Kingston property is located in Fayette and Raleigh Counties, West Virginia. In 2016, approximately 0.7 million tons were produced from the property. We lease this property to a subsidiary of Alpha Natural Resources, Inc. Both steam and metallurgical coal are produced from underground and surface mines that is transported by belt or truck to a preparation plant on the property or shipped raw. Coal is shipped via both the CSX railroad and by truck to barges to steam customers and various export metallurgical customers.
Kepler/National Mines Corp. The Kepler/National Mines Corp. property is located in Wyoming County, West Virginia. In 2016, approximately 0.7 million tons were produced from the property. We lease this property to a subsidiary
The map below shows the location of our major properties in Central Appalachia:
Appalachia—
Appalachia Basin—Southern Appalachia
Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2016,2019, approximately 1.51.2 million tons of metallurgical coal were producedsold from this property. We lease thethis property to a subsidiary of SenecaMurray Metallurgical Coal Resources, LLC.Holdings, LLC ("Murray Metallurgical"). The lease was transferred to Murray Metallurgical in connection with Mission Coal LLC's bankruptcy proceedings. Production comes from an undergrounda longwall mine and is transported primarily by beltline to a preparation plant. Metallurgical products are then shipped via railroad and barge to both domestic and export customers.
BLC Properties. The BLC properties are located While the mine was temporarily idled during the last quarter of 2019 and Murray Metallurgical filed bankruptcy in Kentucky and Tennessee. In 2016, approximately 1.3 million tons were produced from these properties. We lease these propertiesthe first quarter of 2020, the Oak Grove mine is expected to a number of operators including Middlesboro Mining Properties, Inc., Revelation Energy, LLC and Corsa Coal Corp. Production comes from both underground and surface mines and is trucked to preparation plants and loading facilities operated by our lessees. Coal is transported by truck and is shipped via both CSX and Norfolk Southern railroads to utility and industrial customers.resume production in 2020.
The map below shows the location of our major propertiesproperty in Southern Appalachia:
Illinois Basin
Macoupin. The Macoupin property is located in Macoupin County, Illinois. This property is under lease to Macoupin Energy, a subsidiary of Foresight Energy LP ("Foresight Energy"). In 2019, approximately 1.6 million tons of thermal coal were sold from this property. Production is from an underground room and pillar mine. Coal is shipped by the Norfolk Southern or Union Pacific railroads or by barge to domestic utility customers.
Williamson. The Williamson property is located in Franklin and Williamson Counties, Illinois. TheThis property is under lease to Williamson Energy, a subsidiary of Foresight Energy LP, and in 2016,Energy. In 2019, approximately 5.00.3 million tons of thermal coal were mined on thesold from this property. This production isProduction comes from a longwall mine andmine. Coal is shipped primarily via the Canadian National railroad to domestic utility customers and to various export customers. In 2019, we also received overriding royalties from approximately 5.5 million tons of coal sold from non-NRP property.
Macoupin. The Macoupin property is located in Macoupin County, Illinois. The property is under lease to a subsidiary of Foresight Energy LP, and in 2016, approximately 2.1 million tons were shipped from the property. Production is from an underground mine and is shipped via the Norfolk Southern or Union Pacific railroads or by barge to utility customers such or loaded into barges for shipment to export customers.
Hillsboro/Deer Run.Hillsboro. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. TheThis property is under lease to Hillsboro Energy, a subsidiary of Foresight Energy, andEnergy. This property had been idled from March 2015 until production resumed in 2016,January 2019. In 2019, approximately 0.10.2 million tons of thermal coal were shippedsold from thethis property. When active, productionProduction at the Deer Run mine on our Hillsboro property ishas historically come from an underground longwall mine andmining methods; however, 2019 production came from continuous mining methods for development of a longwall panel. Coal is shipped by rail via either the Union Pacific, Norfolk Southern or Canadian National railroads, or by barges to domestic utilities or export customers. The Deer Run mine has been idled since March 2015 as a result of elevated carbon monoxide levels in the mine. In July 2015, we received a notice from Foresight Energy declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. We believe Foresight's claim of force majeure has no merit, and we are vigorously pursuing our claims against them through a lawsuit that we filed in November 2015. However, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. For more information on the idling of the Deer Run mine, see "Item 3. Legal Proceedings" included elsewhere in this Annual Report on Form 10-K.
In addition to these properties, we own loadout and other transportation assets at the Williamson and Macoupin mines and at the Sugar Camp mine, which is another mineare also operated by Foresight Energy. See "—Coal Transportation and Processing Assets."Assets" below for additional information on these assets.
The map below shows the location of our major properties in the Illinois Basin:
Northern Powder River Basin
Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2016,2019, approximately 3.83.0 million tons were producedsold from ourthis property by a subsidiary of Westmoreland Coal Company.Rosebud Mining, LLC. Coal is produced by surface dragline mining and the coalmethods. Coal is transported by either truck or beltline to the four-unit 2,200-megawatt Colstrip generation station located at the mine mouth.
The map below shows the location of our property in the Northern Powder River Basin:
Coal Transportation and Processing Assets
We own transportation and processing infrastructure related to certain of our coal properties. We ownproperties, including loadout and other transportation assets at theForesight Energy's Williamson and Macoupin mines in the Illinois Basin.Basin, for which we collect throughput fees or rents. We lease our Macoupin and Williamson transportation and processing infrastructure to subsidiaries of Foresight Energy and are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we subcontract to a subsidiary of Foresight Energy. In addition, we own rail loadout and associated infrastructure at the Sugar Camp mine, an Illinois Basin mine also operated by a subsidiary of Foresight Energy LP.Energy. While we own coal reserves at the Williamson and Macoupin mines, we do not own coal reserves at the Sugar Camp mine. We typically lease thisThe infrastructure to third parties and collect throughput fees; however, at the loadout facility at the WilliamsonSugar Camp mine we operate the coal handling and transportation infrastructure and have subcontracted out that responsibilityis leased to a third party.
subsidiary of Foresight Energy and we collect minimums and throughput fees. We recorded $19.3 million in revenue related to our coal transportation and processing assets during the year ended December 31, 2019.
Other Coal Royalty and Other Segment Assets
As of December 31, 2016,2019, we owned an estimated 250172 million tons of aggregates reserves primarily located in Kentucky Washington and Indiana. We lease a portion of these reserves to third parties in exchange for royalty payments. We also lease approximately 90 million tons of these reserves to VantaCore's Grand Rivers operation. The structure of these leases is similar to our coal leases, and these leases typically also require minimum rental payments in addition to royalties. During 2016, our aggregates lessees produced 1.5In addition, we hold overriding royalty interests in approximately 82 million tons of aggregatesfrac sand at operations in Wisconsin and Texas and sand and gravel reserves in Washington. During 2019, our lessees sold 4.5 million tons from these properties and we received $3.2$4.3 million in aggregates royalty revenues, including overriding royalty revenues.
Through our 51% ownership of BRP LLC ("BRP"), a joint venture with International Paper Company, we own approximately 10 million mineral acres in 31 states in the U.S. that include the following assets:
approximately 300,000 gross acres of oil and natural gas mineral rights primarily in Louisiana, of which over 53,000 acres were leased as of December 31, 2016;2019;
approximately 50 million tons of aggregates reserves primarily located in North Carolina, Arkansas and South Carolina and approximately 6 million tons of override royalty interest in South Carolina and Georgia;
approximately 2 million tons of coal reserves (primarily lignite and some bituminous coal) on 95,000 net mineral acres of coal rights (primarily lignite and some bituminous coal) in the Gulf Coast region, of which approximately 4,8005,600 acres are leased in Louisiana, AlabamaMississippi and Texas;
an overriding royalty interest of 1% (net) on approximately 25,000 mineral acres in Louisiana;
copper rights in Michigan’sMichigan's Upper Peninsula that are subject to a development agreement with a copper development company;Peninsula; and
various other mineral rights including coalbed methane, metals, aggregates, water and geothermal, in several states throughout the United States.
While the vast majority of the 10 million acres owned by BRP remain largely undeveloped, BRP has an ongoing program to identify additional opportunities to lease its minerals to operating parties.parties or otherwise monetize these assets.
Soda Ash Segment
We own a 49% non-controlling equity interest in Ciner Wyoming. Ciner Resources LP, our operating partner, controls and operates Ciner Wyoming. Ciner Resources LP mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. Ciner Resources LP is a publicly traded master limited partnership that depends on distributions from Ciner Wyoming whichin order to make distributions to its public unitholders.
Ciner Wyoming is one of the largest and lowest cost producers of soda ash in the world, serving a global market from its facility located in the Green River Basin of Wyoming. The Green River Basin geological formation holds the largest, and one of the highest purity, known deposits of trona ore in the world. Trona, a naturally occurring soft mineral, is also known as sodium sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. Ciner Wyoming processes trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other consumer and industrial products. The vast majority of the world’s accessible trona reserves are located in the Green River Basin. According to historical production statistics, approximately one-quarter of global soda ash is produced by processing trona, with the remainder being produced synthetically through chemical processes. The costs associated with procuring the materials needed for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-based production consumes less energy and produces fewer undesirable by-products than synthetic production.
Ciner Wyoming’s Green River Basin surface operations are situated on approximately 880 acres in Wyoming, and its mining operations consist of approximately 23,500 acres of leased and licensed subsurface mining area. The facility is accessible by both road and rail. Ciner Wyoming uses sixseven large continuous mining machines and ten14 underground shuttle cars in its mining operations. Its processing assets consist of material sizing units, conveyors, calciners, dissolver circuits, thickener tanks, drum filters, evaporators and rotary dryers.
The following map provides an aerial overview of Ciner Wyoming’s surface operations:
In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering the liquor, a solution consisting of sodium carbonate dissolved in water. Ciner Wyoming then adds activated carbon to filters to remove organic impurities, which can cause color contamination in the final product. The resulting clear liquid is then crystallized in evaporators, producing sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge to remove excess water. The resulting material is dried in a product dryer to form anhydrous sodium carbonate, or soda ash. The resulting processed soda ash is then stored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. Ciner Wyoming’s storage silos can hold up to 65,000 short tons of processed soda ash at any given time. The facility is in good working condition and has been in service for over 5057 years.
Deca Rehydration. The evaporation stage of trona ore processing produces a precipitate and natural by-product called deca. "Deca," short for sodium carbonate decahydrate, is one part soda ash and ten parts water. Solar evaporation causes deca to crystallize and precipitate to the bottom of the four main surface ponds at the Green River Basin facility. Ciner Wyoming’sThe deca rehydration process enables Ciner Wyoming to recover soda ash from the deca-rich purged liquor as a by-product of the refining process. The soda ash contained in deca is captured by allowing the deca crystals to evaporate in the sun and separating the dehydrated crystals
from the soda ash. The separated deca crystals are then blended with partially processed trona ore in the dissolving stage.stage of the production process. This process enables Ciner Wyoming to reduce waste storage needs and convert what is typically a waste product into a usable raw material. As a result of this process, Ciner Wyoming has been able to reduce the amount ofanticipates that its current deca stockpiles will be exhausted by 2023 and production rates decline approximately 200,000 short tons of trona ore it takes to produce one short ton of soda ash.per year if that production is not replaced.
Shipping and LogisticsLogistics. . All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended December 31, 2016,2019, Ciner Wyoming shipped approximately 96%96.9% of its soda ash to its customers initially via a single rail under a contract withline owned and controlled by Union Pacific that expires on December 31, 2017, and theRailroad Company (“Union Pacific”). The Ciner Wyoming plant receives rail service exclusively from Union Pacific. The agreement with Union Pacific expires on December 31, 2021 and there can be no assurance that it will be renewed on terms favorable to Ciner Wyoming or at all. The rail freight rate charged under the agreement increases annually based on a published index tied to certain rail industry metrics. Ciner Resources Corporation leases a fleet of more than 2,000 hopper cars that serve as dedicated modes of shipment to its domestic customers. For export, Ciner Wyoming ships soda ash on unit trains consisting of approximately 100 cars to two primary ports: Port Arthur,ports located in Texas and Portland, Oregon. From these ports, the soda ash is loaded onto ships for delivery to ports all over the world. American Natural Soda Ash Corporation ("ANSAC") currently provides logistics and support services for all of Ciner Wyoming’s export sales. For domestic sales, Ciner Resources Corporation provides similar services.
Customers. Ciner Wyoming’s customers, including end users to whom ANSAC makes sales overseas, consist primarily of glass manufacturing companies, which account for 50% or more of the consumption of soda ash around the world; and chemical and detergent manufacturing companies. Ciner Wyoming’s largest customer currently is ANSAC, which buys soda ash (through Ciner Resources Corporation, which serves as Ciner Wyoming’s sales agent)agent in its agreement with ANSAC) and other of its member companies for further export to its customers. ANSAC accounted for approximately 55%60% of Ciner Wyoming’s net sales in 2016.2019. ANSAC takes soda ash orders directly from its overseas customers and then purchases soda ash for resale from its member companies pro rata based on each member’s production volumes. ANSAC is the exclusive distributor for its members to the markets it serves. However, Ciner Resources Corporation, on Ciner Wyoming’s behalf, negotiates directly with, and Ciner Wyoming exports to, customers in markets not served by ANSAC.
In November 2018, Ciner Resources Corporation delivered a notice to terminate the membership in ANSAC, which will be effective as of December 31, 2021. Until the effective termination date, ANSAC will continue to sell Ciner Wyoming’s soda ash to ANSAC-designated overseas territories and continue to provide logistics and support services for Ciner Wyoming’s other export sales. After the termination period, Ciner Resources Corporation will begin marketing soda ash directly into international markets which are currently being served by ANSAC, and Ciner Wyoming intends to utilize the distribution network that has already been established by the global Ciner Group. The ANSAC agreement provides that in the event an ANSAC member exits or the ANSAC cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the cooperative. The withdrawal from ANSAC is expected to enable Ciner Wyoming to combine volumes with Ciner Group’s soda ash exports from Turkey and therefore to leverage the larger, global Ciner Group’s soda ash operations. Ciner Wyoming believes this will eventually lower its cost position and improve its ability to optimize its market share both domestically and internationally. However, initial costs may be higher than costs incurred through ANSAC sales. In addition, Ciner Wyoming will need access to an international logistic infrastructure that includes, among other things, a domestic port for export capabilities. These export capabilities are currently being developed by Ciner Group, and options being evaluated range from continued outsourcing in the near term to developing Ciner Group’s own port capabilities in the longer term. Ciner Wyoming expects to bear a portion of these development costs. See "Item 1A—Risk Factors—Risks Related to Our Business—A significant portion of Ciner Wyoming’s historical international sales of soda ash have been to ANSAC, and the termination of the ANSAC membership could adversely affect Ciner Wyoming’s ability to compete in certain international markets and increase Ciner Wyoming’s international sales costs."
For customers in North America, Ciner Resources typically enters into contracts on Ciner Wyoming’s behalf with terms ranging from one to three years. Under these contracts, customers generally agree to purchase either minimum estimated volumes of soda ash or a certain percentage of their soda ash requirements at a fixed price for a given calendar year. Although Ciner Wyoming does not have a “take or pay” arrangements with its customers, substantially all sales are made pursuant to written agreements and
not through spot sales. In 2019, Ciner Wyoming had more than 70 domestic customers and has had long-term relationships with the majority of its customers.
Leases and License. Ciner Wyoming is party to several mining leases and one license for its subsurface mining rights. Some of the leases are renewable at Ciner Wyoming’s option upon expiration. Ciner Wyoming pays royalties to the State of Wyoming, the U.S. Bureau of Land Management and Rock Springs Royalty Company, an affiliate of Occidental Petroleum Corporation (formerly an affiliate of Anadarko Petroleum Corporation), which are calculated based upon a percentage of the quantity or gross value of soda ash and related products sold at a certain stage in the mining process, or a certain sum per ton of such products.process. These royalty payments are typicallymay be subject to a minimum domestic production volume from the Green River Basin facility, althoughfacility. Ciner Wyoming is also obligated to pay minimum royalties or annual rentals to its lessors and licensor regardless of actual sales. The royalty rates paidIn addition, Ciner Wyoming pays a production tax to Ciner Wyoming’s lessorsSweetwater County, and licensor may change upon renewaltrona severance tax to the State of such leases and license. Under the license with Rock Springs, the applicable royalty rate may varyWyoming that is calculated based on a most favored nation clause informula that utilizes the license whichvolume of trona ore mined and the value of the soda ash produced.
Expansion Project. Ciner Wyoming has announced a significant capacity expansion capital project that would increase production levels to up to 3.5 million tons of soda ash per year. Ciner Wyoming has conducted the initial basic design and is currently evaluating and pursuing the subjectrelated permits and detailed cost analysis pursuant to the basic design. This project will require capital expenditures materially higher than have been incurred by Ciner Wyoming over the past few years, and Ciner Wyoming intends to fund the project in part by reinvesting cash that would otherwise be distributed to its partners. In the third quarter of litigation2019, Ciner Wyoming significantly reduced its cash distributions to its partners, and we expect for cash distributions from Ciner Wyoming to remain at approximately $25 million to $28 million per year until the project is funded. However, the costs of the expansion project could be higher than expected, or the execution of the project could be substantially delayed, which could materially impact Ciner Wyoming’s profitability and result in Wyoming.a further reduction of cash distributions to us. See "Item 1A—Risk Factors—Risks Related to Our Business—Significant delays and/or higher than expected costs associated with Ciner Wyoming’s capacity expansion project could adversely affect Ciner Wyoming’s profitability and ability to make distributions to us."
As a minority interest owner in Ciner Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine or soda ash production plant. Our partner, Ciner Resources LP, manages the mining and plant operations. We appoint three of the seven members of the Board of Managers of Ciner Wyoming and have certain limited negative controls relating to the company.
VantaCore Segment
VantaCore is a construction materials company that we acquired on October 1, 2014. VantaCore operates four limestone quarries, one underground limestone mine, five sand and gravel plants, two asphalt plants and two marine terminals. VantaCore is headquartered in Philadelphia, Pennsylvania, and its operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. As of December 31, 2016, VantaCore controlled approximately 400 million tons of estimated aggregates reserves, including approximately 117 million tons of reserves leased at the Grand Rivers operation from the Coal Royalty and Other segment. The reserve estimates for each of VantaCore’s properties were prepared internally and audited by an independent third party advisor. For the year ended December 31, 2016, VantaCore sold approximately 5.5 million tons of crushed stone and gravel, including brokered stone, 1.2 million tons of sand and 0.2 million tons of asphalt. VantaCore’s four operating businesses are Laurel Aggregates, located in Lake Lynn, Pennsylvania, Winn Materials/McIntosh Construction, located in Clarksville, Tennessee, Grand Rivers, located in Grand Rivers, Kentucky and Southern Aggregates, located near Baton Rouge, Louisiana. VantaCore’s business is seasonal, with production typically lower in the first quarter of each year due to winter weather. The following map shows the locations of each of VantaCore’s operations.
Laurel Aggregates
Laurel Aggregates is a limestone mining company located in Lake Lynn, Pennsylvania. Its operations consist of a surface and underground mines and use conventional drilling, blasting and crushing methods. The surface mine is located on approximately 100 acres of owned property, and the underground reserves are located on approximately 670 acres of leased property. Laurel pays royalties for material mined and sold from its leased property. Laurel also brokers stone for third party quarries located in Ohio and Pennsylvania. Crushed stone is loaded into third party trucks for delivery to customers located in southwestern Pennsylvania, northeastern West Virginia and eastern Ohio. Laurel’s customers consist of oilfield service companies, natural gas exploration and production companies and construction and contracting companies.
Winn Materials/McIntosh Construction
Winn Materials’ operations consist of two crushed stone quarries and a river terminal, while McIntosh is a complementary asphalt producer and paving company. Together, the two companies function as a vertically integrated unit. The operations of Winn/McIntosh are located in Clarksville, Tennessee, which is located approximately 45 miles northwest of Nashville and is Tennessee’s fifth largest city.
Winn mines and produces hard rock limestone using conventional drilling, blasting and crushing methods. Winn primarily leases its properties at its two quarries located in Clarksville and in Trenton, Kentucky and pays royalties for material produced and sold from the leased properties. Winn’s marine terminal business is located on the Cumberland River, adjacent to Winn’s Clarksville quarry. Its dock transloads various materials by barge. Through the river terminal, Winn loads out crushed stone and also imports products such as river and granite sand, fertilizer and agricultural products for the local and regional markets. The river terminal is currently being expanded to meet growing demand for additional imported product into these markets. Crushed stone produced at Winn’s quarries and products imported from the river terminal are loaded onto third party trucks for delivery to Winn’s customers.
McIntosh sells asphalt to third parties and also operates its own paving business. Winn supplies most of McIntosh’s crushed stone and sand used for both its asphalt production and construction needs. The Winn/McIntosh businesses sell to and provide services for residential, commercial and industrial customers. These businesses also supply and provide construction services for infrastructure and highway construction projects primarily within Montgomery County, Tennessee, including for Fort Campbell, one of the largest Army bases in the United States.
Grand Rivers
VantaCore purchased this 514 acre hard rock quarry operation located on the Tennessee River near Grand Rivers, Kentucky from one of NRP’s aggregates lessees that had previously idled the operation. Under VantaCore’s ownership, this operation continues to lease reserves from NRP and sell its limestone aggregates in both the local market loaded onto third party trucks and to river-based markets through a barge load out terminal.
The Grand Rivers quarry produces various grades of crushed limestone products mined through its open pit using conventional drilling, blasting and crushing methods performed by a third party mining contractor. Grand Rivers pays royalties for material produced and sold from the leased property to a subsidiary of NRP. Crushed stone is loaded into third party trucks to customers in Kentucky and barges for delivery to customers along the Mississippi River Basin and related waterways. Grand Rivers customers currently consist primarily of ready mix concrete companies and construction and contracting companies.
Southern Aggregates
Southern Aggregates is a sand and gravel mining company based in Denham Springs, Louisiana approximately 25 miles northeast of Baton Rouge, Louisiana. Southern operates five sand and gravel operations. Suction dredges extract sand and gravel, and the mined material is processed at plants generally located at each site. The plants separate gravel and saleable sand from waste sand and clays, with the waste returned to mined-out sections of pits. The saleable sand and gravel material is loaded onto third party trucks for delivery to Southern’s customers. Southern leases its mineral reserves and pays royalties for material produced and sold from the leased properties. Southern’s markets extend approximately 100 miles west and south from its operating locations, including to the cities of Baton Rouge, Lafayette and New Orleans. Southern’s customers consist primarily of ready mix concrete companies, asphalt producers and contractors.
Significant Customers
We have a significant concentration of revenues with Foresight Energy and its subsidiaries, with total revenues of $63.4$58.9 million in 2016. The exposure is spread out over2019 from four different mining operations.operations, including transportation and processing services revenues, coal overriding royalty revenues and wheelage revenues. We are currentlyalso have a significant concentration of revenues from Contura Energy, with total revenues of $40.7 million in disputes with and have filed two separate lawsuits against two of Foresight Energy's subsidiaries, Hillsboro Energy for breach of contract due to wrongful declaration of force majeure at the Deer Run mine, and Macoupin Energy for breach of contract for wrongful recoupment of previously paid minimum royalties.2019 from several different mining operations, including wheelage revenues. For additional information on the Deer Run mine lawsuit, see significant customers, refer to "Note 15. "Major Customers" in the Notes to Consolidated Financial Statements under "ItemItem 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" included elsewhere in this Annual Report on Form 10-K.Data—Note 15. Major Customers."
Competition
We face competition from land companies, coal producers, international steel companies and private equity firms in purchasing coal reserves and royalty producing properties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers in various regions of the United States for domestic sales. Lessees compete with both large and small producers nationwide on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity and steel, as well as government regulations, technological developments and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, wind, solar and hydroelectric power.
The construction aggregates industry that VantaCore operates in is highly competitive and fragmented with a large number17
Ciner Wyoming's trona mining and soda ash refinery business in the Green River Basin, Wyoming, faces competition from a number of soda ash producers in the United States, Europe and Asia, some of which have greater market share and greater financial, production and other resources than Ciner Wyoming does. Some of Ciner Wyoming’s competitors are diversified global corporations that have many lines of business and some have greater capital resources and may be in a better position to withstand a long-term deterioration in the soda ash market. Other competitors, even if smaller in size, may have greater experience and stronger relationships in their local markets. Competitive pressures could make it more difficult for Ciner Wyoming to retain its existing
customers and attract new customers, and could also intensify the negative impact of factors that decrease demand for soda ash in the markets it serves, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of soda ash.
Title to Property
We owned a significant percentagesubstantially all of our coal and aggregates reserves in fee as of December 31, 2016.2019. We lease the remainder from unaffiliated third parties, including leasing aggregates reserves for VantaCore’s construction materials business.parties. Ciner Wyoming also leases or licenses its trona reserves. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operation of our business.
For most of our properties, the surface, oil and gas and mineral or coal estates are not owned by the same entities. Some of those entities are our affiliates. State law and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the existence of the severed estates will materially impede development of the minerals on our properties.
Regulation and Environmental Matters
General
Operations on our properties must be conducted in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls (PCBs)("PCBs"). Because of extensive, comprehensive and often ambiguous regulatory requirements, violations during natural resource extraction operations are not unusual and, notwithstanding compliance efforts, we do not believe violations can be eliminated entirely.
While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations, those costs have been and are expected to continue to be significant. Our lessees in our coal and aggregates royalty businesses are required to post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closures, including the cost of treating mine water discharge when necessary. In many states our lessees also pay taxes into reclamation funds that states use to achieve reclamation where site specific performance bonds are inadequate to do so. Determinations by federal or state agencies that site specific bonds or state reclamation funds are inadequate could result in increased bonding costs for our lessees or even a cessation of operations if adequate levels of bonding cannot be maintained. We do not accrue for reclamation costs because our lessees are both contractually liable and liable under the permits they hold for all costs relating to their mining operations, including the costs of reclamation and mine closures. Although the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. In recent years, compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.
In addition, the electric utility industry, which is the most significant end-user of steamthermal coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which has affected and is expected to continue to affect demand for coal mined from our properties. Current and future proposed legislation and regulations could be adopted that will have a significant additional impact on the mining operations of our lessees or their customers’ ability to use coal and may require our lessees or their customers to change operations significantly or incur additional substantial costs that would negatively impact the coal industry.
Many of the statutes discussed below also apply to VantaCore’s construction aggregates mining and production operations and Ciner Wyoming’s trona mining and soda ash production operations, and therefore we do not present a separate discussion of statutes related to those activities, except where appropriate.
Air Emissions
The Clean Air Act and corresponding state and local laws and regulations affect all aspects of our business. The Clean Air Act directly impacts our lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of federal rulemakings that are focused on emissions from coal-fired electric generating facilities, including the Cross-State Air Pollution Rule (CSAPR)("CSAPR"), regulating emissions of nitrogen oxide and sulfur dioxide, and the Mercury and Air Toxics Rule (MATS)("MATS"), regulating emissions of hazardous air pollutants. Installation of additional emissions control technologies and other measures required under these and other U.S. Environmental Protection Agency (EPA)("EPA") regulations including EPA’s proposed rules to regulate greenhouse gas (GHG) emissions from new and existing fossil fuel-fired power plants, will make it more costly to operate coal-fired power plants and could make coal a less attractive or even effectively prohibited fuel source in the planning, building and operation of power plants in the future. These rules and regulations have resulted in a reduction in coal’s share of power generating capacity, which has negatively impacted our lessees’ ability to sell coal and our coal-related revenues. Further reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed rules and regulations would have a material adverse effect on our coal-related revenues.
Carbon Dioxide and Greenhouse Gas ("GHG") Emissions
In December 2009, EPA determined that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and welfare because emissions of such gases are, according to EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on its findings, EPA has begunbegan adopting and implementing regulations to restrict emissions of GHGs under various provisions of the Clean Air Act.
In August 2015, EPA published its final Clean Power Plan ("CPP") Rule, a multi-factor plan designed to cut carbon pollution from existing power plants, including coal-fired power plants. The rule requiresrequired improving the heat rate of existing coal-fired power plants and substituting lower carbon-emission sources like natural gas and renewables in place of coal. TheAs promulgated, the rule willwould force many existing coal-fired power plants to incur substantial costs in order to comply or alternatively result in the closure of some of these plants. This rule is expected to haveplants, likely resulting in a material adverse effect on the demand for coal by electric power generators and isgenerators. The rule was being challenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit. In February 2016, the Supreme Court of the United States stayed the Clean Power PlanCPP Rule pending a decision by the District of Columbia Circuit as well as any subsequent review by the Supreme Court. In April 2017, the United States Court of Appeals for the District of Columbia Circuit granted EPA’s motion to hold the litigation in abeyance. In December 2017, EPA issued a proposed rule repealing the CPP Rule and issued an Advance Notice of Proposed Rulemaking soliciting information regarding a potential replacement rule to the CPP Rule. In August 2018, EPA formally proposed the Affordable Clean Energy ("ACE") Rule, which would replace the CPP Rule. The ACE Rule contemplates a narrower approach than the CPP Rule, focusing on efficiency improvements at existing power plants and eliminating the CPP Rule’s broader goals that envisioned switches to non-fossil fuel energy sources and the implementation of efficiency measures on demand-side entities, which the EPA now considers beyond the reach of its authority under the Clean Air Act. The ACE Rule would also omit specific numerical emissions targets that had been established under the CPP Rule. The ACE Rule went into effect on September 6, 2019. As a result, the United States Court of Appeals for the District of Columbia Circuit dismissed the pending challenges to the CPP Rule as moot. The ACE Rule has been challenged by public health groups, environmental groups, and a coalition of twenty-two states and six municipalities; various industry groups and power providers have sought to intervene.
In October 2015, EPA published its final rule on performance standards for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The final rule requires new steam generating units to use highly efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture and storage technology. The final emission standard is less stringent than EPA had originally proposed due to updated cost assumptions, but could still have a material adverse effect on new coal-fired power plants. The final rule has been challenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit, but is not subject to a stay. Oral arguments are currently scheduled forIn April 2017.2017, the court granted EPA’s motion to hold the litigation in abeyance while EPA reviews the rule.
President Obama also announced an emission reduction agreement with China’s President Xi Jinping in November 2014. The United States pledged that by 2025 it would cut climate pollution by 2626% to 28% from 2005 levels. China pledged it would reach its peak carbon dioxide emissions around 2030 or earlier, and increase its non-fossil fuel share of energy to around 20% by 2030. In December 2015, the United States was one of 196 countries that participated in the Paris Climate Conference, at which the participants agreed to limit their emissions in order to limit global warming to 2°C above pre-industrial levels, with an aspirational goal of 1.5°C. While there is no way to estimate the impact of these climate pledges and agreements, they could ultimately have an adverse effect on the demand for coal, both nationally and internationally, if implemented. Prior to taking office,In 2019, President Trump expressed his desire that the United States withdrawwithdrew from the Paris Climate Agreement.
EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including coal-fired electric power plants, on an annual basis.
Hazardous Materials and Waste
The Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA("CERCLA" or the Superfund law) and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance"“hazardous substance” into the environment. We could become liable under federal and state Superfund and waste management statutes if our lessees are unable to pay environmental cleanup costs relating to hazardous substances. In addition, we may have liability for environmental clean-up costs in connection with our VantaCore construction aggregates and Ciner WyomingWyoming's soda ash businesses.
Water Discharges
Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water Act and analogous state laws and regulations create two permitting programs for mining operations. The National Pollutant Discharge Elimination System (NPDES) program under Section 402 of the statute is administered by the states or EPA and regulates the concentrations of pollutants in discharges of waste and storm water from a mine site. The Section 404 program is administered by the Army Corps of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise "waters“waters of the United States."” The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and may include land features not commonly understood to be a stream or wetlands. In June 2015, EPA issued a new rule defining the scope of "Waters of the United States" (WOTUS) that are subject to regulation. The WOTUS rule has been challenged by a number of states and private parties and was stayed on a nationwide basis by the Sixth Circuit Court of Appeals in October 2015. In February 2016, the United States Court of Appeals for the Sixth Circuit ruled that it has exclusive jurisdiction over the challenge. In January 2017, the Supreme Court decided to hear a petition by industry groups challenging the Sixth Circuit’s jurisdictional determination. The Clean Water Act and its regulations prohibit the unpermitted discharge of pollutants into such waters, including those from a spill or leak. Similarly, Section 404 also prohibits discharges of fill material and certain other activities in waters unless authorized by the issued permit. In June 2015, EPA issued a new rule defining the scope of “Waters of the United States” (WOTUS) that are subject to regulation. The 2015 WOTUS rule was challenged by a number of states and private parties in federal district and circuit courts. In December 2017, EPA and the Corps proposed a rule to repeal the 2015 WOTUS rule and implement the pre-2015 definition. The repeal of the 2015 WOTUS rule took effect in December 2019. In December 2018, EPA and the Corps issued a proposed rule again revising the definition of “Waters of the United States.” In January 2020, EPA and the Corps announced that the 2018 proposed rule was final. The repeal of the 2015 WOTUS rule and implementation of the pre-2015 rule have been challenged in federal courts, and the 2020 final WOTUS rule will likely be challenged as well.
In connection with EPA’sits review of permits, itEPA has at times sought to reduce the size of fills and to impose limits on specific conductance (conductivity) and sulfate at levels that can be unachievable absent treatment at many mines. Such actions by EPA could make it more difficult or expensive to obtain or comply with such permits, which could, in turn, have an adverse effect on our coal-related revenues.
In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators and landowners. Since 2012, several citizen group lawsuits have been filed against mine operators for allegedly violating conditions in their National Pollutant Discharge Elimination System ("NPDES"(“NPDES”) permits requiring compliance with West Virginia’s water quality standards. Some of the lawsuits allegealleged violations of water quality standards for selenium, whereas others allegealleged that discharges of conductivity and sulfate arewere causing violations of West Virginia’s narrative water quality standards, which generally prohibit adverse effects to aquatic life. The citizen suit groups have sought penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate. The federal district court for the Southern District of West Virginia has ruled in favor of the citizen suit groups in multiple suits alleging violations of the water quality standard for selenium and in two suits alleging violations of water quality standards due to discharges of conductivity (one of which was upheld on appeal by the United States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in large treatment expenses for our lessees. In 2015, the West Virginia Legislature enacted certain changes to West Virginia’s NPDES program to expressly prohibit the direct enforcement of water quality standards against permit holders. EPA approved those changes as a program revision effective March 27, 2019. This approval may prevent future citizen suits alleging violations of water quality standards.
Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. NRP has been named as a defendant in one of these lawsuits. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. While it is too early to determine the merits or predict the outcome of any of these lawsuits, anyAny determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.
Other Regulations Affecting the Mining Industry
Mine Health and Safety Laws
The operations of our coal lessees VantaCore and Ciner Wyoming are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.
Mining accidents in recent years have received national attention and instigated responses at the state and national level that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. Since 2006, heightened scrutiny has been applied to the safe operations of both underground and surface mines. This increased level of review has resulted in an increase in the civil penalties that mine operators have been assessed for non-compliance. Operating companies and their supervisory employees have also been subject to criminal convictions. The Mine Safety and Health Administration (MSHA)("MSHA") has also advised mine operators that it will be more aggressive in placing mines in the Pattern of Violations program, if a mine’s rate of injuries or significant and substantial citations exceed a certain threshold. A mine that is placed in a Pattern of Violations program will receive additional scrutiny from MSHA.
Surface Mining Control and Reclamation Act of 1977
The Surface Mining Control and Reclamation Act of 1977 (SMCRA)("SMCRA") and similar statutes enacted and enforced by the states impose on mine operators the responsibility of reclaiming the land and compensating the landowner for types of damages occurring as a result of mining operations. To ensure compliance with any reclamation obligations, mine operators are required to post performance bonds. Our coal lessees are contractually obligated under the terms of our leases to comply with all federal, state and local laws, including SMCRA. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the reclamation plan approved by the state regulatory authority. In addition, higher and better uses of the reclaimed property are encouraged. Regulatory authorities or individual citizens who bring civil actions under SMCRA may attempt to assign the liabilities
Mining Permits and Approvals
Numerous governmental permits or approvals such as those required by SMCRA and the Clean Water Act are required for mining operations. In connection with obtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for reclaiming the mined property upon the completion of mining operations. Our lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, given the imposition of new requirements in the permits in the form of policies and the increased oversight review that has been exercised by EPA, there are no assurances that they will not experience difficulty and delays in obtaining mining permits in the future. In addition, EPA has used its authority to create significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coal operators.
Regulations under SMCRA include a "stream buffer zone" rule that prohibits certain mining activities near streams. In 2008, the federal Office of Surface Mining (OSM), which implements SMCRA, revised the stream buffer zone rule, making it more clear that valley fills are not prohibited by the rule. Environmental groups challenged the revision to the buffer zone rule in federal court. In February 2014, the federal court vacated the 2008 rule and in December 2014, OSM reinstated the previous version of the rule, without clarifying whether the previous version of the rule impacts the ability to construct excess fills. In December 2016, OSM finalized the "Stream Protection Rule," a re-written version of the stream buffer zone rule which requires coal operators to
restrict mining within 100 feet of waterways. The rule also requires states to impose additional information gathering and monitoring at and around coal mining sites and mandates new financial assurance and reclamation requirements. The rule was repealed by Congress in February 2017; however, to the extent the rule is ever reinstated, it could restrict our lessees’ ability to develop new mines, or could require our lessees to modify existing operations, which could have an adverse effect on our coal-related revenues.
Employees and Labor Relations
As of JanuaryDecember 31, 2017,2019, affiliates of our general partner employed 6356 people who directly supported our operations. None of these employees were subject to a collective bargaining agreement. We employed 221 people who supported VantaCore’s construction aggregates mining and production operations. None of these employees were subject to a collective bargaining agreement.
Website Access to CompanyPartnership Reports
Our internetInternet address is www.nrplp.com.www.nrplp.com. We make available free of charge on or through our internetInternet 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 soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Also includedInformation on our website are ouris not a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us.
Corporate Governance Matters
Our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy and our Corporate Governance Guidelines adopted by our Board of Directors, as well as the charter for our Audit Committee.Committee are available on our website at www.nrplp.com. Copies of our annual report, our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy, our Corporate Governance Guidelines and our committee charters will be made available upon written request.request to our principal executive office at 1201 Louisiana St., Suite 3400, Houston, Texas 77002.
ITEM 1A. RISK FACTORS
Risks Related to Our Business
ToCash distributions are not guaranteed and may fluctuate with our performance and the extent our boardestablishment of directors deems appropriate, it may determine to decrease the amount of our quarterly distribution or suspend or eliminate the distribution altogether.financial reserves. In addition, our debt agreements and our partnership agreement place restrictions on our ability to pay, and in some cases raise, the quarterly distribution under certain circumstances.
Because distributions on the common units are dependent on the amount of cash we generate, distributions fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter depends on numerous factors, some of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits. The actual amount of cash we have to distribute each quarter is reduced by payments in respect of debt service and other contractual obligations, including distributions on the preferred units, fixed charges, maintenance capital expenditures and reserves for future operating or capital needs that the board of directors may determine are appropriate. Cash distributions are dependent primarily on cash flow, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits. Following the recapitalization transactions, we stillWe have significant debt service obligations and obligations to pay cash distributions on our preferred units. To the extent our board of directors deems appropriate, it may determine to decrease the amount of the quarterly distribution on our common units or suspend or eliminate the distribution on our common units altogether. In addition, because our unitholders are required to pay income taxes on their respective shares of our taxable income, youour unitholders may be required to pay taxes in excess of any future distributions we make. YourOur unitholders' share of our portfolio income may be taxable to youthem even though youthey receive other losses from our activities. See "—Tax Risks to CommonOur Unitholders—YouOur unitholders are required to pay taxes on yourtheir share of our income even if youthey do not receive any cash distributions from us. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities."
The agreements governing our indebtedness and preferred units restrict our ability to raise, and in some cases continue to pay, distributions on our common units. Opco’s revolving credit agreement, the indenture governing our 20222025 Senior Notes and our partnership agreement each require that we meet certain consolidated leverage tests in order to raise our quarterly distribution on the common units above the current level of $0.45 per quarter. The maximum leverage covenant under Opco’s revolving credit facility will step down permanently from 4.0x to 3.0x if we increase the common unit distribution above the current level.level of $0.45 per common unit per quarter. In addition, under our partnership agreement, to the extent we have paid any distributions on the preferred units in kind ("PIK units"), and such PIK units are still outstanding at any time after January 1, 2022, we will be prohibited from making any distributions with respect to our common units until we have redeemed all such PIK units in cash. For more information on restrictions on our ability to make distributions on our common units, see "Management’s"Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—2017 Recapitalization Transactions"Resources" and "Item"Item 8. Financial Statements and Supplementary Data—Note 11.12. Debt, and Debt—Affiliate.Net."
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.
As of December 31, 2016,2019, we and our subsidiaries had approximately $1.1 billion of total indebtedness. Following the execution of our recapitalization transactions, we and our subsidiaries had approximately $944$524.1 million of total indebtedness. The terms and conditions governing our indebtedness, including the indenturesindenture for NRP’s 2018 Notes and 20222025 Senior Notes and Opco’s revolving credit facility and senior notes:
require us to meet certain leverage and interest coverage ratios;
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industries in which we operate;
increase our vulnerability to economic downturns and adverse developments in our business;
limit our ability to access the bank and capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness;
make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may default on our debt obligations; and
limit management’s discretion in operating our business.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations, including payment of distributions on the preferred units. If we do not have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money, or sell assets or raise equity at unattractive prices.prices, including higher interest rates. We are required to make substantial principal repayments each year in connection with Opco’s senior notes, with approximately $81$46 million due thereunder each year through 2018. Whileduring 2020. To the extent we intendborrow to make some of these payments, using cash from operations, we may not be able to refinance these amounts on terms acceptable to us, if at all. We may not be able to refinance our debt, sell assets, borrow more money or access the bank and capital markets on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive covenants in our debt agreements will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.
Foresight EnergyIn July 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. Opco’s revolving credit facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which provide that we will adopt a replacement rate that is broadly accepted by the syndicated loan market. We currently do not expect the transition from LIBOR to have a material impact on us. However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty establishing a replacement rate under Opco’s revolving credit facility. In the event that we do not determine a replacement rate for LIBOR, in certain circumstances, Eurodollar Loans under Opco’s revolving credit facility may be suspended and converted to ABR Loans, which could bear higher interest rates. If we are unable to negotiate replacement rates on favorable terms, it could adversely affect our largest lessee, and ongoing disputes with them could have an adverse effect on ourbusiness, financial condition and results of operations. In addition, ifFor a description of the Deer Run mine remains idled for an extended period or does not resume operations, our financial conditioninterest rate on borrowings under Opco’s revolving credit facility, see “Item 8. Financial Statements and results of operations could be adversely affected.Supplementary Data—Note 12. Debt, Net.”
Foresight Energy isPrices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our largest lessee, andcontrol. Declines in 2016, we derived approximately 16% of our revenues from them. We are currently in disputes with them with respect to two of their four mining operations in which we have an interest. Foresight Energy’s Deer Run mine (which we also refer to as our Hillsboro property) has been idled for almost two years as a result of elevated carbon monoxide levels at the mine. Foresight Energy has declared a force majeure event at the Deer Run mine and failed to make $46.0 million in required minimum deficiency payments to us as of the date hereof. Such amount is expected to increase by $7.5 million for each quarter during which mining operations continue to be idled. We have filed a lawsuit against Foresight Energy and Hillsboro Energy to recover the amounts owed to us and compel them to make the required minimum deficiency payments under the lease. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected. In addition, we have also filed a lawsuit against Foresight Energy’s Macoupin subsidiary, which has failed to comply with the terms of the coal mining, rail loadout and rail loop leases at the Macoupin mine by incorrectly recouping previously paid minimum royalties, resulting in a cumulative $6.2 million negative cash impact to us. See "Item 3. Legal Proceedings" included elsewhere in this Annual Report on Form 10-K for more information on our lawsuits against Foresight Energy. These ongoing disputes and further deterioration of our relationship with our largest lesseeprices could have a material adverse effect on our financial conditionbusiness and results of operations.
Depressed coalCoal prices have negatively affected our coal-related revenues and the value of our coal reserves. Further declines or a continued low price environment could have an additional adverse effect on our coal-related revenues and the value of our coal reserves.
Prices for both steam and metallurgical coal have declined substantially in recent years. Steam coal prices remain at levels close to or below the level of operating costs for a number of our lessees. While metallurgical coal prices have improved in recent months, we do not expect the current pricing environmentcontinue to be sustained,volatile and prices could decline substantially.substantially from current levels. Production by some of our lessees may not be economic if prices decline further or remain at current levels. The prices our lessees receive for their coal depend upon factors beyond their or our control, including:
the supply of and demand for domestic and foreign coal;
domestic and foreign governmental regulations and taxes;
changes in fuel consumption patterns of electric power generators;
the price and availability of alternative fuels, especially natural gas;
global economic conditions, including the strength of the U.S. dollar relative to other currenciescurrencies;
global and thedomestic demand for steel;
tariff rates on imports and trade disputes, particularly involving the United States and China;
the availability of, proximity to and capacity of transportation networks and facilities;
global or national health concerns, including the outbreak of pandemic or contagious disease, such as the recent coronavirus;
weather conditions; and
the effect of worldwide energy conservation measures.
Natural gas is the primary fuel that competes with steamthermal coal for power generation, and renewable energy sources continue to gain market share in power generation. Relatively lowThe abundance and ready availability of cheap natural gas, prices have resulted intogether with increased governmental regulations on the power generation industry has caused a number of utilities switchingto switch from steamthermal coal to natural gas to the extent that it is practical to do so.and/or close coal-powered generation plants. This switching has resulted in a decline in steamthermal coal prices, and to the extent that natural gas prices remain low, steamthermal coal prices will also remain low. The closure of coal-fired power plants as a result ofReduced international demand for export thermal coal and increased governmental regulations or the inability to comply with such regulationscompetition from global producers has also resulted in a decrease in the demand for steam coal.put downward pressure on thermal coal prices.
Prices for metallurgical coal reached multi-year lows during 2016 due to global economic conditions. While metallurgical coal prices have improved in recent months, we do not expect the current pricing environment to be sustained. Our lessees produce a significant amount of the metallurgical coal that is used in both the U.S.for steel production domestically and foreign steel industries.internationally. Since the amount of steel that is produced is tied to global economic conditions, a continuation of current conditions or a further declinedeclines in those conditions could result in the decline of steel, coke and metallurgical coal production. In addition, rising exports of metallurgical coal from Australia and a strong U.S. dollar continue to have a negative effect on prices received for metallurgical coal produced in the United States. Since metallurgical coal is priced higher than steamthermal coal, some mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If these mines are unable to sell metallurgical coal, they may not be economically viable and may be temporarily idled or closed. In addition, during 2015Any potential future lessee bankruptcy filings could create additional uncertainty as to the future of operations on our properties and 2016,could have a material adverse effect on our business and results of operations.
To the extent our lessees are unable to economically produce coal over the long term, the carrying value of our reserves could be adversely affected. A long-term asset generally is deemed impaired when the future expected cash flow from its use and disposition is less than its book value. For the fourth quarter of 2019, we recorded an impairment charge of approximately $148 million related to properties that we believe our current or future lessees are unable to operate profitably. Future impairment analyses could result in additional downward adjustments to the carrying value of our assets.
We derive a large percentage of our revenues and other income from a small number of coal lessees.
Challenges in the coal mining industry have led to significant consolidation activity. We own significant interests in all four of Foresight Energy’s mining operations, which accounted for approximately 23% of our total revenues in 2019. We also own significant interests in several of Contura Energy's mining operations, which accounted for approximately 16% of our total revenues in 2019. Certain other lessees have made acquisitions over the past few years resulting in their having an increased interest in our coal reserves. Any interruption in these lessees’ ability to make royalty payments to us could have a disproportionate material adverse effect on our business and results of operations.
Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect on our business and results of operations.
The current coal price environment, together with high operating costs and limited access to capital, has caused a number of coal producers filedto file for protection under U.S. bankruptcy laws, including severaland/or idle or close mines that they cannot operate profitably. To the extent our leases are accepted or assigned in a bankruptcy process, pre-petition amounts are required to be cured in full, but we may ultimately make concessions in the financial terms of those leases in order for the reorganized company or new lessor to operate profitably going forward. To the extent our leases are rejected, operations on those leases will cease, and we will be unlikely to recover the full amount of our coal lessees. Although many of our lessees have emerged from bankruptcies, morerejection damages claims. More of our lessees may file for bankruptcy in the future, which will create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our business and results of operations.
Lower prices reduce the quantity of coal that may be economically produced from Foresight Energy, which is our properties,largest lessee, is currently working with its lenders and contract counterparties to evaluate restructuring options, which in turn reduces our coal-related revenues and the value of our coal reserves. Further declines or a continued low price environment could have an additional adverse effect on our coal-related revenues or the value of our reserves. A long term asset generally is deemed impaired when the future expected cash flow from its use and disposition is less than its book value. Future impairment analyses could result in additional downward adjustmentsthe idling or closure of one or more of its mines or changes in lease terms. To the extent Foresight determines to idle operations on our properties for a prolonged period or to shut any of its mines on our properties down permanently, or to the carrying valueextent we agree to amend the terms of our assets.
leases with them to facilitate their continued operations on our properties, our business and results of operations could be adversely affected.
Mining operations are subject to operating risks that could result in lower revenues to us.
Our revenues are largely dependent on the level of production of minerals from our properties, and any interruptions to or increases in costs of the production from our properties wouldmay reduce our revenues. The level of production isand costs thereof are subject to operating conditions or events beyond our or our lessees’ control including:
the inability to acquiredifficulties or delays in acquiring necessary permits or mining or surface rights;
reclamation costs and bonding costs;
changes or variations in geologic conditions, such as the thickness of the mineral deposits and in the case of coal, the amount of rock embedded in or overlying the coalmineral deposit;
mining and processing equipment failures and unexpected maintenance problems;
the availability of equipment or parts and increased costs related thereto;
the availability of transportation networks and facilities and interruptions due to transportation delays;
adverse weather and natural disasters, such as heavy rains and flooding;
labor-related interruptions;interruptions and trained personnel shortages; and
unexpected mine safety incidents or accidents, including hazardous conditions, roof falls, fires and explosions.
Under the current regulatory environment,While our lessees maintain insurance coverage, there is substantial uncertainty relating tono assurance that insurance will be available or cover the abilitycosts of these risks. Many of our lessees are experiencing rising costs related to regulatory compliance, insurance coverage, permitting and bonding, transportation, and labor. Increased costs result in decreased profitability for our lessees and reduce the competitiveness of coal lessees to be issued permits necessary to conduct mining operations. The non-issuance of permits has limited the ability of our coal lessees to open new operations, expand existing operations, and may preclude new acquisitions in whichas a fuel source. In addition, we might otherwise be involved. We and our lessees may also incur costs and liabilities resulting from third-party claims for damages to property or injury to persons arising from our or their operations. If we or our lessees are pursued for these sanctions, costs and liabilities, mining operations and, as a result, our revenues could be adversely affected.
VantaCore currently operates four hard rock quarries, one underground limestone mine, six sand and gravel plants, two asphalt plants and two marine terminals. As an operatorThe occurrence of any of these assets, we are exposed to risks that we have not historically been exposed to in our mineral rights and royalties business. Such risks include, but are not limited to, prices and demand for construction aggregates, capital and operating expenses necessary to maintain VantaCore’s operations, production levels, general economicevents or conditions conditions in the local markets that VantaCore serves, inclement or hazardous weather conditions and typically lower production levels in the winter months, permitting risk, fire, explosions or other accidents, and unanticipated geologic conditions. Any of these risks could result in damage to, or destruction of, VantaCore’s mining properties or production facilities, personal injury, environmental damage, delays in mining or processing, reduced revenue or losses or possible legal liability. In addition, not all of these risks are reasonably insurable, and our insurance coverage contains limits, deductibles, exclusions and endorsements. Our insurance coverage may not be sufficient to meet our needs in the event of loss. Any prolonged downtime or shutdowns at VantaCore’s mining properties or production facilities or material loss could have ana material adverse effect on our business and results of operations.
ChangesThe adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changes in fuel consumption patterns by electric power generators resulting inand a corresponding decrease in the use of coal have resulted in and will continue to result in lower coal production by our lessees and reduced coal-related revenues.
Enactment of laws and passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, have resulted in and could continue to result in electricity generators switching from coal to other fuel sources and in coal-fueled power plant closures. Further, regulations regarding new coal-fueled power plants could adversely impact the global demand for coal. The potential financial impact on us of existing and future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants and environmental and other governmental regulations. We expect that substantially all newly constructed power plants in the United States will be fired by natural gas because of lower construction and compliance costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of rules and regulations promulgated under the federal Clean Air Act have resulted in more electric power generators shifting from coal to natural-gas-fired power plants, or to other alternative energy sources such as solar and wind. In addition, the proposed rules promulgated by the EPA on greenhouse gas emissions from new and existing power plants are expected to further limit the construction of new coal-fired generation plants in favor of alternative sources of energy and negatively affect the viability of coal-fired power generation. These changes have resulted in reduced coal consumption and the production of coal from our properties and are expected to continue to have an adverse effect on our coal-related revenues.
The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" and other hazardous air pollutants have resulted in and will continue to result in reduced demand for our coal, oil and natural gas.
In December 2009, EPA determined that emissions of carbon dioxide, methane, and other GHGs, present an endangerment to public health and welfare because emissions of such gases are, according to EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on its findings, EPA has begun adopting and implementing regulations to restrict emissions of GHGs under various provisions of the Clean Air Act.
In August 2015, EPA published its final Clean Power Plan Rule, a multi-factor plan designed to cut carbon pollution from existing power plants, including coal-fired power plants. The rule requires improving the heat rate of existing coal-fired power plants and substituting lower carbon-emission sources like natural gas and renewables in place of coal. The rule will force many existing coal-fired power plants to incur substantial costs in order to comply or alternatively result in the closure of some of these plants. This rule is being challenged by industry participants and other parties. In February, 2016, the Supreme Court of the United States stayed the Clean Power Plan Rule pending a decision by the District of Columbia Circuit as well as any subsequent review by the Supreme Court.
In October 2015, EPA published its final rule on performance standards for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The final rule requires new steam generating units to use highly efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture and storage technology. The final emission standard is less stringent than EPA had originally proposed due to updated cost assumptions, but could still have a material adverse effect on new coal-fired power plants. The final rule has been challenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit, but is not subject to a stay. Oral arguments are currently scheduled for April 2017.
In addition to EPA’s GHGgreenhouse gas initiatives, there are several other federal rulemakings that are focused on emissions from coal-fired electric generating facilities, including the Cross-State Air Pollution Rule (CSAPR), regulating emissions of nitrogen oxide and sulfur dioxide, and the Mercury and Air Toxics Rule (MATS), regulating emissions of hazardous air pollutants. Installation of additional emissions control technologies and other measures required under these and other EPA regulations have made it more costly to operate many coal-fired power plants and have resulted in and are expected to continue to result in plant closures. Further
Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending and investment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels.
Global climate issues continue to attract public and scientific attention. Numerous reports have engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In addition to government regulation of greenhouse gas and other air pollutant emissions, there have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels, such as coal. The impact of such efforts may adversely affect our ability to raise capital. In addition, a number of insurance companies have taken action to limit coverage for companies in the coal industry, which could result in significant increases in our costs of insurance or in our inability to maintain insurance coverage at current levels.
In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state and local laws and regulations that may limit production from our properties and our profitability.
The operations of our lessees VantaCore and Ciner Wyoming are subject to stringent health and safety standards under increasingly strict federal, state and local environmental, health and safety laws, including mine safety regulations and governmental enforcement policies. The oil and gas industry is also subject to numerous laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our properties.
New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements, could further regulate or tax the mining and oil and gas industries and may also require significant changes to operations, the incurrence of increased costs or the requirement to obtain new or different permits, any of which could decrease our revenues and have a material adverse effect on our financial condition or results of operations. Under SMCRA, our coal lessees have substantial reclamation obligations on properties where mining operations have been completed and are required to post performance bonds for their reclamation obligations. To the extent an operator is unable to satisfy its reclamation obligations or the performance bonds posted are not sufficient to cover those obligations, regulatory authorities or citizens groups could attempt to shift reclamation liability onto the ultimate landowner, which if successful, could have a material adverse effect on our financial condition.
In addition to governmental regulation, private citizens’ groups have continued to be active in bringing lawsuits against coal mine operators and landowners. Since 2012, several citizen suit group lawsuits have been filed against mine operators and landowners for allegedland owners that allege violations of water quality standards resulting from ongoing discharges of pollutants from reclaimed mining operations, including selenium and conductivity. NRP has been named as a defendant in one of these lawsuits. The citizen suit groups have sought penalties as well as injunctive relief that would limit future discharges of these pollutants, which would result in significant expenses for our lessees. While it is too early to determine the merits or measure the impact of these lawsuits, anyAny determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations and could result in substantial compliance costs or fines.
Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on our results of operations.
The market price of soda ash directly affects the profitability of Ciner Wyoming’s soda ash production operations. If the market price for soda ash declines, Ciner Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile, and those markets are likely to remain volatile in the future. The prices Ciner Wyoming receives for its soda ash depend on numerous factors beyond Ciner Wyoming’s control, including worldwide and regional economic and political conditions impacting supply and demand. Glass manufacturers and other industrial customers drive most of the demand for soda ash, and these customers experience significant fluctuations in demand and production costs. Competition from increased use of glass substitutes, such as plastic and recycled glass, has had a negative effect on demand for soda ash. Substantial or extended declines in prices for soda ash could have a material adverse effect on our results of operations. In addition, Ciner Wyoming relies on natural gas as the main energy source in its soda ash production process. Accordingly, high natural gas prices increase Ciner Wyoming’s cost of production and affect its competitive cost position when compared to other foreign and domestic soda ash producers.
VantaCore operates in a highly competitive and fragmented industry, which may negatively impact prices, volumes and costs. In addition, both commercial and residential construction are dependent upon the overall U.S. economy.
The construction aggregates industry is highly fragmented with a large number of independent local producers operating in VantaCore’s local markets. Additionally, VantaCore also competes against large private and public companies, some of which are significantly vertically integrated. Therefore, there is intense competition in a number of markets in which VantaCore operates. This significant competition could lead to lower prices and lower sales volumes in some markets, negatively affecting our earnings and cash flows.
In addition, commercial and residential construction levels generally move with economic cycles. When the economy is strong, construction levels rise and when the economy is weak, construction levels fall. The U.S. economy is recovering from the 2008-2009 recession, but the pace of recovery is slow. Since construction activity generally lags the recovery after down cycles, construction projects have not returned to their pre-recession levels.
If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.
We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:
the payment of minimum royalties;
marketing of the minerals mined;
mine plans, including the amount to be mined and the method and timing of mining;mining activities;
processing and blending minerals;
expansion plans and capital expenditures;
credit risk of their customers;
permitting;
insurance and surety bonding;
acquisition of surface rights and other mineral estates;
employee wages;
transportation arrangements;
compliance with applicable laws, including environmental laws; and
mine closure and reclamation.
A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell minerals at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for small or isolated mineral reserves.
We have limited control over the activities on our properties that we do not operate and are exposed to operating risks that we do not experience in the royalty business.business through our soda ash joint venture and through our ownership of certain coal transportation assets.
We do not have control over the operations of Ciner Wyoming. We have limited approval rights with respect to Ciner Wyoming, and our partner controls most business decisions, including decisions with respect to distributions and capital expenditures. Adverse developments in Ciner Wyoming’s business, including increased maintenance and expansion capital expenditures that we may be required to fund, would result in decreased distributions to NRP. In addition, we are ultimately responsible for operating the transportation infrastructure at Foresight’sForesight Energy’s Williamson mine, and have assumed the capital and operating risks associated with that business. As a result of these investments, we could experience increased costs as well as increased liability exposure associated with operating these facilities.
A significant portion of Ciner Wyoming’s historical international sales of soda ash have been to ANSAC, and the termination of the ANSAC membership could adversely affect Ciner Wyoming’s ability to compete in certain international markets and increase Ciner Wyoming’s international sales costs.
ANSAC has historically been Ciner Wyoming’s largest customer for the years ended December 31, 2019, 2018 and 2017, accounting for 60%, 52% and 45%, respectively, of its net sales. Following termination of the membership in ANSAC, which will be effective December 31, 2021, there is no assurance that Ciner Wyoming will be able to retain existing foreign customers or secure new foreign customers or the related logistics arrangements on favorable terms. The costs to transport and market soda ash following the ANSAC exit could be higher than costs associated with sales through ANSAC. In addition, Ciner Wyoming will need access to an international logistic infrastructure that includes, among other things, a domestic port for export capabilities. These export capabilities are currently being developed by Ciner Group, and options being evaluated range from continued outsourcing in the near term to developing Ciner Group’s own port capabilities in the longer term. There can be no assurance that sufficient export capacity will be obtained. In addition, the costs associated with a domestic export terminal could be higher than expected. Adverse developments in Ciner Wyoming’s ability to export soda ash and sell into the foreign markets currently served by ANSAC could result in lower cash distributions to us from Ciner Wyoming.
Significant delays and/or higher than expected costs associated with Ciner Wyoming’s capacity expansion project could adversely affect Ciner Wyoming’s profitability and ability to make distributions to us.
Ciner Wyoming has announced a significant capacity expansion capital project intended to increase production levels to up to 3.5 million tons of soda ash per year. This project will require capital expenditures materially higher than have been incurred by Ciner Wyoming over the past few years, and Ciner Wyoming intends to fund the project in part by reinvesting cash that would otherwise be distributed to its partners. In the third quarter of 2019, Ciner Wyoming significantly reduced its cash distributions to its partners, and we expect cash distributions to remain at the current lower level until the project is funded. However, the costs of the expansion project could be higher than expected, or the execution of the project could be substantially delayed, which could materially impact Ciner Wyoming’s profitability and result in a further reduction of cash distributions to us. In addition, Ciner Wyoming's deca stockpiles will be substantially depleted by 2023. Without adding capacity through the expansion project, Ciner Wyoming's production rates would decline approximately 200,000 short tons, which would further impact Ciner Wyoming's profitability.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal, soda ash construction aggregates, and other minerals from our properties.
Transportation costs represent a significant portion of the total delivered cost for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make minerals produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from producers in other parts of the country.
Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks andand/or other events could temporarily impair the ability of our lessees to supply mineralscoal to their customers.customers and/or increase their costs. Many of our lessees are currently experiencing transportation-related issues due in particular to decreased availability and reliability of rail services and port congestion. Our lessees’ transportation providers may
face difficulties in the future that maywould impair the ability of our lessees to supply minerals to their customers, resulting in decreased royalty revenues to us.
In addition, Ciner Wyoming transports its soda ash by rail or truck and ocean vessel. As a result, its business and financial results are sensitive to increases in rail freight, trucking and ocean vessel rates. Increases in transportation costs, including increases resulting from emission control requirements, port taxes and fluctuations in the price of fuel, could make soda ash a less competitive product for glass manufacturers when compared to glass substitutes or recycled glass, or could make Ciner Wyoming’s soda ash less competitive than soda ash produced by competitors that have other means of transportation or are located closer to their customers. Ciner Wyoming may be unable to pass on its freight and other transportation costs in full because market prices for soda ash are generally determined by supply and demand forces. In addition, rail operations are subject to various risks that may result in a delay or lack of service at Ciner Wyoming’s facility, and alternative methods of transportation are impracticable or cost-prohibitive. During 2016,cost prohibitive. For the year ended December 31, 2019, Ciner Wyoming shipped substantially allapproximately 96.9% of its soda ash viafrom the Green River facility on a single rail line owned and controlled by Union Pacific. Ciner Wyoming’s current transportation contract with Union Pacific rail line.expires on December 31, 2021. There can be no assurance that this contract will be renewed on terms favorable to Ciner Wyoming relies on the rail line to service its facilities under a contract that expires in 2017.or at all. Any substantial interruption in or increased costs related to the transportation of Ciner Wyoming’s soda ash or the failure to renew the rail contract on favorable terms could have a material adverse effect on our financial condition and results of operations.
Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves. In addition, compliance with new SEC rules that will become effective beginning in 2021 could result in material adjustments to the quantities of reserves we are allowed to report.
Coal, aggregates and industrial minerals reserve engineering requires subjective estimates of underground accumulations of coal, aggregates and industrial minerals, and assumptions and are by nature imprecise. Our reserve estimates may vary substantially from the actual amounts of coal, aggregates and industrial minerals recovered from our reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:
future prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs;
production levels;
future technology improvements;
the effects of regulation by governmental agencies; and
geologic and mining conditions, which may not be fully identified by available exploration data.
Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. As a result, youundue reliance should not place undue reliancebe placed on our reserve data that is included in this report.
In addition, the SEC has adopted new rules to modernize the property disclosure requirements for registrants with significant mining activities, which we will be required to begin to comply with for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ending December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures. The new rules require that reserve estimates that are reported be based on technical reports prepared using extensive mine-specific geological and engineering data, as well as market and cost assumptions. As a royalty company, we lease coal reserves to third-party operators that have sole control of the mining and selling of coal from our properties. We may not have access to much of the information that is required to prepare the technical reports used to determine reserves under the new rules without unreasonable burden or expense. Accordingly, the amount of coal and other minerals that we are allowed to report under the new rules beginning with the year ending December 31, 2021 may differ materially from what we are currently reporting.
Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.
Mineral supply contracts generally do not require operators to satisfy their obligations to their customers with resources mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with minerals mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. In addition, lessees move on and off of our properties over the course of any given year in accordance with their mine plans. If a lessee satisfies its obligations to its customers with minerals from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues.
A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.
We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.
Our business is subject to cybersecurity risks.
Our business is increasingly dependent on information technologies and services. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Although we utilize various procedures and controls to mitigate our exposure to such risks, cybersecurity attacks and other cyber events are evolving, unpredictable, and sometimes difficult to detect, and could lead to unauthorized access to sensitive information or render data or systems unusable.
We do not presently maintain insurance coverage to protect against cybersecurity risks. If we procure such coverage in the future, we cannot ensure that it will be sufficient to cover any particular losses we may experience as a result of such cyber attacks. Any cyber incident could have a material adverse effect on our business, financial condition and results of operations.
Risks Related to Our Structure
Unitholders may not be able to remove our general partner even if they wish to do so.
Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding common units (including common units held by our general partner and its affiliates)affiliates and including common units deemed to be held by the holders of the preferred units who vote along with the common unitholders on an as-converted basis). Because the owners of our general partner, along with directors and executive officers and their affiliates, own a significant percentage of our outstanding common units,substantial ownership in us, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates.affiliates and the holders of the preferred units.
In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwise change our management:
generally, if a person (other than the holders of preferred units) acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and
our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of management.
As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future, which could result in substantial dilution of our common unitholders’ ownership interests.
The preferred units are a new class of partnership interests that rank senior to our common units with respect to distribution rights and rights upon liquidation. We are required to pay quarterly distributions on the preferred units (plus any PIK Unitsunits issued in lieu of preferred units) in an amount equal to 12.0% per year prior to paying any distributions on our common units. The preferred units also rank senior to the common units in right of liquidation and will be entitled to receive a liquidation preference in any such case.
The preferred units may also be converted into common units under certain circumstances. The number of common units issued in any conversion will be based on the then-current trading price of the common units at the time of conversion. Accordingly, the lower the trading price of our common units at the time of conversion, the greater the number of common units that will be issued upon conversion of the preferred units, which would result in greater dilution to our existing common unitholders. Dilution has the following effects on our common unitholders:
an existing unitholder’s proportionate ownership interest in NRP will decrease;
the amount of cash available for distribution on each unit may decrease; and
the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline.
In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the preferred will have the right to remove our general partner.
We may issue additional common units or preferred units without common unitholder approval, which would dilute a unitholder’s existing ownership interests.
Our general partner may cause us to issue an unlimited number of common units, without common unitholder approval (subject to applicable New York Stock Exchange (NYSE) rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units (including additional preferred units) without common unitholder approval (subject to applicable NYSE rules). In addition, we may issue additional common units upon the exercise of the outstanding warrants held by Blackstone and Goldentree. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
an existing unitholder’s proportionate ownership interest in NRP will decrease;
the amount of cash available for distribution on each unit may decrease; and
the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline.
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.
Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.
Prior to making any distribution on the common units, we reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Conflicts of interest could arise among our general partner and us or the unitholders.
These conflicts may include the following:
Excluding our VantaCore business, weWe do not have any employees and we rely solely on employees of affiliates of the general partner;
under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;
the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly distributions to unitholders;
the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability;
under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arm’s-length negotiations; and
the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights to one of its affiliates or to us.
In addition, as a result of the purchase of the Preferred Units, Blackstone has certain consent rights and board appointment and observation rights. GoldenTree also has more limited consent rights. In the exercise of their applicable consent rights and/or board rights, conflicts of interest could arise between us and our general partner on the one hand, and Blackstone or GoldenTree on the other hand.
The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors and officers with its own choices and to control their decisions and actions.
In addition, a change of control would constitute an event of default under our debt agreements. During the continuance of an event of default under our debt agreements, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us and/or declare all amounts payable by us immediately due and payable. In addition, upon a change of control, the holders of the preferred units would have the right to require us to redeem the preferred units at the liquidation preference or convert all of their preferred units into common units. A change of control also may trigger payment obligations under various compensation arrangements with our officers.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Tax Risks to CommonOur Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to youunitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based on our current operations and current Treasury regulations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement 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 federal income tax on our taxable income at the corporate tax rate and would likely be liable for state income tax at varying rates. Distributions to youour unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you.our unitholders. Because tax would be imposed upon us as a corporation, our cash available for distribution to youour unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of a similar tax on us in a jurisdiction in which we operate or in other jurisdictions to which we may expand could substantially reduce the cash available for distribution to you.
our unitholders.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although thereAny modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. For example, the “Clean Energy for America Act,” which is no current legislative proposal, a prior legislativesimilar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, have eliminatedamong other things, repeal the qualifying income exception towithin Section 7704(d)(1)(E) of the treatment of all publicly traded partnerships as corporationsCode upon which we rely for our treatmentstatus as a partnership for U.S. federal income tax purposes.
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the "Final Regulations") were publishedTreasury Department has issued, and in the Federal Register. The Final Regulations are effective asfuture may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We anticipate that we will continue to meet the qualifying income exception forrules in a manner that could impact our ability to qualify as a publicly traded partnership underin the Final Regulations.future.
However,Furthermore, any interpretation of or modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units.
You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our units.
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.
Changes to U.S. federal income tax laws have been proposed in a prior session of Congress that would eliminate certain key U.S. federal income tax preferences relating to coal exploration and development. These changes include, but are not limited to (i) repealing capital gains treatment of coal and lignite royalties, (ii) eliminating current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, and (iii) repealing the percentage depletion allowance with respect to coal properties, and (iv) excluding from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof.properties. If enacted, these changes would limit or eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units. We are not aware of any current proposals with regard to these changes.
YouOur unitholders are required to pay taxes on yourtheir share of our income even if youthey do not receive any cash distributions from us. YourOur unitholders' share of our portfolio income may be taxable to youthem even though youthey receive other losses from our activities.
Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, youour unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on yourtheir share of our taxable income even if youthey receive no cash distributions from us. YouOur unitholders may not receive cash distributions from us equal to yourtheir share of our taxable income or even equal to the actual tax due from youthem with respect to that income.
For our unitholders subject to the passive loss rules, our current operations include portfolio activities (such as our coal and mineral royalties business)royalty businesses) and passive activities (such as our soda ash and aggregates businesses)business). Any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset (i) our portfolio income, including income related to our coal and mineral royalties business,royalty businesses, (ii) a unitholder’s income from other passive activities or investments, including investments in other publicly traded partnerships, or (iii) a unitholder’s salary or active business income. Thus, yourour unitholders' share of our portfolio income may be subject to federal income tax, regardless of other losses youthey may receive from us.
We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including income and gain from the sale of properties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions made with respect to yourtheir units.
In response to current market conditions, weWe may engage in transactions to reduce our leverage and manage our liquidity that would result in income and gain to our unitholders without a corresponding cash distribution. For example, we may sell assets and use the proceeds to repay existing debt, in which case, youour unitholders could be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt that would result in "cancellation“cancellation of indebtedness income"income” (also referred to as "COD income"“COD income”) being allocated to our unitholders as ordinary taxable income. UnitholdersOur unitholders may be allocated income and gain from these transactions, and income tax liabilities arising therefrom may exceed any distributions we make to you.our unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder's individual tax position, including, for example, the availability of any suspended passive losses that may offset some portion of the allocable income. UnitholdersOur unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against
any capital losses attributable to the unitholder’s ultimate disposition of its units. UnitholdersOur unitholders are encouraged to consult their tax advisors with respect to the consequences to them.
them
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
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.
reduced .
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 newthese 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 Schedule K-1information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) 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. 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 common units could be more or less than expected.
If youour unitholders sell yourtheir common units, youthey will recognize a gain or loss equal to the difference between the amount realized and yourtheir tax basis in those common units. Because distributionsDistributions in excess of youra common unitholder's allocable share of our net taxable income result in a decrease in yourthe tax basis in yoursuch unitholder's common units,units. Accordingly, the amount, if any, of such prior excess distributions with respect to the common units you sellsold will, in effect, become taxable income to youour common unitholders if youthey sell such common units at a price greater than yourtheir tax basis in those common units, even if the price youthey receive is less than yourtheir original cost. Furthermore,In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. In addition, becauseThus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized includeson a sale of such units is less than such unitholder’s shareadjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Our 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 nonrecourse liabilities, if you sell your common units, you may incur a tax liabilitybusiness 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 excessthe case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the amountextent such depreciation, amortization, or depletion is not capitalized into cost of cash you receive from the sale.goods sold with respect to 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 common units that may result in adverse tax consequences to them.
InvestmentsInvestment in commonour units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raise raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/Further, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) 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). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to non-U.S. personsa Non-U.S. unitholder will be reduced bysubject to withholding taxes imposed at the highest applicable effective tax rate applicableand a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to non-U.S. persons, and non-U.S. persons will be required to file U.S. federal income tax returnson the gain realized from the sale or disposition of that unit.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and pay tax on theirwe are required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld. Because the “amount realized” includes a partner’s share of our taxable income.the partnership’s liabilities, 10% of the amount realized could exceed the total cash purchase price for the units. However, pending the issuance of final regulations, the IRS has suspended the application of this withholding rule to transfers of publicly traded interests in publicly traded partnerships. If yourecently promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded interests in publicly traded partnerships effected through a tax-exempt entity orbroker, that the obligation to withhold is imposed on the transferor’s broker and that a non-U.S. person, you should consult your tax advisor before investingpartner’s “amount realized” does not include a partner’s share of a publicly traded partnership’s liabilities for purposes of determining the amount subject to withholding. However, it is not clear when such regulations will be finalized and if they will be finalized in our common units.
their current form.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you.our unitholders. It also could affect the timing of these tax benefits or the amount of gain from yourthe sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to yourour unitholders' tax returns.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our
common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular 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 generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned common units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. UnitholdersOur unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their common units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of us as a partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. The partnership technically terminated on August 31, 2016, as a result of the sale or exchange of 50% or more of our capital and profits interest during the prior twelve
month period. Any technical termination, such as the one occurring in 2016, would, among other things, result in the closing of our taxable year for all unitholders, which would result in our filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing taxable income for the applicable year. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
As a result of investing in our common units, youour unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
In addition to U.S. federal income taxes, youour unitholders are likely 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 own property now or in the future, even if youour unitholders do not live in any of those jurisdictions. YouOur unitholders are likely 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, youour unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in a number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is yourthe unitholder's responsibility to file all U.S. federal, state and local tax returns.
returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, we believemanagement believes these claimsordinary course matters will not have a material effect on our financial position, liquidity or operations. During 2019, we were also involved in the legal proceeding described below.
In January 2013, we acquired a non-controlling 48.51% general partner interest in OCI Wyoming, L.P. ("OCI LP") and all of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko"). The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical Corporation.
The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by us if certain performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015. For those years, we paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment obligations.
In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, we exchanged the stock of OCI Co for a limited partner interest in OCI LP. Following the reorganization, our interest in OCI LP remained at 49%, consisting of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues, management or control of OCI LP.
In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC in the District Court of Harris County, Texas, 157th Judicial District. The complaint alleged that the transactions conducted in 2013 triggered an acceleration of NRP's obligation under the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of such amount, together with interest, court costs and attorneys’ fees.
In November 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"),2019, the trial court ruled in our favor in all respects, including that the Circuit Courtinternal restructuring that occurred did not trigger an acceleration of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late March 2015, elevated carbon monoxide readings were detected atcontingent purchase price payment obligation under the Deer Run mine,purchase agreement with Anadarko. Accordingly, the trial court ordered that Anadarko take nothing. Anadarko did not appeal the trial court's ruling, and coal production at the mine was idled. In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. We believe the force majeure claim by Hillsboro hasthis case is concluded with no merit and we are vigorously pursuing recovery against them. However, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligationliability to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with respect to the second, third and fourth quarters of 2015 and each quarter of 2016 resulted in a cumulative $46.0 million negative cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected.
In April 2016, we filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its recoupable balance and failure to make payments in accordance with these lease agreements has resulted in a cumulative $6.2 million negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount has been recorded.
For more information regarding certain other legal proceedings involving NRP, see "Note 14. Commitments and Contingencies" included in the Notes to Consolidated Financial Statements in "Item 8. Financial Statements and Supplementary Data" included elsewhere in this Annual Report on Form 10-K.
ITEM 4. MINE SAFETY DISCLOSURES
The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95.1 to this Annual Report on Form 10-K.None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NRP Common Units and Cash Distributions
Our common units are listed and traded on the NYSE under the symbol "NRP"."NRP." As of February 1, 201710, 2020, there were approximately 26,50013,180 beneficial and registered holders of our common units. The computation of the approximate number of unitholders is based upon a broker survey.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forthshows the high and low sales prices per common unit, as reported on the NYSE Composite Transaction Tape from January 1, 2015 tosecurities authorized for issuance under our 2017 Long-Term Incentive Plan at December 31, 2016, and2019. The initial number of common units authorized for issuance pursuant to awards under the quarterly cash distribution declared and paid with respect to each quarter per common unit. The information presented in the tables below has been adjusted to give retroactive effect to the one-for-ten reverse unit split thatplan was effective on February 17, 2016.800,000.
|
| | | | | | | | | |
| | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted-average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for issuance under equity compensation plans (excluding securities reflected in column (a)) |
| Plan Category | | (a) | | (b) | | (c) |
| Equity compensation plans approved by security holders | | — |
| | — |
| | 613,018 (1) |
|
| Equity compensation plans not approved by security holders | | n/a |
| | n/a |
| | n/a |
|
| Total | | — |
| | — |
| | 613,018 |
|
|
| | | | | | | | | | | | | | | |
| | Price Range | | Cash Distribution History |
| | High | | Low | | Per Unit | | Record Date | | Payment Date |
| 2015 | | | | | | | | | |
| First Quarter | $ | 98.10 |
| | $ | 63.80 |
| | $ | 0.90 |
| | 5/5/2015 | | 5/14/2015 |
| Second Quarter | $ | 74.50 |
| | $ | 36.10 |
| | $ | 0.90 |
| | 8/5/2015 | | 8/14/2015 |
| Third Quarter | $ | 38.00 |
| | $ | 22.10 |
| | $ | 0.45 |
| | 11/5/2015 | | 11/13/2015 |
| Fourth Quarter | $ | 29.90 |
| | $ | 10.00 |
| | $ | 0.45 |
| | 2/5/2016 | | 2/12/2016 |
| 2016 | | | | | | | | | |
| First Quarter | $ | 13.86 |
| | $ | 5.00 |
| | $ | 0.45 |
| | 5/5/2016 | | 5/13/2016 |
| Second Quarter | $ | 18.92 |
| | $ | 7.13 |
| | $ | 0.45 |
| | 8/5/2016 | | 8/12/2016 |
| Third Quarter | $ | 29.85 |
| | $ | 13.97 |
| | $ | 0.45 |
| | 11/7/2016 | | 11/14/2016 |
| Fourth Quarter | $ | 40.00 |
| | $ | 25.11 |
| | $ | 0.45 |
| | 2/7/2017 | | 2/14/2017 |
|
| | | | | | | | | | | | |
| Cash Distributions to Partners |
| | | General Partner (1) | | Limited Partners (2) | | Total Distributions |
| | | (in thousands) |
| 2015 Distributions | | $ | 1,434 |
| | $ | 70,324 |
| | $ | 71,758 |
|
| 2016 Distributions | | $ | 451 |
| | $ | 22,014 |
| | $ | 22,465 |
|
| |
| (1) | Represents distributions on our general partner’s 2% general partner interest in us. |
| |
(2) | Includes $0.9 million and $0.3 million distributionsAs of December 31, 2019, 157,789 phantom units were outstanding under the plan. Each phantom unit represents the right to our general partner on 156,000receive one common units beneficially owned by our general partner in 2015 and 2016, respectively.unit, together with associated distribution equivalent rights. |
ITEM 6. SELECTED FINANCIAL DATA
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (in thousands, except per unit data) |
| Total revenues and other income | $ | 400,059 |
| | $ | 439,648 |
| | $ | 350,918 |
| | $ | 352,739 |
| | $ | 379,147 |
|
| Asset impairments | $ | 16,926 |
| | $ | 384,545 |
| | $ | 26,209 |
| | $ | 734 |
| | $ | 2,568 |
|
| Income (loss) from operations | $ | 185,745 |
| | $ | (170,427 | ) | | $ | 176,140 |
| | $ | 233,740 |
| | $ | 267,165 |
|
| Net income (loss) from continuing operations | $ | 95,214 |
| | $ | (260,171 | ) | | $ | 96,713 |
| | $ | 169,621 |
| | $ | 213,355 |
|
Net income from continuing operations excluding impairments (1) | $ | 112,140 |
| | $ | 124,374 |
| | $ | 122,922 |
| | $ | 170,355 |
| | $ | 215,923 |
|
| Net income (loss) from discontinued operations | $ | 1,678 |
| | $ | (311,549 | ) | | $ | 12,117 |
| | $ | 2,457 |
| | $ | — |
|
| Net income (loss) | $ | 96,892 |
| | $ | (571,720 | ) | | $ | 108,830 |
| | $ | 172,078 |
| | $ | 213,355 |
|
| Per common unit amounts (basic and diluted) | | | | | | | | | |
| Net income (loss) from continuing operations | $ | 7.65 |
| | $ | (20.78 | ) | | $ | 8.37 |
| | $ | 15.17 |
| | $ | 19.70 |
|
| Net income (loss) from discontinued operations | $ | 0.13 |
| | $ | (24.97 | ) | | $ | 1.05 |
| | $ | 0.22 |
| | $ | — |
|
| Net income (loss) | $ | 7.78 |
| | $ | (45.75 | ) | | $ | 9.42 |
| | $ | 15.39 |
| | $ | 19.70 |
|
| Distributions paid | $ | 1.80 |
| | $ | 2.70 |
| | $ | 14.00 |
| | $ | 22.00 |
| | $ | 22.00 |
|
Average number of common units outstanding (2) | 12,232 |
| | 12,232 |
| | 11,326 |
| | 10,958 |
| | 10,603 |
|
| Net cash provided by (used in) | | | | | | | | | |
| Operating activities of continuing operations | $ | 100,643 |
| | $ | 168,512 |
| | $ | 192,164 |
| | $ | 246,891 |
| | $ | 271,408 |
|
| Investing activities of continuing operations | $ | 59,943 |
| | $ | 6,985 |
| | $ | (169,512 | ) | | $ | (230,436 | ) | | $ | (212,733 | ) |
| Financing activities of continuing operations | $ | (161,419 | ) | | $ | (183,264 | ) | | $ | (65,986 | ) | | $ | (73,574 | ) | | $ | (124,173 | ) |
Distributable Cash Flow (1) | $ | 271,415 |
| | $ | 176,617 |
| | $ | 196,929 |
| | $ | 306,690 |
| | $ | 296,106 |
|
Adjusted EBITDA (1) | $ | 255,471 |
| | $ | 262,639 |
| | $ | 263,871 |
| | $ | 328,690 |
| | $ | 328,116 |
|
| Cash and cash equivalents | $ | 40,371 |
| | $ | 41,204 |
| | $ | 48,971 |
| | $ | 92,305 |
| | $ | 149,424 |
|
| Total assets | $ | 1,444,681 |
| | $ | 1,670,035 |
| | $ | 2,430,819 |
| | $ | 1,980,354 |
| | $ | 1,760,381 |
|
| Long-term debt | $ | 987,400 |
| | $ | 1,206,611 |
| | $ | 1,270,573 |
| | $ | 1,072,962 |
| | $ | 892,986 |
|
| Partners’ capital | $ | 151,530 |
| | $ | 76,336 |
| | $ | 720,155 |
| | $ | 616,789 |
| | $ | 617,447 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In thousands, except per unit data) | 2019 | | 2018 (1) | | 2017 | | 2016 | | 2015 |
| Total revenues and other income | $ | 263,935 |
| | $ | 278,512 |
| | $ | 246,325 |
| | $ | 279,244 |
| | $ | 300,635 |
|
| Asset impairments | $ | 148,214 |
| | $ | 18,280 |
| | $ | 2,967 |
| | $ | 15,861 |
| | $ | 378,327 |
|
| Income (loss) from operations | $ | 51,321 |
| | $ | 192,538 |
| | $ | 176,559 |
| | $ | 181,157 |
| | $ | (170,699 | ) |
| Net income (loss) from continuing operations | $ | (25,414 | ) | | $ | 122,360 |
| | $ | 82,485 |
| | $ | 90,626 |
| | $ | (260,443 | ) |
| Net income from continuing operations excluding impairments | $ | 122,800 |
| | $ | 140,640 |
| | $ | 85,452 |
| | $ | 106,487 |
| | $ | 117,884 |
|
| Net income (loss) from discontinued operations | $ | 956 |
| | $ | 17,687 |
| | $ | 6,182 |
| | $ | 6,266 |
| | $ | (311,277 | ) |
| Net income (loss) | $ | (24,458 | ) | | $ | 140,047 |
| | $ | 88,667 |
| | $ | 96,892 |
| | $ | (571,720 | ) |
| Per common unit amounts (basic) | | | | | | | | | |
| Net income (loss) from continuing operations | $ | (4.43 | ) | | $ | 7.35 |
| | $ | 4.57 |
| | $ | 7.28 |
| | $ | (20.80 | ) |
| Net income (loss) from discontinued operations | $ | 0.08 |
| | $ | 1.42 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | (24.94 | ) |
| Net income (loss) | $ | (4.35 | ) | | $ | 8.77 |
| | $ | 5.06 |
| | $ | 7.78 |
| | $ | (45.75 | ) |
| Per common unit amounts (diluted) | | | | | | | | | |
| Net income (loss) from continuing operations | $ | (4.43 | ) | | $ | 5.90 |
| | $ | 3.68 |
| | $ | 7.28 |
| | $ | (20.80 | ) |
| Net income (loss) from discontinued operations | $ | 0.08 |
| | $ | 0.86 |
| | $ | 0.28 |
| | $ | 0.50 |
| | $ | (24.94 | ) |
| Net income (loss) | $ | (4.35 | ) | | $ | 6.76 |
| | $ | 3.96 |
| | $ | 7.78 |
| | $ | (45.75 | ) |
| Distributions paid per common unit | $ | 2.65 |
| | $ | 1.80 |
| | $ | 1.80 |
| | $ | 1.80 |
| | $ | 2.70 |
|
| Average number of common units outstanding - basic | 12,260 |
| | 12,244 |
| | 12,232 |
| | 12,232 |
| | 12,232 |
|
| Average number of common units outstanding - diluted | 12,260 |
| | 20,234 |
| | 21,950 |
| | 12,232 |
| | 12,232 |
|
| Net cash provided by (used in) | | | | | | | | | |
| Operating activities of continuing operations | $ | 137,319 |
| | $ | 178,282 |
| | $ | 112,151 |
| | $ | 80,243 |
| | $ | 144,907 |
|
| Investing activities of continuing operations | $ | 8,221 |
| | $ | 7,607 |
| | $ | 9,807 |
| | $ | 65,057 |
| | $ | 15,805 |
|
| Financing activities of continuing operations | $ | (253,305 | ) | | $ | (6,839 | ) | | $ | (134,149 | ) | | $ | (146,373 | ) | | $ | (166,443 | ) |
Distributable cash flow (2) | $ | 144,933 |
| | $ | 383,980 |
| | $ | 121,958 |
| | $ | 255,172 |
| | $ | 157,815 |
|
Free cash flow (2) | $ | 139,040 |
| | $ | 183,440 |
| | $ | 121,324 |
| | $ | 75,970 |
| | $ | 144,210 |
|
Cash flow cushion (2) | $ | 7,762 |
| | $ | 16,080 |
| | $ | 9,248 |
| | $ | (29,444 | ) | | $ | (8,339 | ) |
Adjusted EBITDA (2) | $ | 199,228 |
| | $ | 230,241 |
| | $ | 211,483 |
| | $ | 235,273 |
| | $ | 240,553 |
|
| Cash, cash equivalents and restricted cash | $ | 98,265 |
| | $ | 206,030 |
| | $ | 26,980 |
| | $ | 39,171 |
| | $ | 40,244 |
|
| Total assets | $ | 1,085,907 |
| | $ | 1,341,647 |
| | $ | 1,389,164 |
| | $ | 1,448,649 |
| | $ | 1,674,865 |
|
| Current portion of long-term debt, net | $ | 45,776 |
| | $ | 115,184 |
| | $ | 79,740 |
| | $ | 140,037 |
| | $ | 80,745 |
|
| Long-term debt, net | $ | 470,422 |
| | $ | 557,574 |
| | $ | 729,608 |
| | $ | 990,234 |
| | $ | 1,130,696 |
|
Long-term lease obligations (3) | $ | 3,506 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Class A convertible preferred units | $ | 164,587 |
| | $ | 164,587 |
| | $ | 173,431 |
| | $ | — |
| | $ | — |
|
| Partners’ capital | $ | 338,963 |
| | $ | 423,481 |
| | $ | 265,211 |
| | $ | 151,530 |
| | $ | 76,336 |
|
| |
| (1) | On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, and all the related amendments to all open contracts using the modified retrospective method. NRP recognized a $70.5 million cumulative effect of adoption adjustment in the opening balance of partners' capital on January 1, 2018. Comparative information for the years ended December 31, 2017, 2016 and 2015 have not been restated and continues to be reported under the standards in effect for those periods. |
| |
| (2) | See "—Non-GAAP Financial Measures" below. |
| |
(2)(3) | The unit numbers inOn January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effectiverelated amendments and recognized assets and liabilities on February 17, 2016.its Consolidated Balance Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. |
Non-GAAP Financial Measures
Distributable Cash Flow
Our Distributable Cash Flowcash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus returnsdistributions from unconsolidated investment in excess of unconsolidated equity investments,cumulative earnings, proceeds from asset sales and disposals, including sales of assets, including those included in discontinued operations, and returnsreturn of long-term contract receivables—affiliate;receivables; less maintenance capital expenditures and distributions to non-controlling interest. DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies. In addition, DCF presented below is not calculated or presented on the same basis as distributable cash flow as defined in our partnership agreement, which is used as a metric to determine whether we are able to increase quarterly distributions to our common unitholders. DCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the Partnership'sasses our ability to make cash distributions and repay debt.
Free Cash Flow
Free cash flow ("FCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables; less maintenance and expansion capital expenditures, cash flow used in acquisition costs classified as financing activities and distributions to non-controlling interest. FCF is calculated before mandatory debt repayments. FCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. FCF may not be calculated the same for us as for other companies. FCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess our ability to make cash distributions and repay debt.
Cash Flow Cushion
Cash flow cushion represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables; less maintenance and expansion capital expenditures, cash flow used in acquisition costs classified as financing activities, distributions to non-controlling interest, one-time beneficial items, mandatory Opco debt repayments, preferred unit distributions and common unit distributions. Cash flow cushion is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Cash flow cushion is a supplemental liquidity measure used by our management to assess our ability to make or raise cash distributions to our common and preferred unitholders and our general partner and repay debt. debt or redeem preferred units.
The following table (in thousands) reconciles net cash provided by operating activities of continuing operations (the most comparable GAAP financial measure) to Distributable Cash FlowDCF, FCF and cash flow cushion for the years ended December 31, 2019, 2018, 2017, 2016, 2015, 2014, 2013 and 2012:2015:
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| Net cash provided by operating activities of continuing operations | $ | 100,643 |
| | $ | 168,512 |
| | $ | 192,164 |
| | $ | 246,891 |
| | $ | 271,408 |
|
| Add: return of unconsolidated equity investment | — |
| | — |
| | 3,633 |
| | 48,833 |
| | — |
|
| Add: proceeds from sale of PP&E | 1,350 |
| | 11,024 |
| | 1,006 |
| | — |
| | 11,277 |
|
| Add: proceeds from sale of mineral rights | 61,033 |
| | 3,505 |
| | 412 |
| | 10,929 |
| | 13,545 |
|
| Add: proceeds from sale of assets included in discontinued operations | 109,872 |
| | — |
| | — |
| | — |
| | — |
|
| Add: return on long-term contract receivables—affiliate | 2,968 |
| | 2,463 |
| | 1,904 |
| | 2,558 |
| | 2,669 |
|
| Less: maintenance capital expenditures (1) | (4,451 | ) | | (6,143 | ) | | (1,216 | ) | | — |
| | — |
|
| Less: distributions to non-controlling interest | — |
| | (2,744 | ) | | (974 | ) | | (2,521 | ) | | (2,793 | ) |
| Distributable Cash Flow | $ | 271,415 |
| | $ | 176,617 |
| | $ | 196,929 |
| | $ | 306,690 |
| | $ | 296,106 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Net cash provided by operating activities of continuing operations | $ | 137,319 |
| | $ | 178,282 |
| | $ | 112,151 |
| | $ | 80,243 |
| | $ | 144,907 |
|
| Add: distributions from unconsolidated investment in excess of cumulative earnings | — |
| | 2,097 |
| | 5,646 |
| | — |
| | — |
|
| Add: proceeds from asset sales and disposals | 6,500 |
| | 2,449 |
| | 1,151 |
| | 62,117 |
| | 13,605 |
|
| Add: proceeds from sale of discontinued operations | (629 | ) | | 198,091 |
| | — |
| | 109,872 |
| | — |
|
| Add: return of long-term contract receivables | 1,743 |
| | 3,061 |
| | 3,010 |
| | 2,968 |
| | 2,463 |
|
| Less: maintenance capital expenditures | — |
| | — |
| | — |
| | (28 | ) | | (416 | ) |
| Less: distributions to non-controlling interest | — |
| | — |
| | — |
| | — |
| | (2,744 | ) |
| Distributable cash flow | $ | 144,933 |
| | $ | 383,980 |
| | $ | 121,958 |
| | $ | 255,172 |
| | $ | 157,815 |
|
| Less: proceeds from asset sales and disposals | (6,500 | ) | | (2,449 | ) | | (1,151 | ) | | (62,117 | ) | | (13,605 | ) |
| Less: proceeds from sale of discontinued operations | 629 |
| | (198,091 | ) | | — |
| | (109,872 | ) | | — |
|
| Less: expansion capital expenditures | (22 | ) | | — |
| | — |
| | — |
| | — |
|
| Less: acquisition costs classified as financing activities | — |
| | — |
| | 517 |
| | (7,213 | ) | | — |
|
| Free cash flow | $ | 139,040 |
| | $ | 183,440 |
| | $ | 121,324 |
| | $ | 75,970 |
| | $ | 144,210 |
|
| Less: cash flow from one-time Hillsboro litigation settlement | — |
| | (25,000 | ) | | — |
| | — |
| | — |
|
| Less: mandatory Opco debt repayments | (68,128 | ) | | (80,765 | ) | | (80,765 | ) | | (82,949 | ) | | (80,791 | ) |
| Less: preferred unit distributions and redemption of PIK units | (30,000 | ) | | (39,109 | ) | | (8,844 | ) | | — |
| | — |
|
| Less: common unit distributions | (33,150 | ) | | (22,486 | ) | | (22,467 | ) | | (22,465 | ) | | (71,758 | ) |
| Cash flow cushion | $ | 7,762 |
| | $ | 16,080 |
| | $ | 9,248 |
| | $ | (29,444 | ) | | $ | (8,339 | ) |
| |
(1) | Maintenance capital expenditures primarily consist of costs to maintain the long-term productive capacity of VantaCore. |
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) from continuing operations less equity earnings from unconsolidated investment, net income attributable to non-controlling interest and gain on reserve swaps and income to non-controlling interest;swap; plus total distributions from equity earnings in unconsolidated investment, interest expense, net, debt modification expense, loss on extinguishment of debt, depreciation, depletion and amortization and asset impairments.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies.
In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnership agreement or Consolidated EBITDDA as defined in Opco's debt agreements. See "Item 8. Financial Statements and Supplementary Data—Note 12. Debt, Net" included elsewhere in this Annual Report on Form 10-K for a description of Opco’s debt agreements. Adjusted EBITDA is a supplemental performance measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA for the years ended December 31, 2019, 2018, 2017, 2016, 2015, 2014, 2013 and 2012:2015:
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| Net income (loss) from continuing operations | $ | 95,214 |
| | $ | (260,171 | ) | | $ | 96,713 |
| | $ | 169,621 |
| | $ | 213,355 |
|
| Less: equity earnings from unconsolidated investment | (40,061 | ) | | (49,918 | ) | | (41,416 | ) | | (34,186 | ) | | — |
|
| Less: gain on reserve swaps | — |
| | (9,290 | ) | | (5,690 | ) | | (8,149 | ) | | — |
|
| Add: distributions from equity earnings in unconsolidated investment | 46,550 |
| | 46,795 |
| | 46,638 |
| | 72,946 |
| | — |
|
| Add: interest expense | 90,570 |
| | 89,762 |
| | 79,523 |
| | 64,357 |
| | 53,972 |
|
| Add: depreciation, depletion and amortization | 46,272 |
| | 60,916 |
| | 61,894 |
| | 63,367 |
| | 58,221 |
|
| Add: asset impairments | 16,926 |
| | 384,545 |
| | 26,209 |
| | 734 |
| | 2,568 |
|
| Adjusted EBITDA | $ | 255,471 |
|
| $ | 262,639 |
|
| $ | 263,871 |
|
| $ | 328,690 |
|
| $ | 328,116 |
|
Adjusted EBITDA presented in the table above differs from the EBITDDA definitions contained in Opco’s debt agreements. See Note 11. "Debt and Debt—Affiliate" included in the Notes to Consolidated Financial Statements in Item 8. "Financial Statements and Supplementary Data" included elsewhere in this Annual Report on Form 10-K for a description of Opco’s debt agreements.
Net Income from Continuing Operations Excluding Impairments
Net income from continuing operations excluding impairments is a non-GAAP financial measure that we define as net income (loss) from continuing operations plus asset impairments. Net income from continuing operations excluding impairments, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Net income excluding impairments should not be considered in isolation or as a substitute for operating income (loss), net income (loss), cash flows provided by operating, investing and financial activities, or other income or cash flow statement data prepared in accordance with GAAP. Our management team believes net income excluding impairments is useful in evaluating our financial performance because asset impairments are irregular non-cash charges and excluding these from net income allows us to better compare results period-over-period.The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to net income excluding impairment for the years ended December 31, 2016, 2015, 2014, 2013 and 2012:
| | | | Year Ended December 31, | For the Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | |
| (In thousands) | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Net income (loss) from continuing operations | $ | 95,214 |
| | $ | (260,171 | ) | | $ | 96,713 |
| | $ | 169,621 |
| | $ | 213,355 |
| $ | (25,414 | ) | | $ | 122,360 |
| | $ | 82,485 |
| | $ | 90,626 |
| | $ | (260,443 | ) |
| Less: equity earnings from unconsolidated investment | | (47,089 | ) | | (48,306 | ) | | (40,457 | ) | | (40,061 | ) | | (49,918 | ) |
| Less: net income attributable to non-controlling interest | | — |
| | (510 | ) | | — |
| | — |
| | — |
|
| Less: gain on reserve swap | | — |
| | — |
| | — |
| | — |
| | (9,290 | ) |
| Add: total distributions from unconsolidated investment | | 31,850 |
| | 46,550 |
| | 49,000 |
| | 46,550 |
| | 46,795 |
|
| Add: interest expense, net | | 47,453 |
| | 70,178 |
| | 82,028 |
| | 90,531 |
| | 89,744 |
|
| Add: debt modification expense | | — |
| | — |
| | 7,939 |
| | — |
| | — |
|
| Add: loss on extinguishment of debt | | 29,282 |
| | — |
| | 4,107 |
| | — |
| | — |
|
| Add: depreciation, depletion and amortization | | 14,932 |
| | 21,689 |
| | 23,414 |
| | 31,766 |
| | 45,338 |
|
| Add: asset impairments | 16,926 |
| | 384,545 |
| | 26,209 |
| | 734 |
| | 2,568 |
| 148,214 |
| | 18,280 |
| | 2,967 |
| | 15,861 |
| | 378,327 |
|
| Net income from continuing operations excluding impairments | $ | 112,140 |
| | $ | 124,374 |
| | $ | 122,922 |
| | $ | 170,355 |
| | $ | 215,923 |
| |
| Adjusted EBITDA | | $ | 199,228 |
|
| $ | 230,241 |
|
| $ | 211,483 |
|
| $ | 235,273 |
|
| $ | 240,553 |
|
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consists of the following subjects:
•Executive Overview
•Results of Operations
•Liquidity and Capital Resources
•Off-Balance Sheet Transactions
•Inflation
•Environmental Regulation
•Related Party Transactions
•Summary of Critical Accounting Estimates
•Recent Accounting Standards
As used in this Item 7, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes due 20182025 (the "2018 Notes") and the 10.50% senior notes due 2022 (the "2022"2025 Senior Notes").
Executive Overview
We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal and other natural resources and own a non-controlling 49% interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining and soda ash construction aggregates and other natural resources.production business. Our common units trade on the New York Stock Exchange under the symbol "NRP".
"NRP." Our business is organized into threetwo operating segments:
Coal Royalty and Other—consists primarily of coal royalty properties and coal relatedcoal-related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty properties, aggregates royalty properties, oil and gas royalty properties and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the WesternNorthern Powder River Basin in the United States. Our aggregates and industrial minerals and aggregates properties are located in a number ofvarious states across the United States. OurStates, our oil and gas royalty assets are primarily located in Louisiana.Louisiana and our timber assets are primarily located in West Virginia.
Soda Ash—consists of our 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining operation and soda ash refineryproduction business located in the Green River Basin of Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business.
Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest and financing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment.
VantaCore—consistsWe remain focused on strengthening our balance sheet and maintaining sufficient liquidity to manage our business through periods of volatility in commodity prices. We devote significant amounts of cash each year to make mandatory amortization payments on the Opco Senior Notes as well as to make distributions on our preferred units and common units. Accordingly, preserving the financial flexibility to respond to changes in market conditions while continuing to service our debt and make distributions to unitholders is one of our construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.key objectives.
ForOur financial results by segment for the year ended December 31, 2016, our financial results included (in thousands):2019 are as follows:
|
| | | |
| Revenues and other income | $ | 400,059 |
|
| Net income from continuing operations | $ | 95,214 |
|
| Adjusted EBITDA (1) | $ | 255,471 |
|
| | |
| Operating cash flow provided by continuing operations | $ | 100,643 |
|
| Investing cash flow provided by continuing operations | $ | 59,943 |
|
| Financing cash flow (used in) continuing operations | $ | (161,419 | ) |
| Distributable Cash Flow ("DCF") (1) | $ | 271,415 |
|
|
| | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| (In thousands) | | Coal Royalty and Other | | Soda Ash | | Corporate and Financing | | Total |
| Revenues and other income | | $ | 216,846 |
| | $ | 47,089 |
| | $ | — |
| | $ | 263,935 |
|
| Net income (loss) from continuing operations | | $ | 21,211 |
| | $ | 46,840 |
| | $ | (93,465 | ) | | $ | (25,414 | ) |
| Asset impairments | | 148,214 |
| | — |
| | — |
| | 148,214 |
|
| Net income (loss) from continuing operations excluding asset impairments | | $ | 169,425 |
| | $ | 46,840 |
| | $ | (93,465 | ) | | $ | 122,800 |
|
Adjusted EBITDA (1) | | $ | 184,357 |
| | $ | 31,601 |
| | $ | (16,730 | ) | | $ | 199,228 |
|
| | | | | | | | | |
| Cash flow provided by (used in) continuing operations | | | | | | | | |
| Operating activities | | $ | 178,863 |
| | $ | 31,601 |
| | $ | (73,145 | ) | | $ | 137,319 |
|
| Investing activities | | $ | 8,221 |
| | $ | — |
| | $ | — |
| | $ | 8,221 |
|
| Financing activities | | $ | — |
| | $ | — |
| | $ | (253,305 | ) | | $ | (253,305 | ) |
Distributable cash flow (1) | | $ | 187,106 |
| | $ | 31,601 |
| | $ | (73,145 | ) | | $ | 144,933 |
|
Free cash flow (1) | | $ | 180,584 |
| | $ | 31,601 |
| | $ | (73,145 | ) | | $ | 139,040 |
|
Cash flow cushion (1) | | N/A |
| | N/A |
| | N/A |
| | $ | 7,762 |
|
| |
| (1) | See "—Results of Operations" below"Item 6. Selected Financial Data" for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures. |
2017 Recapitalization Transactions
We have been pursuing or considering a number45
the issuance of $250 million of a new class of 12.0% preferred units representing limited partner interests in NRP, together with warrants to purchase common units, to certain entities controlled by funds affiliated with The Blackstone Group, L.P. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree");
the exchange of $241 million of our 9.125% Senior Notes due 2018 (the "2018 Notes") for $241 million of a new series of 10.500% Senior Notes due 2022 (the "2022 Notes"), and the sale of $105 million of additional 2022 Notes in exchange for cash proceeds; and
the extension of Opco’s revolving credit facility (the "Opco Credit Facility") to April 2020, with commitments thereunder reduced to $180 million.
We used a portion of the proceeds from these transactions to repay Opco’s revolving credit facility in full and pay all fees and expenses associated with the transactions described above. We will also use a portion of the proceeds to redeem the remaining 2018 Notes. On March 3, 2017, we delivered a notice of partial redemption for $90.0 million of our outstanding 2018 Notes at a
redemption price of 104.563%, plus accrued and unpaid interest to the redemption date. This partial redemption of the 2018 Notes is expected to occur on April 3, 2017. We will redeem all of the remaining 2018 Notes within 60 days after October 1, 2017 at the then-applicable price and pay all accrued and unpaid interest thereon.
For more information on these transactions, including the terms of the preferred units, warrants and 2022 Notes, see "—Liquidity and Capital Resources—2017 Recapitalization Transactions."
2016 Asset Sales
Prior to completion of these recapitalization transactions, we had been pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments and scheduled debt principal payments. As part of this plan, we sold assets during the year ended December 31, 2016, for total gross proceeds of $181.0 million that consisted of the following:
Oil and gas working interest in the Williston Basin for $116.1 million gross sales proceeds that marked our exit from the non-operated oil and gas working interest business.
Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $36.4 million gross sales proceeds.
Aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds.
Mineral reserves in multiple sale transactions for cumulative $17.3 million of gross sales proceeds. These amounts primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas royalty interests. Additional asset sales during the year included sales of land and plant and equipment for $1.2 million of gross proceeds.
Current Liquidity
As of December 31, 2016, we had a total of $40.4 million of cash and cash equivalents. During the year ended December 31, 2016, we reduced our debt by approximately $248.1 million by repaying $85.0 million of the NRP Oil and Gas reserve based lending facility in full (the "RBL Facility"), $82.9 million of the Opco Private Placement Notes (as defined below), $80.0 million of the Opco Credit Facility and $0.2 million of Opco's utility local improvement obligation.
In March 2017, we increased our liquidity through the completion of the recapitalization transactions described above, including by repaying borrowings outstanding under the Opco Credit Facility in full. In addition to enhancing our liquidity, these recapitalization transactions reduced our 2018 debt maturities by $575 million through the extension of debt principal payments from 2018 to 2020 and 2022. Even with these meaningful improvements to our liquidity and balance sheet, we continue to have substantial debt outstanding and intend to continue to use cash from operations to deleverage our balance sheet over time. While we have a diversified portfolio of assets, we face challenges in coal and other commodity markets. Our going concern analysis included an analysis of these relevant conditions and events and our ability to meet our obligations and remain in compliance with our debt covenants within one year after the issuance date of these financial statements. We expect that we will meet all of our obligations, including scheduled principal and interest payments on our debt and required distributions on the preferred units, comply with all covenants contained in our debt agreements and that we will continue as a going concern.Contents
Current Results/Market OutlookCommentary
Coal Royalty and Other Business Segment
For the year ended December 31, 2016,Our lessees sold 23.7 million tons of coal from our Coal Royaltyproperties in 2019 and Other business segment financial results included the following (in thousands):
|
| | | |
| Revenues and other income | $ | 239,183 |
|
| Net income from continuing operations | $ | 161,816 |
|
| Adjusted EBITDA (1) | $ | 209,443 |
|
| | |
| Operating cash flow provided by continuing operations | $ | 134,490 |
|
| Investing cash flow provided by continuing operations | $ | 65,057 |
|
| Financing cash flow provided by continuing operations | $ | 16 |
|
| DCF (1) | $ | 199,547 |
|
| |
(1) | See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures. |
In the fourth quarter of 2016, we began to realize the benefits of the dramatic increase in metallurgical coal prices as well as the improvement in the thermal coal markets. A number of our lessees were able to take advantage of the improved markets and lock in tonnage commitments for 2017 at substantially higher prices than they realized in 2016. While spot metallurgical prices have recently retreated from the highs reached in the fourth quarter, we believe that that global supply/demand dynamic will support long-term metallurgical coal prices well above the lows hit in the first half of 2016. We derived approximately 37%65% of our coal royalty revenues and approximately 35%50% of the related productionour coal royalty sales volumes from metallurgical coal during the year ended December 31, 2016.year. We experienced strong coal realizations from our lessees during the first half of 2019, but weakened coal markets and lower activity at certain of our properties negatively impacted our results in the second half of the year. The current market downturn and lessee bankruptcies are expected to put downward pressure on our performance in the coming months.
The market for metallurgical coal weakened and prices for metallurgical coal sold from our properties declined in 2019. The domestic thermal coal markets have also shown modest improvements, as production cuts over the last year have rationalized coal stockpiles. Although a mild winter has tempered demandmarket for thermal coal remains challenged by low natural gas prices, remain higher than 2016, causingpressure over emissions and climate change and increasing use of renewable energy. In addition, the export market for thermal coal has weakened due to be more competitive for electricity generation as compared to recent years. In addition,a combination of lower demand from European utilities, competition from international producers and increasing supply of LNG. While we expect thermal coal will continue to have a role in providing global economies and populations with affordable and reliable energy, we expect these headwinds facing the actionsU.S thermal coal industry will continue.
We remain cautious about the financial position of U.S. coal producers with over-leveraged capital structures and the state of the Trump Administrationdomestic and global coal markets generally. The current price environment along with limited access to ease the regulatory burdenscapital has taken a toll on the coal industry, reducing the production costs and increasing the competitivenessa number of producers. Four of our lessees against natural gas. Despite these improvements, producers of Central Appalachian thermal coalfiled for protection under the U.S. Bankruptcy Code in 2019, and other lessees continue to face challenges, as many still have large debt burdenschallenges. Foresight Energy LP ("Foresight Energy"), which is our largest lessee, has agreed to a forbearance period with its lenders and their production costs remain high relativeis engaging with other contract counterparties to sales prices. We have successfully navigatedevaluate restructuring options. To the bankruptciesextent Foresight Energy determines to idle operations on our properties for a prolonged period or to shut any of several ofits mines on our lessees and have had substantially allproperties down permanently, or to the extent we agree to amend the terms of our leases assumed or assignedwith them to facilitate their continued operations on our properties, our business could be adversely affected. Accordingly, we remain focused on further strengthening our liquidity and received substantially all past-due amounts in these bankruptcies.
Production from our Illinois Basin properties decreased by 27% during the year ended December 31, 2016 as compared to the year ended December 31, 2015. Substantially all of the decrease is attributable to the idling of Foresight Energy's Deer Run mine (which we also refer to as our Hillsboro property) during 2016. In July 2015, we received a notice from Foresight Energy declaring a force majeure event at the Deer Run mine after elevated levels of carbon monoxide were detected. We believe Foresight's claim of force majeure has no merit and we are vigorously pursuing our claims against them through a lawsuit filed in November 2015. However, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us quarterly minimum deficiency payments with respect to the Deer Run mine until mining resumes. Under the lease for the Deer Run mine, Foresight Energy is required to make minimum deficiency payments to us of $7.5 million per quarter, or $30.0 million per year. Foresight Energy’s failure to make the deficiency payments with respect to the second, third and fourth quarters of 2015 and all four quarters of 2016 resulted in a cumulative negative cash impact to us of $46.0 million. Such amount will increase for each quarter during which mining operations continue to be idled. Foresight Energy is continuing efforts to reenter the mine, but we do not know when, or if, mining activities at the Deer Run mine will recommence.
balance sheet.
Soda Ash Business Segment
ForCiner Wyoming's results are primarily affected by the year ended December 31, 2016, our Soda Ash business segment financial results included the following (in thousands):
|
| | | |
| Revenues and other income | $ | 40,061 |
|
| Net income from continuing operations | $ | 40,061 |
|
| Adjusted EBITDA (1) | $ | 46,550 |
|
| | |
| Operating cash flow provided by continuing operations | $ | 46,550 |
|
| Financing cash flow used by continuing operations | $ | (7,229 | ) |
| DCF (1) | $ | 46,550 |
|
| |
(1) | See "—Results of Operations" belowglobal supply of and demand for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures. |
Income from our trona mining and soda ash, refinery investment was lower year-over-yearwhich in turn directly impacts the prices Ciner Wyoming and other producers charge for the year ended December 31, 2016. This decrease is primarily related to lower international prices compared to the prior year, in addition to higher royalty and G&A costs. These decreases were partially offset by an increase inits products. Demand for soda ash volumes sold compared toin the prior year. Ciner Resources LP, our partnerUnited States is driven in a large part by economic growth and activity levels in the end markets that controlsthe glass-making industry serve, such as the automotive and operates Ciner Wyoming,construction industries. Because the United States is a publicly traded master limited partnership that depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders.
VantaCore Business Segment
For the year ended December 31, 2016, our VantaCore business segment financial results included the following (in thousands):
|
| | | |
| Revenues and other income | $ | 120,815 |
|
| Net income from continuing operations | $ | 4,438 |
|
| Adjusted EBITDA (1) | $ | 20,009 |
|
| | |
| Operating cash flow provided by continuing operations | $ | 20,400 |
|
| Investing cash flow used by continuing operations | $ | (5,114 | ) |
| Financing cash flow used by continuing operations | $ | (1,825 | ) |
| DCF (1) | $ | 16,243 |
|
| |
(1) | See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures. |
VantaCore’s construction aggregates mining and production business is largely dependent on the strength of the local markets that it serves. VantaCore’s Laurel Aggregates operation in southwestern Pennsylvania serves producers and oilfield service companies operating in the Marcellus and Utica Shales and was impacted during the year ended December 31, 2016 by the slowing pace of exploration and development of natural gas in those areas due to low natural gas prices. Increased local construction activity partially offset these declines during the year ended December 31, 2016, butwell-developed market for soda ash, we expect that Laurel’s businessdomestic supply of and demand for soda ash will continueremain stable for the near future. Soda ash demand in international markets has continued to be impacted by decreased natural gas development activities. While VantaCore's productiongrow in conjunction with GDP. We expect that future global economic growth will positively influence global demand and revenues have declinedpricing over the long term, which will likely result in 2016 comparedincreased exports, primarily from the United States, Turkey and to 2015,a limited extent, from China, the largest suppliers of soda ash to international markets. Over the nearer term, Ciner Wyoming could face increased costs and competition for customers as a result of its cost management efforts have enabledplanned exit from ANSAC at the business to maintain its profitability.end of 2021.
Discontinued Operations
In July 2016, NRP Oil and Gas closed onWhile the saleperformance of the underlying business remains stable, Ciner Wyoming has announced that it will commence a significant capacity expansion capital project soon that it intends to fund in part by reinvesting cash that would otherwise be distributed to its non-operated oil and gas working interest assets in the Williston Basin for $116.1 million in gross sales proceeds. Our exit from our non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on our soda ash, coal royalty and construction aggregates business segments.partners. As a result, we have classifiedexpect for the assets and liabilities, operating resultscash distributions we receive from Ciner Wyoming to remain at approximately $25 million to $28 million per year until the project is funded. We believe that we will benefit over the long-term from increased productivity and cash flowsdistributions from Ciner Wyoming’s operations following completion of our non-operated oil and gas working interest assets as discontinued operations in our consolidated financial statements for all periods presented.this capital project.
Business Outlook
We expect the challenges described above to continue to negatively impact our results. However, we believe the progress made to strengthen our financial profile in recent years positions us well to navigate this downturn.
Results of Operations
Year Ended December 31, 20162019 and 2018 Compared to Year Ended December 31, 2015
Revenues and Other Income
Revenues and other income decreased $39.5 million, or 9%, from $439.6 million in the year ended December 31, 2015 to $400.1 million in the year ended December 31, 2016. The following table showsincludes our diversified sources of natural resource revenues and other income by business segment for the year ended December 31, 2016 and 2015 (in thousands except for percentages):operating segment:
|
| | | | | | | | | | | | | | | | |
| | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Total |
| 2016 | | | | | | | | |
| Revenues and other income | | $ | 239,183 |
| | $ | 40,061 |
| | $ | 120,815 |
| | $ | 400,059 |
|
| Percentage of total | | 60 | % | | 10 | % | | 30 | % | | |
| 2015 | | | | | | | | |
| Revenues and other income | | $ | 250,717 |
| | $ | 49,918 |
| | $ | 139,013 |
| | $ | 439,648 |
|
| Percentage of total | | 57 | % | | 11 | % | | 32 | % | | |
|
| | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, | | | | |
| Operating Segment (In thousands) | | 2019 | | 2018 | | Increase (Decrease) | | Percentage Change |
| Coal Royalty and Other | | $ | 216,846 |
| | $ | 230,206 |
| | $ | (13,360 | ) | | (6 | )% |
| Soda Ash | | 47,089 |
| | 48,306 |
| | (1,217 | ) | | (3 | )% |
| Total | | $ | 263,935 |
| | $ | 278,512 |
| | $ | (14,577 | ) | | (5 | )% |
The changes in revenuerevenues and other income is discussed for each of the our businessoperating segments below:
Coal Royalty and Other
RevenuesThe following table presents coal sales volumes, coal royalty revenue per ton and coal royalty revenues by major coal producing region, the significant categories of other revenues and other incomeincome:
|
| | | | | | | | | | | | | | |
| | For the Year Ended December 31, | | Increase (Decrease) | | Percentage Change |
| (In thousands, except per ton data) | 2019 | | 2018 | |
| Coal sales volumes (tons) | | | | | | | |
| Appalachia | | | | | | | |
| Northern | 3,460 |
| | 3,187 |
| | 273 |
| | 9 | % |
| Central | 13,377 |
| | 14,997 |
| | (1,620 | ) | | (11 | )% |
| Southern | 1,670 |
| | 1,710 |
| | (40 | ) | | (2 | )% |
| Total Appalachia | 18,507 |
| | 19,894 |
| | (1,387 | ) | | (7 | )% |
| Illinois Basin | 2,201 |
| | 2,739 |
| | (538 | ) | | (20 | )% |
| Northern Powder River Basin | 3,036 |
| | 4,313 |
| | (1,277 | ) | | (30 | )% |
| Total coal sales volumes | 23,744 |
| | 26,946 |
| | (3,202 | ) | | (12 | )% |
| | | | | | | | |
| Coal royalty revenue per ton | | | | | | | |
| Appalachia | | | | | | | |
| Northern | $ | 1.96 |
| | $ | 2.74 |
| | $ | (0.78 | ) | | (28 | )% |
| Central | 5.53 |
| | 5.62 |
| | (0.09 | ) | | (2 | )% |
| Southern | 6.69 |
| | 7.20 |
| | (0.51 | ) | | (7 | )% |
| Illinois Basin | 4.66 |
| | 4.63 |
| | 0.03 |
| | 1 | % |
| Northern Powder River Basin | 2.90 |
| | 2.65 |
| | 0.25 |
| | 9 | % |
| Combined average coal royalty revenue per ton | 4.67 |
| | 4.80 |
| | (0.13 | ) | | (3 | )% |
| | | | | | | | |
| Coal royalty revenues | | | | | | | |
| Appalachia | | | | | | | |
| Northern | $ | 6,775 |
| | $ | 8,719 |
| | $ | (1,944 | ) | | (22 | )% |
| Central | 73,960 |
| | 84,302 |
| | (10,342 | ) | | (12 | )% |
| Southern | 11,169 |
| | 12,312 |
| | (1,143 | ) | | (9 | )% |
| Total Appalachia | 91,904 |
| | 105,333 |
| | (13,429 | ) | | (13 | )% |
| Illinois Basin | 10,255 |
| | 12,673 |
| | (2,418 | ) | | (19 | )% |
| Northern Powder River Basin | 8,809 |
| | 11,445 |
| | (2,636 | ) | | (23 | )% |
| Unadjusted coal royalty revenues | 110,968 |
| | 129,451 |
| | (18,483 | ) | | (14 | )% |
| Coal royalty adjustment for minimum leases | (1,356 | ) | | (110 | ) | | (1,246 | ) | | (1,133 | )% |
| Total coal royalty revenues | $ | 109,612 |
| | $ | 129,341 |
| | $ | (19,729 | ) | | (15 | )% |
| | | | | | | | |
| Other revenues | | | | | | | |
| Production lease minimum revenues | $ | 24,068 |
| | $ | 8,207 |
| | $ | 15,861 |
| | 193 | % |
| Minimum lease straight-line revenues | 14,910 |
| | 2,362 |
| | 12,548 |
| | 531 | % |
| Property tax revenues | 6,287 |
| | 5,422 |
| | 865 |
| | 16 | % |
| Wheelage revenues | 5,880 |
| | 6,484 |
| | (604 | ) | | (9 | )% |
| Coal overriding royalty revenues | 13,496 |
| | 13,878 |
| | (382 | ) | | (3 | )% |
| Lease amendment revenues | 7,991 |
| | — |
| | 7,991 |
| | 100 | % |
| Aggregates royalty revenues | 4,265 |
| | 4,739 |
| | (474 | ) | | (10 | )% |
| Oil and gas royalty revenues | 3,031 |
| | 6,608 |
| | (3,577 | ) | | (54 | )% |
| Other revenues | 1,529 |
| | 1,837 |
| | (308 | ) | | (17 | )% |
| Total other revenues | $ | 81,457 |
| | $ | 49,537 |
| | $ | 31,920 |
| | 64 | % |
| Coal royalty and other | $ | 191,069 |
|
| $ | 178,878 |
| | $ | 12,191 |
| | 7 | % |
| Transportation and processing services revenues | 19,279 |
| | 23,887 |
| | (4,608 | ) | | (19 | )% |
| Gain on litigation settlement | — |
| | 25,000 |
| | (25,000 | ) | | (100 | )% |
| Gain on asset sales and disposals | 6,498 |
| | 2,441 |
| | 4,057 |
| | 166 | % |
| Total Coal Royalty and Other segment revenues and other income | $ | 216,846 |
| | $ | 230,206 |
| | $ | (13,360 | ) | | (6 | )% |
Coal Royalty Revenues
Total coal royalty revenues decreased $19.7 million from 2018 to 2019 driven primarily by lower coal sales volumes. The discussion of these decreases by region is as follows:
Appalachia: Sales volumes decreased 7% and revenues decreased $13.4 million year-over-year. Northern Appalachia includes our Hibbs Run property that has significant sales volumes but a low fixed royalty rate per ton and as a result has a minimal impact on our revenues. Excluding Hibbs Run, sales volumes from our Appalachia properties decreased approximately 11% primarily as a result of weakened coal markets and the temporary idling of certain mines due to lessee bankruptcies.
Illinois Basin: Sales volumes decreased 20% and coal royalty revenues decreased $2.4 million primarily due to weakening of the thermal export market and lower domestic thermal coal demand in 2019 along with flooding and high water throughout the river systems that affected transportation logistics during the first half of 2019, including at the Convent Marine Terminal on the Gulf of Mexico.
Northern Powder River Basin: Sales volumes decreased 30% and coal royalty revenues decreased $2.6 million primarily due to our lessee mining off of our property in accordance with its mine plan in 2019, partially offset by a 9% increase in sales prices year-over-year.
Other Revenues
Total other revenues increased $31.9 million from 2018 to 2019 primarily due to:
$15.9 million increased production lease minimum revenues primarily as a result of increased lessee forfeitures of recoupable balances from minimums paid in prior periods.
$12.5 million increased minimum lease straight-line revenues primarily related to our Coal RoyaltyHillsboro property that we began to recognize in 2019 after the completion of the Hillsboro litigation settlement with Foresight.
$8.0 million of lease amendment revenues during the year ended December 31, 2019.
Transportation and Other segmentProcessing Services Revenues
Transportation and processing services revenues decreased $11.5$4.6 million or 5%, from $250.7 millionprimarily due to weakened demand for Illinois Basin coal that resulted in fewer tons being transported out of our Illinois Basin transportation and processing assets during the year ended December 31, 2019.
Gain on Litigation Settlement
Gain on litigation settlement in the year ended December 31, 20152018 related to $239.2a one-time payment of $25.0 million inwe received from Foresight Energy to settle the year ended December 31, 2016.
The table below presents coal production and coal royalty revenues (including affiliates) derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:
|
| | | | | | | | | | | | | | |
| | For the Year Ended December 31, | | Increase (Decrease) | | Percentage Change |
| | 2016 | | 2015 | |
| | (In thousands, except percent and per ton data) (Unaudited) |
| Coal production (tons) | | | | | | | |
| Appalachia | | | | | | | |
| Northern | 2,312 |
| | 9,562 |
| | (7,250 | ) | | (76 | )% |
| Central | 13,222 |
| | 16,862 |
| | (3,640 | ) | | (22 | )% |
| Southern | 2,776 |
| | 3,803 |
| | (1,027 | ) | | (27 | )% |
| Total Appalachia | 18,310 |
| | 30,227 |
| | (11,917 | ) | | (39 | )% |
| Illinois Basin | 8,116 |
| | 11,173 |
| | (3,057 | ) | | (27 | )% |
| Northern Powder River Basin | 3,781 |
| | 4,905 |
| | (1,124 | ) | | (23 | )% |
| Gulf Coast | 0.4 |
| | 740 |
| | (740 | ) | | (100 | )% |
| Total coal production | 30,207 |
| | 47,045 |
| | (16,838 | ) | | (36 | )% |
| | | | | | | | |
| Coal royalty revenue per ton | | | | | | | |
| Appalachia | | | | | | | |
| Northern | $ | 1.15 |
| | $ | 0.28 |
| | $ | 0.87 |
| | 311 | % |
| Central | 3.64 |
| | 3.85 |
| | (0.21 | ) | | (5 | )% |
| Southern | 3.84 |
| | 4.57 |
| | (0.73 | ) | | (16 | )% |
| Illinois Basin | 3.66 |
| | 3.94 |
| | (0.28 | ) | | (7 | )% |
| Northern Powder River Basin | 2.81 |
| | 2.54 |
| | 0.27 |
| | 11 | % |
| Gulf Coast | 3.28 |
| | 3.47 |
| | (0.19 | ) | | (5 | )% |
| | | | | | | | |
| Coal royalty revenues | | | | | | | |
| Appalachia | | | | | | | |
| Northern | $ | 2,667 |
| | $ | 2,672 |
| | $ | (5 | ) | | — | % |
| Central | 48,119 |
| | 64,877 |
| | (16,758 | ) | | (26 | )% |
| Southern | 10,660 |
| | 17,390 |
| | (6,730 | ) | | (39 | )% |
| Total Appalachia | 61,446 |
| | 84,939 |
| | (23,493 | ) | | (28 | )% |
| Illinois Basin | 29,680 |
| | 44,063 |
| | (14,383 | ) | | (33 | )% |
| Northern Powder River Basin | 10,637 |
| | 12,443 |
| | (1,806 | ) | | (15 | )% |
| Gulf Coast | 1 |
| | 2,570 |
| | (2,569 | ) | | (100 | )% |
| Total coal royalty revenue | $ | 101,764 |
| | $ | 144,015 |
| | $ | (42,251 | ) | | (29 | )% |
| | | | | | | | |
| Other revenues | | | | | | | |
| Minimums recognized as revenue | $ | 64,591 |
| | $ | 15,489 |
| | $ | 49,102 |
| | 317 | % |
| Transportation and processing fees | 19,336 |
| | 22,033 |
| | (2,697 | ) | | (12 | )% |
| Property tax revenue | 10,457 |
| | 11,258 |
| | (801 | ) | | (7 | )% |
| Wheelage | 2,374 |
| | 3,166 |
| | (792 | ) | | (25 | )% |
| Coal override revenue | 2,281 |
| | 2,920 |
| | (639 | ) | | (22 | )% |
| Lease assignment fee | — |
| | 21,000 |
| | (21,000 | ) | | (100 | )% |
| Gain on reserve swap | — |
| | 9,290 |
| | (9,290 | ) | | (100 | )% |
| Hard mineral royalty revenues | 3,163 |
| | 8,090 |
| | (4,927 | ) | | (61 | )% |
| Oil and gas royalty revenues | 3,537 |
| | 4,364 |
| | (827 | ) | | (19 | )% |
| Other | 2,612 |
| | 2,156 |
| | 456 |
| | 21 | % |
| Total other revenues | $ | 108,351 |
| | $ | 99,766 |
| | $ | 8,585 |
| | 9 | % |
| Coal royalty and other income | 210,115 |
| | 243,781 |
| | (33,666 | ) | | (14 | )% |
| Gain on coal royalty and other segment asset sales | 29,068 |
| | 6,936 |
| | 22,132 |
| | 319 | % |
| Total coal royalty and other segment revenues and other income | $ | 239,183 |
| | $ | 250,717 |
| | $ | (11,534 | ) | | (5 | )% |
Total coal production decreased 16.8 million tons, or 36%, from 47.0 million tons in the year ended December 31, 2015 to 30.2 million tons in the year ended December 31, 2016. Total coal royalty revenues decreased $42.3 million, or 29%, from $144.0 million in the year ended December 31, 2015 to $101.8 million in the year ended December 31, 2016. Total coal production and coal royalty revenue decreases were driven by downward pressure in the coal markets as described above, with Central Appalachian thermal coal producers in particular continuing to face challenges, as their production costs remain high relative to sales prices.
Total other revenues increased $8.6 million in 2016 compared to 2015 primarily as a result of the agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the recognition of $40.5 million of deferred revenue. This increase was partially offset by non-recurring revenue transactions in 2015 that included $21.0 million in lease assignment fees and $9.3 million gain on reserve swap. Other revenues were also decreased $4.9 million in 2016 primarily as a result of the sale of our aggregates royalty assets in the first quarter of 2016.
Hillsboro lawsuit.
Gain on coal royaltyAsset Sales and other segmentDisposals
Gain on asset sales and disposals increased $22.1$4.1 million from 2018 to 2019 primarily asdue to a resultdisposal of the following asset salescertain mineral right assets during the firstthird quarter of 2016:
1)Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $36.4 million gross sales proceeds. The effective date of the sale was January 1, 2016, and we recorded an $18.6 million gain from this sale.
2)Aggregate reserves and related royalty rights in the Coal Royalty and Other segment at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds. The effective date of the sale was February 1, 2016, and we recorded a $1.5 million gain from this sale.
2019.
Soda Ash
Revenues and other income related to our equity investmentSoda Ash segment decreased $1.2 million primarily due to Ciner Wyoming's settlement of a royalty dispute in Ciner Wyoming decreased $9.8the second quarter of 2018 that resulted in $12.7 million or 20%, from $49.9 millionof income in the prior year, partially offset by an increase in production and sales volumes and increased domestic and international sales prices in the year ended December 31, 2015 to $40.1 million in the year ended December 31, 2016. This decrease is primarily related to lower international prices compared to the prior year, in addition to higher royalty and G&A costs. These decreases were partially offset by an increase in soda ash volumes sold2019 compared to the prior year.
Operating and Other Expenses
The following table presents the significant categories of our consolidated operating and other income relatedexpenses:
|
| | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, | | Increase (Decrease) | | Percentage Change |
| (In thousands) | | 2019 | | 2018 | | |
| Operating expenses | | | | | | | | |
| Operating and maintenance expenses | | $ | 32,738 |
| | $ | 29,509 |
| | $ | 3,229 |
| | 11 | % |
| Depreciation, depletion and amortization | | 14,932 |
| | 21,689 |
| | (6,757 | ) | | (31 | )% |
| General and administrative expenses | | 16,730 |
| | 16,496 |
| | 234 |
| | 1 | % |
| Asset impairments | | 148,214 |
| | 18,280 |
| | 129,934 |
| | 711 | % |
| Total operating expenses | | $ | 212,614 |
| | $ | 85,974 |
| | $ | 126,640 |
| | 147 | % |
| | | | | | | | | |
| Other expenses, net | | | | | | | | |
| Interest expense, net | | $ | 47,453 |
| | $ | 70,178 |
| | $ | (22,725 | ) | | (32 | )% |
| Loss on extinguishment of debt | | 29,282 |
| | — |
| | 29,282 |
| | 100 | % |
| Total other expenses, net | | $ | 76,735 |
| | $ | 70,178 |
| | $ | 6,557 |
| | 9 | % |
Total operating expenses increased by $126.6 million primarily due to our VantaCore segment decreased $18.2the following:
Asset impairments increased $129.9 million or 13%, from $139.0 million2018 to 2019. Asset impairments in the year ended December 31, 2015 to $120.8 million in the year ended December 31, 2016. This decrease is primarily due to a decrease in construction aggregates and brokered stone revenue as well as lower delivery and fuel income year-over-year. Tonnage sold by the VantaCore segment decreased 0.4 million tons, or 5% from 7.4 million tons in the year ended December 31, 2015 to 7.0 million tons in the year ended December 31, 2016 as a result of decreased construction aggregates demand in the oil and gas services sector that was partially offset by increased aggregates sales into the construction market.
Operating and Maintenance Expenses (including affiliates)
Operating and maintenance expenses (including affiliates) decreased $21.8 million, or 14%, from $152.3 million in the year ended December 31, 2015 to $130.5 million in the year ended December 31, 2016. This decrease is primarily related to the following:
VantaCore
Operating and maintenance expenses (including affiliates) in our VantaCore segment decreased $16.2 million, or 14% from $116.9 million in the year ended December 31, 2015 to $100.7 million in the year ended December 31, 2016. This decrease is primarily due to the decline in materials cost as a result of the decrease in construction aggregates and brokered stone volume year-over-year due to reduced demand in the oil and gas sector and a decrease in delivery and fuel costs due to the lower construction aggregates production and brokered stone purchases year-over-year partially and effective variable cost management.
Depreciation, Depletion and Amortization ("DD&A") Expense
DD&A expense decreased $14.6 million, or 24%, from $60.9 million in the year ended December 31, 2015 to $46.3 million in the year ended December 31, 2016. This decrease is primarily related to the reduced cost basis of our coal and aggregates royalty mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in coal royalty production year-over-year.
General and Administrative (including affiliates) ("G&A") Expense
Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized treasury and accounting. These costs increased $8.3 million, or 67%, from $12.3 million in the year ended December 31, 2015 to $20.6 million in the year ended December 31, 2016. This increase is primarily related to increased legal and consulting fees associated with the implementation of our long-term plan to strengthen our balance sheet, reduce debt and enhance our liquidity and increased LTIP expense as a result of our unit price increasing in 2016 compared to decreasing unot price in 2015 and the accelerated recognition of our LTIP awards granted in 2016
Asset Impairments
Asset impairments decreased $367.6 million, or 96%, from $384.5 million in the year ended December 31, 2015 to $16.9 million in the year ended December 31, 2016. We recorded the following asset impairments during the years ended December 31, 2016 and 2015 (in thousands):
|
| | | | | | | |
| | For the Year Ended December 31, |
| Impaired Assets | 2016 | | 2015 |
| Coal Royalty and Other | | | |
| Mineral Rights | $ | 13,801 |
| | $ | 371,397 |
|
| Plant and Equipment | 2,060 |
| | 6,930 |
|
| Total Coal Royalty and Other Impairment | $ | 15,861 |
| | $ | 378,327 |
|
| | | | |
| VantaCore | | | |
| Plant and Equipment | $ | 1,065 |
| | $ | 692 |
|
| Goodwill | — |
| | 5,526 |
|
| Total VantaCore Impairment | $ | 1,065 |
| | $ | 6,218 |
|
| | | | |
| Total impairment | $ | 16,926 |
| | $ | 384,545 |
|
Coal Royalty and Other
Asset impairments decreased $362.4 million, or 96%, from $378.3 million in the year ended December 31, 2015 to $15.9 million in the year ended December 31, 2016. This decrease is primarily related to $257.5 million in coal property impairment, $70.5 million in oil and gas property impairment and $43.4 million in aggregate property impairment recorded during the year ended December 31, 2015 as compared to $12.1 million in coal property impairment and $1.7 million in aggregate property impairment recorded during the year ended December 31, 2016. The impairments in 20152019 primarily resulted from the continued deterioration in thermal coal markets, lessee capital constraints, thermal coal lease terminations, and expectations of further reductions in global and domestic thermal coal demand due to reduced global steel demand, sustained low natural gas prices and continued regulatory pressure on the electric power generation industry.
VantaCore
industry over emissions and climate change, resulting in reductions in expected cash flows (combination of lower expected coal sales volumes, sales prices, minimums and/or life of mine assumptions) on certain of our mineral rights and intangible assets. Asset impairments decreased $5.1 million, or 82%, from $6.2 million in the year ended December 31, 20152018 primarily related to $1.1a $13.0 million impairment of an aggregates property that we own and lease to our former construction aggregates business, which mines, produces and sells the aggregates, in addition to $5.3 million of impairments related to certain of our coal properties.
Operating and maintenance expenses include costs to manage the Coal Royalty and Other and Soda Ash segments and primarily consist of royalty, tax, employee-related and legal costs and bad debt expense. These costs increased $3.2 million primarily due to bad debt expense recognized in the second quarter of 2019 related to certain of our Coal Royalty and Other receivables, partially offset by lower legal costs and lower overriding royalty interest fees.
Depreciation, depletion and amortization expense decreased $6.8 million due to lower coal sales volumes at certain properties.
Total other expenses, net increased $6.6 million primarily due to the following:
Loss on extinguishment of debt was $29.3 million for the year ended December 31, 2019 and related to the 105.25% premium paid to redeem the 2022 Senior Notes in the second quarter of 2019 as well as the write-off of unamortized debt issuance costs and debt discount related to the 2022 Senior Notes.
Interest expense, net decreased $22.7 million primarily due to lower debt balances in 2019 as a result of debt repayments.
Income from Discontinued Operations
Income from discontinued operations decreased $16.7 million primarily as a result of the $13.1 million gain on sale of our construction aggregates business in the year ended December 31, 2016. This decrease is primarily related2018 in addition to $4.7 million of income generated by this business in 2018 prior to the $5.5 million write off of goodwill during the year ended December 31, 2015.sale.
Income (Loss) from Discontinued Operations50
Adjusted EBITDA (Non-GAAP Financial Measure)
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the years ended December 31, 2016 and 2015:segment:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Operating Segments | | | |
| For the Year Ended | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Corporate and Financing | | Total |
| December 31, 2016 | | | | | | | | | | |
| Net income (loss) from continuing operations | | $ | 161,816 |
| | $ | 40,061 |
| | $ | 4,438 |
| | $ | (111,101 | ) | | $ | 95,214 |
|
| Less: equity earnings from unconsolidated investment | | — |
| | (40,061 | ) | | — |
| | — |
| | (40,061 | ) |
| Add: distributions from unconsolidated investment | | — |
| | 46,550 |
| | — |
| | — |
| | 46,550 |
|
| Add: interest expense | | — |
| | — |
| | — |
| | 90,570 |
| | 90,570 |
|
| Add: depreciation, depletion and amortization | | 31,766 |
| | — |
| | 14,506 |
| | — |
| | 46,272 |
|
| Add: asset impairment | | 15,861 |
| | — |
| | 1,065 |
| | — |
| | 16,926 |
|
| Adjusted EBITDA | | $ | 209,443 |
| | $ | 46,550 |
| | $ | 20,009 |
| | $ | (20,531 | ) | | $ | 255,471 |
|
| | | | | | | | | | | |
| December 31, 2015 | | | | | | | | | | |
| Net income (loss) from continuing operations | | $ | (208,248 | ) | | $ | 49,918 |
| | $ | 251 |
| | $ | (102,092 | ) | | $ | (260,171 | ) |
| Less: equity earnings from unconsolidated investment | | — |
| | (49,918 | ) | | — |
| | — |
| | (49,918 | ) |
| Less: gain on reserve swap | | (9,290 | ) | | — |
| | | | | | (9,290 | ) |
| Add: distributions from unconsolidated investment | | — |
| | 46,795 |
| | — |
| | — |
| | 46,795 |
|
| Add: interest expense | | — |
| | — |
| | — |
| | 89,762 |
| | 89,762 |
|
| Add: depreciation, depletion and amortization | | 45,338 |
| | — |
| | 15,578 |
| | — |
| | 60,916 |
|
| Add: asset impairment | | 378,327 |
| | — |
| | 6,218 |
| | — |
| | 384,545 |
|
| Adjusted EBITDA | | $ | 206,127 |
| | $ | 46,795 |
| | $ | 22,047 |
| | $ | (12,330 | ) | | $ | 262,639 |
|
|
| | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| For the Year Ended (In thousands) | | Coal Royalty and Other | | Soda Ash | | Corporate and Financing | | Total |
| December 31, 2019 | | | | | | | | |
| Net income (loss) from continuing operations | | $ | 21,211 |
| | $ | 46,840 |
| | $ | (93,465 | ) | | $ | (25,414 | ) |
| Less: equity earnings from unconsolidated investment | | — |
| | (47,089 | ) | | — |
| | (47,089 | ) |
| Add: total distributions from unconsolidated investment | | — |
| | 31,850 |
| | — |
| | 31,850 |
|
| Add: interest expense, net | | — |
| | — |
| | 47,453 |
| | 47,453 |
|
| Add: loss on extinguishment of debt | | — |
| | — |
| | 29,282 |
| | 29,282 |
|
| Add: depreciation, depletion and amortization | | 14,932 |
| | — |
| | — |
| | 14,932 |
|
| Add: asset impairments | | 148,214 |
| | — |
| | — |
| | 148,214 |
|
| Adjusted EBITDA | | $ | 184,357 |
| | $ | 31,601 |
| | $ | (16,730 | ) | | $ | 199,228 |
|
| | | | | | | | | |
| December 31, 2018 | | | | | | | | |
| Net income (loss) from continuing operations | | $ | 160,728 |
| | $ | 48,306 |
| | $ | (86,674 | ) | | $ | 122,360 |
|
| Less: equity earnings from unconsolidated investment | | — |
| | (48,306 | ) | | — |
| | (48,306 | ) |
| Less: net income attributable to non-controlling interest | | (510 | ) | | — |
| | — |
| | (510 | ) |
| Add: total distributions from unconsolidated investment | | — |
| | 46,550 |
| | — |
| | 46,550 |
|
| Add: interest expense, net | | — |
| | — |
| | 70,178 |
| | 70,178 |
|
| Add: depreciation, depletion and amortization | | 21,689 |
| | — |
| | — |
| | 21,689 |
|
| Add: asset impairments | | 18,280 |
| | — |
| | — |
| | 18,280 |
|
| Adjusted EBITDA | | $ | 200,187 |
| | $ | 46,550 |
| | $ | (16,496 | ) | | $ | 230,241 |
|
Adjusted EBITDA decreased $7.1$31.0 million or 3%, from $262.6 million in the year ended December 31, 2015 to $255.5 million in the year ended December 31, 2016. The decrease is primarily a result of $42.3 million in reduced coal royalty revenue resulting from decreased coal production and coal royalty revenue per ton driven by the continued pressure on U.S. coal producers as described above, $21.0 million in non-recurring 2015 lease assignment fees, $4.9 million of reduced aggregates royalty revenue in 2016 due to decreased 2016 aggregates productionthe following:
Coal Royalty and sales and $8.3 million of additional G&A expense in 2016 compared to 2015 as described above. These decreases were partially offset by a $49.1 million increase in minimums recognized as revenue primarily as a result of coal lease modifications or terminations that resulted in our lessee forfeiting their minimum royalty balances and $22.2 million of additional gains on asset sales as compared to the same period in 2015. "ItemOther Segment
| |
| ◦ | Adjusted EBITDA decreased $15.8 million primarily as a result of the decrease in revenues and other income driven by the weakened coal markets and the $25 million gain on litigation settlement in 2018. |
Soda Ash Segment
| |
| ◦ | Adjusted EBITDA decreased $14.9 million as a result of lower cash distributions received from Ciner Wyoming during the year ended December 31, 2019. The managing partner of Ciner Wyoming decided to reduce distributions during 2019 to fund a multi-year capacity expansion project that is expected to result in higher earnings and distributions. NRP expects to receive approximately $25 million to $28 million of annual cash distributions from Ciner Wyoming until the project is funded. |
Distributable Cash Flow ("DCF"), Free Cash Flow ("FCF") (Non-GAAPand Cash Flow Cushion (Non-GAAP Financial Measure)Measures)
The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the years ended December 31, 2016 and 2015:segment:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| For the Year Ended | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Corporate and Financing | | Total |
| December 31, 2016 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 134,490 |
| | $ | 46,550 |
| | $ | 20,400 |
| | $ | (100,797 | ) | | $ | 100,643 |
|
| Net cash provided by (used in) investing activities of continuing operations | | 65,057 |
| | — |
| | (5,114 | ) | | — |
| | 59,943 |
|
| Net cash provided by (used in) financing activities of continuing operations | | 16 |
| | (7,229 | ) | | (1,825 | ) | | (152,381 | ) | | (161,419 | ) |
| | | | | | | | | | | |
| December 31, 2015 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 204,934 |
| | $ | 43,029 |
| | $ | 23,605 |
| | $ | (103,056 | ) | | $ | 168,512 |
|
| Net cash provided by (used in) investing activities of continuing operations | | 15,805 |
| | — |
| | (8,820 | ) | | — |
| | 6,985 |
|
| Net cash provided by (used in) financing activities of continuing operations | | (2,744 | ) | | — |
| | — |
| | (180,520 | ) | | (183,264 | ) |
|
| | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| For the Year Ended (In thousands) | | Coal Royalty and Other | | Soda Ash | | Corporate and Financing | | Total |
| December 31, 2019 | | | | | | | | |
| Cash flow provided by (used in) continuing operations | | | | | | | | |
| Operating activities | | $ | 178,863 |
| | $ | 31,601 |
| | $ | (73,145 | ) | | $ | 137,319 |
|
| Investing activities | | 8,221 |
| | — |
| | — |
| | 8,221 |
|
| Financing activities | | — |
| | — |
| | (253,305 | ) | | (253,305 | ) |
| | | | | | | | | |
| December 31, 2018 | | | | | | | | |
| Cash flow provided by (used in) continuing operations | | | | | | | | |
| Operating activities | | $ | 212,394 |
| | $ | 44,453 |
| | $ | (78,565 | ) | | $ | 178,282 |
|
| Investing activities | | 5,510 |
| | 2,097 |
| | — |
| | 7,607 |
|
| Financing activities | | — |
| | — |
| | (6,839 | ) | | (6,839 | ) |
The following table (in thousands) reconcilestables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCF, for the years ended December 31, 2016FCF and 2015:cash flow cushion:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Operating Segments | | | |
| For the Year Ended | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Corporate and Financing | | Total |
| December 31, 2016 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 134,490 |
| | $ | 46,550 |
| | $ | 20,400 |
| | $ | (100,797 | ) | | $ | 100,643 |
|
| Add: proceeds from sale of PP&E | | 1,084 |
| | — |
| | 266 |
| | — |
| | 1,350 |
|
| Add: proceeds from sale of mineral rights | | 61,033 |
| | — |
| | — |
| | — |
| | 61,033 |
|
| Add: proceeds from sale of assets included in discontinued operations | | — |
| | — |
| | — |
| | — |
| | 109,872 |
|
| Add: return on long-term contract receivables—affiliate | | 2,968 |
| | — |
| | — |
| | — |
| | 2,968 |
|
| Less: maintenance capital expenditures | | (28 | ) | | — |
| | (4,423 | ) | | — |
| | (4,451 | ) |
| Distributable Cash Flow | | $ | 199,547 |
| | $ | 46,550 |
| | $ | 16,243 |
| | $ | (100,797 | ) | | $ | 271,415 |
|
| | | | | | | | | | | |
| December 31, 2015 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 204,934 |
| | $ | 43,029 |
| | $ | 23,605 |
| | $ | (103,056 | ) | | $ | 168,512 |
|
| Add: proceeds from sale of PP&E | | 10,100 |
| | — |
| | 924 |
| | — |
| | 11,024 |
|
| Add: proceeds from sale of mineral rights | | 3,505 |
| | — |
| | — |
| | — |
| | 3,505 |
|
| Add: return on long-term contract receivables—affiliate | | 2,463 |
| | — |
| | — |
| | — |
| | 2,463 |
|
| Less: maintenance capital expenditures | | (416 | ) | | — |
| | (5,727 | ) | | — |
| | (6,143 | ) |
| Less: distributions to non-controlling interest | | (2,744 | ) | | — |
| | — |
| | — |
| | (2,744 | ) |
| Distributable Cash Flow | | $ | 217,842 |
| | $ | 43,029 |
| | $ | 18,802 |
| | $ | (103,056 | ) | | $ | 176,617 |
|
|
| | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| For the Year Ended (In thousands) | | Coal Royalty and Other | | Soda Ash | | Corporate and Financing | | Total |
| December 31, 2019 | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 178,863 |
| | $ | 31,601 |
| | $ | (73,145 | ) | | $ | 137,319 |
|
| Add: proceeds from asset sales and disposals | | 6,500 |
| | — |
| | — |
| | 6,500 |
|
| Add: proceeds from sale of discontinued operations | | — |
| | — |
| | — |
| | (629 | ) |
| Add: return of long-term contract receivable | | 1,743 |
| | — |
| | — |
| | 1,743 |
|
| Distributable cash flow | | $ | 187,106 |
| | $ | 31,601 |
| | $ | (73,145 | ) | | $ | 144,933 |
|
| Less: proceeds from asset sales and disposals | | (6,500 | ) | | — |
| | — |
| | (6,500 | ) |
| Less: proceeds from sale of discontinued operations | | — |
| | — |
| | — |
| | 629 |
|
| Less: expansion capital expenditures | | (22 | ) | | — |
| | — |
| | (22 | ) |
| Free cash flow | | $ | 180,584 |
| | $ | 31,601 |
| | $ | (73,145 | ) | | $ | 139,040 |
|
| Less: mandatory Opco debt repayments | | | | | | | | (68,128 | ) |
| Less: preferred unit distributions | | | | | | | | (30,000 | ) |
| Less: common unit distributions | | | | | | | | (33,150 | ) |
| Cash flow cushion | | | | | | | | $ | 7,762 |
|
|
| | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| For the Year Ended (In thousands) | | Coal Royalty and Other | | Soda Ash | | Corporate and Financing | | Total |
| December 31, 2018 | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 212,394 |
| | $ | 44,453 |
| | $ | (78,565 | ) | | $ | 178,282 |
|
| Add: distributions from unconsolidated investment in excess of cumulative earnings | | — |
| | 2,097 |
| | — |
| | 2,097 |
|
| Add: proceeds from asset sales and disposals | | 2,449 |
| | — |
| | — |
| | 2,449 |
|
| Add: proceeds from sale of discontinued operations | | — |
| | — |
| | — |
| | 198,091 |
|
| Add: return of long-term contract receivable | | 3,061 |
| | — |
| | — |
| | 3,061 |
|
| Distributable cash flow | | $ | 217,904 |
| | $ | 46,550 |
| | $ | (78,565 | ) | | $ | 383,980 |
|
| Less: proceeds from asset sales and disposals | | (2,449 | ) | | — |
| | — |
| | (2,449 | ) |
| Less: proceeds from sale of discontinued operations | | — |
| | — |
| | — |
| | (198,091 | ) |
| Free cash flow | | $ | 215,455 |
| | $ | 46,550 |
| | $ | (78,565 | ) | | $ | 183,440 |
|
| Less: cash flow from one-time Hillsboro litigation settlement | | | | | | | | (25,000 | ) |
| Less: mandatory Opco debt repayments | | | | | | | | (80,765 | ) |
| Less: preferred unit distributions and redemption of PIK units | | | | | | | | (39,109 | ) |
| Less: common unit distributions | | | | | | | | (22,486 | ) |
| Cash flow cushion | | | | | | | | $ | 16,080 |
|
DCF increased $94.8and FCF decreased $239.0 million or 54%, from $176.6and $44.4 million, respectively, primarily due to the following:
Coal Royalty and Other Segment
| |
| ◦ | DCF and FCF decreased $30.8 million and $34.9 million, respectively, primarily due to a one-time $25 million payment we received from Foresight Energy to settle the Hillsboro lawsuit in 2018 and lower coal royalty revenues as described above, partially offset by increased cash from the receipt of lease amendment fees and Hillsboro minimum payments in 2019. |
Soda Ash Segment
| |
| ◦ | DCF and FCF decreased $14.9 million as a result of lower cash distributions received from Ciner Wyoming during the year ended December 31, 2019. |
Corporate and Financing Segment
| |
| ◦ | DCF and FCF increased $5.4 million primarily due to lower cash paid for interest in 2019 as a result of lower debt balances during 2019. |
Total DCF for the year ended December 31, 2015 to $271.42018 was also impacted by the $198.1 million in the year ended December 31, 2016. This increase is due primarily to the $109.9 million net cash proceeds from the sale of our discontinued operationconstruction aggregates business in addition to $61.02018.
Cash flow cushion decreased $8.3 million as a result of the decrease in netFCF discussed above (excluding the impact of the $25 million Hillsboro payment) and a $10.7 million increase in common unit distributions made in 2019 primarily as a result of a one-time special distribution of $0.85 per common unit. These decreases in 2019 cash proceeds from sales of mineral rights in 2016. These increasesflow cushion were partially offset by a $12.6 million decrease in mandatory Opco debt repayments as a result of the lower coal royalty production, lower coal royalty revenue per tonprincipal balances on the Opco Senior Notes and less minimum payments received from our coal leases. These decreases are driven bya $9.1 million decrease in preferred unit distributions primarily as a result of the continued pressure on U.S. coal producers as described above. $8.8 million redemption of PIK units in 2018.
For discussion of our Results of Operations comparing 2018 to 2017, refer to our 2018 Annual Report on Form 10-K filed March 7, 2019 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Revenues and Other Income
Revenues and other income increased $88.7 million, or 25%, from $350.9 million in the year ended December 31, 2014 to $439.6 million in the year ended December 31, 2015. The following table shows our diversified sources of natural resource revenues and other income by business segment for the years ended December 31, 2015 and 2014 (in thousands except for percentages):
|
| | | | | | | | | | | | |
| | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Total |
| 2015 | | | | | | | | |
| Revenues | | 250,717 |
| | 49,918 |
| | 139,013 |
| | 439,648 |
|
| Percentage of total | | 57 | % |
| 11 | % |
| 32 | % | | |
| 2014 | | | | | | | | |
| Revenues | | 267,451 |
| | 41,416 |
| | 42,051 |
| | 350,918 |
|
| Percentage of total | | 76 | % | | 12 | % | | 12 | % | | |
The changes in revenue and other income is discussed for each of the our business segments below:
Coal Royalty and Other
Revenues and other income related to our Coal Royalty and Other segment decreased $16.8 million, or 6%, from $267.5 million in 2014 to $250.7 million in 2015.
The table below presents coal royalty production and revenues derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:
|
| | | | | | | | | | | | | | |
| | For the Years Ended December 31, | | Increase (Decrease) | | Percentage Change |
| | 2015 | | 2014 | |
| | (In thousands, except percent and per ton data) (Unaudited) |
| Coal production (tons) | | | | | | | |
| Appalachia | | | | | | | |
| Northern | 9,562 |
| | 9,339 |
| | 223 |
| | 2 | % |
| Central | 16,862 |
| | 20,092 |
| | (3,230 | ) | | (16 | )% |
| Southern | 3,803 |
| | 3,914 |
| | (111 | ) | | (3 | )% |
| Total Appalachia | 30,227 |
| | 33,345 |
| | (3,118 | ) | | (9 | )% |
| Illinois Basin | 11,173 |
| | 13,177 |
| | (2,004 | ) | | (15 | )% |
| Northern Powder River Basin | 4,905 |
| | 2,844 |
| | 2,061 |
| | 72 | % |
| Gulf Coast | 740 |
| | 1,093 |
| | (353 | ) | | (32 | )% |
| Total coal production | 47,045 |
| | 50,459 |
| | (3,414 | ) | | (7 | )% |
| | | | | | | | |
| Coal royalty revenue per ton | | | | | | | |
| Appalachia | | | | | | | |
| Northern | $ | 0.28 |
| | $ | 0.92 |
| | $ | (0.64 | ) | | (70 | )% |
| Central | 3.85 |
| | 4.46 |
| | (0.61 | ) | | (14 | )% |
| Southern | 4.57 |
| | 5.18 |
| | (0.61 | ) | | (12 | )% |
| Illinois Basin | 3.94 |
| | 4.10 |
| | (0.16 | ) | | (4 | )% |
| Northern Powder River Basin | 2.54 |
| | 2.74 |
| | (0.20 | ) | | (7 | )% |
| Gulf Coast | 3.47 |
| | 3.47 |
| | — |
| | — | % |
| | | | | | | | |
| Coal royalty revenues | | | | | | | |
| Appalachia | | | | | | | |
| Northern | $ | 2,672 |
| | $ | 8,621 |
| | $ | (5,949 | ) | | (69 | )% |
| Central | 64,877 |
| | 89,627 |
| | (24,750 | ) | | (28 | )% |
| Southern | 17,390 |
| | 20,292 |
| | (2,902 | ) | | (14 | )% |
| Total Appalachia | 84,939 |
| | 118,540 |
| | (33,601 | ) | | (28 | )% |
| Illinois Basin | 44,063 |
| | 54,049 |
| | (9,986 | ) | | (18 | )% |
| Northern Powder River Basin | 12,443 |
| | 7,804 |
| | 4,639 |
| | 59 | % |
| Gulf Coast | 2,570 |
| | 3,793 |
| | (1,223 | ) | | (32 | )% |
| Total coal royalty revenue | $ | 144,015 |
| | $ | 184,186 |
| | $ | (40,171 | ) | | (22 | )% |
| | | | | | | | |
| Other revenues | | | | | | | |
| Coal override revenue | $ | 2,920 |
| | $ | 4,601 |
| | $ | (1,681 | ) | | (37 | )% |
| Transportation and processing fees | 22,033 |
| | 22,048 |
| | (15 | ) | | — | % |
| Minimums recognized as revenue | 15,489 |
| | 6,659 |
| | 8,830 |
| | 133 | % |
| Lease assignment fee | 21,000 |
| | — |
| | 21,000 |
| | 100 | % |
| Gain on reserve swap | 9,290 |
| | 5,690 |
| | 3,600 |
| | 63 | % |
| Wheelage | 3,166 |
| | 3,442 |
| | (276 | ) | | (8 | )% |
| Hard mineral royalty revenues | 8,090 |
| | 12,073 |
| | (3,983 | ) | | (33 | )% |
| Oil and gas royalty revenues | 4,364 |
| | 10,732 |
| | (6,368 | ) | | (59 | )% |
| Property tax revenue | 11,258 |
| | 13,609 |
| | (2,351 | ) | | (17 | )% |
| Other | 2,156 |
| | 3,045 |
| | (889 | ) | | (29 | )% |
| Total other revenues | $ | 99,766 |
| | $ | 81,899 |
| | $ | 17,867 |
| | 22 | % |
| Coal royalty and other income | 243,781 |
| | 266,085 |
| | (22,304 | ) | | (8 | )% |
| Gain on coal royalty and other segment asset sales | 6,936 |
| | 1,366 |
| | 5,570 |
| | 408 | % |
| Total coal royalty and other segment revenues and other income | $ | 250,717 |
| | $ | 267,451 |
| | $ | (16,734 | ) | | (6 | )% |
Total coal production decreased 3.4 million tons, or 7%, from 50.4 million tons in 2014 to 47.0 million tons in 2015. Total coal royalty revenues decreased $40.2 million, or 22%, from $184.2 million in 2014 to $144.0 million in 2015. During 2015, depressed coal prices negatively affected our coal related revenues. During the year ended December 31, 2015 as compared to 2014, total coal production and total coal royalty revenues were down in Appalachia, the Illinois Basin and the Gulf Coast, while we saw a significant increase in the Northern Powder River Basin. All Appalachian regions saw a decrease in coal royalty revenues during the year with coal royalty revenues in Northern Appalachia down 69% despite a 2% increase in production from that area. We saw a decrease in the average coal revenue per ton throughout all of our regions, with the exception of the Gulf Coast whose average coal revenue per ton remained flat, for the year ended December 31, 2015 when compared to the year ended December 31, 2014.Contents
Other coal royalty and other income increased $17.9 million, or 22%, from $81.9 million in 2014 to $99.8 million in 2015. This increase is primarily a result of two lease assignment fee payments received in 2015 totaling $21.0 million, an $8.8 million increase in minimums recognized as revenue and a $3.6 million increase in reserve swap gains year-over-year. These increases were partially offset by decreased oil and gas royalty revenue as a result of lower commodity prices year-over-year and decreases in hard mineral royalty revenues, property taxes and override revenue in 2015 when compared to 2014.
Soda Ash
Revenues and other income related to our Soda Ash segment increased $8.5 million, or 21%, from $41.4 million in 2014 to $49.9 million in 2015. This increase is primarily related to our allocated percentage of Ciner Wyoming's $15.0 million increase in income year-over-year. For the year ended December 31, 2015, we received $46.8 million in cash distributions from Ciner Wyoming and for the year ended December 31, 2014, we received $46.6 million in cash distributions.
VantaCore
Tonnage sold by the VantaCore segment increased 5.1 million tons from 2.3 million tons in 2014 to 7.4 million tons in 2015. Revenues and other income related to our VantaCore segment increased $96.9 million, or 231%, from $42.1 million in 2014 to $139.0 million in 2015. This increase is due to the fact that VantaCore was acquired in the fourth quarter of 2014.
Operating and Maintenance Expenses (including affiliates)
Operating and maintenance expenses (including affiliates) increased $76.2 million, or 100%, from $76.1 million in 2014 to $152.3 million in 2015. This increase is primarily related to the following:
VantaCore
Operating and maintenance expenses in our VantaCore segment increased $78.2 million from $38.7 million in 2014 to $116.9 million in 2015. This increase is due to the fact that 2014 results only include three months of VantaCore activity as compared to twelve months in 2015.
Depreciation, Depletion and Amortization ("DD&A") Expense
DD&A expense decreased $1.0 million from $61.9 million in 2014 to $60.9 million in 2015. This decrease is primarily related to the following:
Coal Royalty and Other
DD&A expense for our Coal Royalty and Other segment decreased $13.3 million, or 23%, from $58.6 million in 2014 to $45.3 million in 2015. This decrease was primarily the result of the reduction in depletion expense on the assets that were impaired during the third and fourth quarters of 2015 and reduced production year-over-year.
VantaCore
DD&A expense for our VantaCore segment increased $12.3 million from $3.3 million in 2014 to $15.6 million in 2015. This increase was due to the fact that 2014 results only include three months of activity as compared to a full year in 2015.
General and Administrative (including affiliates) ("G&A") Expense
Corporate and financing G&A expense includes corporate headquarters, financing and centralized treasury and accounting. These costs increased $1.8 million, or 17%, from $10.5 million in 2014 to $12.3 million in 2015. This increase was primarily due to an increase in salaries, bonus and benefits, consulting, rent and legal fees. This increase was partially offset by a decrease in LTIP expense as a result of the decline in unit price year-over-year.
Asset Impairment
Asset impairment expense increased $358.3 million from $26.2 million in 2014 to $384.5 million in 2015. We recorded the following asset impairments during the years ended December 31, 2015 and 2014 (in thousands):
|
| | | | | | | |
| | For the Year Ended December 31, |
| Impaired Assets | 2015 | | 2014 |
| Coal Royalty and Other | | | |
| Mineral Rights | $ | 371,397 |
| | $ | 19,806 |
|
| Plant and Equipment | 6,930 |
| | 779 |
|
| Intangible Assets | — |
| | 5,624 |
|
| Total Coal Royalty and Other Impairment | $ | 378,327 |
| | $ | 26,209 |
|
| | | | |
| VantaCore | | | |
| Plant and Equipment | $ | 692 |
| | $ | — |
|
| Goodwill | 5,526 |
| | — |
|
| Total VantaCore Impairment | $ | 6,218 |
| | $ | — |
|
| | | | |
| Total impairment | $ | 384,545 |
| | $ | 26,209 |
|
Coal Royalty and Other
Asset impairment expense related to our Coal Royalty and Other segment increased $352.1 million from $26.2 million in 2014 to $378.3 million in 2015. This increase was primarily due to the significant impairment expense taken in the third quarter 2015. Coal property impairments primarily resulted from idled operations in Appalachia combined with the continued deterioration in the coal markets and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, low natural gas prices, and continued regulatory pressure on the electric power generation industry. Oil and gas royalty property impairments primarily results from declines in future expected realized commodity prices and reduced expected drilling activity on our acreage. Aggregate royalty property impairments primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. During the fourth quarter of 2015, we recognized an additional $8.2 million impairment expense on our coal properties as a result of continued market declines and $4.7 million impairment expense related to coal processing and transportation assets as well as obsolete equipment at our Logan office. During the second quarter of 2015 we recorded a $2.3 million impairment expense related to a coal preparation plant.
VantaCore
The $6.2 million impairment expense in 2015 was related to a $5.5 million write off of goodwill as well as a $0.7 million impairment related to obsolete plant and equipment.
Interest Expense
Interest expense increased $10.3 million, or 13%, from $79.4 million in 2014 to $89.7 million in 2015. This increase was primarily the result of additional debt incurred to complete acquisitions in the fourth quarter of 2014.
Income (Loss) from Discontinued Operations
Income from discontinued operations decreased $323.6 million, from income of $12.1 million in 2014 to a loss of $311.5 million in 2015. The change in income (loss) from discontinued operations primarily related to asset impairments recorded in 2015 due to the declines in future expected realized commodity prices and reduced expected drilling activity and reduced oil and gas prices in 2015 compared to 2014.
Adjusted EBITDA (Non-GAAP Financial Measure)
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the years ended December 31, 2015 and 2014:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Operating Segments | | | |
| For the Year Ended | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Corporate and Financing | | Total |
| December 31, 2015 | | | | | | | | | | |
| Net income (loss) from continuing operations | | $ | (208,248 | ) | | $ | 49,918 |
| | $ | 251 |
| | $ | (102,092 | ) | | $ | (260,171 | ) |
| Less: equity earnings from unconsolidated investment | | — |
| | (49,918 | ) | | — |
| | — |
| | (49,918 | ) |
| Less: gain on reserve swap | | (9,290 | ) | | — |
| | | | | | (9,290 | ) |
| Add: distributions from unconsolidated investment | | — |
| | 46,795 |
| | — |
| | — |
| | 46,795 |
|
| Add: interest expense | | — |
| | — |
| | — |
| | 89,762 |
| | 89,762 |
|
| Add: depreciation, depletion and amortization | | 45,338 |
| | — |
| | 15,578 |
| | — |
| | 60,916 |
|
| Add: asset impairment | | 378,327 |
| | — |
| | 6,218 |
| | — |
| | 384,545 |
|
| Adjusted EBITDA | | $ | 206,127 |
| | $ | 46,795 |
| | $ | 22,047 |
| | $ | (12,330 | ) | | $ | 262,639 |
|
| | | | | | | | | | | |
| December 31, 2014 | | | | | | | | | | |
| Net income (loss) from continuing operations | | $ | 145,237 |
| | $ | 41,416 |
| | $ | 32 |
| | $ | (89,972 | ) | | $ | 96,713 |
|
| Less: equity earnings from unconsolidated investment | | — |
| | (41,416 | ) | | — |
| | — |
| | (41,416 | ) |
| Less: gain on reserve swap | | (5,690 | ) | | — |
| | — |
| | — |
| | (5,690 | ) |
| Add: distributions from unconsolidated investment | | — |
| | 46,638 |
| | — |
| | — |
| | 46,638 |
|
| Add: interest expense | | — |
| | — |
| | — |
| | 79,523 |
| | 79,523 |
|
| Add: depreciation, depletion and amortization | | 58,598 |
| | — |
| | 3,296 |
| | — |
| | 61,894 |
|
| Add: asset impairment | | 26,209 |
| | — |
| | — |
| | — |
| | 26,209 |
|
| Adjusted EBITDA | | $ | 224,354 |
| | $ | 46,638 |
| | $ | 3,328 |
| | $ | (10,449 | ) | | $ | 263,871 |
|
Adjusted EBITDA decreased $1.3 million from $263.9 million in 2014 to $262.6 million in 2015. The decrease is mainly related to declines in our Coal Royalty and Other segment, partially offset by higher income from our VantaCore business that was acquired in October 2014. Adjusted EBITDA is a non-GAAP financial measure. See "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA" for an explanation of Adjusted EBITDA.
Distributable Cash Flow(Non-GAAP Financial Measure)
The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the years ended December 31, 2015 and 2014:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| For the Year Ended | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Corporate and Financing | | Total |
| December 31, 2015 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 204,934 |
| | $ | 43,029 |
| | $ | 23,605 |
| | $ | (103,056 | ) | | $ | 168,512 |
|
| Net cash provided by (used in) investing activities of continuing operations | | $ | 15,805 |
| | $ | — |
| | $ | (8,820 | ) | | $ | — |
| | $ | 6,985 |
|
| Net cash provided by (used in) financing activities of continuing operations | | $ | (2,744 | ) | | $ | — |
| | $ | — |
| | $ | (180,520 | ) | | $ | (183,264 | ) |
| | | | | | | | | | | |
| December 31, 2014 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 238,564 |
| | $ | 42,516 |
| | $ | 2,746 |
| | $ | (91,662 | ) | | $ | 192,164 |
|
| Net cash provided by (used in) investing activities of continuing operations | | $ | (2,067 | ) | | $ | 3,633 |
| | $ | (171,078 | ) | | $ | — |
| | $ | (169,512 | ) |
| Net cash provided by (used in) financing activities of continuing operations | | $ | (974 | ) | | $ | — |
| | $ | — |
| | $ | (65,012 | ) | | $ | (65,986 | ) |
The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to DCF for the years ended December 31, 2015 and 2014:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Operating Segments | | | |
| For the Year Ended | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Corporate and Financing | | Total |
| December 31, 2015 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 204,934 |
| | $ | 43,029 |
| | $ | 23,605 |
| | $ | (103,056 | ) | | $ | 168,512 |
|
| Add: proceeds from sale of PP&E | | 10,100 |
| | — |
| | 924 |
| | — |
| | 11,024 |
|
| Add: proceeds from sale of mineral rights | | 3,505 |
| | — |
| | — |
| | — |
| | 3,505 |
|
| Add: return on long-term contract receivables—affiliate | | 2,463 |
| | — |
| | — |
| | — |
| | 2,463 |
|
| Less: maintenance capital expenditures | | (416 | ) | | — |
| | (5,727 | ) | | — |
| | (6,143 | ) |
| Less: distributions to non-controlling interest | | (2,744 | ) | | — |
| | — |
| | — |
| | (2,744 | ) |
| Distributable Cash Flow | | $ | 217,842 |
| | $ | 43,029 |
| | $ | 18,802 |
| | $ | (103,056 | ) | | $ | 176,617 |
|
| | | | | | | | | | | |
| December 31, 2014 | | | | | | | | | | |
| Net cash provided by (used in) operating activities of continuing operations | | $ | 238,564 |
| | $ | 42,516 |
| | $ | 2,746 |
| | $ | (91,662 | ) | | $ | 192,164 |
|
| Add: return of unconsolidated equity investment | | — |
| | 3,633 |
| | — |
| | — |
| | 3,633 |
|
| Add: proceeds from sale of PP&E | | 968 |
| | — |
| | 38 |
| | — |
| | 1,006 |
|
| Add: proceeds from sale of mineral rights | | 412 |
| | — |
| | — |
| | — |
| | 412 |
|
| Add: return on long-term contract receivables—affiliate | | 1,904 |
| | — |
| | — |
| | — |
| | 1,904 |
|
| Less: maintenance capital expenditures | | (316 | ) | | — |
| | (900 | ) | | — |
| | (1,216 | ) |
| Less: distributions to non-controlling interest | | (974 | ) | | — |
| | — |
| | — |
| | (974 | ) |
| Distributable Cash Flow | | $ | 240,558 |
| | $ | 46,149 |
| | $ | 1,884 |
| | $ | (91,662 | ) | | $ | 196,929 |
|
Distributable Cash Flow for 2015 decreased $20.3 million, or 10%, from $196.9 million in 2014 to $176.6 million in 2015. This decrease is due primarily to a reduction in cash provided by our coal operations, partially offset by our VantaCore business that was acquired in October 2014. Distributable Cash Flow is a non-GAAP financial measure. See "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Distributable Cash Flow" for an explanation of Distributable Cash Flow.
Liquidity and Capital Resources
2017 Restructuring Transactions
The following discussion describes the recapitalization transactions completed on March 2, 2017 and the terms of the preferred units, warrants to purchase common units and debt securities issued in connection therewith.
Issuance of Preferred Units and Warrants
We issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred Units") to Blackstone and GoldenTree (together the "Preferred Purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. We issued 250,000 Preferred Units to the Preferred Purchasers at a price of $1,000 per Preferred Unit (the "Per Unit Purchase Price"), less a 2.5% structuring and origination fee. The Preferred Units entitle the Preferred Purchasers to receive cumulative dividends at a rate of 12% per year, up to one half of which NRP may pay in additional Preferred Units (such additional Preferred Units, the "PIK Units"). We also issued two tranches of warrants (the "Warrants") to purchase common units to the Preferred Purchasers (Warrants to purchase 1.75 million common units with a strike price of $22.81 and Warrants to purchase 2.25 million common units with a strike price of $34.00). The Warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the Warrants, we may, at our option, elect to settle the Warrants in common units or cash, each on a net basis.
The Preferred Units have a perpetual term, unless converted or redeemed as described below. The Preferred Units (including any PIK Units) are convertible into common units at the election of the holders (1) after the fifth anniversary and prior to the eighth anniversary of the issue date at a 7.5% discount to the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to the notice of conversion if the 30-day VWAP immediately prior to such notice is greater than $51.00 (subject to a maximum of 33% of the Preferred Units per year) and (2) after the eighth anniversary of the issue date at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Instead of issuing common units pursuant to clause (1) of the preceding sentence, we have the option to redeem the Preferred Units proposed to be converted for cash at a price equal to the Per Unit Purchase Price, plus the value of any accrued and unpaid distributions. To the extent the holders of the Preferred Units have not elected to convert their Preferred Units by the twelfth anniversary of the issue date, we have the right to force conversion of the Preferred Units into common units at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. In addition, we have the ability to redeem at any time (subject to compliance with our debt agreements) all or any portion of the Preferred Units (including PIK Units) for cash at the agreed upon per unit amount, which is calculated as the Per Unit Purchase Price multiplied by (i) prior to the third anniversary of the closing date, 1.50, (ii) on or after the third anniversary of the closing date and prior to the fourth anniversary of the closing date, 1.70 and (iii) on or after the fourth anniversary of the closing date, 1.85.
The terms of the Preferred Units contain certain restrictions on our ability to pay distributions on our common units. To the extent that either (i) our consolidated Leverage Ratio (as defined in the Restated Partnership Agreement) is greater than 3.25x, or (ii) the ratio of our Distributable Cash Flow to cash distributions made or proposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), we may not increase the quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding Preferred Units. In addition, if at any time after January 1, 2022, any PIK Units are outstanding, we may not make distributions on our common units until we have redeemed all PIK Units for cash.
The holders of the Preferred Units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rights with respect to changes of the terms of the Preferred Units. In addition, Blackstone has certain approval rights over certain matters, including:
the incurrence of new indebtedness, subject to certain exceptions;
material changes to NRP’s business;
acquisitions and divestitures in excess of certain dollar thresholds;
amendments to material contracts resulting in a cash impact to NRP in excess of certain dollar thresholds;
settlement of any litigation or regulatory matter resulting in cash payments by NRP in excess of certain thresholds; and
amendments to related party contracts outside of the ordinary course of business.
GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the Minimum Preferred Unit Threshold (as defined below). The Preferred Purchaser Approval Rights are not transferrable without our consent. In addition, the Preferred Purchaser Approval Rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). To the extent any Preferred Units that have converted into common units are still held by the applicable Preferred Purchaser (or its affiliates), such common units will be deemed to represent a number of Preferred Units based on the weighted average number of common units issued in each conversion and will count towards the Minimum Preferred Unit Threshold.
The foregoing terms of the Preferred Units are reflected in our Fifth Amended and Restated Agreement of Limited Partnership, dated as of March 2, 2017, which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference. The terms of the Warrants are reflected in the Form of Warrant to Purchase Common Units filed as Exhibit 4.28 to this Annual Report on Form 10-K, which is incorporated herein by reference.
At the closing, pursuant to a Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights and appointed one director and one observer to the Board of Directors of GP Natural Resource Partners LLC. For more information on these rights, see "Certain Relationships and Related Transactions, and Director Independence—Board Representation and Observation Rights Agreement."
We also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with the Preferred Purchasers, pursuant to which we are required to file (i) a shelf registration statement to register the common units issuable upon exercise of the Warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the Preferred Units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of Preferred Units (the "Registration Deadlines"). In addition, the Preferred Unit and Warrant Registration Rights Agreement gives the Preferred Purchasers piggyback registration and demand underwritten offering rights under certain circumstances. If the shelf registration statements are not effective by the applicable Registration Deadline, we will be required to pay the Preferred Purchasers liquidated damages in the amounts and upon the term set forth in the Preferred Unit and Warrant Registration Rights Agreement.
Opco Credit Facility Amendment
We entered into the Second Amendment to Opco’s Third Amended and Restated Credit Agreement to extend the term thereof until April 2020, and reduced the commitments of the lenders to $180 million (from $210 million) effective at the closing of the recapitalization transactions. Pursuant the Second Amendment, commitments under the Opco Credit Facility will be reduced to $150 million at December 31, 2017 and further reduced to $100 million at December 31, 2018 through maturity in April 2020. The amendment does not change the pricing grid or financial covenants under the Opco Credit Facility; provided, however, that if we increase our quarterly distribution to our common unitholders above $0.45 per common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from 4.0x to 3.0x. Other terms of the Second Amendment include revisions to the mandatory prepayment provisions with respect to net cash proceeds received from certain asset sales, additional limitations on the ability of Opco and its subsidiaries to make certain investments. The Second Amendment is filed as Exhibit 10.14 to this Annual Report on Form 10-K and is incorporated herein by reference.
Issuance of 2022 Notes; Exchange and Redemption of 2018 Notes
NRP and NRP Finance issued $346 million aggregate principal amount of 10.500% Senior Notes due 2022 to several holders of its 2018 Notes. Of the $346 million of 2022 Notes issued, $241 million in aggregate principal amount were issued in exchange for $241 million in aggregate principal amount of 2018 Notes, and $105 million of the 2022 Notes were issued to the holders in exchange for cash. The 2022 Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 Indenture"), bear interest at 10.500% per year, are payable semi-annually on March 15 and September 15, beginning September 15, 2017, and mature on March 15, 2022.
We and NRP Finance have the option to redeem the 2022 Notes, in whole or in part, at any time on or after March 15, 2019, at the redemption prices (expressed as percentages of principal amount) of 105.25% for the 12-month period beginning March 15, 2019, 102.625% for the 12-month period beginning March 15, 2020, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the date of redemption. Furthermore, before March 15, 2019, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of certain public or private equity offerings at a redemption price of 110.500% of the principal amount of 2022 Notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Notes issued under the 2022 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the 2022 Indenture, the holders of the 2022 Notes may require us to purchase their 2022 Notes at a purchase price equal to 101% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any. The 2022 Notes purchased for cash were issued at a price of 98.75% (original issue discount of 1.25%), and each holder exchanging 2018 Notes received a fee of 5.813% of the aggregate principal amount of all 2018 Notes tendered for exchange by such holder, as well as all accrued and unpaid interest thereon.
The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing the 2018 Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under the debt incurrence covenant, our non-guarantor restricted subsidiaries will not be permitted to incur additional indebtedness unless their consolidated leverage ratio is less than 3.00x (measured on a pro forma basis and assuming that the greater of (i) $150.0 million of debt (or, if less, at our election, the amount of total lending commitments under any revolving credit facility) and (ii) the actual amount of debt outstanding is outstanding under any revolving credit facility); provided, however, that such non-guarantor restricted subsidiaries will be permitted to make up to $150 million in borrowings under a revolving credit facility (which amount will be reduced on a dollar-for-dollar basis to the extent we have made the election described in clause (i) above). Under the restricted payments covenant, we will not be able to increase the quarterly distribution on our common units or elect to pay more than 50% of the distributions required to be made on the Preferred Units in the form of cash, unless, in each case, our consolidated leverage ratio is less than 4.00x. The 2022 Indenture also contains restrictions on our ability to redeem the Preferred Units in cash.
The 2022 Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance, including the remaining outstanding 2018 Notes, and senior in right of payment to any of our subordinated debt. The 2022 Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of our subsidiaries guarantee the 2022 Notes.
The terms of the 2022 Notes are more fully described in the 2022 Indenture, which is filed as Exhibit 4.24 to this Annual Report on Form 10-K and incorporated herein by reference.
We entered into a registration rights agreement (the "Notes Registration Rights Agreement") with the holders of the 2022 Notes, pursuant to which we and NRP Finance agreed to file a registration statement with the Securities and Exchange Commission for the benefit of the holders of the 2022 Notes so that such holders can exchange the 2022 Notes for exchange securities that have substantially identical terms as the 2022 Notes. We and NRP Finance agreed to use commercially reasonable efforts to cause the exchange to be completed within 180 days after the closing and will be required to pay additional interest, as specified in the Notes Registration Rights Agreement, if we fail to comply with our obligations to register the 2022 Notes within the specified time periods.
We expect to redeem $90 million in aggregate principal amount of the 2018 Notes at a redemption price of 104.563%, and pay all accrued and unpaid interest thereon, in April 2017. In addition, we are required to redeem any and all remaining outstanding 2018 Notes (and pay all accrued and unpaid interest thereon) within 60 days after October 1, 2017.
The following table summarizes our long-term debt and convertible preferred unit obligations at December 31, 2016 and at December 31, 2016 after giving pro forma effect to the recapitalization transactions described above (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period |
| As of December 31, 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter | | Total |
| 2018 Notes | | $ | — |
| | $ | 425.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 425.0 |
|
| Opco Credit Facility | | 60.0 |
| | 150.0 |
| | — |
| | — |
| | — |
| | — |
| | 210.0 |
|
| Opco Senior Notes and other | | 80.6 |
| | 80.6 |
| | 76.0 |
| | 54.7 |
| | 47.0 |
| | 164.9 |
| | 503.8 |
|
| Total long-term debt obligations | | $ | 140.6 |
| | $ | 655.6 |
| | $ | 76.0 |
| | $ | 54.7 |
| | $ | 47.0 |
| | $ | 164.9 |
| | $ | 1,138.8 |
|
| | | | | | | | | | | | | | | |
| | | Payments Due by Period |
| After Recapitalization Transactions | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter | | Total |
| 2022 Notes | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 346.0 |
| | $ | 346.0 |
|
| 2018 Notes | | 94.0 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 94.0 |
|
Opco Credit Facility(1) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Opco Senior Notes and other | | 80.6 |
| | 80.6 |
| | 76.0 |
| | 54.7 |
| | 47.0 |
| | 164.9 |
| | 503.8 |
|
| Total long-term debt obligations | | $ | 174.6 |
| | $ | 80.6 |
| | $ | 76.0 |
| | $ | 54.7 |
| | $ | 47.0 |
| | $ | 510.9 |
| | $ | 943.8 |
|
| | | | | | | | | | | | | | | |
| Convertible preferred unit obligations | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 250.0 |
| | $ | 250.0 |
|
| | | | | | | | | | | | | | | |
| Total long-term debt and convertible preferred unit obligations | | $ | 174.6 |
| | $ | 80.6 |
| | $ | 76.0 |
| | $ | 54.7 |
| | $ | 47.0 |
| | $ | 760.9 |
| | $ | 1,193.8 |
|
| |
(1) | Assumes no additional borrowings under the Opco Credit Facility following closing. |
Current Liquidity
Generally, we satisfy our working capital requirements with cash generated from operations. Our current liabilities exceeded our current assets by approximately $83.8 million asAs of December 31, 2016, primarily due to $80.62019, we had total liquidity of $198.3 million, consisting of $98.3 million of cash and cash equivalents and $100.0 million in total principal payments due in 2017 on the Opco Senior Notes and Opco utility local improvement obligation and $60.0 million of payments due in 2017 on theborrowing capacity under our Opco Credit Facility. Excluding these principal payments, our current assets exceeded our current liabilities by approximately $56.8 million as of December 31, 2016. In March 2017, we increased our liquidity through the completion of the recapitalization transactions described above. In addition to enhancing our liquidity, these recapitalization transactions reduced our 2018 debt maturities by $575 million through the extension of debt principal payments from 2018 to 2020 and 2022.
Capital Expenditures
A portion of the capital expenditures associated with our VantaCore segment are maintenance capital expenditures, which are capital expenditures made to maintain the long-term production capacity of those businesses. Expansion capital expenditures are made to increase productive capacity. We deduct maintenance capital expenditures when calculating DCF. VantaCore’s maintenance and expansion capital expenditures for the year ended December 31, 2016 were $4.4 million and $1.0 million, respectively.
Cash Flows
Year Ended December 31, 2019 and 2018 Compared
Cash flowflows provided by operating activities decreased $95.4$51.6 million, from $203.4$188.9 million in the year ended December 31, 20152018 to $108.0$137.3 million in the year ended December 31, 2016. Operating cash flow from continuing operations decreased $70.4 million in our Coal Royalty and Other segment year-over-year2019 primarily as a result of the reduction in coal royalty revenue and reduction of coal royalty minimum cash payments received on certain leases. Cash flow provided by operating activities of discontinued operations decreased $27.6 million, from $34.9 million in the year ended December 31, 2015 to $7.3 million in the year ended December 31, 2016 primarily as a result of completing the sale of our non-operated oil and gas working interest assets in July 2016 that had an effective date of April 1, 2016.
Cash flow provided by operating activities decreased $7.4 million, from $210.8 million in the year ended December 31, 2014 to $203.4 million in the year ended December 31, 2015. Operating cash flow from continuing operations decreased $33.7 million in our Coal Royalty and Other segment year-over-year primarily as a result of the reduction in coal royalty revenue and reduction of coal royalty minimum cash payments received on certain leases. Corporate and Financing used an additional $11.4 million in operating activities of continuing operations primarily due to the increase in cash paid for interest year-over-year. These decreases were partially offset by a $20.9 million increase in cash provided by operating activities of continuing operations in our VantaCore segment primarily duerelated to a full yearone-time $25 million payment we received from Foresight Energy in 2018 to settle the Hillsboro lawsuit, $12.6 million of operations due to the fourth quarter of 2014 acquisition. Cash flowlower cash distributions received from Ciner Wyoming in 2019, $10.6 million lower cash provided by operating activities of discontinued operations increased $16.3 million, from $18.6 million in the year ended December 31, 2014 to $34.9 million in the year ended December 31, 2015 primarily as a result of a full year of revenue on our fourth quarter 2014 Williston Basin non-operated working interest asset acquisition.
Cash flow provided by investing activities increased $197.1 million, from $30.3 million used in the year ended December 31, 2015 to $166.8 million provided in the year ended December 31, 2016. Investing cash flows from discontinued operations increased $144.2 million primarily as a result of the sale of our non-operated oilconstruction aggregates business in the fourth quarter of 2018 and gas working interest assets in July 2016 for $109.9 million in net cash proceeds in addition to a $37.8 million decreaselower coal royalty revenues driven by weakened coal markets and the temporary idling of certain mines. These decreases in cash flow usedprovided by operating activities were partially offset by the collection of Hillsboro minimum payments, lease amendment fees and $6.4 million lower cash paid for interest as a result of lower oil and gas drilling activity and the non-operated working interest asset saledebt balances in July 2016. Investing cash flows from continuing operations increased $52.9 million primarily as a result of 2016 sales of oil and gas and aggregate royalty properties.2019.
Cash flow usedflows provided by investing activities decreased $490.2$183.0 million, from $520.5$190.6 million in the year ended December 31, 20142018 to $30.3$7.6 million in the year ended December 31, 2015 primarily due to2019. Cash flows from discontinued operations decreased $183.7 million as a result of the 2014 VantaCore acquisition and various 2015 asset sales including an aggregate preparation plant, cell phone tower lease contracts and condemnation payments within$198.1 million proceeds received from the sale of our Coal Royalty and Other segment,construction aggregates business in December 2018, partially offset by plant and equipment acquisitions within our VantaCore segment. Cash flow used by investing activities$10.9 million of discontinued operations decreased $313.7 million primarily due to our 2014 investing activities consisting of our Sanish Field acquisition as well as additionalconstruction aggregates capital expenditures related toduring 2018. Cash flows from continuing operations was relatively flat year-over-year as the participation$4.1 million increase in new wells,proceeds from asset sales and disposals was partially offset by 2015 well participation costs.a portion of our distribution from Ciner Wyoming classified as an investing activity in 2018 and a lower return of our long-term contract receivable in 2019.
Cash flowflows used in financing activities increased $114.7$49.3 million, from $171.5$203.3 million in the year ended December 31, 20152018 to $286.2$252.7 million in the year ended December 31, 2016. Cash2019. In the second quarter of 2019, we extended the maturity date of the $100 million Opco Credit Facility to April 2023 and issued $300 million of a new series of 9.125% senior notes due 2025. We used in financing activitiesthe net proceeds from this offering, together with $76 million of discontinued operations increased $136.6 million primarily ascash on hand to redeem all of our 2022 Senior Notes. As a result of using $85.0 million to repay the RBL Credit Facilitythese transactions, our outstanding debt was reduced, our annual interest expense has decreased, and contributing the $39.4 million of discontinued asset sales proceeds that remained after repayment of the RBL Facility in full to continuing operations. This increaseour debt maturities were extended. Significant increases in cash flow used in financing activities was partially offset by a $21.9included the following:
$345.6 million decrease in cash flow used in financing activities from continuing operations primarily a resultfor the redemption of distributing $49.3 million less cash to partners and receiving the remaining net proceeds from discontinuing operations after repayment as described above.
Cash flow used in financing activities increased $438.8 million, from $267.3 million providedour 2022 Senior Notes in the year ended December 31, 2014 to $171.5second quarter of 2019;
$36.7 million usedincrease in payments on the year ended December 31, 2015 primarily due to $518.4 million in loan proceeds and $127.2 million in general partner contributions received during the year ended December 31, 2014. This change was partially offset by higher distributions to partners and loan repayments made during 2014. Cash flow provided by financing activities of discontinued operations decreased $321.5 million, from $333.3 million in the year ended December 31, 2014 to $11.8 million provided in the year ended December 31, 2015,Opco Senior Notes primarily as a result of contributionsthe prepayment made using proceeds from continuing operationsthe sale of our construction aggregates business;
$35.0 million less borrowings on our Opco Credit Facility in 2019 compared to fund investingthe prior year period;
$26.2 million increase in debt issuance costs and other primarily related to the 2019 debt refinancings; and
$10.7 million increase in common unit distributions made in 2019 primarily as a result of a one-time special distribution of $0.85 per common unit.
These increases in cash flows used in financing activities were partially offset by the following:
$300 million provided by the issuance of the discontinued operation2025 Senior Notes in 2014.the second quarter of 2019;
$95 million less cash used in 2019 compared to the prior year as a result of the repayment of the Opco Credit Facility during the fourth quarter of 2018; and
$8.8 million less cash used in 2019 compared to the prior year as a result of the redemption of preferred units paid-in-kind in the first quarter of 2018.
Capital Resources and Obligations
IndebtednessDebt, Net
AsWe had the following debt outstanding as of December 31, 20162019 and 2015, we had the following indebtedness (in thousands):2018:
|
| | | | | | | |
| | December 31, 2016 | | December 31, 2015 |
| Current portion of long-term debt, net | $ | 138,903 |
| | $ | 80,745 |
|
| Long-term debt and debt—affiliate, net | 987,400 |
| | 1,290,211 |
|
| Total debt and debt—affiliate, net | $ | 1,126,303 |
| | $ | 1,370,956 |
|
|
| | | | | | | |
| | December 31, |
| (In thousands) | 2019 | | 2018 |
| Current portion of long-term debt, net | $ | 45,776 |
| | $ | 115,184 |
|
| Long-term debt, net | 470,422 |
| | 557,574 |
|
| Total debt, net | $ | 516,198 |
| | $ | 672,758 |
|
We werehave been and continue to be in compliance with the terms of the financial covenants contained in Opco's debt agreements. Adjusted EBITDA as defined in "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA" differs
Long-Term Contractual Obligations
The following table reflects our long-term, non-cancelable contractual obligations as of December 31, 2016 (in millions):2019:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period |
| Contractual Obligations | | Total | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter |
| NRP: | | | | | | | | | | | | | | |
| Long-term debt principal payments (including current maturities) (1) | | $ | 425.0 |
| | $ | — |
| | $ | 425.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Long-term debt interest payments (1) | | 77.6 |
| | 38.8 |
| | 38.8 |
| | — |
| | — |
| | — |
| | — |
|
| Opco: | | | | | | | | | | | | | | |
| Long-term debt principal payments (including current maturities) (2) | | 713.8 |
| | 140.6 |
| | 230.6 |
| | 76.0 |
| | 54.7 |
| | 47.0 |
| | 164.9 |
|
| Long-term debt interest payments (3) | | 114.8 |
| | 28.1 |
| | 23.1 |
| | 18.1 |
| | 14.2 |
| | 11.1 |
| | 20.2 |
|
| Rental leases (4) | | 5.2 |
| | 2.2 |
| | 1.6 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 1.1 |
|
| Total | | $ | 1,336.4 |
| | $ | 209.7 |
| | $ | 719.1 |
| | $ | 94.2 |
| | $ | 69.0 |
| | $ | 58.2 |
| | $ | 186.2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period |
| Contractual Obligations (In thousands) | | Total | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter |
| NRP: | | | | | | | | | | | | | | |
Long-term debt principal payments (1) | | $ | 300,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 300,000 |
|
Long-term debt interest payments (1) | | 150,563 |
| | 27,375 |
| | 27,375 |
| | 27,375 |
| | 27,375 |
| | 27,375 |
| | 13,688 |
|
| Opco: | | | | | | | | | | | | | | |
Long-term debt principal payments (including current maturities) (2) | | 224,056 |
| | 46,176 |
| | 39,396 |
| | 39,396 |
| | 39,396 |
| | 31,028 |
| | 28,664 |
|
Long-term debt interest payments (3) | | 39,865 |
| | 12,447 |
| | 9,868 |
| | 7,631 |
| | 5,020 |
| | 2,724 |
| | 2,175 |
|
Rental leases (4) | | 14,012 |
| | 483 |
| | 483 |
| | 483 |
| | 483 |
| | 483 |
| | 11,597 |
|
| Total | | $ | 728,496 |
| | $ | 86,481 |
| | $ | 77,122 |
| | $ | 74,885 |
| | $ | 72,274 |
| | $ | 61,610 |
| | $ | 356,124 |
|
| |
| (1) | The amounts indicated in the table include principal and interest due on NRP’s 20182025 Senior Notes. |
| |
| (2) | The amounts indicated in the table include principal due on Opco’s senior notes, credit facility and utility local improvement obligation.notes. |
| |
| (3) | The amounts indicated in the table include interest due on Opco’s senior notes and utility local improvement obligation.the 0.50% annual commitment fee on the unused portion of the Opco Credit Facility, which matures in April 2023. At December 31, 2019 we did not have any borrowings outstanding under the Opco Credit Facility and had $100 million in available borrowing capacity. |
| |
| (4) | TheOn January 1, 2019, Opco entered into a lease agreement for the rental lease amounts primarily consist of office space from Western Pocahontas Properties Limited Partnership for $0.5 million per year. Not included in this table is approximately $0.3 million of annual operating expenses Opco is obligated to pay to Western Pocahontas Properties Limited Partnership in connection with this lease. The lease has a five-year base term and VantaCore equipment leases.five additional five-year renewal options. Upon lease commencement and as of December 31, 2019, the Partnership was reasonably certain to exercise all renewal options included in the lease and have included rental payments in the table through 2048. |
Shelf Registration Statement
In September 2015, we filed a registration statement on Form S-3 with the SEC that is available for registered offerings of common units.
Off-Balance Sheet Transactions
We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the years ended December 31, 2016, 20152019, 2018 and 2014.2017.
Environmental Regulation
Related Party Transactions
Summary of Critical Accounting Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, and liabilities, in the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying Consolidatedexpenses. See "Item 8. Financial Statements of Comprehensive Income during the reporting period. See "Noteand Supplementary Data—Note 2. Summary of Significant Accounting Policies" toPolicies" in the audited consolidated financial statements under Item 8Consolidated Financial Statements of this Form 10-K for discussion of our significant accounting policies. The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates.
Revenues
Coal Royalty and Other Revenues.Segment Revenues
Royalty-based leases. Coal royalty and other revenues are recognized onApproximately two-thirds of the basisour royalty-based leases have initial terms of tonsfive to 40 years, with substantially all lessees having the option to extend the lease for additional terms. For these types of mineral sold by our lessees and the corresponding revenue from those sales. Generally,leases, the lessees generally make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons of material processed through the facilities by our lesseesmined and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, we receive a fixed price per ton for all material transported on the beltlines.
sold. Most of our coal and aggregates lessees must makeroyalty leases require the lessee to pay quarterly or annual minimum annualamounts, either made in advance or quarterly paymentsarrears, which are generally recoupable through actual royalty production over certain time periods. Theseperiods that generally range from three to five years.
In accordance with previous accounting standards in effect prior to January 1, 2018, we recognized all coal and aggregates royalty revenues over the lease term based on production. The recognition of revenue from minimum payments are recordedwas deferred until either recoupment through royalty production occurred or when the recoupment period expired for unrecouped minimums. In accordance with the accounting standard in effect subsequent to January 1, 2018 ("ASC 606"), we have defined our coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell our coal or aggregates over the lease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production would exceed consideration expected to be received from minimum payments over the lease term.
As a deferredresult of this evaluation, revenue liability when received. The deferredrecognition from our royalty-based leases is based on either production or minimum payments as follows:
Production Leases: Leases for which we expect that consideration from production will be greater than consideration from minimums over the lease term. Revenue recognition for these leases is recognized over time based on production as coal royalty revenues or aggregates royalty revenues, as applicable. Deferred revenue attributable to the minimum paymentfrom minimums is recognized as revenue based upon the underlying mineralroyalty revenues when recoupment occurs or as production lease minimum revenues when the lessee recoupsrecoupment period expires. In addition, we recognize breakage revenue from minimums when we determine that recoupment is remote. This breakage revenue is included in production lease minimum revenues.
Minimum Leases: Leases for which we expect that consideration from minimums will be greater than consideration from production over the lease term. Revenue recognition for these leases is recognized straight-line over the lease term based on the minimum payment through production or inconsideration amount as minimum lease straight-line revenues.
This evaluation is performed at the period immediately following the expirationinception of the lessee’s ability to recouplease and only reassessed upon modification or renewal of the payments.
lease.
Oil and gas related revenues consist of revenues from royalties and overriding royalties. Oilroyalties and gas royalty revenues are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenuerevenues from those sales.
Also included within oil and gas royalty revenues are lease bonus payments, which are generally paid upon the execution of a lease. We also have overriding royalty revenue interests in coal reserves. Revenues from these interests is recognized over time based on when the coal is sold.
Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property we own that is recognized over time as transportation across our property occurs.
Other revenues. Other revenues consists primarily of rental payments and surface damage fees related to certain land we own and is recognized straight-line over time as it is earned. Other revenues also include property tax revenues. The majority of property taxes paid on our properties are reimbursable by the lessee and are recognized on a gross basis over time which reflects the reimbursement of property taxes by the lessee. Property taxes we pay are included in operating and maintenance expenses on our Consolidated Statements of Comprehensive Income (Loss).
Transportation and processing services revenues. We own transportation and processing infrastructure that is leased to third parties for throughput fees. Revenue is recognized over time based on the coal tons transported over the beltlines or processed through the facilities.
Contract Modifications
Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A majority of our contract modifications pertain to our coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices or minimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within coal royalty and other revenues on our Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognized prospectively in accordance with the above lease classification.
Contract Assets and Liabilities from Contracts with Customers
Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes unconditional. Receivables are recognized when the minimums are contractually owed, production occurs or minimums are accrued for based on the passage of time.
Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time. The current portion of deferred revenue relates to deferred revenue on minimum leases and lease amendment fees that are to be recognized as revenue on a straight-line basis over the next twelve months. The long-term portion of deferred revenue relates to deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-line basis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as coal royalty revenues from production leases over the next twelve months, we are unable to estimate the current portion of deferred revenue.
Equity in Earnings fromof Ciner Wyoming.
We account for non-marketable equity investments using the equity method of accounting if the investment gives usit the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for ourOur 49% investment in Ciner Wyoming is accounted for using this method.
Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of the investee's net assets is hypothetically allocated first to identified tangible assets and liabilities, then to finite-lived intangibles or indefinite-lived intangibles and the remaining balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived intangibles, if any, and goodwill are not amortized.life. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income.
Our carrying value in anCiner Wyoming is recognized in equity method investee company is reflected in the caption "Equity and other unconsolidated investments" ininvestment on our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming and amortization of the investee companybasis difference is reflectedrecognized in equity in earnings of Ciner Wyoming on the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity and other unconsolidated(Loss). We decrease our investment income." Our share of investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the proportionate share of the investee’s net assets, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets.
VantaCore Revenues. Revenues from the sale57
are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred.
for our proportional share of distributions received from Ciner Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are considered returns on investment and classified as operating cash inflows unless the cumulative distributions received exceed our cumulative equity in earnings. The excess of cumulative distributions received over our cumulative equity in earnings are considered returns of investment and classified as investing cash inflows.
Mineral Rights
Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregateaggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage as defined by the SEC’s Industry Guide 7 and estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of our proved reserves include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statistical analysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results.
Asset Impairment
We have developed procedures to periodically evaluate our long-lived assets for possible impairment. These proceduresimpairment periodically or whenever events or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are performed throughout the year and are basednot limited to, specific events such as a reduction in economically recoverable reserves or production ceasing on historic, current and future performance and are designed to be early warning tests. Ifa property for an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information.extended period. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carryingasset's net book value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the assets’ carryingasset's net book value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property.
We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.
Recent Accounting Standards
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:
Commodity Price Risk
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices. Historically, coal prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenues and could potentially trigger an impairment of our coal properties or a violation of certain financial debt covenants. Because substantially all of our reserves are coal, changes in coal prices have a more significant impact on our financial results.
We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees’ failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees’ operations and adversely affect our coal royalty revenues.future financial results. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices.
We have market risk related to prices for our aggregates products. Aggregates prices are primarily driven by economic conditions in the local markets in which the products are sold.
The market price of soda ash and energy costs directly affects the profitability of Ciner Wyoming’s operations. If the market price for soda ash declines, Ciner Wyoming’s sales revenues will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile and those markets are likely to remain volatile in the future.
Interest Rate Risk
Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to variable interest rates based upon LIBOR. At December 31, 2016,2019 we had $210.0 milliondid not have any borrowings outstanding in variable interest rateunder the Opco Credit Facility.
Fair Value of Financial Assets and Liabilities
Our financial assets and liabilities consist of cash and cash equivalents, restricted cash, contract receivable and debt. If interest rates wereThe carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to increase by 1%, annual interest expense would increase approximately $2.1 million, assumingtheir short-term nature. We use available market data and valuation methodologies to estimate the same principalfair value of our debt and contract receivable.
The following table shows the carrying amount remained outstanding during the year.and estimated fair value of our debt and contract receivable:
|
| | | | | | | | | | | | | | | | | |
| | | | December 31, |
| | | | 2019 | | 2018 |
| (In thousands) | Fair Value Hierarchy Level | | Carrying Value | | Estimated
Fair Value | | Carrying
Value | | Estimated
Fair Value |
| Debt: | | | | | | | | | |
| NRP 2025 Senior Notes | 1 | | $ | 294,084 |
| | $ | 269,250 |
| | $ | — |
| | $ | — |
|
| NRP 2022 Senior Notes | 1 | | — |
| | — |
| | 334,024 |
| | 356,871 |
|
| Opco Senior Notes | 3 | | 222,114 |
| | 201,090 |
| | 338,734 |
| | 352,599 |
|
| Opco Credit Facility | 3 | | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | |
| Assets: | | | | | | | | | |
| Contract receivable (current and long-term) | 3 | | $ | 38,945 |
| | $ | 33,460 |
| | $ | 40,776 |
| | $ | 34,704 |
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TheReport of Independent Registered Public Accounting Firm
To the Partners of Natural Resource Partners L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. (the Partnership) as of December 31, 20162019 and 2015, and2018, the related consolidated statements of comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2016. These2019, and the related notes (collectively referred to as the “consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express anstatements”). In our opinion, on these financial statements based on our audits. audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.
We did not audit the financial statements of Ciner Wyoming LLC (Ciner Wyoming), a Limited Liability Companylimited liability company in which Natural Resource Partners L.P. ownsthe Partnership has a 49% interest. In the consolidated financial statements, Natural Resource Partners L.P.’sthe Partnership’s investment in Ciner Wyoming is stated at $256$263 million and $262$247 million as of December 31, 20162019 and 20152018, respectively, and Natural Resource Partners L.P.’sthe Partnership’s equity in the net income of Ciner Wyoming is stated at $47 million in 2019, $48 million in 2018 and $40 million $50 million, and $41 million for each of the three years in the period ended December 31, 2016.2017. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ciner Wyoming, LLC, is based solely on the report of the other auditors.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 27, 2020 expressed an unqualified opinion thereon.
Adoption of ASU No. 2014-09
The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” effective January 1, 2018. As a result, for the years ended December 31, 2018 and 2019, the Partnership changed its method for revenue recognition related to royalty lease arrangements.
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 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 Public Company Accounting Oversight Board (United States).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. An audit includesmisstatement, whether due to error or fraud. 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 supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. /s/ Ernst & Young LLP
We also have audited, in accordance withserved as the standards of the Public Company Accounting Oversight Board (United States), Natural Resource Partners L.P.'s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 6, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLPPartnership’s auditor since 2002.
Houston, Texas
March 6, 2017February 27, 2020
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ciner Wyoming LLC (the "Company"(“the Company”) as of December 31, 20162019 and 20152018, and the related statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years in the period ended December 31, 2016. 2019, and the related notes included in Exhibit 99.1 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’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 Company 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 Public Company Accounting Oversight Board (United States)PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
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 supportingregarding the amounts and disclosures in the financial statements, assessingstatements. 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 statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America./s/ Deloitte & Touche LLP
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
March 6, 2017February 27, 2020
We have served as the Company’s auditor since 2008.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data)
| | | | December 31, | December 31, |
| | 2016 | | 2015 | |
| (In thousands, except unit data) | | 2019 | | 2018 |
| ASSETS | | | | | | |
| Current assets: | | | | |
| Current assets | | | | |
| Cash and cash equivalents | $ | 40,371 |
| | $ | 41,204 |
| $ | 98,265 |
| | $ | 101,839 |
|
| Restricted cash | | — |
| | 104,191 |
|
| Accounts receivable, net | 43,202 |
| | 43,633 |
| 30,869 |
| | 32,058 |
|
| Accounts receivable—affiliates, net | 6,658 |
| | 6,345 |
| |
| Inventory | 6,893 |
| | 7,835 |
| |
| Prepaid expenses and other | 6,137 |
| | 4,268 |
| |
| Current assets of discontinued operations (see Note 3) | 991 |
| | 17,844 |
| |
| Prepaid expenses and other, net | | 1,244 |
| | 3,462 |
|
| Current assets of discontinued operations | | 1,706 |
| | 993 |
|
| Total current assets | 104,252 |
| | 121,129 |
| $ | 132,084 |
| | $ | 242,543 |
|
| Land | 25,252 |
| | 25,022 |
| 24,008 |
| | 24,008 |
|
| Plant and equipment, net | 49,443 |
| | 60,675 |
| |
| Mineral rights, net | 908,192 |
| | 984,522 |
| 605,096 |
| | 743,112 |
|
| Intangible assets, net | 3,236 |
| | 3,930 |
| 17,687 |
| | 42,513 |
|
| Intangible assets, net—affiliate | 49,811 |
| | 52,997 |
| |
| Equity in unconsolidated investment | 255,901 |
| | 261,942 |
| 263,080 |
| | 247,051 |
|
| Long-term contracts receivable—affiliate | 43,785 |
| | 47,359 |
| |
| Other assets | 3,791 |
| | 1,173 |
| |
| Other assets—affiliate | 1,018 |
| | 1,124 |
| |
| Non-current assets of discontinued operations (see Note 3) | — |
| | 110,162 |
| |
| Long-term contract receivable | | 36,963 |
| | 38,945 |
|
| Other assets, net | | 6,989 |
| | 3,475 |
|
| Total assets | $ | 1,444,681 |
| | $ | 1,670,035 |
| $ | 1,085,907 |
| | $ | 1,341,647 |
|
| LIABILITIES AND CAPITAL | | | | | | |
| Current liabilities: | | | | |
| Current liabilities | | | | |
| Accounts payable | $ | 6,234 |
| | $ | 5,022 |
| $ | 1,179 |
| | $ | 2,414 |
|
| Accounts payable—affiliates | 940 |
| | 801 |
| |
| Accrued liabilities | 41,587 |
| | 44,997 |
| 8,764 |
| | 12,347 |
|
| Accrued liabilities—affiliates | — |
| | 456 |
| |
| Accrued interest | | 2,316 |
| | 14,345 |
|
| Current portion of deferred revenue | | 4,608 |
| | 3,509 |
|
| Current portion of long-term debt, net | 138,903 |
| | 80,745 |
| 45,776 |
| | 115,184 |
|
| Current liabilities of discontinued operations (see Note 3) | 353 |
| | 4,388 |
| |
| Current liabilities of discontinued operations | | 65 |
| | 947 |
|
| Total current liabilities | 188,017 |
| | 136,409 |
| $ | 62,708 |
| | $ | 148,746 |
|
| Deferred revenue | 44,931 |
| | 80,812 |
| 47,213 |
| | 49,044 |
|
Deferred revenue—affiliates | 71,632 |
| | 82,853 |
| |
| Long-term debt, net | 987,400 |
| | 1,186,681 |
| 470,422 |
| | 557,574 |
|
Long-term debt, net—affiliate | — |
| | 19,930 |
| |
| Other non-current liabilities | 4,565 |
| | 5,171 |
| 4,949 |
| | 1,150 |
|
| Non-current liabilities of discontinued operations (see Note 3) | — |
| | 85,237 |
| |
| Commitments and contingencies (see Note 14) | | | | |
| Partners’ capital: | | | | |
| Common unitholders’ interest (12,232,006 units outstanding) | 152,309 |
| | 79,094 |
| |
| Total liabilities | | $ | 585,292 |
| | $ | 756,514 |
|
| Commitments and contingencies (see Note 16) | | | | |
| Class A Convertible Preferred Units (250,000 units issued and outstanding at $1,000 par value per unit; liquidation preference of $1,500 per unit) | | $ | 164,587 |
| | $ | 164,587 |
|
| Partners’ capital | | | | |
| Common unitholders’ interest (12,261,199 and 12,249,469 units issued and outstanding at December 31, 2019 and 2018, respectively) | | $ | 271,471 |
| | $ | 355,113 |
|
| General partner’s interest | 887 |
| | (606 | ) | 3,270 |
| | 5,014 |
|
| Warrant holders’ interest | | 66,816 |
| | 66,816 |
|
| Accumulated other comprehensive loss | (1,666 | ) | | (2,152 | ) | (2,594 | ) | | (3,462 | ) |
| Total partners’ capital | 151,530 |
| | 76,336 |
| $ | 338,963 |
| | $ | 423,481 |
|
| Non-controlling interest | (3,394 | ) | | (3,394 | ) | (2,935 | ) | | (2,935 | ) |
| Total capital | 148,136 |
| | 72,942 |
| $ | 336,028 |
| | $ | 420,546 |
|
| Total liabilities and capital | $ | 1,444,681 |
| | $ | 1,670,035 |
| $ | 1,085,907 |
| | $ | 1,341,647 |
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands, except per unit data)
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Revenues and other income: | | | | | |
| Coal royalty and other | $ | 144,520 |
| | $ | 154,066 |
| | $ | 181,526 |
|
| Coal royalty and other—affiliates | 65,595 |
| | 89,715 |
| | 84,559 |
|
| VantaCore | 120,802 |
| | 139,049 |
| | 42,031 |
|
| Equity in earnings of Ciner Wyoming | 40,061 |
| | 49,918 |
| | 41,416 |
|
| Gain on asset sales, net | 29,081 |
| | 6,900 |
| | 1,386 |
|
| Total revenues and other income | 400,059 |
|
| 439,648 |
|
| 350,918 |
|
| | | | | | |
| Operating expenses: | | | | | |
| Operating and maintenance expenses | 119,621 |
| | 136,943 |
| | 65,933 |
|
| Operating and maintenance expenses—affiliates, net | 10,925 |
| | 15,323 |
| | 10,197 |
|
| Depreciation, depletion and amortization | 43,087 |
| | 57,295 |
| | 58,586 |
|
| Amortization expense—affiliate | 3,185 |
| | 3,621 |
| | 3,308 |
|
| General and administrative | 16,979 |
| | 7,036 |
| | 7,287 |
|
| General and administrative—affiliates | 3,591 |
| | 5,312 |
| | 3,258 |
|
| Asset impairments | 16,926 |
| | 384,545 |
| | 26,209 |
|
| Total operating expenses | 214,314 |
| | 610,075 |
| | 174,778 |
|
| | | | | | |
| Income (loss) from operations | 185,745 |
| | (170,427 | ) | | 176,140 |
|
| | | | | | |
| Other income (expense) | | | | | |
| Interest expense | (90,047 | ) | | (87,911 | ) | | (79,144 | ) |
| Interest expense—affiliate | (523 | ) | | (1,851 | ) | | (379 | ) |
| Interest income | 39 |
| | 18 |
| | 96 |
|
| Other expense, net | (90,531 | ) | | (89,744 | ) | | (79,427 | ) |
| | | | | | |
| Net income (loss) from continuing operations | 95,214 |
| | (260,171 | ) | | 96,713 |
|
| Income (loss) from discontinued operations (see Note 3) | 1,678 |
| | (311,549 | ) | | 12,117 |
|
| Net income (loss) | $ | 96,892 |
| | $ | (571,720 | ) | | $ | 108,830 |
|
| | | | | | |
| Net income (loss) attributable to limited partners: | | | | | |
| Continuing operations | $ | 93,585 |
| | $ | (254,173 | ) | | $ | 94,779 |
|
| Discontinued operations | 1,644 |
| | (305,319 | ) | | 11,874 |
|
| Total | $ | 95,229 |
| | $ | (559,492 | ) | | $ | 106,653 |
|
| | | | | | |
| Net income (loss) attributable to the general partner: | | | | | |
| Continuing operations | $ | 1,629 |
| | $ | (5,998 | ) | | $ | 1,934 |
|
| Discontinued operations | 34 |
| | (6,230 | ) | | 243 |
|
| Total | $ | 1,663 |
| | $ | (12,228 | ) | | $ | 2,177 |
|
| | | | | | |
| Basic and diluted net income (loss) per common unit: | | | | | |
| Continuing operations | $ | 7.65 |
| | $ | (20.78 | ) | | $ | 8.37 |
|
| Discontinued operations | 0.13 |
| | (24.97 | ) | | 1.05 |
|
| Total | $ | 7.78 |
| | $ | (45.75 | ) | | $ | 9.42 |
|
| | | | | | |
| Average number of common units outstanding | 12,232 |
| | 12,232 |
| | 11,326 |
|
| | | | | | |
| Net income (loss) | $ | 96,892 |
| | $ | (571,720 | ) | | $ | 108,830 |
|
| Add: comprehensive income (loss) from unconsolidated investment and other | 486 |
| | (1,693 | ) | | (81 | ) |
| Comprehensive income (loss) | $ | 97,378 |
| | $ | (573,413 | ) | | $ | 108,749 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In thousands, except per unit data) | 2019 | | 2018 | | 2017 |
| Revenues and other income | | | | | |
| Coal royalty and other | $ | 191,069 |
| | $ | 178,878 |
| | $ | 181,801 |
|
| Transportation and processing services | 19,279 |
| | 23,887 |
| | 20,522 |
|
| Equity in earnings of Ciner Wyoming | 47,089 |
| | 48,306 |
| | 40,457 |
|
| Gain on litigation settlement | — |
| | 25,000 |
| | — |
|
| Gain on asset sales and disposals | 6,498 |
| | 2,441 |
| | 3,545 |
|
| Total revenues and other income | $ | 263,935 |
|
| $ | 278,512 |
|
| $ | 246,325 |
|
| | | | | | |
| Operating expenses | | | | | |
| Operating and maintenance expenses | $ | 32,738 |
| | $ | 29,509 |
| | $ | 24,883 |
|
| Depreciation, depletion and amortization | 14,932 |
| | 21,689 |
| | 23,414 |
|
| General and administrative expenses | 16,730 |
| | 16,496 |
| | 18,502 |
|
| Asset impairments | 148,214 |
| | 18,280 |
| | 2,967 |
|
| Total operating expenses | $ | 212,614 |
| | $ | 85,974 |
| | $ | 69,766 |
|
| | | | | | |
| Income from operations | $ | 51,321 |
| | $ | 192,538 |
| | $ | 176,559 |
|
| | | | | | |
| Other expenses, net | | | | | |
| Interest expense, net | $ | (47,453 | ) | | $ | (70,178 | ) | | $ | (82,028 | ) |
| Debt modification expense | — |
| | — |
| | (7,939 | ) |
| Loss on extinguishment of debt | (29,282 | ) | | — |
| | (4,107 | ) |
| Total other expenses, net | $ | (76,735 | ) | | $ | (70,178 | ) | | $ | (94,074 | ) |
| | | | | | |
| Net income (loss) from continuing operations | $ | (25,414 | ) | | $ | 122,360 |
| | $ | 82,485 |
|
| Income from discontinued operations (see Note 4) | 956 |
| | 17,687 |
| | 6,182 |
|
| Net income (loss) | $ | (24,458 | ) | | $ | 140,047 |
| | $ | 88,667 |
|
| Net income attributable to non-controlling interest | — |
| | (510 | ) | | — |
|
| Net income (loss) attributable to NRP | $ | (24,458 | ) | | $ | 139,537 |
| | $ | 88,667 |
|
| Less: income attributable to preferred unitholders | (30,000 | ) | | (30,000 | ) | | (25,453 | ) |
| Net income (loss) attributable to common unitholders and general partner | $ | (54,458 | ) | | $ | 109,537 |
| | $ | 63,214 |
|
| | | |
|
| | |
| Net income (loss) attributable to common unitholders | $ | (53,369 | ) | | $ | 107,346 |
| | $ | 61,950 |
|
| Net income (loss) attributable to the general partner | (1,089 | ) | | 2,191 |
| | 1,264 |
|
| | | | | | |
| Income (loss) from continuing operations per common unit (see Note 7) | | | | | |
| Basic | $ | (4.43 | ) | | $ | 7.35 |
| | $ | 4.57 |
|
| Diluted | (4.43 | ) | | 5.90 |
| | 3.68 |
|
| | | | | | |
| Net income (loss) per common unit (see Note 7) | | | | | |
| Basic | $ | (4.35 | ) | | $ | 8.77 |
| | $ | 5.06 |
|
| Diluted | (4.35 | ) | | 6.76 |
| | 3.96 |
|
| | | | | | |
| Net income (loss) | $ | (24,458 | ) | | $ | 140,047 |
| | $ | 88,667 |
|
| Comprehensive income (loss) from unconsolidated investment and other | 868 |
| | (149 | ) | | (1,647 | ) |
| Comprehensive income (loss) | $ | (23,590 | ) | | $ | 139,898 |
| | $ | 87,020 |
|
| Comprehensive income attributable to non-controlling interest | — |
| | (510 | ) | | — |
|
| Comprehensive income (loss) attributable to NRP | $ | (23,590 | ) | | $ | 139,388 |
| | $ | 87,020 |
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Unitholders | | General Partner | | Accumulated
Other
Comprehensive
Income (Loss) | | Partners' Capital Excluding Non-Controlling Interest | | Non-Controlling Interest | | Total Capital |
| |
| | Units | | Amounts | |
| Balance at December 31, 2013 | 10,983 |
| | $ | 606,774 |
| | $ | 10,069 |
| | $ | (378 | ) | | $ | 616,465 |
| | $ | 324 |
| | $ | 616,789 |
|
| Net income | — |
| | 106,653 |
| | 2,177 |
| | — |
| | 108,830 |
| | — |
| | 108,830 |
|
| Issuance of common units | 1,006 |
| | 127,202 |
| | — |
| | — |
| | 127,202 |
| | — |
| | 127,202 |
|
| Issuance of common units for acquisitions | 243 |
| | 31,604 |
| | — |
| | — |
| | 31,604 |
| | — |
| | 31,604 |
|
| Capital contribution | — |
| | — |
| | 3,240 |
| | — |
| | 3,240 |
| | — |
| | 3,240 |
|
| Cost associated with equity transactions | — |
| | (4,413 | ) | | — |
| | — |
| | (4,413 | ) | | — |
| | (4,413 | ) |
| Distributions to unitholders | — |
| | (158,801 | ) | | (3,241 | ) | | — |
| | (162,042 | ) | | — |
| | (162,042 | ) |
| Distributions to non-controlling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (974 | ) | | (974 | ) |
| Comprehensive loss from unconsolidated investment and other | — |
| | — |
| | — |
| | (81 | ) | | (81 | ) | | — |
| | (81 | ) |
| Balance at December 31, 2014 | 12,232 |
| | $ | 709,019 |
| | $ | 12,245 |
| | $ | (459 | ) | | $ | 720,805 |
| | $ | (650 | ) | | $ | 720,155 |
|
| Net loss | — |
| | (559,492 | ) | | (12,228 | ) | | — |
| | (571,720 | ) | | — |
| | (571,720 | ) |
| Cost associated with equity transactions | — |
| | (109 | ) | | — |
| | — |
| | (109 | ) | | — |
| | (109 | ) |
| Distributions to unitholders | — |
| | (70,324 | ) | | (1,434 | ) | | — |
| | (71,758 | ) | | — |
| | (71,758 | ) |
| Distributions to non-controlling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (2,744 | ) | | (2,744 | ) |
| Non-cash contributions | — |
| | — |
| | 811 |
| | — |
| | 811 |
| | — |
| | 811 |
|
| Comprehensive loss from unconsolidated investment and other | — |
| | — |
| | — |
| | (1,693 | ) | | (1,693 | ) | | — |
| | (1,693 | ) |
| Balance at December 31, 2015 | 12,232 |
| | $ | 79,094 |
| | $ | (606 | ) | | $ | (2,152 | ) | | $ | 76,336 |
| | $ | (3,394 | ) | | $ | 72,942 |
|
| Net income | — |
| | 95,229 |
| | 1,663 |
| | — |
| | 96,892 |
| | — |
| | 96,892 |
|
| Distributions to unitholders | — |
| | (22,014 | ) | | (451 | ) | | — |
| | (22,465 | ) | | — |
| | (22,465 | ) |
| Non-cash contributions | — |
| | — |
| | 281 |
| | — |
| | 281 |
| | — |
| | 281 |
|
| Comprehensive income from unconsolidated investment and other | — |
| | — |
| | — |
| | 486 |
| | 486 |
| | — |
| | 486 |
|
| Balance at December 30, 2016 | 12,232 |
| | $ | 152,309 |
| | $ | 887 |
| | $ | (1,666 | ) | | $ | 151,530 |
| | $ | (3,394 | ) | | $ | 148,136 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Unitholders | | General Partner | | Warrant Holders | | Accumulated
Other
Comprehensive
Loss | | Partners' Capital Excluding Non-Controlling Interest | | Non-Controlling Interest | | Total Capital |
| |
| (In thousands) | Units | | Amounts | |
| Balance at December 31, 2016 | 12,232 |
| | $ | 152,309 |
| | $ | 887 |
| | $ | — |
| | $ | (1,666 | ) | | $ | 151,530 |
| | $ | (3,394 | ) | | $ | 148,136 |
|
Net income (1) | — |
| | 86,894 |
| | 1,773 |
| | — |
| | — |
| | 88,667 |
| | — |
| | 88,667 |
|
| Distributions to common unitholders and general partner | — |
| | (22,018 | ) | | (449 | ) | | — |
| | — |
| | (22,467 | ) | | — |
| | (22,467 | ) |
| Distributions to preferred unitholders | — |
| | (17,334 | ) | | (354 | ) | | — |
| | — |
| | (17,688 | ) | | — |
| | (17,688 | ) |
| Issuance of warrants | — |
| | — |
| | — |
| | 66,816 |
| | — |
| | 66,816 |
| | — |
| | 66,816 |
|
| Comprehensive loss from unconsolidated investment and other | — |
| | — |
| | — |
| | — |
| | (1,647 | ) | | (1,647 | ) | | — |
| | (1,647 | ) |
| Balance at December 31, 2017 | 12,232 |
| | $ | 199,851 |
| | $ | 1,857 |
| | $ | 66,816 |
| | $ | (3,313 | ) | | $ | 265,211 |
| | $ | (3,394 | ) | | $ | 261,817 |
|
| Cumulative effect of adoption of accounting standard | — |
| | 69,057 |
| | 1,409 |
| | — |
| | — |
| | 70,466 |
| | — |
| | 70,466 |
|
Net income (2) | — |
| | 136,746 |
| | 2,791 |
| | — |
| | — |
| | 139,537 |
| | 510 |
| | 140,047 |
|
| Distributions to common unitholders and general partner | — |
| | (22,036 | ) | | (450 | ) | | — |
| | — |
| | (22,486 | ) | | — |
| | (22,486 | ) |
| Distributions to preferred unitholders | — |
| | (29,660 | ) | | (605 | ) | | — |
| | — |
| | (30,265 | ) | | — |
| | (30,265 | ) |
| Issuance of unit-based awards | 17 |
| | 546 |
| | — |
| | — |
| | — |
| | 546 |
| | — |
| | 546 |
|
| Unit-based awards amortization and vesting | — |
| | 560 |
| | — |
| | — |
| | — |
| | 560 |
| | — |
| | 560 |
|
| Comprehensive income (loss) from unconsolidated investment and other | — |
| | 49 |
| | 12 |
| | — |
| | (149 | ) | | (88 | ) | | (51 | ) | | (139 | ) |
| Balance at December 31, 2018 | 12,249 |
| | $ | 355,113 |
| | $ | 5,014 |
| | $ | 66,816 |
| | $ | (3,462 | ) | | $ | 423,481 |
| | $ | (2,935 | ) | | $ | 420,546 |
|
Net loss (2) | — |
| | (23,969 | ) | | (489 | ) | | — |
| | — |
| | (24,458 | ) | | — |
| | (24,458 | ) |
| Distributions to common unitholders and general partner | — |
| | (32,487 | ) | | (663 | ) | | — |
| | — |
| | (33,150 | ) | | — |
| | (33,150 | ) |
| Distributions to preferred unitholders | — |
| | (29,400 | ) | | (600 | ) | | — |
| | — |
| | (30,000 | ) | | — |
| | (30,000 | ) |
| Issuance of unit-based awards | 12 |
| | 486 |
| | — |
| | — |
| | — |
| | 486 |
| | — |
| | 486 |
|
| Unit-based awards amortization and vesting | — |
| | 1,804 |
| | — |
| | — |
| | — |
| | 1,804 |
| | — |
| | 1,804 |
|
| Comprehensive income (loss) from unconsolidated investment and other | — |
| | (76 | ) | | 8 |
| | — |
| | 868 |
| | 800 |
| | — |
| | 800 |
|
| Balance at December 31, 2019 | 12,261 |
| | $ | 271,471 |
| | $ | 3,270 |
| | $ | 66,816 |
| | $ | (2,594 | ) | | $ | 338,963 |
| | $ | (2,935 | ) | | $ | 336,028 |
|
| |
| (1) | Net income includes $25.5 million attributable to preferred unitholders that accumulated during the period, of which $24.9 million is allocated to the common unitholders and $0.5 million is allocated to the general partner. |
| |
| (2) | Net income (loss) includes $30.0 million attributable to preferred unitholders that accumulated during the period, of which $29.4 million is allocated to the common unitholders and $0.6 million is allocated to the general partner. |
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 |
| Cash flows from operating activities | | | | | |
| Net income (loss) | $ | (24,458 | ) | | $ | 140,047 |
| | $ | 88,667 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities of continuing operations: | | | | | |
| Depreciation, depletion and amortization | 14,932 |
| | 21,689 |
| | 23,414 |
|
| Distributions from unconsolidated investment | 31,850 |
| | 44,453 |
| | 43,354 |
|
| Equity earnings from unconsolidated investment | (47,089 | ) | | (48,306 | ) | | (40,457 | ) |
| Gain on asset sales and disposals | (6,498 | ) | | (2,441 | ) | | (3,545 | ) |
| Debt modification expense | — |
| | — |
| | 7,939 |
|
| Loss on extinguishment of debt | 29,282 |
| | — |
| | 4,107 |
|
| Income from discontinued operations | (956 | ) | | (17,687 | ) | | (6,182 | ) |
| Asset impairments | 148,214 |
| | 18,280 |
| | 2,967 |
|
| Bad debt expense | 7,462 |
| | (62 | ) | | 2,353 |
|
| Unit-based compensation expense | 2,361 |
| | 1,434 |
| | 18 |
|
| Amortization of debt issuance costs and other | 3,687 |
| | 7,133 |
| | 10,284 |
|
| Change in operating assets and liabilities: | | | | | |
| Accounts receivable | (6,035 | ) | | (6,062 | ) | | 3,919 |
|
| Accounts payable | (1,234 | ) | | 1,138 |
| | (184 | ) |
| Accrued liabilities | (3,656 | ) | | 19 |
| | (7,963 | ) |
| Accrued interest | (12,029 | ) | | (1,138 | ) | | (105 | ) |
| Deferred revenue | (732 | ) | | 19,465 |
| | (15,957 | ) |
| Other items, net | 2,218 |
| | 320 |
| | (478 | ) |
| Net cash provided by operating activities of continuing operations | $ | 137,319 |
| | $ | 178,282 |
| | $ | 112,151 |
|
| Net cash provided by (used in) operating activities of discontinued operations | (8 | ) | | 10,641 |
| | 14,988 |
|
| Net cash provided by operating activities | $ | 137,311 |
| | $ | 188,923 |
| | $ | 127,139 |
|
| | | | | | |
| Cash flows from investing activities | | | | | |
| Distributions from unconsolidated investment in excess of cumulative earnings | $ | — |
| | $ | 2,097 |
| | $ | 5,646 |
|
| Proceeds from asset sales and disposals | 6,500 |
| | 2,449 |
| | 1,151 |
|
| Return of long-term contract receivables | 1,743 |
| | 3,061 |
| | 3,010 |
|
| Acquisition of mineral rights | (22 | ) | | — |
| | — |
|
| Net cash provided by investing activities of continuing operations | $ | 8,221 |
| | $ | 7,607 |
| | $ | 9,807 |
|
| Net cash provided by (used in) investing activities of discontinued operations | (629 | ) | | 183,021 |
| | (6,264 | ) |
| Net cash provided by investing activities | $ | 7,592 |
| | $ | 190,628 |
| | $ | 3,543 |
|
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 |
| | | | | | |
| Cash flows from financing activities | | | | | |
| Proceeds from issuance of preferred units and warrants, net | $ | — |
| | $ | — |
| | $ | 242,100 |
|
| Debt borrowings | 300,000 |
| | 35,000 |
| | 180,688 |
|
| Debt repayments | (463,082 | ) | | (175,706 | ) | | (492,319 | ) |
| Redemption of preferred units paid-in-kind | — |
| | (8,844 | ) | | — |
|
| Distributions to common unitholders and general partner | (33,150 | ) | | (22,486 | ) | | (22,467 | ) |
| Distributions to preferred unitholders | (30,000 | ) | | (30,265 | ) | | (8,844 | ) |
| Contributions from (to) discontinued operations | (637 | ) | | 195,690 |
| | 5,784 |
|
| Debt issuance costs and other | (26,436 | ) | | (228 | ) | | (39,091 | ) |
| Net cash used in financing activities of continuing operations | $ | (253,305 | ) | | $ | (6,839 | ) | | $ | (134,149 | ) |
| Net cash provided by (used in) financing activities of discontinued operations | 637 |
| | (196,509 | ) | | (7,077 | ) |
| Net cash used in financing activities | $ | (252,668 | ) | | $ | (203,348 | ) | | $ | (141,226 | ) |
| Net increase (decrease) in cash, cash equivalents and restricted cash | $ | (107,765 | ) | | $ | 176,203 |
| | $ | (10,544 | ) |
| | | | | | |
| Cash, cash equivalents and restricted cash of continuing operations at beginning of period | $ | 206,030 |
| | $ | 26,980 |
| | $ | 39,171 |
|
| Cash and cash equivalents of discontinued operations at beginning of period | — |
| | 2,847 |
| | 1,200 |
|
| Cash, cash equivalents and restricted cash at beginning of period | $ | 206,030 |
| | $ | 29,827 |
| | $ | 40,371 |
|
| | | | | | |
| Cash, cash equivalents and restricted cash at end of period | $ | 98,265 |
| | $ | 206,030 |
| | $ | 29,827 |
|
| Less: cash and cash equivalents of discontinued operations at end of period | — |
| | — |
| | (2,847 | ) |
| Cash, cash equivalents and restricted cash of continuing operations at end of period | $ | 98,265 |
| | $ | 206,030 |
| | $ | 26,980 |
|
| | | | | | |
| Supplemental cash flow information: | | | | | |
| Cash paid during the period for interest of continuing operations | $ | 58,597 |
| | $ | 64,991 |
| | $ | 72,850 |
|
| Non-cash investing and financing activities: | | | | | |
| Issuance of 2022 Senior Notes in exchange for 2018 Senior Notes | $ | — |
| | $ | — |
| | $ | 240,638 |
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | 96,892 |
| | $ | (571,720 | ) | | $ | 108,830 |
|
| Adjustments to reconcile net income to net cash provided by operating activities of continuing operations: | | | | | |
| Depreciation, depletion and amortization | 43,087 |
| | 57,295 |
| | 58,586 |
|
| Amortization expense—affiliates | 3,185 |
| | 3,621 |
| | 3,308 |
|
| Distributions from equity earnings from unconsolidated investment | 46,550 |
| | 46,795 |
| | 43,005 |
|
| Equity earnings from unconsolidated investment | (40,061 | ) | | (49,918 | ) | | (41,416 | ) |
| Gain on asset sales, net | (29,081 | ) | | (6,900 | ) | | (1,386 | ) |
| (Income) loss from discontinued operations | (1,678 | ) | | 311,549 |
| | (12,117 | ) |
| Asset impairments | 16,926 |
| | 384,545 |
| | 26,209 |
|
| Gain on reserve swap | — |
| | (9,290 | ) | | (5,690 | ) |
| Other, net | 8,284 |
| | (7,109 | ) | | (5,279 | ) |
| Other, net—affiliates | 993 |
| | (912 | ) | | (180 | ) |
| Change in operating assets and liabilities: | | | | | |
| Accounts receivable | 431 |
| | 7,705 |
| | 4,483 |
|
| Accounts receivable—affiliates | (313 | ) | | 3,149 |
| | (1,828 | ) |
| Accounts payable | 707 |
| | (3,625 | ) | | (8,928 | ) |
| Accounts payable—affiliates | 139 |
| | (32 | ) | | 457 |
|
| Accrued liabilities | 4,618 |
| | 1,420 |
| | 6,002 |
|
| Accrued liabilities—affiliates | (456 | ) | | — |
| | 456 |
|
| Deferred revenue | (35,881 | ) | | 7,605 |
| | 2,056 |
|
| Deferred revenue—affiliates | (11,222 | ) | | (4,200 | ) | | 15,618 |
|
| Other items, net | (2,477 | ) | | (1,466 | ) | | (22 | ) |
| Other items, net—affiliates | — |
| | — |
| | — |
|
| Net cash provided by operating activities of continuing operations | 100,643 |
| | 168,512 |
| | 192,164 |
|
| Net cash provided by operating activities of discontinued operations | 7,318 |
| | 34,912 |
| | 18,591 |
|
| Net cash provided by operating activities | 107,961 |
| | 203,424 |
| | 210,755 |
|
| | | | | | |
| Cash flows from investing activities: | | | | | |
| Proceeds from sale of oil and gas royalty properties | 42,844 |
| | — |
| | — |
|
| Proceeds from sale of coal and aggregate royalty properties | 18,189 |
| | 3,505 |
| | 412 |
|
| Return of long-term contract receivables—affiliate | 2,968 |
| | 2,463 |
| | 1,904 |
|
| Proceeds from sale of plant and equipment and other | 1,350 |
| | 11,024 |
| | 1,006 |
|
| Acquisition of plant and equipment and other | (5,408 | ) | | (9,607 | ) | | (2,454 | ) |
| Acquisition of mineral rights | — |
| | (400 | ) | | (5,035 | ) |
| Acquisition of aggregates business | — |
| | — |
| | (168,978 | ) |
| Return of equity from unconsolidated investment | — |
| | — |
| | 3,633 |
|
| Net cash provided by (used in) investing activities of continuing operations | 59,943 |
| | 6,985 |
| | (169,512 | ) |
| Net cash provided by (used in) investing activities of discontinued operations | 106,872 |
| | (37,256 | ) | | (350,991 | ) |
| Net cash provided by (used in) investing activities | 166,815 |
| | (30,271 | ) | | (520,503 | ) |
| | | | | | |
| Cash flows from financing activities: | | | | | |
| Proceeds from loans | 20,000 |
| | 100,000 |
| | 498,471 |
|
| Proceeds from loan—affiliate | — |
| | — |
| | 19,904 |
|
| Proceeds from issuance of common units | — |
| | — |
| | 127,202 |
|
| Capital contribution by general partner | — |
| | — |
| | 3,240 |
|
| Repayments of loans | (183,141 | ) | | (165,983 | ) | | (318,983 | ) |
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
| | | | | | | | | | | |
| Distributions to unitholders | (22,465 | ) | | (71,758 | ) | | (162,042 | ) |
| Distributions to non-controlling interest | — |
| | (2,744 | ) | | (974 | ) |
| Contributions from (to) discontinued operations | 39,421 |
| | (36,725 | ) | | (226,000 | ) |
| Debt issue costs and other | (15,234 | ) | | (6,054 | ) | | (6,804 | ) |
| Net cash used in financing activities of continuing operations | (161,419 | ) | | (183,264 | ) | | (65,986 | ) |
| Net cash provided by (used in) financing activities of discontinued operations | (124,759 | ) | | 11,808 |
| | 333,297 |
|
| Net cash provided by (used in) financing activities | (286,178 | ) | | (171,456 | ) | | 267,311 |
|
| | | | | | |
| Net increase (decrease) in cash and cash equivalents | (11,402 | ) | | 1,697 |
| | (42,437 | ) |
| | | | | | |
| Cash and cash equivalents of continuing operations at beginning of period | 41,204 |
| | 48,971 |
| | 92,305 |
|
| Cash and cash equivalents of discontinued operations at beginning of period | 10,569 |
| | 1,105 |
| | 208 |
|
| Cash and cash equivalents at beginning of period | 51,773 |
| | 50,076 |
| | 92,513 |
|
| | | | | | |
| Cash and cash equivalents at end of period | 40,371 |
| | 51,773 |
| | 50,076 |
|
| Less: cash and cash equivalents of discontinued operations at end of period | — |
| | 10,569 |
| | 1,105 |
|
| Cash and cash equivalents of continuing operations at end of period | $ | 40,371 |
| | $ | 41,204 |
| | $ | 48,971 |
|
| | | | | | |
| Supplemental cash flow information: | | | | | |
| Cash paid during the period for interest | $ | 84,380 |
| | $ | 85,738 |
| | $ | 75,833 |
|
| Non-cash investing activities: | | | | | |
| Plant, equipment and mineral rights funded with accounts payable or accrued liabilities | $ | — |
| | $ | 4,304 |
| | $ | — |
|
| Units issued for acquisition of aggregates business | $ | — |
| | $ | — |
| | $ | 31,604 |
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning, operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal trona and soda ash, construction aggregates and other natural resources and owns a non-controlling 49% interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining and soda ash production business. The Partnership is organized into threetwo operating segments further described in Note 4.8. Segment Information. As used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or indicated by context.
The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through one wholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. RobertsonSubject to the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with The Blackstone Group Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree"), RCM is entitled to nominate all tenappoint the directors of the directors to the boardBoard of directorsDirectors of GP Natural Resource Partners LLC. Mr. RobertsonLLC (the "Board of Directors"). RCM has delegated the right to nominate two of the directors,appoint one of whom must be independent,director to Adena Minerals, LLC, an affiliate of Christopher Cline.Blackstone.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statementsConsolidated Financial Statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with International Paper Company controlled by the Partnership. The Partnership has an equity investment in Ciner Wyoming through which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the investee’s activities whichand is accounted for using the equity method. Intercompany transactions and balances have been eliminated.
Management’s Going Concern Analysis
While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics Certain reclassifications have been impacted by challenges in coal and other commodity markets. The following going concern analysis includes discussion of the relevant conditions and events and an evaluation of NRP's abilitymade to meet its obligations and remain in compliance with its debt covenants within oneprior year after the issuance date of these financial statements.
In order to mitigate the effect of these adverse market developmentsamounts on the Partnership's ability to remain in compliance with the covenants under its debt agreementsConsolidated Balance Sheets, Consolidated Statements of Comprehensive Income (Loss) and meet scheduled debt principal payments, the Partnership pursued or considered a numberConsolidated Statements of actions. On a cumulative basis since January 1, 2015, the Partnership reduced debt by $339.1 million and completed asset sales for $199 million in gross sales proceeds. In addition, the Partnership completed the following series of recapitalization transactions on March 2, 2017 (see Note 19. Subsequent Events for further detail):the issuance of $250 million of a new class of 12.0% preferred units representing limited partner interests in NRP, together with warrants to purchase common units, to certain entities controlled by funds affiliated with The Blackstone Group, L.P. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree");
the exchange of $241 million of our 9.125% Senior Notes due 2018 (the "2018 Notes") for $241 million of a new series of 10.500% Senior Notes due 2022 (the "2022 Notes"), and the sale of $105 million of additional 2022 Notes in exchange for cash proceeds; and
the extension of Opco’s revolving credit facility (the "Opco Credit Facility") to April 2020, with commitments thereunder reduced to $180 million.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
These recapitalization transactions increased the Partnership's liquidity and reduced the Partnership's 2018 debt maturities by $575 million through the extension of debt principal payments from 2018 to 2020 and 2022. While the Partnership continues to face challenges in coal and other commodity markets, it expects that it will meet all of its obligations, including scheduled principal and interest payments on its debt and required distributions on the convertible preferred units, that it will remain in compliance with its debt covenants and that it will continue as a going concern.
Recasting of Certain Prior Period Information
As described in Note 3. Discontinued Operations, the Partnership has classified the assets and liabilities, operating results and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated financial statements for all periods presented. As described in Note 4. Segment Information, the Partnership has reclassified oil and gas royalty activities in prior period amountsCash Flows to conform to the way it internally manages and monitors segment performance thatwith current year presentation. These reclassifications had no impact on the Partnership's consolidated financial position,previously reported total assets, total liabilities, partners' capital, net income (loss) or cash flows.
On January 1, 2016, the Partnership adopted a new accounting standard using a retrospective approach that required the presentation of the Partnership's debt issuance costs as a direct deductionflows from the related debt liability, rather than recorded as an asset. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $0.2 million and reduced other assets and long-term debt (including affiliate) by $13.8 million on the Partnership’s Consolidated Balance Sheet at December 31, 2015.
Reverse Unit Split
On January 26, 2016, the board of directors of our general partner approved a 1-for-10 reverse split on our common units, effective following market close on February 17, 2016. Pursuant to the authorization provided, the Partnership completed the 1-for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange on February 18, 2016. As a result of the reverse unit split, every 10 outstanding common units were combined into one common unit. The reverse unit split reduced the number of common units outstanding from 122.3 million units to approximately 12.2 million units. All units and per unit data included in the December 31, 2015 consolidated financial statements were retroactively restated to reflect the reverse unit split.operating, investing or financing activities.
Use of Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United StatesGAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities inon the accompanying Consolidated Balance Sheets, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses inon the accompanying Consolidated Statements of Comprehensive Income (Loss) during the reporting period. Actual results could differ from those estimates.
Business Combinations
For purchase acquisitions accounted for as business combinations, the Partnership is required The most significant estimates pertain to record the assets acquired, including identifiedcoal and aggregates reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization and impairments of coal and aggregates properties and related intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques.commitments and contingencies.
Fair Value
The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See "Note 12.Note 13. Fair Value Measurements."Measurements for further details.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
There are three levels of inputs that may be used to measure fair value:
Level 1—Quoted prices in active markets for identical assets or liabilities.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instrumentsassets and liabilities whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.
Cash, and Cash Equivalents
and Restricted Cash
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents. Restricted cash at December 31, 2018 included cash proceeds received from the sale of the Partnership's construction aggregates business that the Partnership used to repay debt in 2019.
Allowance for Doubtful Accounts Receivable
Accounts receivable from the Partnership’s lessees and customers do not bear interest. Receivables are recorded net of theThe Partnership records an allowance for doubtful accounts in the accompanying Consolidated Balance Sheets. The Partnership evaluates the collectability offor its accounts receivablereceivables and notes receivables which it determines to be uncollectible based on a combination of factors. The Partnership regularly analyzes its accounts receivable and when it becomes aware of athe specific lessee’s or customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s or customer’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. The reserve is recognized as a reduction in the accounts receivable and an increase in operating and maintenance expenses or operating and maintenance expenses—affiliates. Accountsidentification method. Receivables are chargedwritten off when collection efforts are completeexhausted and future recovery is doubtful. The allowance for doubtful accounts receivable is included in accounts receivable, net and the allowance for doubtful accounts for notes receivable is included in prepaid expenses and other, net on the Partnership's netConsolidated Balance Sheets, respectively. The allowance for doubtful accounts receivable balance (including affiliates)related to accounts receivables was $4.6 million and $5.3$0.4 million at December 31, 2016 and December 31, 2015, respectively. A significant amount of the Partnership's2019. The allowance for doubtful accounts relatesrelated to allowances for doubtful coal-related receivables.
Inventory
Inventories are statednotes receivables was $1.2 million at the lowerDecember 31, 2019 and 2018. The Partnership recorded bad debt expense of cost or market. The cost of aggregates$7.5 million, $(0.1) million and asphalt components such as stone, sand, and recycled and liquid asphalt is determined by the first-in, first-out (FIFO) method. Cost includes all direct materials, direct labor and related production overheads based on normal operating capacity. The cost of supplies inventory is determined by the average cost method and includes$2.4 million included in operating and maintenance supplies to be used in the Partnership’s aggregates operations.
Plant and Equipment
Plant and equipment is recorded atexpenses on its original cost of construction or, upon acquisition, at fair value of the asset acquired and consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at costComprehensive Income (Loss) for the years ended December 31, 2019, 2018 and are depreciated on a straight-line basis over their useful lives generally as follows:
|
| |
| Years |
Buildings and improvements | 20 to 40 |
Machinery and equipment | 5 to 12 |
Leasehold improvements | Life of Lease |
The Partnership begins capitalizing mine development costs at its aggregates operations at a point when reserves are determined to be proven or probable, economically mineable and when demand supports investment in the market. Capitalization of these costs ceases when production commences. Mine development costs are amortized based on production over the estimated life of mineral reserves and amortization is included as a component of depreciation expense.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
2017, respectively.
Mineral Rights
Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregateaggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.
Intangible Assets
The Partnership’s intangible assets consist primarily of mineral royalty and transportation contracts that at acquisition were more favorable for the Partnership than prevailing market rates, known as above-market contracts. The estimated fair valuesvalue of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis except that a minimum amortization is calculated on a straight-line basis for temporarily idled assets.by asset based upon minerals mined or transported in relation to the net book value of the intangible asset and estimated proven and probable tonnage expected to be mined or transported during the above-market contract term.
Asset Impairment
The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These proceduresimpairment periodically or whenever events or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are performed throughout the year and arenot limited to, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period. This analysis is based on historic, current and future performance and are designed to be early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carryingasset's net book value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flowflows compared to the assets’ carryingasset's net book value. The Partnership believes its estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership evaluates its equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices (Level 1), or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants (Level 3), plus market analysis of comparable assets owned by the investee, if appropriate.appropriate (Level 3).
Accrued Liabilities
Included in accrued liabilities on the Partnership's Consolidated Balance Sheets at December 31, 2019 were $3.7 million of accrued employee costs and $5.0 million of other accrued liabilities, which includes property and franchise taxes and disputed well liabilities.
Revenue Recognition
Coal Royalty and Other Revenues.Segment Revenues
Royalty-based leases. Coal royalty and other revenues are recognized onApproximately two-thirds of the basisPartnership's royalty-based leases have initial terms of tonsfive to 40 years, with substantially all lessees having the option to extend the lease for additional terms. For these types of mineral sold by our lessees and the corresponding revenue from those sales. Generally,leases, the lessees generally make payments to usNRP based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons of material processed through the facilities by our lesseesmined and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, the Partnership receives a fixed price per ton for all material transported on the beltlines.
sold. Most of the Partnership’sNRP’s coal and aggregates lessees mustroyalty leases require the lessee to pay the Partnershipquarterly or annual minimum annualamounts, either made in advance or quarterly amountsarrears, which are generally recoupable out ofthrough actual royalty production over certain time periods. Theseperiods that generally range from three to five years.
In accordance with previous accounting standards in effect prior to January 1, 2018, the Partnership recognized all coal and aggregates royalty revenues over the lease term based on production. The recognition of revenue from minimum payments are recordedwas deferred until either recoupment through royalty production occurred or when the recoupment period expired for unrecouped minimums. In accordance with the accounting standard in effect subsequent to January 1, 2018 ("ASC 606"), management has defined NRP's coal and aggregates royalty lease performance obligation as deferredproviding the lessee the right to mine and sell NRP's coal or aggregates over the lease term. The Partnership then evaluated the likelihood that consideration NRP expected to receive from its lessees resulting from production would exceed consideration expected to be received from minimum payments over the lease term.
As a result of this evaluation, revenue liability when received. The deferredrecognition from the Partnership's royalty-based leases is based on either production or minimum payments as follows:
Production Leases: Leases for which the Partnership expects that consideration from production will be greater than consideration from minimums over the lease term. Revenue recognition for these leases is recognized over time based on production as coal royalty revenues or aggregates royalty revenues, as applicable. Deferred revenue attributable to the minimum paymentfrom minimums is recognized as revenue based upon the underlying mineralroyalty revenues when recoupment occurs or as production lease minimum revenues when the lessee recoupsrecoupment period expires. In addition, NRP recognizes breakage revenue from minimums when NRP determines that recoupment is remote. This breakage revenue is included in production lease minimum revenues.
Minimum Leases: Leases for which the Partnership expects that consideration from minimums will be greater than consideration from production over the lease term. Revenue recognition for these leases is recognized straight-line over the lease term based on the minimum payment through production or inconsideration amount as minimum lease straight-line revenues.
This evaluation is performed at the period immediately following the expirationinception of the lessee’s ability to recouplease and only reassessed upon modification or renewal of the payments.
lease.
Oil and gas related revenues consist of revenues from royalties and overriding royalties. Oilroyalties and gas royalty revenues are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenuerevenues from those sales. Also, included within oil and gas royaltiesroyalty revenues are lease bonus payments, which are generally paid upon the execution of a lease. The Partnership also has overriding royalty revenue interests in coal reserves. Revenues from these interests are recognized over time based on when the coal is sold.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property owned by the Partnership that is recognized over time as transportation across the property occurs.
Other revenues. Other revenues consists primarily of rental payments and surface damage fees related to certain land owned by the Partnership and is recognized straight-line over time as it is earned. Other revenues also include property tax revenues. The majority of property taxes paid on the Partnership's properties are reimbursable by the lessee and are recognized on a gross basis over time which reflects the reimbursement of property taxes by the lessee. Property taxes paid by NRP are included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
Transportation and processing services revenues. ThePartnership owns transportation and processing infrastructure that is leased to third parties for throughput fees. Revenue is recognized over time based on the coal tons transported over the beltlines or processed through the facilities.
Contract Modifications
Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A majority of the Partnership's contract modifications pertain to its coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices or minimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within coal royalty and other revenues on the Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognized prospectively in accordance with the above lease classification.
Contract Assets and Liabilities from Contracts with Customers
Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes unconditional. Receivables are recognized when the minimums are contractually owed, production occurs or minimums accrued for based on the passage of time.
Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time. The current portion of deferred revenue relates to deferred revenue on minimum leases and lease amendment fees that are to be recognized as revenue on a straight-line basis over the next twelve months. The long-term portion of deferred revenue relates to deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-line basis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as coal royalty revenues from its production leases over the next twelve months, the Partnership is unable to estimate the current portion of deferred revenue.
Equity in Earnings fromof Ciner Wyoming. Wyoming
The Partnership accounts for non-marketable equity investments using the equity method of accounting if the investment gives usit the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if the Partnership has an ownership interest representing between 20% and 50% of the voting stock of the investee. The Partnership accounts for itsPartnership's 49% investment in Ciner Wyoming is accounted for using this method.
Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets is hypothetically allocated first to identified tangible assets and liabilities, then to finite-lived intangibles or indefinite-lived intangibles and the balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived intangibles, if any, and goodwill are not amortized.life. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income.
Our carrying value in Ciner Wyoming is reflectedrecognized in the caption "Equityequity in unconsolidated investments" in ourinvestment on the Partnership's Consolidated Balance Sheets. OurThe Partnership's adjusted share of the earnings or losses of Ciner Wyoming and amortization of the basis difference is reflectedrecognized in equity in earnings of Ciner Wyoming on the Consolidated Statements of Comprehensive Income (Loss). The Partnership decreases its investment for its proportional share of distributions received from Ciner Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are considered returns on investment and classified as revenues and other income underoperating cash inflows unless the caption ‘‘Equitycumulative distributions received exceed the Partnership's cumulative equity in earnings. The excess of cumulative distributions received over the Partnership's cumulative equity in earnings of Ciner Wyoming." Our share of investee earnings are adjusted to reflect the amortizationconsidered returns of any difference between the cost basis of the equity investment and the proportionate share of the investee’s net assets, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets.classified as investing cash inflows.
VantaCore Revenues. Revenues from the sale71
Table of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to the estimated total costs for each contract. That method is used since the Partnership considers total cost to be the best available measure of progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred.Contents NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Property Taxes
The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in Coal Royalty and Other revenues and in Operatingoperating and maintenance expenses and in coal royalty and other revenues, respectively, inon the Consolidated Statements of Comprehensive Income.Income (Loss).
Transportation Revenues and Expenses
Transportation Revenue and Expense
The CompanyPartnership records transportation revenueand processing revenues and pays transportation and processing costs to aan affiliate of Foresight affiliateEnergy LP to operate equipment on behalf of the Company.Partnership. The revenuerevenues and expenses related to these transactions are recorded as Coal Royaltytransportation and Other—affiliatesprocessing services revenues and Operatingoperating and maintenance expenses—affiliates inexpenses, respectively, on the Consolidated Statements of Comprehensive Income. Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as VantaCore revenues and Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income. Shipping and handling revenue included in VantaCore revenues was $36.0 million, $42.6 million and $14.0 millionIncome (Loss). See Note 14. Related Party Transactions for the years ended December 31, 2016, 2015 and 2014, respectively. Shipping and handling costs included in Operating and maintenance expenses was $35.9 million, $42.1 million and $13.9 million for the years ended December 31, 2016, 2015, and 2014, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
more information.
Unit-Based Compensation
The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units that are more fully described in Note 16. Unit-Based Compensation. A summary of our accounting policyunits. Compensation cost is measured at the grant date for unit-basedequity-classified awards follows.
The Partnership accountsand remeasured each reporting period for
liability-classified awards
relating to its unit-based Long-Term Incentive Plan using the fair value method, which requires the Partnership to estimatebased on the fair value of
the grant,an award and
charge or credit the estimated fair value to expense over the requisite service period of the grant based on fluctuations in the Partnership’s common unit price. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability and the fair value is
recalculated at each reporting daterecognized over the service
orperiod, which is generally the vesting
periodperiod. Forfeitures are recognized as they occur. Unit-based compensation expense for all awards is recognized in general and administrative expenses and operating and maintenance expenses on the Consolidated Statements of
the grant.Comprehensive Income (Loss). See Note 17. Unit-Based Compensation for more information.
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These costs are amortized over the term of the debt.respective line-of-credit or debt arrangements. Deferred financing costs for existing debt agreementsrelated to the Partnership's revolving credit facility are included as a a direct deduction from the related debt liabilityin other assets, net on the Partnership's Consolidated Balance Sheets. Deferred financing costs that the Partnership has incurred related to its restructuring effortsthe Partnership's note agreements are included as a direct deduction from the carrying amount of the debt liability in Other Assetscurrent portion of long-term debt, net or long-term debt, net on the Partnership's Consolidated Balance Sheets until the related debt agreement has been executed.Sheets.
Income Taxes
The Partnership is not subject to federal or material state income taxes as the partnersunitholders are taxed individually on their allocable share of taxable income. Net income (loss) for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basesbasis and financial reporting basesbasis of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the partnersunitholders could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.
Lessee Audits and Inspections
The Partnership periodically audits lessee information by examining certain records and internal reports of its lessees. The Partnership’s regional managers also perform periodic mine inspections to verify that the information that has been reported to the Partnership is accurate. The audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to the Partnership and the actual results from each property. Audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the revenue was initially recorded. Typically there are no material adjustments from this process.
Recently IssuedAdopted Accounting Standards
The FinancialLeases
On January 1, 2019, NRP adopted Accounting Standards Board ("FASB"Codification (ASC) 842, Leases, and all the related amendments (the “new lease standard” and "ASC 842") issued guidance that requires an entity's management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The Partnership adopted this guidance on December 31, 2016. For additional information, see Management’s Going Concern Analysis located in this footnote above.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The FASB issued authoritative guidance on revenue recognition. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance will also require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. The Partnership is required to adopt this guidance in the first quarter of 2018 using one of two retrospective application methods. The Partnership has performed revenue scoping procedures to identify the contracts for all of its revenue streams and utilized the practical expedient of grouping contracts or performance obligations with similar characteristics as prescribed by the new standard. The Partnership is currently evaluating these contracts and while the effect of adoption is unknown, it is not currently aware of any material changes that would result from adoption of this new revenue recognition guidance and expects to complete its assessment of how it will be affected in the second quarter of 2016. The Partnership anticipates utilizing the full retrospective adoption method for financial statement comparability and electing the practical expedient of not restating contracts that begin and are completed within the same annual reporting period.
The FASB issued authoritative guidance which intended to simplify the measurement of inventory. This guidance requires an entity to measure inventory at the lower of cost or net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This guidance is effective for annual and interim periods beginning after December 15, 2016. The Partnership does not expect for the adoption of this guidance to have a material impact on its consolidated financial statements.
The FASB issued authoritative lease guidance that requires lessees to recognizerecognized assets and liabilities on the balance sheetits Consolidated Balance Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. This standard does not apply to leases that explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. The guidance also requiresrequired disclosures designed to give financial statement users information on the amount, timing and uncertainty of cash flows arising from leases. The guidance is effective for annual and interim periods ending after December 31, 2018. was adopted by NRP on January 1, 2019 using a modified retrospective approach.
The Partnership is currently evaluatinga lessee in one lease that is accounted for as an operating lease under the impactnew lease standard, and the adoption of the provisionsnew lease standard did not have a material impact to the Partnership's Consolidated Financial Statements. For lease agreements entered into or reassessed after the adoption of this guidance on its consolidated financial statements.ASC 842, the Partnership elected to not combine lease and non-lease components. See Note 19. Leases for more information.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Recently Issued Accounting Standards
Credit Losses
In June 2016, the FASB issued authoritative guidance that replaces the incurred loss impairment methodology in the currentASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326). The new standard with a methodology that reflects expectedchanges how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new standard replaces today's "incurred loss" model with an "expected credit loss" model that requires consideration of a broader range of reasonable and supportable informationentities to informestimate an expected lifetime credit loss estimates.on financial assets, including trade accounts receivable. The guidance is effective for annual and interim periods endingbeginning after December 31, 2019. The Partnership15, 2019 and is currently evaluating the impactto be adopted using a modified retrospective approach. As a result of implementation of the provisionsnew standard the Partnership expects to record an approximate $5 million reduction of its financial assets and a corresponding decrease in Partners' Capital on January 1, 2020. NRP does not expect this guidancestandard to have a material effect on its consolidated financial statements.
The FASB issued authoritative guidanceConsolidated Financial Statements subsequent to clarify how certain cash receipts and cash payments are presented and classified in the statement of cash flows in order to reduce current and potential future diversity in practice. The guidance is effective for annual and interim periods ending after December 31, 2017. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.
adoption.
3. Discontinued Operations
In June 2016, NRP Oil and Gas signed a definitive agreement to sell its non-operated oil and gas working interest assets assets for $116.1 million in gross sales proceeds, and the Partnership determined it met the criteria required for held for sale classification. In July 2016, NRP Oil and Gas closed this transaction, which had an effective date of April 1, 2016.
Revenues from Contracts with Customers
The Partnership's exit from its non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on its construction aggregates, soda ash and coal royalty and other business segments. As a result,following table represents the Partnership classified the operating results, cash flows and assets and liabilities of its non-operated oil and gas working interest assets as discontinued operations in its consolidated statements of comprehensive income and consolidated statements of cash flows for all periods presented. The Partnership transitioned the remaining investments in royalty interests in oil and natural gas properties into thePartnership's Coal Royalty and Other operating segment during the third quarter of 2016.revenues by major source:
|
| | | | | | | | |
| | | Year Ended December 31, |
| (In thousands) | | 2019 | | 2018 |
| Coal royalty revenues | | $ | 109,612 |
| | $ | 129,341 |
|
| Production lease minimum revenues | | 24,068 |
| | 8,207 |
|
| Minimum lease straight-line revenues | | 14,910 |
| | 2,362 |
|
| Property tax revenues | | 6,287 |
| | 5,422 |
|
| Wheelage revenues | | 5,880 |
| | 6,484 |
|
| Coal overriding royalty revenues | | 13,496 |
| | 13,878 |
|
| Lease amendment revenues | | 7,991 |
| | — |
|
| Aggregates royalty revenues | | 4,265 |
| | 4,739 |
|
| Oil and gas royalty revenues | | 3,031 |
| | 6,608 |
|
| Other revenues | | 1,529 |
| | 1,837 |
|
Coal royalty and other revenues (1) | | $ | 191,069 |
| | $ | 178,878 |
|
Transportation and processing services revenues (2) | | 19,279 |
| | 23,887 |
|
| Total Coal royalty and Other segment revenues | | $ | 210,348 |
| | $ | 202,765 |
|
| |
| (1) | Coal royalty and other revenues from contracts with customers as defined under ASC 606. |
| |
| (2) | Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $9.6 million and $13.2 million for the year ended December 31, 2019 and 2018, respectively. The remaining transportation and processing services revenues of $9.7 million and $10.7 million for the year ended December 31, 2019 and 2018, respectively, related to other NRP-owned infrastructure leased to and operated by third-party operators accounted for under other guidance. See Note 18. Financing Transaction and Note 19. Leases for more information. |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table (in thousands) presents summarized financial results ofdetails the Partnership's discontinued operations in the Consolidated Statements of Comprehensive Income:Coal Royalty and Other segment receivables and liabilities resulting from contracts with customers:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Revenues and other income: | | | | | |
| Oil and gas | $ | 16,486 |
| | $ | 48,750 |
| | $ | 48,834 |
|
| Gain on asset sales | 8,274 |
| | 451 |
| | — |
|
| Total revenues and other income | 24,760 |
| | 49,201 |
| | 48,834 |
|
| | | | | | |
| Operating expenses: | | | | | |
| Operating and maintenance expenses (including affiliates) | 11,503 |
| | 19,724 |
| | 18,073 |
|
| Depreciation, depletion and amortization | 7,527 |
| | 39,912 |
| | 17,982 |
|
| Asset impairments | 564 |
| | 297,049 |
| | — |
|
| Total operating expenses | 19,594 |
| | 356,685 |
| | 36,055 |
|
| | | | | | |
| Interest expense | (3,488 | ) | | (4,065 | ) | | (662 | ) |
| Income (loss) from discontinued operations | $ | 1,678 |
| | $ | (311,549 | ) | | $ | 12,117 |
|
The following table (in thousands) presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations in the Consolidated Balance Sheets:
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | 10,569 |
|
| Accounts receivable, net (including affiliates) (1) | 991 |
| | 7,053 |
|
| Other | — |
| | 222 |
|
| Total current assets | 991 |
| | 17,844 |
|
| Mineral rights, net | — |
| | 109,505 |
|
| Other non-current assets | — |
| | 657 |
|
| Total assets of discontinued operations | $ | 991 |
| | $ | 128,006 |
|
| | | | |
| LIABILITIES | | | |
| Current liabilities: | | | |
| Other (including affiliates) (1) | $ | 353 |
| | $ | 4,388 |
|
| Total current liabilities | 353 |
| | 4,388 |
|
| Long-term debt, net (2) | — |
| | 83,600 |
|
| Other non-current liabilities | — |
| | 1,637 |
|
| Total liabilities of discontinued operations | $ | 353 |
| | $ | 89,625 |
|
|
| | | | | | | | |
| | | December 31, |
| (In thousands) | | 2019 | | 2018 |
| Receivables | | | | |
| Accounts receivable, net | | $ | 27,915 |
| | $ | 29,001 |
|
Prepaid expenses and other (1) | | 90 |
| | 2,483 |
|
| | | | | |
| Contract liabilities | | | | |
| Current portion of deferred revenue | | $ | 4,608 |
| | $ | 3,509 |
|
| Deferred revenue | | 47,213 |
| | 49,044 |
|
| |
| (1) | See Note 13. Related Party Transactions for additional information on the Partnership's related party assetsPrepaid expenses and liabilities.other includes notes receivable from contracts with customers. |
The following table shows the activity related to the Partnership's Coal Royalty and Other segment deferred revenue:
|
| | | | | | | | |
| | | Year Ended December 31, |
| (In thousands) | | 2019 | | 2018 |
| Balance at end of prior period (current and non-current) | | $ | 52,553 |
| | $ | 100,605 |
|
| Cumulative adjustment for change in accounting principle | | — |
| | (65,591 | ) |
| Balance at beginning of period (current and non-current) | | $ | 52,553 |
| | $ | 35,014 |
|
| Increase due to minimums and lease amendment fees | | 47,038 |
| | 37,781 |
|
| Recognition of previously deferred revenue | | (47,770 | ) | | (20,242 | ) |
| Balance at end of period (current and non-current) | | $ | 51,821 |
| | $ | 52,553 |
|
The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty and overriding royalty leases are as follows (in thousands):
|
| | | | | | |
Lease Term (1) | | Weighted Average Remaining Years as of December 31, 2019 | | Annual Minimum Payments (2) |
| 0 - 5 years | | 2.3 | | $ | 13,812 |
|
| 5 - 10 years | | 6.2 | | 9,718 |
|
| 10+ years | | 11.9 | | 44,757 |
|
| Total | | 9.1 | | $ | 68,287 |
|
| |
| (1) | Lease term does not include renewal periods. |
| |
| (2) | The Partnership identified the RBL FacilityAnnual minimum payments do not include $5.0 million from a coal infrastructure lease that is accounted for as specifically attributed to its non-operated oil and gas working interest assets and included the interest from this debt in discontinued operations.a financing transaction. See Note 11. Debt and Debt—Affiliate18. Financing Transaction for additional information on the Partnership's debt related to discontinued operations.information. |
4. Discontinued Operations
In December 2018, the Partnership sold VantaCore Partners LLC, its construction aggregates materials business for $205 million, before customary purchase price adjustments and transaction expenses, and recorded a gain of $13.1 million, and in July 2016, the Partnership sold its non-operated oil and gas working interest assets. The following table (in thousands) presents supplementalPartnership's exit from both its construction aggregates business and non-operated oil and gas working interest business represented strategic shifts to reduce debt and focus on its Coal Royalty and Other and Soda Ash business segments. As a result, the Partnership classified the assets and liabilities, operating results and cash flow informationflows of the Partnership'sthese businesses as discontinued operations:operations on its Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Cash Flows for all periods presented.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Cash paid for interest | $ | 1,906 |
| | $ | 2,755 |
| | $ | 322 |
|
| Plant, equipment and mineral rights funded with accounts payable or accrued liabilities | — |
| | 1,645 |
| | 11,879 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations on the Consolidated Balance Sheets:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| (In thousands) | Construction Aggregates | | NRP
Oil and Gas | | Total | | Construction Aggregates | | NRP
Oil and Gas | | Total |
| ASSETS | | | | | | | | | | | |
| Current assets | | | | | | | | | | | |
| Accounts receivable, net | $ | — |
| | $ | 1,706 |
| | $ | 1,706 |
| | $ | 5 |
| | $ | 988 |
| | $ | 993 |
|
| Total assets of discontinued operations | $ | — |
| | $ | 1,706 |
| | $ | 1,706 |
|
| $ | 5 |
|
| $ | 988 |
|
| $ | 993 |
|
| | | | | | | | | | | | |
| LIABILITIES | | | | | | | | | | | |
| Current liabilities | | | | | | | | | | | |
| Accounts payable | $ | 42 |
| | $ | — |
| | $ | 42 |
| | $ | 181 |
| | $ | — |
| | $ | 181 |
|
| Accrued liabilities | 23 |
| | — |
| | 23 |
| | 766 |
| | — |
| | 766 |
|
| Total liabilities of discontinued operations | $ | 65 |
| | $ | — |
| | $ | 65 |
| | $ | 947 |
| | $ | — |
| | $ | 947 |
|
The following tables present summarized financial results of the Partnership's discontinued operations on the Consolidated Statements of Comprehensive Income (Loss):
|
| | | | | | | | | | | |
| | For the Year Ended December 31, 2019 |
| (In thousands) | Construction Aggregates | | NRP Oil and Gas | | Total |
| Revenues and other income | | | | | |
| Oil and gas | $ | — |
| | $ | 2 |
| | $ | 2 |
|
| Gain on asset sales and disposals | 280 |
| | — |
| | 280 |
|
| Total revenues and other income | $ | 280 |
| | $ | 2 |
| | $ | 282 |
|
| | | | | |
|
| Operating expenses | | | | |
|
| Operating and maintenance expenses | $ | 27 |
| | $ | 16 |
| | $ | 43 |
|
| Total operating expenses | $ | 27 |
| | $ | 16 |
| | $ | 43 |
|
| | | | | | |
| Other income | $ | — |
| | $ | 717 |
| | $ | 717 |
|
| Income from discontinued operations | $ | 253 |
| | $ | 703 |
| | $ | 956 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | |
| | For the Year Ended December 31, 2018 |
| (In thousands) | Construction Aggregates | | NRP Oil and Gas | | Total |
| Revenues and other income | | | | | |
| Construction aggregates | $ | 116,066 |
| | $ | — |
| | $ | 116,066 |
|
| Road construction and asphalt paving services | 18,400 |
| | — |
| | 18,400 |
|
| Oil and gas | — |
| | (3 | ) | | (3 | ) |
| Gain on asset sales and disposals | 13,414 |
| | — |
| | 13,414 |
|
| Total revenues and other income | $ | 147,880 |
| | $ | (3 | ) | | $ | 147,877 |
|
| | | | | | |
| Operating expenses | | | | | |
| Operating and maintenance expenses | $ | 117,568 |
| | $ | 134 |
| | $ | 117,702 |
|
| Depreciation, depletion and amortization | 12,218 |
| | — |
| | 12,218 |
|
| Asset impairments | 232 |
| | — |
| | 232 |
|
| Total operating expenses | $ | 130,018 |
| | $ | 134 |
| | $ | 130,152 |
|
| | | | | | |
| Interest expense | $ | (38 | ) | | $ | — |
| | $ | (38 | ) |
| Income (loss) from discontinued operations | $ | 17,824 |
| | $ | (137 | ) | | $ | 17,687 |
|
|
| | | | | | | | | | | |
| | For the Year Ended December 31, 2017 |
| (In thousands) | Construction Aggregates | | NRP Oil and Gas | | Total |
| Revenues and other income | | | | | |
| Construction aggregates | $ | 112,970 |
| | $ | — |
| | $ | 112,970 |
|
| Road construction and asphalt paving services | 18,411 |
| | — |
| | 18,411 |
|
| Oil and gas | — |
| | 38 |
| | 38 |
|
| Gain (loss) on asset sales and disposals | 311 |
| | (289 | ) | | 22 |
|
| Total revenues and other income | $ | 131,692 |
| | $ | (251 | ) | | $ | 131,441 |
|
| | | | | | |
| Operating expenses | | | | | |
| Operating and maintenance expenses | $ | 111,633 |
| | $ | 290 |
| | $ | 111,923 |
|
| Depreciation, depletion and amortization | 12,579 |
| | — |
| | 12,579 |
|
| Asset impairments | 64 |
| | — |
| | 64 |
|
| Total operating expenses | $ | 124,276 |
| | $ | 290 |
| | $ | 124,566 |
|
| | | | | | |
| Interest expense | $ | (693 | ) | | $ | — |
| | $ | (693 | ) |
| Income (loss) from discontinued operations | $ | 6,723 |
| | $ | (541 | ) | | $ | 6,182 |
|
Capital expenditures related to the Partnership's discontinued operations were $1.4 million, $30.6$10.9 million and $359.9$7.6 million during the years months ended December 31, 2016, 20152018 and 2014,2017, respectively, of which $0.9 million and $0.3 million were funded with accounts payable or accrued liabilities during 2018 and 2017, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
5. Class A Convertible Preferred Units and Warrants
On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "preferred units") to certain entities controlled by funds affiliated with The Blackstone Group Inc. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree") (together the "preferred purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000 preferred units to the preferred purchasers at a price of $1,000 per preferred unit (the "per unit purchase price"), less a 2.5% structuring and origination fee. The preferred units entitle the preferred purchasers to receive cumulative distributions at a rate of 12% of the purchase price per year, up to one half of which NRP may pay in additional preferred units (such additional preferred units, the "PIK units"). The preferred units have a perpetual term, unless converted or redeemed as described below.
NRP also issued two tranches of warrants (the "warrants") to purchase common units to the preferred purchasers (warrants to purchase 1.75 million common units with a strike price of $22.81 and warrants to purchase 2.25 million common units with a strike price of $34.00). The warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the warrants, NRP may, at its option, elect to settle the warrants in common units or cash, each on a net basis.
After March 2, 2022 and prior to March 2, 2025, the holders of the preferred units may elect to convert up to 33% of the outstanding preferred units in any 12-month period into common units if the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to date notice is provided is greater than $51.00. In such case, the number of common units to be issued upon conversion would be equal to the per unit purchase price plus the value of any accrued and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Rather than have the preferred units convert to common units in accordance with the provisions of this paragraph, NRP would have the option to elect to redeem the preferred units proposed to be converted for cash at a price equal to the per unit purchase price plus the value of any accrued and unpaid distributions.
On or after March 2, 2025, the holders of the preferred units may elect to convert the preferred units to common units at a conversion rate equal to the Liquidation Value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. The “liquidation value” will be an amount equal to the greater of: (1) (a) the per unit purchase price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021, 1.70 and (iii) on or after March 2, 2021, 1.85, less (b)(i) all preferred unit distributions previously made by NRP and (ii) all cash payments previously made in respect of redemption of any PIK units; and (2) the per unit purchase price plus the value of all accrued and unpaid distributions.
To the extent the holders of the preferred units have not elected to convert their preferred units before March 2, 2029, NRP has the right to force conversion of the preferred units at a price equal to the liquidation value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion.
In addition, NRP has the ability to redeem at any time (subject to compliance with its debt agreements) all or any portion of the preferred units and any outstanding PIK units for cash. The redemption price for each outstanding PIK unit is $1,000 plus the value of any accrued and unpaid distributions per PIK unit. The redemption price for each preferred unit is the liquidation value divided by the number of outstanding preferred units. The preferred units are redeemable at the option of the preferred purchasers only upon a change in control.
The terms of the preferred units contain certain restrictions on NRP's ability to pay distributions on its common units. To the extent that either (i) NRP's consolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership Agreement dated March 2, 2017 (the "restated partnership agreement"), is greater than 3.25x, or (ii) the ratio of NRP's Distributable Cash Flow (as defined in the Restated Partnership Agreement) to cash distributions made or proposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), NRP may not increase the quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding preferred units. In addition, if at any time after January 1, 2022, any PIK units are outstanding, NRP may not make distributions on its common units until it has redeemed all PIK units for cash.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The holders of the preferred units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rights with respect to changes of the terms of the preferred units. In addition, Blackstone has certain approval rights over certain matters as identified in the restated partnership agreement. GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the minimum preferred unit threshold (as defined below). These approval rights are not transferrable without NRP's consent. In addition, the approval rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of preferred units issued on the closing date, together with all PIK units that have been issued but not redeemed (the "minimum preferred unit threshold").
At the closing, pursuant to the Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights, and Blackstone appointed one director and one observer to the Board of Directors.
NRP also entered into a registration rights agreement (the "preferred unit and warrant registration rights agreement") with the preferred purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the preferred units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of preferred units (the "registration deadlines"). In addition, the preferred unit and warrant registration rights agreement gives the preferred purchasers piggyback registration and demand underwritten offering rights under certain circumstances. The shelf registration statement to register the common units issuable upon exercise of the warrants became effective on April 20, 2017. If the shelf registration statement to register the common units issuable upon conversion of the preferred units is not effective by the applicable registration deadline, NRP will be required to pay the preferred purchasers liquidated damages in the amounts and upon the term set forth in the preferred unit and warrant registration rights agreement.
Accounting for the Preferred Units and Warrants
Classification
The preferred units are accounted for as temporary equity on NRP's Consolidated Balance Sheets due to certain contingent redemption rights that may be exercised at the election of preferred purchasers. The warrants are accounted for as equity on NRP's Consolidated Balance Sheets.
Initial Measurement
The net transaction price as shown below was allocated to the preferred units and warrants based on their relative fair values at inception date. NRP allocated the transaction issuance costs to the preferred units and warrants primarily on a pro-rata basis based on their relative inception date allocated values.
The preferred units and warrants were initially recognized as follows:
|
| | | | |
| (In thousands) | | March 2, 2017 |
| Transaction price, gross | | $ | 250,000 |
|
| Structuring, origination and other fees to preferred purchasers | | (7,900 | ) |
| Transaction costs to other third parties | | (10,697 | ) |
| Transaction price, net | | $ | 231,403 |
|
| Allocation of net transaction price | | |
| Preferred units, net | | $ | 164,587 |
|
| Warrant holders interest, net | | 66,816 |
|
| Transaction price, net | | $ | 231,403 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Subsequent Measurement
Subsequent adjustment of the preferred units will not occur until NRP has determined that the conversion or redemption of all or a portion of the preferred units is probable of occurring. Once conversion or redemption becomes probable of occurring, the carrying amount of the preferred units will be accreted to their redemption value over the period from the date the feature is probable of occurring to the date the preferred units can first be converted or redeemed.
Activity related to the preferred units is as follows:
|
| | | | | | | |
| (In thousands, except unit data) | | Units Outstanding | | Financial Position |
| Balance at December 31, 2016 | | — |
| | $ | — |
|
| Issuance of preferred units, net | | 250,000 |
| | 164,587 |
|
| Distribution paid-in-kind | | 8,844 |
| | 8,844 |
|
| Balance at December 31, 2017 | | 258,844 |
| | $ | 173,431 |
|
| Redemption of PIK units | | (8,844 | ) | | (8,844 | ) |
| Balance at December 31, 2018 and 2019 | | 250,000 |
| | $ | 164,587 |
|
Subsequent adjustment of the warrants will not occur until the warrants are exercised, at which time, NRP may, at its option, elect to settle the warrants in common units or cash, each on a net basis. The net basis will be equal to the difference between the Partnership's common unit price and the strike price of the warrant. Once warrant exercise occurs, the difference between the carrying amount of the warrants and the net settlement amount will be allocated on a pro-rata basis to the common unitholders and general partner.
Certain embedded features within the preferred unit and warrant purchase agreement are accounted for at fair value and are remeasured each quarter. See Note 13. Fair Value Measurements for further information regarding valuation of these embedded derivatives.
6. Common and Preferred Unit Distributions
4.The Partnership makes cash distributions to common and preferred unitholders on a quarterly basis, subject to approval by the Board of Directors. NRP recognizes both common unit and preferred unit distributions on the date the distribution is declared.
Distributions made on the common units and the general partner's general partner ("GP") interest are made on a pro-rata basis in accordance with their relative percentage interests in the Partnership. The general partner is entitled to receive 2% of such distributions.
Income (loss) available to common unitholders and the general partner is reduced by preferred unit distributions that accumulated during the period. NRP reduced net income (loss) available to common unitholders and the general partner by $30.0 million during the years ended December 31, 2019 and 2018 and $25.5 million during the year ended December 31, 2017 as a result of accumulated preferred unit distributions earned during the period. During the three months ended March 31, 2018, the Partnership redeemed all of the outstanding PIK units, which resulted in an $8.8 million cash payment during the period. This $8.8 million cash payment is not included in the table below.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows the distributions declared and paid to common and preferred unitholders during the years ended December 31, 2019, 2018 and 2017, respectively:
|
| | | | | | | | | | | | | | | | | | |
| | | Common Units | | Preferred Units |
| Date Paid | | Period Covered by Distribution | | Distribution per Unit | | Total Distribution (1) (In thousands) | | Distribution per Unit | | Total Distribution (In thousands) |
| 2019 | | | | | | | | | | |
| February 2019 | | October 1 - December 31, 2018 | | $ | 0.45 |
| | $ | 5,625 |
| | $ | 30.00 |
| | $ | 7,500 |
|
| May 2019 | | January 1 - March 31, 2019 | | 0.45 |
| | 5,630 |
| | 30.00 |
| | 7,500 |
|
May 2019 (2) | | Special Distribution | | 0.85 |
| | 10,635 |
| | — |
| | — |
|
| August 2019 | | April 1 - June 30, 2019 | | 0.45 |
| | 5,630 |
| | 30.00 |
| | 7,500 |
|
| November 2019 | | July 1 - September 30, 2019 | | 0.45 |
| | 5,630 |
| | 30.00 |
| | 7,500 |
|
| | | | | | | | | | | |
| 2018 | | | | | | | | | | |
| February 2018 | | October 1 - December 31, 2017 | | $ | 0.45 |
| | $ | 5,617 |
| | $ | 30.00 |
| | $ | 7,765 |
|
| May 2018 | | January 1 - March 31, 2018 | | 0.45 |
| | 5,623 |
| | 30.00 |
| | 7,500 |
|
| August 2018 | | April 1 - June 30, 2018 | | 0.45 |
| | 5,623 |
| | 30.00 |
| | 7,500 |
|
| November 2018 | | July 1 - September 30, 2018 | | 0.45 |
| | 5,623 |
| | 30.00 |
| | 7,500 |
|
| | | | | | | | | | | |
| 2017 | | | | | | | | | | |
| February 2017 | | October 1 - December 31, 2016 | | $ | 0.45 |
| | $ | 5,615 |
| | $ | — |
| | $ | — |
|
| May 2017 | | January 1 - March 31, 2017 | | 0.45 |
| | 5,619 |
| | 5.00 |
| | 2,500 |
|
| August 2017 | | April 1 - June 30, 2017 | | 0.45 |
| | 5,616 |
| | 15.00 |
| | 7,538 |
|
| November 2017 | | July 1 - September 30, 2017 | | 0.45 |
| | 5,617 |
| | 15.00 |
| | 7,650 |
|
| |
| (1) | Totals include the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest. |
| |
| (2) | The special distribution of $0.85 per common unit was made to cover the common unitholders’ tax liability resulting from the sale of NRP’s construction aggregates business in December 2018. |
7. Net Income (Loss) Per Common Unit
Basic net income (loss) per common unit is computed by dividing net income (loss), after considering income attributable to non-controlling interest, preferred unitholders and the general partner’s general partner interest, by the weighted average number of common units outstanding. Diluted net income (loss) per common unit includes the effect of NRP's preferred units, warrants, and unvested unit-based awards if the inclusion of these items is dilutive.
The dilutive effect of the preferred units is calculated using the if-converted method. Under the if-converted method, the preferred units are assumed to be converted at the beginning of the period, and the resulting common units are included in the denominator of the diluted net income (loss) per unit calculation for the period being presented. Distributions declared in the period and undeclared distributions on the preferred units that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. The calculation of diluted net loss per common unit for the year ended December 31, 2019 did not include the assumed conversion of the preferred units because the impact would have been anti-dilutive. The calculation of diluted net income (loss) per common unit for the years ended December 31, 2018 and 2017 included the assumed conversion of the preferred units.
The dilutive effect of the warrants is calculated using the treasury stock method, which assumes that the proceeds from the exercise of these instruments are used to purchase common units at the average market price for the period. Due to NRP's net loss during the year ended December 31, 2019, the dilutive effect of the warrants were not included as the impact would have been anti-dilutive. The calculation of the dilutive effect of the warrants for the years ended December 31, 2018 and 2017 included the net settlement of warrants to purchase 1.75 million common units with a strike price of $22.81 but did not include the net settlement of warrants to purchase 2.25 million common units with a strike price of $34.00 because the impact would have been anti-dilutive.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following tables reconcile the numerators and denominators of the basic and diluted net income (loss) per common unit computations and calculates basic and diluted net income (loss) per common unit:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (In thousands, except per unit data) | | 2019 | | 2018 | | 2017 |
| Allocation of net income (loss) | | | | | | |
| Net income (loss) from continuing operations | | $ | (25,414 | ) | | $ | 122,360 |
| | $ | 82,485 |
|
| Less: net income attributable to non-controlling interest | | — |
| | (510 | ) | | — |
|
| Less: income attributable to preferred unitholders | | (30,000 | ) | | (30,000 | ) | | (25,453 | ) |
| Net income (loss) from continuing operations attributable to common unitholders and general partner | | $ | (55,414 | ) | | $ | 91,850 |
| | $ | 57,032 |
|
| Add (less): net loss (income) from continuing operations attributable to the general partner | | 1,108 |
| | (1,837 | ) | | (1,141 | ) |
| Net income (loss) from continuing operations attributable to common unitholders | | $ | (54,306 | ) | | $ | 90,013 |
| | $ | 55,891 |
|
| | | | | | | |
| Net income from discontinued operations | | $ | 956 |
| | $ | 17,687 |
| | $ | 6,182 |
|
| Less: net income from discontinued operations attributable to the general partner | | (19 | ) | | (354 | ) | | (123 | ) |
| Net income from discontinued operations attributable to common unitholders | | $ | 937 |
| | $ | 17,333 |
| | $ | 6,059 |
|
| | | | | | | |
| Net income (loss) | | $ | (24,458 | ) | | $ | 140,047 |
| | $ | 88,667 |
|
| Less: net income attributable to non-controlling interest | | — |
| | (510 | ) | | — |
|
| Less: income attributable to preferred unitholders | | (30,000 | ) | | (30,000 | ) | | (25,453 | ) |
| Net income (loss) attributable to common unitholders and general partner | | $ | (54,458 | ) | | $ | 109,537 |
| | $ | 63,214 |
|
| Add (less): net loss (income) attributable to the general partner | | 1,089 |
| | (2,191 | ) | | (1,264 | ) |
| Net income (loss) attributable to common unitholders | | $ | (53,369 | ) | | $ | 107,346 |
| | $ | 61,950 |
|
| | | | | | | |
| Basic income (loss) per common unit | | | | | | |
| Weighted average common units—basic | | 12,260 |
| | 12,244 |
| | 12,232 |
|
| Basic net income (loss) from continuing operations per common unit | | $ | (4.43 | ) | | $ | 7.35 |
| | $ | 4.57 |
|
| Basic net income from discontinued operations per common unit | | $ | 0.08 |
| | $ | 1.42 |
| | $ | 0.50 |
|
| Basic net income (loss) per common unit | | $ | (4.35 | ) | | $ | 8.77 |
| | $ | 5.06 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (In thousands, except per unit data) | | 2019 | | 2018 | | 2017 |
| Diluted income (loss) per common unit | | | | | | |
| Weighted average common units—basic | | 12,260 |
| | 12,244 |
| | 12,232 |
|
| Plus: dilutive effect of preferred units | | — |
| | 7,479 |
| | 9,418 |
|
| Plus: dilutive effect of warrants | | — |
| | 511 |
| | 300 |
|
| Plus: dilutive effect of unvested unit-based awards | | — |
| | — |
| | — |
|
| Weighted average common units—diluted | | 12,260 |
| | 20,234 |
| | 21,950 |
|
| | | | | | | |
| Net income (loss) from continuing operations | | $ | (25,414 | ) | | $ | 122,360 |
| | $ | 82,485 |
|
| Less: net income attributable to non-controlling interest | | — |
| | (510 | ) | | — |
|
| Less: net income attributable to preferred unitholders | | (30,000 | ) | | — |
| | — |
|
| Diluted net income (loss) from continuing operations attributable to common unitholders and general partner | | $ | (55,414 | ) | | $ | 121,850 |
| | $ | 82,485 |
|
| Add (less): net loss (income) from continuing operations attributable to the general partner | | 1,108 |
| | (2,437 | ) | | (1,650 | ) |
| Diluted net income (loss) from continuing operations attributable to common unitholders | | $ | (54,306 | ) | | $ | 119,413 |
| | $ | 80,835 |
|
| | | | | | | |
| Diluted net income from discontinued operations attributable to common unitholders | | $ | 937 |
| | $ | 17,333 |
| | $ | 6,059 |
|
| | | | | | | |
| Net income (loss) | | $ | (24,458 | ) | | $ | 140,047 |
| | $ | 88,667 |
|
| Less: net income attributable to non-controlling interest | | — |
| | (510 | ) | | — |
|
| Less: net income attributable to preferred unitholders | | (30,000 | ) | | — |
| | — |
|
| Diluted net income (loss) attributable to common unitholders and general partner | | $ | (54,458 | ) | | $ | 139,537 |
| | $ | 88,667 |
|
| Add (less): diluted net loss (income) attributable to the general partner | | 1,089 |
| | (2,791 | ) | | (1,773 | ) |
| Diluted net income (loss) attributable to common unitholders | | $ | (53,369 | ) | | $ | 136,746 |
| | $ | 86,894 |
|
| | | | | | | |
| Diluted net income (loss) from continuing operations per common unit | | $ | (4.43 | ) | | $ | 5.90 |
| | $ | 3.68 |
|
| Diluted net income from discontinued operations per common unit | | $ | 0.08 |
| | $ | 0.86 |
| | $ | 0.28 |
|
| Diluted net income (loss) per common unit | | $ | (4.35 | ) | | $ | 6.76 |
| | $ | 3.96 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
8. Segment Information
The Partnership's segments are strategic business units that offer distinct products and services to different customer segmentscustomers in different geographies within the U.S. and that are managed accordingly. NRP has the following threetwo operating segments:
Coal Royalty and Other—consists primarily of coal royalty properties and coal relatedcoal-related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty properties, aggregates royalty properties, oil and gas royalty properties and timber. The Partnership's coal reserves are primarily located in Appalachia, the Illinois Basin and the WesternNorthern Powder River Basin in the United States. The Partnership's aggregates and industrial minerals and aggregates properties are located in a number ofvarious states across the United States. The Partnership's oil and gas royalty assets are primarily located in Louisiana.Louisiana and its timber assets are primarily located in West Virginia.
Soda Ash—consists of the Partnership's 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining operation and soda ash refinery in the Green River Basin of Wyoming. Ciner Resources LP, the Partnership's operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally intoto the glass and chemicals industries. The Partnership receives regular quarterly distributions from this business.
VantaCore—consists of the Partnership's construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
Direct segment costs and certain other costs incurred at athe corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments.segments accordingly. These allocated costs generally include costs of:salaries and benefits, insurance, property taxes, legal, royalty, information technology and shared facilities services and are included in Operatingoperating and maintenance expenses and Operating and maintenance expenses—affiliates on the Partnership's Consolidated Statements of Comprehensive Income. Intersegment sales are at prices that approximate market.
Income (Loss).
Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest and financing, corporate headquarters and overhead, financing, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment.
segment and are included in general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands):business segments:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Operating Segments | | | |
| For the Year Ended | | Coal Royalty and Other | | Soda Ash | | VantaCore | | Corporate and Financing | | Total |
| December 31, 2016 | | | | | | | | | | |
| Revenues (including affiliates) | | $ | 210,115 |
| | $ | 40,061 |
| | $ | 120,802 |
| | $ | — |
| | $ | 370,978 |
|
| Intersegment revenues (expenses) | | 150 |
| | — |
| | (150 | ) | | — |
| | — |
|
| Gain on asset sales | | 29,068 |
| | — |
| | 13 |
| | — |
| | 29,081 |
|
Operating and maintenance expenses (including affiliates) | | 29,890 |
| | — |
| | 100,656 |
| | — |
| | 130,546 |
|
| General and administrative (including affiliates) | | — |
| | — |
| | — |
| | 20,570 |
| | 20,570 |
|
Depreciation, depletion and amortization (including affiliates) | | 31,766 |
| | — |
| | 14,506 |
| | — |
| | 46,272 |
|
| Asset impairment | | 15,861 |
| | — |
| | 1,065 |
| | — |
| | 16,926 |
|
| Other expense, net | | — |
| | — |
| | — |
| | 90,531 |
| | 90,531 |
|
| Net income (loss) from continuing operations | | 161,816 |
| | 40,061 |
| | 4,438 |
| | (111,101 | ) | | 95,214 |
|
| Net income from discontinued operations | | — |
| | — |
| | — |
| | — |
| | 1,678 |
|
| Capital expenditures | | 5 |
| | — |
| | 5,380 |
| | — |
| | 5,385 |
|
| Total assets of continuing operations at December 31, 2016 | | 990,172 |
| | 255,901 |
| | 190,615 |
| | 7,002 |
| | 1,443,690 |
|
| Total assets of discontinued operations at December 31, 2016 | | — |
| | — |
| | — |
| | — |
| | 991 |
|
| | | | | | | | | | | |
| December 31, 2015 | | | | | | | | | | |
| Revenues (including affiliates) | | $ | 243,781 |
| | $ | 49,918 |
| | $ | 139,049 |
| | $ | — |
| | $ | 432,748 |
|
| Intersegment revenues (expenses) | | 21 |
| | — |
| | (21 | ) | | — |
| | — |
|
| Gain (loss) on asset sales | | 6,936 |
| | — |
| | (36 | ) | | — |
| | 6,900 |
|
Operating and maintenance expenses
(including affiliates) | | 35,321 |
| | — |
| | 116,945 |
| | — |
| | 152,266 |
|
| General and administrative (including affiliates) | | — |
| | — |
| | — |
| | 12,348 |
| | 12,348 |
|
Depreciation, depletion and amortization (including affiliates) | | 45,338 |
| | — |
| | 15,578 |
| | — |
| | 60,916 |
|
| Asset impairment | | 378,327 |
| | — |
| | 6,218 |
| | — |
| | 384,545 |
|
| Other expense, net | | — |
| | — |
| | — |
| | 89,744 |
| | 89,744 |
|
| Net income (loss) from continuing operations | | (208,248 | ) | | 49,918 |
| | 251 |
| | (102,092 | ) | | (260,171 | ) |
| Net loss from discontinued operations | | — |
| | — |
| | — |
| | — |
| | (311,549 | ) |
| Capital expenditures | | 428 |
| | — |
| | 14,039 |
| | — |
| | 14,467 |
|
| Total assets of continuing operations at December 31, 2015 | | 1,078,778 |
| | 261,942 |
| | 200,348 |
| | 961 |
| | 1,542,029 |
|
| Total assets of discontinued operations at December 31, 2015 | | — |
| | — |
| | — |
| | — |
| | 128,006 |
|
| | | | | | | | | | | |
| December 31, 2014 | | | | | | | | | | |
| Revenues (including affiliates) | | $ | 266,085 |
| | $ | 41,416 |
| | $ | 42,031 |
| | $ | — |
| | $ | 349,532 |
|
| Gain on asset sales | | 1,366 |
| | — |
| | 20 |
| | — |
| | 1,386 |
|
Operating and maintenance expenses (including affiliates) | | 37,407 |
| | — |
| | 38,723 |
| | — |
| | 76,130 |
|
| General and administrative (including affiliates) | | — |
| | — |
| | — |
| | 10,545 |
| | 10,545 |
|
Depreciation, depletion and amortization (including affiliates) | | 58,598 |
| | — |
| | 3,296 |
| | — |
| | 61,894 |
|
| Asset impairment | | 26,209 |
| | — |
| | — |
| | — |
| | 26,209 |
|
| Other expense, net | | — |
| | — |
| | — |
| | 79,427 |
| | 79,427 |
|
| Net income (loss) from continuing operations | | 145,237 |
| | 41,416 |
| | 32 |
| | (89,972 | ) | | 96,713 |
|
| Net income from discontinued operations | | — |
| | — |
| | — |
| | — |
| | 12,117 |
|
| Capital expenditures | | 5,351 |
| | — |
| | 171,116 |
| | — |
| | 176,467 |
|
|
| | | | | | | | | | | | | | | | |
| | | Operating Segments | | | | |
| (In thousands) | | Coal Royalty and Other | | Soda Ash | | Corporate and Financing | | Total |
| For the Year Ended December 31, 2019 | | | | | | | | |
| Revenues | | $ | 210,348 |
| | $ | 47,089 |
| | $ | — |
| | $ | 257,437 |
|
| Gain on asset sales and disposals | | 6,498 |
| | — |
| | — |
| | 6,498 |
|
| Operating and maintenance expenses | | 32,489 |
| | 249 |
| | — |
| | 32,738 |
|
| Depreciation, depletion and amortization | | 14,932 |
| | — |
| | — |
| | 14,932 |
|
| General and administrative expenses | | — |
| | — |
| | 16,730 |
| | 16,730 |
|
| Asset impairments | | 148,214 |
| | — |
| | — |
| | 148,214 |
|
| Other expenses, net | | — |
| | — |
| | 76,735 |
| | 76,735 |
|
| Net income (loss) from continuing operations | | 21,211 |
| | 46,840 |
| | (93,465 | ) | | (25,414 | ) |
| Income from discontinued operations | | — |
| | — |
| | — |
| | 956 |
|
| As of December 31, 2019 | | | | | | | | |
| Total assets of continuing operations | | $ | 817,768 |
| | $ | 263,080 |
| | $ | 3,353 |
| | $ | 1,084,201 |
|
| Total assets of discontinued operations | | — |
| | — |
| | — |
| | 1,706 |
|
| | | | | | | | | |
| For the Year Ended December 31, 2018 | | | | | | | | |
| Revenues | | $ | 202,765 |
| | $ | 48,306 |
| | $ | — |
| | $ | 251,071 |
|
| Gain on litigation settlement | | 25,000 |
| | — |
| | — |
| | 25,000 |
|
| Gain on asset sales and disposals | | 2,441 |
| | — |
| | — |
| | 2,441 |
|
| Operating and maintenance expenses | | 29,509 |
| | — |
| | — |
| | 29,509 |
|
| Depreciation, depletion and amortization | | 21,689 |
| | — |
| | — |
| | 21,689 |
|
| General and administrative expenses | | — |
| | — |
| | 16,496 |
| | 16,496 |
|
| Asset impairments | | 18,280 |
| | — |
| | — |
| | 18,280 |
|
| Other expenses, net | | — |
| | — |
| | 70,178 |
| | 70,178 |
|
| Net income (loss) from continuing operations | | 160,728 |
| | 48,306 |
| | (86,674 | ) | | 122,360 |
|
| Income from discontinued operations | | — |
| | — |
| | — |
| | 17,687 |
|
| As of December 31, 2018 | | | | | | | | |
| Total assets of continuing operations | | $ | 986,680 |
| | $ | 247,051 |
| | $ | 106,923 |
| | $ | 1,340,654 |
|
| Total assets of discontinued operations | | — |
| | — |
| | — |
| | 993 |
|
| | | | | | | | | |
| For the Year Ended December 31, 2017 | | | | | | | | |
| Revenues | | $ | 202,323 |
| | $ | 40,457 |
| | $ | — |
| | $ | 242,780 |
|
| Gain on asset sales and disposals | | 3,545 |
| | — |
| | — |
| | 3,545 |
|
| Operating and maintenance expenses | | 24,883 |
| | — |
| | — |
| | 24,883 |
|
| Depreciation, depletion and amortization | | 23,414 |
| | — |
| | — |
| | 23,414 |
|
| General and administrative expenses | | — |
| | — |
| | 18,502 |
| | 18,502 |
|
| Asset impairments | | 2,967 |
| | — |
| | — |
| | 2,967 |
|
| Other expenses, net | | — |
| | — |
| | 94,074 |
| | 94,074 |
|
| Net income (loss) from continuing operations | | 154,604 |
| | 40,457 |
| | (112,576 | ) | | 82,485 |
|
| Income from discontinued operations | | — |
| | — |
| | — |
| | 6,182 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
5. Acquisitions and Divestitures
Acquisitions
On October 1, 2014, the Partnership completed its acquisition of VantaCore for total consideration of $200.6 million in cash and common units. The Partnership funded this acquisition through the borrowing of $169.0 million under its Opco’s revolving credit facility and the issuance of 0.2 million common units to certain of the sellers. Revenue and operating income from VanataCore included in the Consolidated Statements of Comprehensive Income were $42.1 million and $0.1 million, respectively, for the year ended December 31, 2014.
On November 12, 2014, the Partnership completed its acquisition of non-operated oil and gas working interests in the Sanish Field of the Williston Basin from an affiliate of Kaiser-Francis Oil Company for $339.1 million. These non-operated working interest assets were sold during 2016 as discussed in Note 3. Discontinued Operations. The Partnership funded this acquisition using the net proceeds from the issuance of additional $125 million principal amount of its 9.125% Senior Notes due 2018, borrowing $117.0 million under an NRP Oil and Gas revolving credit facility and proceeds of $100.4 million from a public common unit offering. Revenue and operating income from these acquired oil and gas assets included in the Consolidated Statements of Comprehensive Income were $12.8 million and $3.7 million, respectively, for the year ended December 31, 2014.
These acquisitions were accounted for under the acquisition method of accounting for businesses. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The results of operations of all acquisitions have been included in the consolidated financial statements since the acquisition dates. The following unaudited pro forma financial information (in thousands) presents a summary of the Partnership’s consolidated revenues, net income and net income per common unit for the twelve months ended December 31, 2014 assuming the VantaCore and Sanish Field acquisitions had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired:
|
| | | |
| | For the Year ended December 31, 2014 |
| Total revenues and other income | $ | 533,517 |
|
| Net income | $ | 122,319 |
|
| Basic and diluted net income per common unit | $ | 9.90 |
|
Divestitures
As discussed in Note 2. Summary of Significant Accounting Policies, the Partnership has been and is currently pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments which could otherwise cause the Partnership to breach financial covenants under its debt agreements, and mitigate the effects of scheduled debt principal payments that will strain the Partnership's liquidity. As part of this plan, the Partnership completed the sale of the following assets during the year ended December 31, 2016:2)Oil and gas royalty and overriding royalty interests in the Coal Royalty and Other segment in several producing properties located in the Appalachian Basin for $36.4 million gross sales proceeds. The effective date of the sale was January 1, 2016, and the Partnership recorded an $18.6 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
3)Aggregate reserves and related royalty rights in the Coal Royalty and Other segment at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds. The effective date of the sale was February 1, 2016, and the Partnership recorded a $1.5 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
4)In addition to the asset sales described above, during the year ended December 31, 2016, the Partnership sold mineral reserves within its Coal Royalty and Other segment in multiple sale transactions for cumulative $17.3 million of gross sales proceeds and recorded $8.6 million of cumulative gain from these sale transactions that are included in Gain on asset sales, net
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
on its Consolidated Statement of Comprehensive Income. These amounts primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas royalty interests.
Additional asset sales during the year included sales of land and plant and equipment within the Coal Royalty and Other segment for $1.2 million of gross proceeds and a $0.3 million of cumulative gain from these transactions that are included in Gain on asset sales, net on the Consolidated Statement of Comprehensive Income.
During the year ended December 31, 2015, the Partnership sold mineral reserves in multiple transactions for cumulative $3.5 million of gross sales proceeds and recorded a $3.3 million gain on asset sales included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income. The Partnership sold intangible assets for $4.4 million in gross proceeds and recorded a gain of $3.1 million included in Gain on asset sales, net in the Consolidated Statement of Comprehensive Income. The Partnership also sold plant and equipment $6.7 million of gross proceeds and recorded a gain of $0.6 million included in Gain on asset sales, net on the Consolidated Statement of Comprehensive Income.
During the year ended December 31, 2014, the Partnership sold land and mineral reserves for $1.4 million in gross sales proceeds and recorded a cumulative gain of $1.4 million on these asset sales included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
6.9. Equity Investment
The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Ciner Wyoming distributed $46.6 million, $46.8 million and $46.6 millionActivity related to the Partnership in the year ended December 31, 2016, 2015 and 2014, respectively.this investment is as follows:
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 |
| Balance at beginning of period | $ | 247,051 |
| | $ | 245,433 |
| | $ | 255,901 |
|
Income allocation to NRP’s equity interests (1) | 52,016 |
| | 53,095 |
| | 44,846 |
|
| Amortization of basis difference | (4,927 | ) | | (4,789 | ) | | (4,389 | ) |
| Other comprehensive income (loss) | 790 |
| | (138 | ) | | (1,925 | ) |
| Distribution | (31,850 | ) | | (46,550 | ) | | (49,000 | ) |
| Balance at end of period | $ | 263,080 |
| | $ | 247,051 |
| | $ | 245,433 |
|
| |
| (1) | Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $0.6 million, $0.5 million and $0.7 million for the year ended December 31, 2019, 2018 and 2017, respectively. |
The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was $150.0$135.8 million and $154.8$140.8 million as of December 31, 20162019 and 2015,2018, respectively. This excess basis relates to property, plant property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years. The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method.
The following table represents summarized financial information for Ciner Wyoming as derived from their respective financial statements for the years ended December 31, 2019, 2018, and 2017:
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 |
| Net sales | $ | 522,843 |
| | $ | 486,759 |
| | $ | 497,340 |
|
| Gross profit | 131,712 |
| | 104,053 |
| | 114,202 |
|
| Net income | 106,155 |
| | 108,357 |
| | 91,523 |
|
The Partnership's equity in the earningsfinancial position of Ciner Wyoming is summarized as follows (in thousands):follows:
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2016 | | 2015 | | 2014 |
Income allocation to NRP’s equity interests (1) | $ | 44,882 |
| | $ | 54,709 |
| | $ | 47,354 |
|
| Amortization of basis difference | (4,821 | ) | | (4,791 | ) | | (5,938 | ) |
| Equity in earnings of unconsolidated investment | $ | 40,061 |
| | $ | 49,918 |
| | $ | 41,416 |
|
| |
(1) | Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $0.9 million, $0.7 million and $0.5 million for the year ended December 31, 2016, 2015 and 2014, respectively. |
The results of Ciner Wyoming’s operations are summarized as follows (in thousands):
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Sales | $ | 475,187 |
| | $ | 486,393 |
| | $ | 465,032 |
|
| Gross profit | 114,232 |
| | 131,493 |
| | 118,439 |
|
| Net Income | 91,596 |
| | 111,650 |
| | 96,640 |
|
|
| | | | | | | |
| | December 31, |
| (In thousands) | 2019 | | 2018 |
| Current assets | $ | 170,696 |
| | $ | 138,080 |
|
| Noncurrent assets | 282,387 |
| | 252,743 |
|
| Current liabilities | 55,339 |
| | 64,012 |
|
| Noncurrent liabilities | 138,087 |
| | 109,921 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The financial position of Ciner Wyoming is summarized as follows (in thousands):
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| Current assets | $ | 134,616 |
| | $ | 144,695 |
|
| Noncurrent assets | 235,427 |
| | 233,845 |
|
| Current liabilities | 55,396 |
| | 43,018 |
|
| Noncurrent liabilities | 98,425 |
| | 116,808 |
|
The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming required the Partnership to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement were met by Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014, 2015 and 2016, the Partnership paid contingent consideration of $0.5 million, $3.8 million and $7.2 million, respectively, in contingent consideration to Anadarko for performance criteria met by Ciner Wyoming in 2013, 2014 and 2015, respectively. The Partnership has no further contingent consideration payments due to Anadarko under the purchase agreement.
7. Inventory
The components of inventories at December 31, 2016 and 2015 are as follows (in thousands):
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| Aggregates | $ | 6,037 |
| | $ | 7,056 |
|
| Supplies and parts | 856 |
| | 779 |
|
| Total inventory | $ | 6,893 |
| | $ | 7,835 |
|
8. Plant and Equipment
The Partnership’s plant and equipment consist of the following (in thousands):
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| Plant and equipment at cost | $ | 79,171 |
| | $ | 92,049 |
|
| Construction in process | 557 |
| | 646 |
|
| Less accumulated depreciation | (30,285 | ) | | (32,020 | ) |
| Total plant and equipment, net | $ | 49,443 |
|
| $ | 60,675 |
|
Depreciation expense related to the Partnership's plant and equipment totaled $12.4 million, $15.9 million and $7.6 million for the year ended December 31, 2016, 2015 and 2014, respectively.
Impairment expense related to the Partnership's plant and equipment totaled $3.1 million, $7.7 million, and $0.8 million and are included in Asset impairments in the Consolidated Statements of Comprehensive Income for the year ending December 31, 2016, 2015 and December 31, 2014, respectively. During 2016, the Partnership recorded a $2.0 million impairment expense in its Coal Royalty and Other segment primarily related to a coal preparation plant and a $1.1 million impairment expense in its VantaCore segment primarily related to equipment write-downs. During the second quarter of 2015 the Partnership recorded a $2.3 million impairment expense related to a coal preparation plant and during the fourth quarter of 2015 the Partnership recorded a $4.7 million impairment expense related to coal processing and transportation assets and obsolete equipment. During 2015, the Partnership also recorded a $0.7 million impairment expense related to obsolete plant and equipment at VantaCore.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9.10. Mineral Rights, Net
The Partnership’s mineral rights consist of the following (in thousands):following:
|
| | | | | | | | | | | |
| | For the Year Ended December 31, 2016 |
| | Carrying Value | | Accumulated Depletion | | Net Book Value |
| Coal properties | $ | 1,170,904 |
| | $ | (420,032 | ) | | $ | 750,872 |
|
| Aggregates properties | 176,774 |
| | (39,056 | ) | | 137,718 |
|
| Oil and gas royalty properties | 12,395 |
| | (6,289 | ) | | 6,106 |
|
| Other | 14,946 |
| | (1,450 | ) | | 13,496 |
|
| Total | $ | 1,375,019 |
| | $ | (466,827 | ) | | $ | 908,192 |
|
| | | | For the Year Ended December 31, 2015 | December 31, |
| | Carrying Value | | Accumulated Depletion | | Net Book Value | 2019 | | 2018 |
| (In thousands) | | Carrying Value | | Accumulated Depletion | | Net Book Value | | Carrying Value | | Accumulated Depletion | | Net Book Value |
| Coal properties | $ | 1,169,718 |
| | $ | (398,235 | ) | | $ | 771,483 |
| $ | 981,352 |
| | $ | (420,448 | ) | | $ | 560,904 |
| | $ | 1,164,845 |
| | $ | (451,210 | ) | | $ | 713,635 |
|
| Aggregates properties | 206,309 |
| | (35,752 | ) | | 170,557 |
| 41,486 |
| | (13,357 | ) | | 28,129 |
| | 24,920 |
| | (11,814 | ) | | 13,106 |
|
| Oil and gas royalty properties | 38,885 |
| | (9,994 | ) | | 28,891 |
| 12,395 |
| | (7,887 | ) | | 4,508 |
| | 12,395 |
| | (7,632 | ) | | 4,763 |
|
| Other | 14,947 |
| | (1,356 | ) | | 13,591 |
| 13,156 |
| | (1,601 | ) | | 11,555 |
| | 13,158 |
| | (1,550 | ) | | 11,608 |
|
| Total | $ | 1,429,859 |
| | $ | (445,337 | ) | | $ | 984,522 |
| |
| Total mineral rights, net | | $ | 1,048,389 |
| | $ | (443,293 | ) | | $ | 605,096 |
| | $ | 1,215,318 |
| | $ | (472,206 | ) | | $ | 743,112 |
|
Depletion expense related to the Partnership’s mineral rights is included in depreciation, depletion and amortization on its Consolidated Statements of Comprehensive Income (Loss) and totaled $29.8$12.1 million, $40.4$17.0 million and $50.6$20.1 million for the years ended December 31, 2019, 2018 and 2017, respectively.
Sales of Mineral Rights
During the year ended December 31, 2016, 20152019, the Partnership recorded a gain of $6.5 million included in gain on asset sales and 2014, respectively.
disposals on the Consolidated Statements of Comprehensive Income (Loss) primarily related to the disposal of certain coal mineral rights with a $0 net book value. During the years ended December 31, 2018 and 2017, the Partnership recorded a cumulative gain of $2.4 million and $3.5 million, respectively, included in gain on asset sales and disposals on the Consolidated Statements of Comprehensive Income (Loss) related to sales of multiple mineral reserves.
Impairment of Mineral Rights
The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These procedures are performed throughout the year and consider both quantitative and qualitative information based on historic, current and future performance and are designed to identify impairment indicators. If an impairment indicator is identified, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is primarily determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. The Partnership believes its estimates of cash flows and discount rates are consistent with those of principal market participants. The inputs used by management for fair value measurements include significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement for these types of assets. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require that a separate impairment evaluation be completed on a significant property.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the years ended December 31, 2016, 20152019, 2018 and 2014,2017, the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense included in asset impairments on the Consolidated Statements of Comprehensive Income (Loss) as follows (in thousands):follows:
|
| | | | | | | | | | | |
| | For the years ended December 31, |
| Impaired Asset Description | 2016 | | 2015 | | 2014 |
| Coal properties (1) | $ | 12,088 |
| | $ | 257,468 |
| | $ | 16,793 |
|
| Oil and gas properties (2) | 36 |
| | 70,527 |
| | — |
|
| Aggregates royalty properties (3) | 1,677 |
| | 43,402 |
| | 3,013 |
|
| Total | $ | 13,801 |
| | $ | 371,397 |
| | $ | 19,806 |
|
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 |
Coal properties (1) | $ | 125,806 |
| | $ | 5,259 |
| | $ | 595 |
|
Aggregates and timber royalty properties (2) | 103 |
| | 13,021 |
| | 2,372 |
|
| Total | $ | 125,909 |
| | $ | 18,280 |
| | $ | 2,967 |
|
| |
| (1) | The Partnership recorded $12.1$125.8 million of impairment expense during the year ended December 31, 2019 primarily due to deterioration in thermal coal markets, lessee capital constraints, thermal coal lease terminations, and expectations of further reductions in global and domestic thermal coal demand due to low natural gas prices and continued pressure on the electric power generation industry over emissions and climate change, resulting in reductions in expected cash flows (combination of lower expected coal sales volumes, sales prices, minimums and/or life of mine assumptions) on certain of our coal properties. During the year ended December 31, 2019, the Partnership recorded $36.0 million to fully impair certain coal properties. In addition, NRP recorded $89.8 million of impairment expense on coal royalty properties with $97 million of net book value, resulting in a fair value of $7.2 million at December 31, 2019. The fair value of the impaired assets at December 31, 2019 was calculated using a discount rate of 15%. The Partnership recorded $5.3 million of coal property impairments during the year ended December 31, 2016,2018 primarily as a result of lease surrender and termination. The Partnershipterminations, of which it recorded $3.8$5.0 million of impairment expense to fully impair certain coal property impairment during the three months ended September 30, 2016 and the fair value of the impaired asset recorded at fair value was $4.0 million at September 30, 2016. The Partnership recorded $8.2 million of coal property impairmentproperties during the three months ended December 31, 2016 and2018. The Partnership recorded $0.6 million of coal property impairments during the year ended December 31, 2017. NRP compared the net book value of its coal properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of the net book value over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flows from coal sales and minimum payments, discount rate and useful economic life. Estimated cash flows are the impaired asset recorded at fair value was $0.0 million at December 31, 2016. |
Total coal property impairment expense for the year ended December 31, 2015 was $257.5 million. The Partnership recorded $1.5 million
Table of coal property impairment during the three months ended June 30, 2015 and the fair value measurement of these impaired assets recorded at fair value was $0.0 million at June 30, 2015. The Partnership recorded $247.8 million of coal property impairment during the three months ended September 30, 2015 and the fair value of these impaired assets recorded at fair value was $28.4 million at September 30, 2015. The Partnership recorded the remaining $8.2 million of coal property impairment during the three months ended December 31, 2015 and the fair value of these impaired assets recorded at fair value was $0.4 million at December 31, 2015. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the Contents NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows.
Total coal property impairment expense for the year ended December 31, 2014 was $16.8 million. This expense was recorded during the fourth quarter of 2014 when management concluded certain unleased properties were impaired due primarily to the ongoing regulatory environment and continued depressed coal markets with little indications of improvement in the near term. The fair values for those unleased properties were determined for the associated reserves using Level 2 market approaches based upon recent comparable sales and Level 3 expected cash flows.
| |
| (2) | The Partnership recorded $36 thousand of oil and gas royalty asset impairment during the year ended December 31, 2016. Total oil and gas royalty asset impairment expense for the year ended December 31, 2015 was $70.5 million. The Partnership recorded this impairment during the three months ended September 30, 2015. The fair value measurement of these impaired assets recorded at fair value were $13.0 million at September 30, 2015. This impairment primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on its acreage. NRP compared net capitalized costs of its oil and gas royalty properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials. |
| |
(3) | The Partnership recorded $1.7$0.1 million of aggregates royalty property impairments during the year ended December 31, 2016. Total2019. During the three months ended December 31, 2018, the Partnership recorded $13.0 million of impairment expense related to an aggregates property impairment expense forthat the Partnership owns and leases to its former construction aggregates business, which mines, produces and sells the aggregates. The fair value of the impaired asset was reduced to $2.3 million at December 31, 2018 using a discount rate of 11%. The Partnership recorded $2.4 million of aggregates and timber royalty properties impairments during the year ended December 31, 20152017. NRP compared the net book value of its aggregates and timber properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of the net book value over fair value. A discounted cash flow model was $43.4 million.This impairment was recorded during the three months ended September 30, 2015. Theused to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flows from aggregates and timber sales and minimum payments, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of these impaired assets recorded at fair value was $13.1 million at September 30, 2015. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royaltiescash flows. |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. Total aggregates property impairment expense for the year ended December 31, 2014 was $3.0 million.
10. Goodwill and11. Intangible Assets, (Including Affiliate)
The Partnership's intangible assets—affiliate relate to above market coal transportation contracts with subsidiaries of Foresight Energy LP ("Foresight Energy") in which the Partnership receives throughput fees for the handling and transportation of coal as follows (in thousands):
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| Intangible assets—affiliate | $ | 81,109 |
| | $ | 81,109 |
|
| Less accumulated amortization—affiliate | (31,298 | ) | | (28,112 | ) |
| Total intangible assets, net—affiliate | $ | 49,811 |
| | $ | 52,997 |
|
Amortization expense related to the Partnership's intangible assets—affiliate totaled $3.2 million, $3.6 million and $3.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.Net
The Partnership's intangible assets consist of permits, aggregate-related trade namesabove-market coal royalty and other agreementsrelated transportation contracts with subsidiaries of Foresight Energy pursuant to which the Partnership receives royalty payments for coal sales and throughput fees for the transportation and processing of coal. The Partnership's intangible assets included on its Consolidated Balance Sheets are as follows (in thousands):follows:
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| Intangible assets | $ | 5,227 |
| | $ | 5,076 |
|
| Less accumulated amortization | (1,991 | ) | | (1,146 | ) |
| Total intangible assets, net | $ | 3,236 |
| | $ | 3,930 |
|
|
| | | | | | | |
| | December 31, |
| (In thousands) | 2019 | | 2018 |
| Intangible assets at cost | $ | 53,878 |
| | $ | 81,109 |
|
| Less: accumulated amortization | (36,191 | ) | | (38,596 | ) |
| Total intangible assets, net | $ | 17,687 |
| | $ | 42,513 |
|
Amortization expense related toincluded in depreciation, depletion and amortization on the Partnership's intangible assets totaled $0.8Consolidated Statements of Comprehensive Income (Loss) was $2.5 million, $1.0$4.3 million and $0.3$3.0 million for the years ended December 31, 2016, 20152019, 2018 and 2014,2017, respectively.
During the second quarter of 2014,year ended December 31, 2019, the Partnership identified facts and a lessee amended an aggregates lease in its Coal Royalty and Other segment, which ledcircumstances that indicated that the Partnership to conclude an impairment triggering event had occurred. Faircarrying value of the lease agreement was determined using Level 3 expectedcertain of its above-market contracts exceed future cash flows. The resultingflows from those assets and recorded a non-cash impairment expense of $5.6$22.3 million isto fully impair these assets. These impairments are included in Assetasset impairments on the Partnership's Consolidated Statements of Comprehensive Income.Income (Loss) and resulted from deterioration in thermal coal markets, lessee capital constraints, and expectations of further reductions in global and domestic thermal coal demand due to low natural gas prices and continued pressure on the electric power generation industry over emissions and climate change, resulting in reductions in expected cash flows (combination of lower expected coal sales volumes, sales prices and/or life of mine assumptions) on certain of our intangible assets.
The estimates of amortization expense for the periodsyears ended December 31, as indicated below, are based on current mining plans and are subject to revision as those plans change in future periods.
|
| | | | |
| For the Year Ended December 31, | | Estimated Amortization Expense |
| | | (in thousands) |
| 2017 | | $ | 3,559 |
|
| 2018 | | 3,289 |
|
| 2019 | | 3,275 |
|
| 2020 | | 3,280 |
|
| 2021 | | 3,280 |
|
|
| | | | |
| (In thousands) | | Estimated Amortization Expense |
| 2020 | | $ | 508 |
|
| 2021 | | 913 |
|
| 2022 | | 738 |
|
| 2023 | | 765 |
|
| 2024 | | 1,006 |
|
The weighted average remaining amortization period for contract intangibles and other intangibles was 28 years and 16 years, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
12. Debt, Net
During the fourth quarter of 2014, $52.0 million of goodwill was added relating to the VantaCore acquisition. This amount represented the preliminary residual value. During 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for VantaCore’s property, plant and equipment, right to mine assets and asset retirement obligations that existed asThe Partnership's debt consists of the acquisition date. These adjustments decreased goodwill by $46.5 million and resulted in an acquisition date goodwill of $5.5 million.
During the fourth quarter of 2015, the Partnership evaluated goodwill for impairment and compared the estimated fair value of the VantaCore reporting unit to its carrying amount. The carrying amount exceeded fair value and the Partnership recorded a $5.5 million goodwill impairment expense include in Asset impairments on the Partnership's Consolidated Statements of Comprehensive Income. The lower fair value was primarily a result of the deterioration in certain regional markets in which VantaCore operates causing a decline in future performance levels compared to levels estimated during the purchase price allocation process. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. These estimates were based on current conditions and historical experience applied to develop projections of future operating performance.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
11. Debt and Debt—Affiliate
As of December 31, 2016 and 2015, Debt and debt—affiliate consisted of the following (in thousands):following:
| | | | December 31, | December 31, |
| | 2016 | | 2015 | |
NRP LP debt (1): | | | | |
9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% (2) | $ | 425,000 |
| | $ | 425,000 |
| |
Opco debt (1): | | | | |
Revolving credit facility, due June 2018 (2) | 210,000 |
| | 290,000 |
| |
| Senior notes | | | | |
| 4.91% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018 | 9,187 |
| | 13,850 |
| |
| (In thousands) | | 2019 | | 2018 |
| NRP LP debt: | | | | |
| 9.125% senior notes, with semi-annual interest payments in June and December, due June 2025 issued at par ("2025 Senior Notes") | | $ | 300,000 |
| | $ | — |
|
| 10.500% senior notes, with semi-annual interest payments in March and September, due March 2022, $241 million issued at par and $105 million issued at 98.75% ("2022 Senior Notes") | | — |
| | 345,638 |
|
| Opco debt: | | | | |
| Revolving credit facility | | $ | — |
| | $ | — |
|
| Senior Notes | | | | |
| 8.38% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019 | 64,029 |
| | 85,714 |
| $ | — |
| | $ | 21,319 |
|
| 5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020 | 30,633 |
| | 38,462 |
| 6,780 |
| | 15,290 |
|
| 5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 | 18,825 |
| | 21,600 |
| 9,458 |
| | 13,414 |
|
| 4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 | 52,204 |
| | 60,000 |
| 24,016 |
| | 37,195 |
|
| 5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 119,524 |
| | 135,000 |
| 63,423 |
| | 89,529 |
|
| 8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 36,272 |
| | 40,909 |
| 20,059 |
| | 27,185 |
|
| 5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 134,035 |
| | 148,077 |
| 79,945 |
| | 107,013 |
|
| 5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 38,262 |
| | 42,308 |
| 20,375 |
| | 30,555 |
|
| 5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021 | 961 |
| | 1,153 |
| |
| NRP Oil and Gas debt: | | | | |
| Revolving credit facility | — |
| | 85,000 |
| |
| Total Opco Senior Notes | | $ | 224,056 |
| | $ | 341,500 |
|
| Total debt at face value | $ | 1,138,932 |
| | $ | 1,387,073 |
| $ | 524,056 |
| | $ | 687,138 |
|
| Net unamortized debt discount | (1,322 | ) | | (2,077 | ) | — |
| | (1,266 | ) |
Net unamortized debt issuance costs (1) | (11,307 | ) | | (14,040 | ) | |
| Net unamortized debt issuance costs | | (7,858 | ) | | (13,114 | ) |
| Total debt, net | $ | 1,126,303 |
| | $ | 1,370,956 |
| $ | 516,198 |
| | $ | 672,758 |
|
| Less: current portion of long-term debt | 138,903 |
| | 80,745 |
| (45,776 | ) | | (115,184 | ) |
| Less: debt classified as non-current liabilities of discontinued operations | — |
| | 83,600 |
| |
| Total long-term debt | $ | 987,400 |
| | $ | 1,206,611 |
| |
| Total long-term debt, net | | $ | 470,422 |
| | $ | 557,574 |
|
| |
(1) | See Note 2. Summary of Significant Accounting Policies for discussion of debt issuance costs reclassification upon adoption of new accounting standard on January 1, 2016.2025 Senior Notes In April 2019, NRP and NRP Finance issued the 2025 Senior Notes and used the $300 million proceeds and $76 million of cash on hand to fund the redemption of the 2022 Senior Notes. The 2025 Senior Notes were issued under an Indenture dated as of April 29, 2019 (the "2025 Indenture"), bear interest at 9.125% per year and mature on June 30, 2025. Interest is payable semi-annually on June 30 and December 30 beginning December 30, 2019. |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NRP LP Debt
NRP 2018 Senior Notes
In September 2013, the Partnership, together with NRP Finance Corporation ("NRP Finance"), a wholly owned subsidiary of the Partnership, as co-issuer, issued $300.0 million of 9.125% Senior Notes at an offering price of 99.007% of par (the "NRP 2018 Senior Notes"). Net proceeds after expenses from the issuance of NRP 2018 Senior Notes were approximately $289.0 million. The NRP 2018 Senior Notes call for semi-annual interest payments on April 1 and October 1 of each year, and will mature on October 1, 2018. None of the Partnership's subsidiaries guarantee the NRP 2018 Senior Notes.
In October 2014, the Partnership, together with NRP Finance as co-issuer, issued an additional $125.0 million of the NRP 2018 Senior Notes at an offering price of 99.5% of par. The additional issuance constituted the same series of securities as the existing NRP 2018 Senior Notes. Net proceeds of $122.6 million from the additional issuance of the NRP 2018 Senior Notes were used to fund a portion of the purchase price of NRP’s acquisition of non-operated working interests in oil and gas assets located in the Williston Basin in North Dakota.
The Partnership and NRP Finance have the option to redeem the NRP 20182025 Senior Notes, in whole or in part, at any time on or after April 1, 2016,October 30, 2021, at fixedthe redemption prices specified(expressed as percentages of principal amount) of 104.563% for the 12-month period beginning October 30, 2021, 102.281% for the 12-month period beginning October 30, 2022, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the indenture governingdate of redemption. Furthermore, before October 30, 2021, NRP may on any one or more occasions redeem up to 35% of the NRP 2018aggregate principal amount of the 2025 Senior Notes (the "2018 Indenture"). The 2018 Indenture contains covenants that, among other things, limitwith the abilitynet proceeds of certain public or private equity offerings at a redemption price of 109.125% of the Partnershipprincipal amount of 2025 Senior Notes, plus any accrued and certainunpaid interest, if any, to the date of its subsidiaries to incur or guarantee additional indebtedness. Underredemption, if at least 65% of the 2018aggregate principal amount of the 2025 Senior Notes issued under the 2025 Indenture remains outstanding immediately after such redemption and the Partnership and certainredemption occurs within 180 days of its subsidiaries generally are not permitted to incur additional indebtedness unless, onthe closing date of such equity offering. In the event of a consolidated basis, the fixed charge coverage ratio (aschange of control, as defined in the indenture) is at least 2.0 to 1.0 for2025 Indenture, the four preceding full fiscal quarters. The abilityholders of the Partnership and certain2025 Senior Notes may require us to purchase their 2025 Senior Notes at a purchase price equal to 101% of its subsidiaries to incur additional indebtedness is further limited in the event theprincipal amount of indebtednessthe 2025 Senior Notes, plus accrued and unpaid interest, if any. The 2025 Senior Notes were issued at par.
The 2025 Senior Notes are the senior unsecured obligations of NRP and NRP Finance. The 2025 Senior Notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance and senior in right of payment to any of NRP's subordinated debt. The 2025 Senior Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiaries guarantee the 2025 Senior Notes. As of December 31, 2019, NRP and NRP Finance were in compliance with the terms of the Indenture relating to their 2025 Senior Notes.
2022 Senior Notes
During the second quarter of 2019, the Partnership redeemed the 2022 Senior Notes at a redemption price equal to 105.250% of the principal amount of the 2022 Senior Notes, plus accrued and certainunpaid interest. In connection with the early redemption, the Partnership paid an $18.1 million call premium and also wrote off $10.4 million of its subsidiaries that is senior tounamortized debt issuance costs and debt discount. These expenses are included in loss on extinguishment of debt on the Partnership's unsecured indebtedness exceeds certain thresholds.
Consolidated Statements of Comprehensive Income (Loss). As of December 31, 2018, NRP and NRP Finance were in compliance with the terms of the Indenture relating to their 2022 Senior Notes.
Opco Debt
All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below.LLC. As of December 31, 20162019 and 2015,2018, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.
Opco Credit Facility
In June 2016, OpcoApril 2019, the Partnership entered into the first amendmentFourth Amendment (the "First Amendment"“Fourth Amendment”) to its Amended and Restatedthe Opco Credit AgreementFacility (the "Opco Credit Facility") that is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of. The Fourth Amendment extends the assets of Opco and its subsidiaries, as further described below. Under the First Amendment:
The maturity dateterm of the Opco Credit Facility was extended from October 1, 2017 to June 30, 2018;
The maximum leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Opco Credit Facility) has been amended to remain at 4.0x for the remaining term of the Opco Credit Facility;
The asset sale covenant was amended to allow asset sales of up to $300.0 million from and after the effective date of the First Amendment; provided, however, that 75% of the net cash proceeds of any such asset sales must be used to repay the Opco Credit Facility (without any corresponding commitment reduction) and/or NRP Opco’s Senior Notes described below.
On the effective date of the First Amendment, the total commitment under the Opco Credit Facility was reduced from $300.0 million to $260.0 million. In addition, Opco and the lenders agreed to further reduceuntil April 2023. Lender commitments under the Opco Credit Facility to (a) $210.0 million on December 31, 2016, (b) $180.0 million on June 30, 2017 and (c) $150.0 million on December 31, 2017. Opco will have the right to delay any of these commitment reductions by up to 90 days each upon the agreement of the lenders holding 66.7% of the then-existing commitments. To the extent any such commitment reduction is extended under the terms of the A&R Revolving Credit Facility, Opco's ability to make distributions to the Partnership will be limited to amounts necessary for the Partnership to pay taxes and other general partnership expenses and make interest payments on its 9.125% Senior Notes due 2018.remain at $100.0 million.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In addition to the 4.0x leverage ratio described above, the Opco Credit Facility requires Opco to maintain a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0. As of December 31, 2016, Opco's leverage ratio was 2.80x, and fixed charge coverage ratio was 4.99x.
Effective on the date of the First Amendment, indebtednessIndebtedness under the Opco Credit Facility bears interest, at Opco's option, at:
the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 2.50% to 3.50%; or
a rate equal to LIBOR plus an applicable margin ranging from 3.50% to 4.50%.
As of December 31, 2019, the Partnership did not have any borrowings outstanding under the Opco Credit Facility and had $100.0 million in available borrowing capacity. The weighted average interest ratesrate for the borrowings outstanding under the Opco Credit Facility forduring the yearsyear ended December 31, 2016 and 2015 were 4.46% and 2.91%, respectively.
2018 was 6.23%. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Opco Credit Facility contains financial covenants requiring Opco to maintain:
A leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 4.0x; provided, however, that if the Partnership increases its quarterly distribution to its common unitholders above $0.45 per common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from 4.0x to 3.0x; and
a fixed charge coverage ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0.
The Opco Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of liquidity. In addition, Opco is required to use 75% of the net cash proceeds of certain non-ordinary course asset sales to repay the Opco Credit Facility (without any corresponding commitment reduction) and use the remaining 25% of the net cash proceeds to offer to repay its Senior Notes on a pro-rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes (as described below).Senior Notes.
The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $673.0$399.7 million and $709.9$548.9 million classified as Land, Plantmineral rights, net and equipment and Mineral rightsother assets, net on the Partnership’s Consolidated Balance SheetSheets as of December 31, 20162019 and 2015,2018, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of VantaCore’s construction aggregates mining operations, and (5)(4) certain of Opco’s coal-related infrastructure assets.
Opco Senior Notes
Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of December 31, 20162019 and 2015,2018, the Opco Senior Notes had cumulative principal balances of $503.0$224.1 million and $585.9$341.5 million, respectively. Opco made mandatory principal payments of $82.9 million on the Opco Senior Notes of $117.4 million, $80.7 million and $80.8 million during the years ended December 31, 2019, 2018 and 2017, respectively. The payments made during the year ended December 31, 2016 and $80.82019 included a $49.3 million forpre-payment as a result of the years ended December 31, 2015 and 2014.
sale of the Partnership's construction aggregates business.
The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to:
maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters;
not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and
maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.
In addition, the Note Purchase Agreements include a covenant that provides that, in the event NRP Operating or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the Note Purchase Agreements and the holders of the Notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement.
The 8.38% and 8.92% Opco Senior Notes also provideprovides that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Note Purchase Agreements) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2016. As of December 31, 2016, Opco's leverage ratio was 2.80x, and fixed charge coverage ratio was 4.99x.2019.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepayment offers on the Opco Senior Notes as follows:
Untiluntil the earlier of the time that (1) Opco has sold $300 million of assets and (2) June 30, 2020, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using 25% of the net cash proceeds from certain asset sales; and
Afterafter the earlier to occur of the dates above, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid.
The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes.
NRP Oil and Gas Debt Classified as Liabilities of Discontinued Operations
RBL Facility
In August 2013, NRP Oil and Gas entered into the RBL Facility, a senior secured, reserve-based revolving credit facility, in order to fund capital expenditure requirements related to the development of the oil and gas assets in which it owned non-operated working interests. The RBL Facility was secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas was the sole obligor under the RBL Facility, and neither the Partnership nor any of its other subsidiaries was a guarantor of the RBL Facility.
At December 31, 2015, there was $85.0 million respectively, outstanding under the RBL Facility. As described in Note 3. Discontinued Operations, the Partnership included this debt and its related interest expense in discontinued operations. In July 2016, NRP Oil and Gas LLC closed the sale of its non-operated oil and gas working interest assets and used a portion of the proceeds to repay the RBL Facility in full.
Consolidated Principal Payments
The consolidated principal payments due are set forth below (in thousands):below:
|
| | | | | | | | | | | | | | | | | |
| | NRP LP | | | | Opco | |
| | Senior Notes | | | | Senior Notes (2) | | Credit Facility | | Total |
| 2017 | $ | — |
| | | | $ | 80,638 |
| | $ | 60,000 |
| | $ | 140,638 |
|
| 2018 | 425,000 |
| | (1) | | 80,638 |
| | 150,000 |
| | 655,638 |
|
| 2019 | — |
| | | | 76,045 |
| | — |
| | 76,045 |
|
| 2020 | — |
| | | | 54,704 |
| | — |
| | 54,704 |
|
| 2021 | — |
| | | | 47,043 |
| | — |
| | 47,043 |
|
| Thereafter | — |
| | | | 164,864 |
| | — |
| | 164,864 |
|
| | $ | 425,000 |
|
|
|
| $ | 503,932 |
|
| $ | 210,000 |
|
| $ | 1,138,932 |
|
| |
(1) | The 9.125% senior notes due 2018 were issued at a discount and were carried at $423.7 million as of December 31, 2016. |
| |
(2) | Incudes $1.0 million utility local improvement obligation. | | | | | | | | | | | | | | | | | | | NRP LP | | Opco | | | (In thousands) | Senior Notes | | Senior Notes | | Credit Facility | | Total | | 2020 | $ | — |
| | $ | 46,176 |
| | $ | — |
| | $ | 46,176 |
| | 2021 | — |
| | 39,396 |
| | — |
| | 39,396 |
| | 2022 | — |
| | 39,396 |
| | — |
| | 39,396 |
| | 2023 | — |
| | 39,396 |
| | — |
| | 39,396 |
| | 2024 | — |
| | 31,028 |
| | — |
| | 31,028 |
| | Thereafter | 300,000 |
| | 28,664 |
| | — |
| | 328,664 |
| | | $ | 300,000 |
|
| $ | 224,056 |
|
| $ | — |
|
| $ | 524,056 |
|
13. Fair Value Measurements |
Fair Value of Financial Assets and Liabilities
The Partnership’s financial assets and liabilities consist of cash and cash equivalents, restricted cash, contract receivable and debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature. There were no transfers between Level 1, Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 2019 or 2018. The Partnership uses available market data and valuation methodologies to estimate the fair value of its debt and contract receivable.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
12. Fair Value Measurements
The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. The following table (in thousands) shows the carrying amount and estimated fair value of the Partnership's other financial instruments:debt and contract receivable:
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 | | December 31, 2015 |
| | Carrying Value | | Estimated
Fair Value | | Carrying
Value | | Estimated
Fair Value |
| Debt and debt—affiliate: | | | | | | | |
| NRP 2018 Senior Notes (1) | $ | 420,097 |
| | $ | 412,250 |
| | $ | 417,296 |
| | $ | 277,313 |
|
| Opco Senior Notes and utility local improvement obligation (2) | 500,174 |
| | 488,814 |
| | 584,890 |
| | 383,065 |
|
| Opco Revolving Credit Facility (3) | $ | 206,032 |
| | $ | 210,000 |
| | $ | 285,170 |
| | $ | 290,000 |
|
| NRP Oil and Gas RBL Facility (3) | $ | — |
| | $ | — |
| | $ | 83,600 |
| | $ | 85,000 |
|
| | | | | | | | |
| Assets: | | | | | | | |
| Contracts receivable—affiliate, current and long-term(2) | 46,742 |
| | 32,554 |
| | 50,366 |
| | 34,498 |
|
|
| | | | | | | | | | | | | | | | | |
| | | | December 31, |
| | | | 2019 | | 2018 |
| (In thousands) | Fair Value Hierarchy Level | | Carrying Value | | Estimated
Fair Value | | Carrying
Value | | Estimated
Fair Value |
| Debt: | | | | | | | | | |
| NRP 2025 Senior Notes | 1 | | $ | 294,084 |
| | $ | 269,250 |
| | $ | — |
| | $ | — |
|
| NRP 2022 Senior Notes | 1 | | — |
| | — |
| | 334,024 |
| | 356,871 |
|
| Opco Senior Notes | 3 | | 222,114 |
| | 201,090 |
| | 338,734 |
| | 352,599 |
|
| Opco Credit Facility | 3 | | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | |
| Assets: | | | | | | | | | |
| Contract receivable (current and long-term) | 3 | | $ | 38,945 |
| | $ | 33,460 |
| | $ | 40,776 |
| | $ | 34,704 |
|
NRP has embedded derivatives in the preferred units related to certain conversion options, redemption features and the change of control provision that are accounted for separately from the preferred units as assets and liabilities at fair value on the Partnership's Consolidated Balance Sheets. Level 3 valuation of the embedded derivatives are based on numerous factors including the likelihood of the event occurring. The embedded derivatives are revalued quarterly and changes in their fair value would be recorded in other expenses, net on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The embedded derivatives had zero value as of December 31, 2019 and 2018. | |
(1) | The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period end. |
| |
(2) | The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing trading prices near period end. |
| |
(3) | The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. |
Fair Value of Non-Financial Assets
The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregates properties and other assets, at fair value on a nonrecurring basis. Refer to Note 10. Mineral Rights, Net and Note 11. Intangible Assets, Net for additional disclosures related to the fair value associated with the impaired assets. 13.14. Related Party Transactions
Reimbursements to Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P.NRP. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, provide their services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. In addition, the Partnership receives non-cash equity contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners' Capital and were $0.3 million and $0.8 million during the years ended December 31, 2016 and 2015, respectively. These QMC and WPPLP employee management service costs and non-cash equity compensation expenses are presented as Operatingoperating and maintenance expenses—affiliates, netexpenses and Generalgeneral and administrative—affiliatesadministrative expenses on the Partnership's Consolidated Statements of Comprehensive Income.Income (Loss). NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain rent, legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by or on behalf of the Partnership’s general partner and its affiliates and are presented as Operatingoperating and maintenance expenses—affiliates, netexpenses and Generalgeneral and administrative—affiliatesadministrative expenses on the Partnership's Consolidated Statements of Comprehensive Income.Income (Loss).
TheDirect general and administrative expenses charged to the Partnership had Accounts payable—affiliates to QMC of $0.4 million and $1.1 million, including less than $0.1 million and $0.6 million related to discontinued operations at December 31, 2016 and 2015, respectively, for services provided by QMC toand WPPLP are included on the Partnership. The Partnership had Accounts payable—affiliates to WPPLPPartnership's Consolidated Statement of $0.6 million and $0.3 million at December 31, 2016 and 2015, respectively.Comprehensive Income (Loss) as follows:
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 |
| Operating and maintenance expenses | $ | 6,436 |
| | $ | 6,170 |
| | $ | 6,184 |
|
| General and administrative expenses | 3,548 |
| | 3,658 |
| | 4,989 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Direct generalThe Partnership had accounts payable to QMC of $0.4 million and administrative expenses charged$0.5 million on its Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively and $0.1 million of accounts payable to WPPLP as of December 31, 2019.
During the years ended December 31, 2019, 2018 and 2017, the Partnership by WPPLP and QMC are as follows (in thousands):
|
| | | | | | | | |
| | For the Year Ended
December 31, |
| | 2016 | | 2015 | | 2014 |
| Operating and maintenance expenses—affiliates, net | 9,891 |
| | 10,063 |
| | 9,166 |
|
| General and administrative—affiliates | 3,591 |
| | 5,312 |
| | 3,258 |
|
Included in income (loss) from discontinued operations are $1.3recognized $4.0 million, $0.7$5.4 million and $0.6$1.5 million ofin operating and maintenance expenses, charged by QMC for the year endedrespectively, on its Consolidated Statements of Comprehensive Income (Loss) related to an overriding royalty agreement with WPPLP. At December 30, 2016, 201531, 2019 and 2014, respectively.
Cline Affiliates
Various companies affiliated with Chris Cline, including Foresight Energy LP, lease coal reserves from2018, the Partnership had $0.1 million and the Partnership also leases coal transportation assets$1.4 million, respectively of accounts payable on its Consolidated Balance Sheets to themWPPLP for this agreement.
Industrial Minerals Group LLC
Corbin J. Robertson, III, a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals,Director of GP Natural Resource Partners LLC, owns a 31%minority ownership interest (unaudited) in the NRP's general partner, as well as approximately 0.5 millionIndustrial Minerals Group LLC (“Industrial Minerals”), which, through its subsidiaries, leases two of NRP's common units (unaudited) at December 31, 2016.
coal royalty properties in Central Appalachia. Coal royalty related revenues from Foresight EnergyIndustrial Minerals totaled $63.4$1.7 million, $86.6$0.8 million and $81.5$0.7 million for the years ended December 31, 2016, 20152019, 2018 and 2014,2017, respectively. As of December 31, 2016 and 2015, theThe Partnership had Accounts receivable—affiliatesaccounts receivable from Foresight EnergyIndustrial Minerals of $6.5$0.7 million and $6.4$0.1 million respectively. As of December 31, 2016 and 2015, the Partnership had received $71.6 million and $82.6 million, respectively in minimum royalty payments to date that have been recorded as Deferred revenue—affiliates since they have not been recouped by Foresight Energy.
NRP owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy's Sugar Camp mine. The lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at December 31, 2016 were $76.4 million with unearned income of $31.8 million, and the net amount receivable was $44.6 million, of which $2.2 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanyingits Consolidated Balance Sheets. Minimum lease payments are $5.0 million per year for the next five years and represent a $1.25 million per quarter in deficiency payment. Total projected remaining payments under the lease at December 31, 2015 were $81.2 million with unearned income of $35.4 million and the net amount receivable was $45.9 million, of which $2.0 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates on the accompanying Consolidated Balance Sheets.
NRP holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreementSheets as of December 31, 2016 was $2.7 million, of which $1.4 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 2015 was $4.9 million, of which $1.5 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.2019 and 2018, respectively.
Quinwood Coal Company Royalty
NRP owns rail load out transportation assetsIn May 2017, a subsidiary of Alpha Natural Resources assigned two coal leases with us to Quinwood Coal Company ("Quinwood"), an entity wholly owned by Corbin J. Robertson III. Coal related revenues from Quinwood totaled $0.2 million, $0.0 million and subcontracts out the operating responsibilities to an affiliate of Foresight Energy at Foresight's Williamson mine. During$0.9 million for the years ended December 31, 2016, 20152019, 2018 and 2014, the Partnership recorded operating and maintenance expenses—affiliates of $1.3 million, $1.4 million and $1.6 million, respectively, to operate these assets.
During the years ended December 31, 2016, 2015 and 2014, the Partnership recognized a gain of $0.0 million, $9.3 million and $5.7 million, respectively on a reserve swap at Foresight Energy's Williamson mine. The gain is included in Coal royalty and other—affiliates revenues on the Consolidated Statements of Comprehensive Income. The Level 3 fair value of the reserves was estimated using a discounted cash flow model. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Long-Term Debt—Affiliate
Donald R. Holcomb, one of the Partnership’s former directors, was a manager of Cline Trust Company, LLC (the "Cline Trust Company"). As of December 31, 2015, Cline Trust Company owned approximately 0.5 million of the Partnership’s common units and $20.0 million in principal amount of the Partnership’s 9.125% Senior Notes due 2018. As of December 31, 2015, the members of the Cline Trust Company were four trusts for the benefit of the children of Chris Cline, each of which owns an approximately equal membership interest in the Cline Trust Company. As of December 31, 2015, Mr. Holcomb also served as trustee of each of the four trusts. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million as of December 31, 2015 and was included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet. In April 2016, Mr. Holcomb resigned from the Partnership's board of directors and as a result the $19.9 million debt balance held by Cline Trust Company was subsequently reclassified as Long-term debt, net on the Partnership's accompanying Consolidated Balance Sheet.
2017, respectively.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in the Partnership's conflicts policy.
At December 31, 2016,2019, a fund controlled by Quintana Capital owned a majoritysubstantial interest in Corsa Coal CorpCorp. ("Corsa")., a coal mining company traded on the TSX Venture Exchange that iswas one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, oneDuring the second quarter of the Partnership’s directors,2018, Corsa assigned its lease with NRP to a third party and is Chairmanno longer deemed a related party as of the Board of Corsa.such date. Coal related revenues from Corsa totaled $2.2 million, $3.1$0.5 million and $3.0$1.3 million for the years ended December 31, 2016, 20152018 and 2014,2017, respectively.
Cline Affiliates and Foresight Energy
Mr. Chris Cline, both individually and through another affiliate, Adena Minerals, LLC ("Adena"), owned a 31% interest in NRP (GP) LP, NRP's general partner ("NRP GP"), through May 9, 2017. On May 9, 2017, Adena sold its 31% limited partner interest in NRP GP to Great Northern Properties Limited Partnership (“GNPLP”) and WPPLP (the “Adena Sale”). GNPLP and WPPLP are companies controlled by Corbin J. Robertson, the Chairman and Chief Executive Officer of GP Natural Resource Partners LLC (the general partner of NRP GP) (“GP LLC”). Upon closing of this transaction, NRP no longer considers the various companies affiliated with Chris Cline, including Foresight Energy to be affiliates of NRP. As of December 31, 2016a result, all transactions (including revenues, expenses and 2015cash flows) after May 9, 2017 with the Partnership had recorded $0.0 million and $0.3 million, respectively in minimum royalty paymentsvarious companies affiliated with Chris Cline, including Foresight Energy, are considered to date as Deferred revenue—affiliates since they have not been recouped by Corsa. The Partnership also had Accounts receivable—affiliates totaling $0.2 million and $0.2 million from Corsa at December 31, 2016 and 2015, respectively.be third-party transactions.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Revenues and expenses related to transactions with Foresight Energy are included on the Partnership's Consolidated Statements of Comprehensive Income (Loss) as follows:
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In thousands) | 2019 | | 2018 | | 2017 |
| Revenues: | | | | | |
Coal royalty and other (1) | $ | 39,755 |
| | $ | 30,777 |
| | $ | 49,967 |
|
Transportation and processing services (2) | 19,168 |
| | 23,818 |
| | 20,522 |
|
| Total | $ | 58,923 |
| | $ | 54,595 |
| | $ | 70,489 |
|
| | | | | | |
Operating and maintenance expenses (3) | $ | 1,329 |
| | $ | 1,761 |
| | $ | 1,518 |
|
| |
| (1) | Included in 2017 coal royalty and other revenues was $21.2 million of related party revenues earned from Foresight Energy prior to May 9, 2017. |
| |
| (2) | Included in 2017 transportation and processing services revenues was $6.0 million of related party revenues earned from Foresight Energy prior to May 9, 2017. |
| |
| (3) | Included in 2017 operating and maintenance expenses was $0.5 million of related party expenses incurred from Foresight Energy prior to May 9, 2017. |
Coal Royalty and Overriding RoyaltyOther Revenues
ForVarious subsidiaries of Foresight Energy lease coal reserves from the year ended December 31, 2016,Partnership. In addition, NRP owns a contractual overriding royalty interest at Foresight Energy's Sugar Camp mine in the Illinois Basin which provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations on certain reserves owned by another affiliate of Chris Cline. Revenues related to these transactions are included in coal royalty and other revenues on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
Transportation and Processing Services Revenues and Expenses
The Partnership recorded $0.7 millionowns transportation and processing infrastructure related to certain of its coal properties, including loadout and other transportation assets at Foresight Energy's Williamson and Macoupin mines in the Illinois Basin, for which it collects throughput fees. These fees are included in transportation and processing services revenues on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
NRP is responsible for operating and maintaining the rail loadout transportation assets at the Williamson mine and subcontracts the operating responsibilities to a subsidiary of Foresight Energy. Expenses related to these operations are included in operating and maintenance expenses—affiliates relatedexpenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
In addition, NRP owns rail loadout and associated infrastructure at the Sugar Camp mine, an Illinois Basin mine also operated by a subsidiary of Foresight Energy LP. While the Partnership owns coal reserves at the Williamson and Macoupin mines, it does not own coal reserves at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a non-participating production royalty payable to WPPLP pursuant tosubsidiary of Foresight Energy and NRP collects minimums and throughput fees, which are considered a conveyance agreement entered intoreturn of a financing receivable or included in 2007. These charges were $0.4 milliontransportation and zeroprocessing services revenues on the Partnership's Consolidated Statements of Comprehensive Income (Loss). See Note 18. Financing Transaction for the years ended December 31, 2015 and 2014, respectively. The Partnership had Other assets—affiliate from WPPLP of $1.0 million and $1.1 million at December 31, 2016 and December 31, 2015, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.more information.
14.NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
15. Major Customers
Revenues from customers that exceeded 10 percent of total revenues for any of the periods presented below are as follows:
|
| | | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| (In thousands) | | Revenues | | Percent | | Revenues | | Percent | | Revenues | | Percent |
Foresight Energy (1) | | $ | 58,923 |
| | 22.9 | % | | $ | 54,595 |
| | 21.7 | % | | $ | 70,489 |
| | 29.0 | % |
Contura Energy (1) (2) | | 40,743 |
| | 15.8 | % | | 24,580 |
| | 9.8 | % | | 20,172 |
| | 8.3 | % |
| |
| (1) | Revenues from Foresight Energy and Contura Energy are included within the Partnership's Coal Royalty and Other segment. |
| |
| (2) | In the fourth quarter of 2018, Contura Energy and Alpha Natural Resources merged. Revenues during the year ended December 31, 2019 relate to the combined company, while revenues during the year ended December 31, 2018 do not include revenues from Alpha Natural Resources until the date of the merger. Revenues during the year ended December 31, 2017 do not include revenues from Alpha Natural Resources. |
16. Commitments and Contingencies
Legal
NRP is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claimsordinary course matters will not have a material effect on the Partnership’s financial position, liquidity or operations. During 2019, NRP was also involved in the legal proceeding described below.
SinceIn January 2013, several citizen group lawsuitsNRP acquired a non-controlling 48.51% general partner interest in OCI Wyoming, L.P. ("OCI LP") and all of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko"). The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical Corporation.
The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by NRP if certain performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015. For those years, NRP paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment obligations.
In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, NRP exchanged the stock of OCI Co for a limited partner interest in OCI LP. Following the reorganization, NRP's interest in OCI LP remained at 49%, consisting of both limited and general partner interests. The restructuring did not have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mineany impact on the subject property had been closed,operations, revenues, management or control of OCI LP.
In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC in the property had been reclaimed,District Court of Harris County, Texas, 157th Judicial District. The complaint alleged that the transactions conducted in 2013 triggered an acceleration of NRP's obligation under the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of such amount, together with interest, court costs and attorneys’ fees.
In November 2019, the state reclamation bond had been released. Any determinationtrial court ruled in NRP’s favor in all respects, including that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations. A subsidiarythe internal restructuring that occurred did not trigger an acceleration of the Partnership has been named as a defendant in one of these lawsuits. The Partnership currently cannot reasonably estimate a range of potential loss, if any, relatedcontingent purchase price payment obligation under the purchase agreement with Anadarko. Accordingly, the trial court ordered that Anadarko take nothing. Anadarko did not appeal the trial court's ruling, and this case is concluded with no liability to this matter.the Partnership.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Foresight Energy Disputes
In November 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled. In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. We believe the force majeure claim by Hillsboro has no merit and we are vigorously pursuing recovery against them. However, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with respect to 2015 and 2016 resulted in a cumulative $46.0 million negative cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected.
In April 2016, we filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its recoupable balance and failure to make payments in accordance with these lease agreements has resulted in a cumulative $6.2 million negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount has been recorded.
Environmental Compliance
The operations the Partnership’s lessees conduct on its properties, as well as the aggregates/industrial minerals, aggregates and oil and gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. See "Item"Items 1. Business—and 2. Business and Properties—Regulation and Environmental Matters.Matters." As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership makes regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. The Partnership believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply with environmental laws and regulations towill have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31, 2016.2019. The Partnership is not associated with any material environmental contamination that may require remediation costs. However, the Partnership’s lessees doare required to conduct reclamation work on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, the Partnership is not responsible for the costs associated with these reclamation operations. As a former owner of the working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities, including environmental liabilities, arising from uninsured and underinsured events during the period it was an owner. The Partnership is also responsible for losses and liabilities, including environmental liabilities that may arise from uninsured and underinsured events at its VantaCore operations.
15. Major Customers
Revenues from customers that exceeded ten percent of total revenues and other income for any of the periods presented below are as follows (in thousands except for percentages):
|
| | | | | | | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2016 | | 2015 | | 2014 |
| | | Revenues | | Percent | | Revenues | | Percent | | Revenues | | Percent |
| Foresight Energy | | $ | 63,355 |
| | 15.8 | % | | $ | 86,614 |
| | 19.7 | % | | $ | 81,546 |
| | 23.2 | % |
| Alpha Natural Resources | | $ | 18,184 |
| | 4.5 | % | | $ | 34,364 |
| | 7.8 | % | | $ | 48,783 |
| | 13.9 | % |
All of the revenue related to the customers above is included in revenues of the Coal Royalty and Other segment.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership had a significant concentration of revenues with Foresight Energy and Alpha Natural Resources. The exposure is currently spread out over a number of different mining operations and leases. During the year ended December 31, 2015, total revenues and other income from Alpha Natural Resources included a $6.0 million non-recurring lease assignment fee.
16.17. Unit-Based Compensation
GP Natural Resource Partners LLC adopted2017 Long-Term Incentive Plan
In December 2017, the Natural Resource Partners2017 Long-Term Incentive Plan (the "Long-Term Incentive Plan"“2017 LTIP”) was approved and it became effective in January 2018. The 2017 LTIP authorizes 800,000 common units that are available for directorsdelivery by the Partnership pursuant to awards under the plan. The term is 10 years from the date of GP Natural Resource Partners LLC and employeesapproval of its affiliates who perform services for the Partnership. The compensationBoard of Directors or, if earlier, the date the 2017 LTIP is terminated by the Board of Directors or the committee appointed by the Board of GP Natural Resource Partners LLC’s board of directors administersDirectors to administer the Long-Term Incentive Plan. Subject2017 LTIP, or the date all available common units available have been delivered. Common units delivered pursuant to the rules2017 LTIP will consist, in whole or part, of (i) common units acquired in the open market, (ii) common units acquired from the Partnership (including newly issued units), any of our affiliates or any other person or (iii) any combination of the exchange upon which the common units are listed at the time, the board offoregoing.
Employees, consultants and non-employee directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.
Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a unit of the Parent common units upon each vesting. The Partnership records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted quarterly for any changes in the Partnership’s unit price. Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, orGeneral Partner, GP Natural Resource Partners LLC. IfLLC and their affiliates are generally eligible to receive awards under the 2017 LTIP. The 2017 LTIP provides for the issuance of a grantee’s employment or membership onvariety of equity-based grants, including grants of (i) options, (ii) unit appreciation rights, (iii) restricted units, (iv) phantom units, (v) cash awards, (vi) performance awards, (vii) distribution equivalent rights, and (viii) other unit-based awards. The plan is administered by the boardCompensation, Nominating and Governance Committee ("CNG Committee") of directors terminatesthe Board of Directors, which determines the terms and conditions of awards granted under the 2017 LTIP. The Partnership recognizes forfeitures for any reason, outstanding grantsawards issued under this plan as they occur.
Unit-Based Awards
Unit-based awards under the 2017 LTIP are generally issued to certain employees and non-employee directors of the Partnership. Awards granted to employees vest at the end of a 3 year period and awards granted to non-employee directors are immediately vested. Directors are given the option to take immediate issuance of the vested awards or defer such issuance until a later date. Upon deferral of issuance, such units will be automatically forfeited unless andcontinue to the extent the compensation committee provides otherwise.
accumulate distribution equivalent rights ("DERs") until issuance.
In connection with the phantom unit awards, the Compensation, Nominating and GovernanceCNG Committee also granted tandem Distribution Equivalent Rights ("DERs"),DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.
|
| | |
| Phantom Units |
Outstanding grants at January 1, 2016 | 126 |
|
Grants during the period | — |
|
Grants vested and paid during the period | (28 | ) |
Forfeitures during the period | (12 | ) |
Outstanding grants at December 31, 2016 | 86 |
|
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The Partnership recorded a credit to general and administrative expenses related to its Long-Term Incentive Plan of $3.4 million for the year ended December 31, 2015, due to the decline in the market price of the Partnership's common units during 2015. For the years ended December 31, 2016 and 2014 the Partnership recorded G&A expenses of $1.4 million and $1.0 million, respectively.
In connection with the Long-Term Incentive Plans, payments are typically made during the first quarter of the year. Payments of $1.5 million, $4.4 million and $6.5 million were made during the years ended December 31, 2016, 2015, and 2014, respectively. The grant date fair value was $0.0 million, $4.2 million and $6.6 million for awards in 2016, 2015 and 2014, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at December 31, 2016 and December 31, 2015, was $0.8 million and $0.7 million, respectively.
Contents
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
17. Cash Distributions
The following table showsawards granted in 2019 and 2018 were valued using the distributions paid byclosing price of NRP's units as of the Partnershipgrant date. The grant date fair value of these awards granted during the yearyears ended December 31, 2016, 20152019 and 2014:2018 were $5.4 million and $2.2 million, respectively. Total unit-based compensation expense associated with these awards was $2.4 million and $1.1 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses and operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The unamortized cost associated with unvested outstanding awards as of December 31, 2019 is $3.5 million, which is to be recognized over a weighted average period of 2.0 years. The unamortized cost associated with unvested outstanding awards as of December 31, 2018 was $1.2 million.
A summary of the unit activity in the outstanding grants during 2019 is as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | Total Distributions (In thousands) |
| Date Paid | | Period Covered by Distribution | | Distribution per Common Unit | | Common Units | | GP Interest | | Total |
| 2016 | | | | | | | | | | |
| February 12, 2016 | | October 1 - December 31, 2015 | | $ | 0.45 |
| | $ | 5,503 |
| | $ | 113 |
| | $ | 5,616 |
|
| May 13, 2016 | | January 1 - March 31, 2016 | | 0.45 |
| | 5,503 |
| | 113 |
| | 5,616 |
|
| August 12, 2016 | | April 1 - June 30, 2016 | | 0.45 |
| | 5,505 |
| | 112 |
| | 5,617 |
|
| November 14, 2016 | | July 1 - September 30, 2016 | | 0.45 |
| | 5,503 |
| | 113 |
| | 5,616 |
|
| | | | | | | | | | | |
| 2015 | | | | | | | | | | |
| February 13, 2015 | | October 1 - December 31, 2014 | | $ | 3.50 |
| | $ | 42,804 |
| | $ | 874 |
| | $ | 43,678 |
|
| May 14, 2015 | | January 1 - March 31, 2015 | | 0.90 |
| | 11,007 |
| | 225 |
| | 11,232 |
|
| August 14, 2015 | | April 1 - June 30, 2015 | | 0.90 |
| | 11,009 |
| | 223 |
| | 11,232 |
|
| November 13, 2015 | | July 1 - September 30, 2015 | | 0.45 |
| | 5,504 |
| | 112 |
| | 5,616 |
|
| | | | | | | | | | | |
| 2014 | | | | | | | | | | |
| January 31, 2014 | | October 1 - December 31, 2013 | | $ | 3.50 |
| | $ | 38,433 |
| | $ | 785 |
| | $ | 39,218 |
|
| May 14, 2014 | | January 1 - March 31, 2014 | | 3.50 |
| | 38,634 |
| | 787 |
| | 39,421 |
|
| August 14, 2014 | | April 1 - June 30, 2014 | | 3.50 |
| | 38,938 |
| | 795 |
| | 39,733 |
|
| November 14, 2014 | | July 1 - September 30, 2014 | | 3.50 |
| | 42,796 |
| | 874 |
| | 43,670 |
|
|
| | | | | | |
| (In thousands) | Common Units | | Weighted Average Exercise Price |
| Outstanding grants at January 1, 2019 | 55 |
| | $ | 29.10 |
|
| Granted | 129 |
| | $ | 41.41 |
|
| Fully vested and issued | (12 | ) | | $ | 41.47 |
|
| Forfeitures | (15 | ) | | $ | 37.33 |
|
| Outstanding at December 31, 2019 | 157 |
| | $ | 37.48 |
|
18. Deferred RevenueFinancing Transaction
The Partnership owns rail loadout and Deferred Revenue—Affiliate
Mostassociated infrastructure at the Sugar Camp mine in the Illinois Basin operated by a subsidiary of Foresight Energy. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight Energy and is accounted for as a financing transaction (the "Sugar Camp lease"). The Sugar Camp lease expires in 2032 with renewal options for up to 80 additional years. Minimum payments are $5.0 million per year through the end of the Partnership’slease term. The Partnership is also entitled to variable payments in the form of throughput fees determined based on the amount of coal transported and aggregates lessees must payprocessed utilizing the Partnership minimum annual or quarterlyPartnership's assets. In the event the Sugar Camp lease is renewed beyond 2032, payments become a fixed $10 thousand per year for the remainder of the renewed term.
The following table shows certain amounts which are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as a deferred revenue liability when received. The deferred revenue attributablerelated to the minimum payment is recognized as revenue based upon the underlying mineralPartnership's Sugar Camp lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments. The Partnership’s deferred revenue (including affiliate) consist of the following (in thousands):2032:
|
| | | | | | | |
| | December 31, 2016 | | December 31, 2015 |
| Deferred revenue | $ | 44,931 |
| | $ | 80,812 |
|
| Deferred revenue—affiliate | 71,632 |
| | 82,853 |
|
| Total deferred revenue (including affiliate) | $ | 116,563 |
| | $ | 163,665 |
|
|
| | | | | | | |
| | December 31, |
| (In thousands) | 2019 | | 2018 |
| Accounts receivable | $ | 540 |
| | $ | 661 |
|
| Contract receivable (current and long-term) | 38,945 |
| | 40,776 |
|
| Unearned income | 21,889 |
| | 25,058 |
|
| Projected remaining payments | $ | 61,374 |
| | $ | 66,495 |
|
19. Leases
Lessee Accounting
As of December 31, 2019, the Partnership had one operating lease for an office building that is owned by WPPLP. On January 1, 2019, the Partnership entered into a new lease of the building with a five-year base term and five additional five-year renewal options. Upon lease commencement and as of December 31, 2019, the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liability on its Consolidated Balance Sheet using the present value of the future lease payments over 30 years. The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums as Coal royaltyPartnership's right-of-use asset and lease liability included within other assets and other revenue (in thousands):
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Coal royalty and other | $ | 49,284 |
| | $ | 3,451 |
| | $ | 6,659 |
|
| Coal royalty and other—affiliates | 15,307 |
| | 12,038 |
| | — |
|
| Total coal royalty and other (including affiliates) | $ | 64,591 |
| | $ | 15,489 |
| | $ | 6,659 |
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Lease Modifications, TerminationThe following table details the maturity analysis of the Partnership's operating lease liability and Forfeitures of Minimum Royalty Balances
Duringreconciles the year ended December 31, 2016, the Partnership entered into agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the Partnership recognizing $40.5 million of deferred revenue as follows:
•An agreement that terminated a central Appalachia coal royalty lease and resulted in the lessee forfeiting the right to recoup $26.2 million of minimum royalties previously paidundiscounted cash flows to the Partnership. The Partnership agreed to transfer its coal mineral rights that were subject to this formeroperating lease to the lessee. This terminated lease had no current or planned production and the mineral rights transferred had zero net book value on the Partnership's consolidated Balance Sheets as of March 31, 2016. As a result of this transaction, in April 2016 the Partnership recognized $26.2 million of revenue.
•Lease modifications, terminations and forfeitures of existing coal royalty and other leases resulted in lessee forfeiture of rights to recoup previously paid minimum royalties and the reduction in lessee recoupment time. As a result of these modifications, in the first and second quarters of 2016 the Partnership recognized $10.7 million of revenue.
•The Partnership recognized $3.6 million of revenue from various other coal and aggregates lease modifications, terminations and forfeitures during the year ended December 31, 2016.
During the years ended December 31, 2015 and 2014, there was less than $0.1 million and $1.4 million of revenue recognized from coal and aggregate lease modifications, terminations or forfeitures, respectively.
19. Subsequent Events
The following represents material events that have occurred subsequent to December 31, 2016 through the time of the Partnership’s filing of its Annual Report on Form 10-K with the SEC:
Distribution Declared
On February 14, 2017, the Partnership paid a distribution of $0.45 per unit to unitholders of record on February 7, 2017.
Recapitalization Transactions
On March 2, 2017, the Partnership completed the following recapitalization transactions:
Issuance of Preferred Units and Warrants
NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred Units") to Blackstone and GoldenTree (together the "Preferred Purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000 Preferred Units to the Preferred Purchasers at a price of $1,000 per Preferred Unit (the "Per Unit Purchase Price"), less a 2.5% structuring and origination fee. The Preferred Units entitle the Preferred Purchasers to receive cumulative dividends at a rate of 12% per year, up to one half of which NRP may pay in additional Preferred Units (such additional Preferred Units, the "PIK Units"). NRP also issued two tranches of warrants (the "Warrants") to purchase common units to the Preferred Purchasers (Warrants to purchase 1.75 million common units with a strike price of $22.81 and Warrants to purchase 2.25 million common units with a strike price of $34.00). The Warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the Warrants, NRP may, at its option, elect to settle the Warrants in common units or cash, each on a net basis.
The Preferred Units have a perpetual term, unless converted or redeemed as described below. The Preferred Units (including any PIK Units) are convertible into common units at the election of the holders (1) after the fifth anniversary and prior to the eighth anniversary of the issue date at a 7.5% discount to the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to the notice of conversion if the 30-day VWAP immediately prior to such notice is greater than $51.00 (subject to a maximum of 33% of the Preferred Units per year) and (2) after the eighth anniversary of the issue date at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Instead of issuing common units pursuant to clause (1) of the preceding sentence, NRP has the option to redeem the Preferred Units proposed to be converted for cash at a price equal to the Per Unit Purchase Price, plus the value of any accrued and unpaid distributions. To the extent the holders of the Preferred Units have not elected to convert their Preferred Units by the twelfth anniversary of the issue date, NRP has the right to force conversion of the Preferred Units into common units at a 10% discount to the VWAP for the 30
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
trading days immediately prior to the notice of conversion. In addition, NRP has the ability to redeem at any time (subject to compliance with our debt agreements) all or any portion of the Preferred Units (including PIK Units) for cash at the agreed upon per unit amount, which is calculated as the Per Unit Purchase Price multiplied by (i) prior to the third anniversary of the closing date, 1.50, (ii) on or after the third anniversary of the closing date and prior to the fourth anniversary of the closing date, 1.70 and (iii) on or after the fourth anniversary of the closing date, 1.85.
The terms of the Preferred Units contain certain restrictions on our ability to pay distributions on our common units. To the extent that either (i) our consolidated Leverage Ratio (as defined in the Restated Partnership Agreement) is greater than 3.25x, or (ii) the ratio of our Distributable Cash Flow to cash distributions made or proposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), NRP may not increase the quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding Preferred Units. In addition, if at any time after January 1, 2022, any PIK Units are outstanding, NRP may not make distributionsliability included on its common units until it has redeemed all PIK Units for cash.
The holders of the Preferred Units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rights with respect to changes of the terms of the Preferred Units. In addition, Blackstone has certain approval rights over certain matters, including:
the incurrence of new indebtedness, subject to certain exceptions;
material changes to NRP’s business;
acquisitions and divestitures in excess of certain dollar thresholds;
amendments to material contracts resulting in a cash impact to NRP in excess of certain dollar thresholds;
settlement of any litigation or regulatory matter resulting in cash payments by NRP in excess of certain thresholds; and
amendments to related party contracts outside of the ordinary course of business.
GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the Minimum Preferred Unit Threshold (as defined below). The Preferred Purchaser Approval Rights are not transferrable without NRP's consent. In addition, the Preferred Purchaser Approval Rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). To the extent any Preferred Units that have converted into common units are still held by the applicable Preferred Purchaser (or its affiliates), such common units will be deemed to represent a number of Preferred Units based on the weighted average number of common units issued in each conversion and will count towards the Minimum Preferred Unit Threshold.
The foregoing terms of the Preferred Units are reflected in our Fifth Amended and Restated Agreement of Limited Partnership, dated as of March 2, 2017, which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference. The terms of the Warrants are reflected in the Form of Warrant to Purchase Common Units filed as Exhibit 4.28 to this Annual Report on Form 10-K, which is incorporated herein by reference.
At the closing, pursuant to a Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights and appointed one director and one observer to the Board of Directors of GP Natural Resource Partners LLC. For more information on these rights, see "Certain Relationships and Related Transactions, and Director Independence—Board Representation and Observation Rights Agreement."
NRP also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with the Preferred Purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the Warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the Preferred Units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of Preferred Units (the "Registration Deadlines"). In addition, the Preferred Unit and Warrant Registration Rights Agreement gives the Preferred Purchasers piggyback registration and demand underwritten offering rights under certain circumstances. If the shelf registration statements are not effective by theConsolidated Balance Sheet:
|
| | | | |
| Remaining Annual Lease Payments (In thousands) | | December 31, 2019 |
| 2020 | | $ | 483 |
|
| 2021 | | 483 |
|
| 2022 | | 483 |
|
| 2023 | | 483 |
|
| 2024 | | 483 |
|
| After 2024 | | 11,597 |
|
Total lease payments (1) | | $ | 14,012 |
|
Less: present value adjustment (2) | | (10,506 | ) |
| Total operating lease liability | | $ | 3,506 |
|
NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
applicable Registration Deadline, NRP will be required to pay the Preferred Purchasers liquidated damages in the amounts and upon the term set forth in the Preferred Unit and Warrant Registration Rights Agreement.
Opco Credit Facility Amendment
NRP entered into the Second Amendment to Opco’s Third Amended and Restated Credit Agreement to extend the term thereof until April 2020, and reduced the commitments of the lenders to $180 million (from $210 million) effective at the closing of the recapitalization transactions. Pursuant the Second Amendment, commitments under the Opco Credit Facility will be reduced to $150 million at December 31, 2017 and further reduced to $100 million at December 31, 2018 through maturity in April 2020. The amendment does not change the pricing grid or financial covenants under the Opco Credit Facility; provided, however, that if NRP increases its quarterly distribution to its common unitholders above $0.45 per common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from 4.0x to 3.0x. Other terms of the Second Amendment include revisions to the mandatory prepayment provisions with respect to net cash proceeds received from certain asset sales and additional limitations on the ability of Opco and its subsidiaries to make certain investments. The Second Amendment is filed as Exhibit 10.14 to this Annual Report on Form 10-K and is incorporated herein by reference.
Issuance of 2022 Notes; Exchange and Redemption of 2018 Notes
NRP and NRP Finance issued $346 million aggregate principal amount of 10.500% Senior Notes due 2022 to several holders of its 2018 Notes. Of the $346 million of 2022 Notes issued, $241 million in aggregate principal amount were issued in exchange for $241 million in aggregate principal amount of 2018 Notes, and $105 million of the 2022 Notes were issued to the holders in exchange for cash. The 2022 Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 Indenture"), bear interest at 10.500% per year, are payable semi-annually on March 15 and September 15, beginning September 15, 2017, and mature on March 15, 2022.
NRP and NRP Finance have the option to redeem the 2022 Notes, in whole or in part, at any time on or after March 15, 2019, at the redemption prices (expressed as percentages of principal amount) of 105.25% for the 12-month period beginning March 15, 2019, 102.625% for the 12-month period beginning March 15, 2020, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the date of redemption. Furthermore, before March 15, 2019, NRP may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of certain public or private equity offerings at a redemption price of 110.500% of the principal amount of 2022 Notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Notes issued under the 2022 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the 2022 Indenture, the holders of the 2022 Notes may require us to purchase their 2022 Notes at a purchase price equal to 101% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any. The 2022 Notes purchased for cash were issued at a price of 98.75% (original issue discount of 1.25%), and each holder exchanging 2018 Notes received a fee of 5.813% of the aggregate principal amount of all 2018 Notes tendered for exchange by such holder, as well as all accrued and unpaid interest thereon.
The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing the 2018 Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under the debt incurrence covenant, NRP's non-guarantor restricted subsidiaries will not be permitted to incur additional indebtedness unless their consolidated leverage ratio is less than 3.00x (measured on a pro forma basis and assuming that the greater of (i) $150.0 million of debt (or, if less, at NRP's election, the amount of total lending commitments under any revolving credit facility) and (ii) the actual amount of debt outstanding is outstanding under any revolving credit facility); provided, however, that such non-guarantor restricted subsidiaries will be permitted to make up to $150 million in borrowings under a revolving credit facility (which amount will be reduced on a dollar-for-dollar basis to the extent we have made the election described in clause (i) above). Under the restricted payments covenant, NRP will not be able to increase the quarterly distribution on its common units or elect to pay more than 50% of the distributions required to be made on the Preferred Units in the form of cash, unless, in each case, our consolidated leverage ratio is less than 4.00x. The 2022 Indenture also contains restrictions on NRP's ability to redeem the Preferred Units.
The 2022 Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance, including the remaining outstanding 2018 Notes, and senior in right of payment to any of NRP's subordinated debt. The 2022 Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiaries guarantee the 2022 Notes.
The terms of the 2022 Notes are more fully described in the 2022 Indenture, which is filed as Exhibit 4.24 to this Annual Report on Form 10-K and incorporated herein by reference.
NRP entered into a registration rights agreement (the "Notes Registration Rights Agreement") with the holders of the 2022 Notes, pursuant to which we and NRP Finance agreed to file a registration statement with the Securities and Exchange Commission for the benefit of the holders of the 2022 Notes so that such holders can exchange the 2022 Notes for exchange securities that have substantially identical terms as the 2022 Notes. NRP and NRP Finance agreed to use commercially reasonable efforts to cause the exchange to be completed within 180 days after the closing and will be required to pay additional interest, as specified in the Notes Registration Rights Agreement, if NRP fails to comply with its obligations to register the 2022 Notes within the specified time periods.
NRP expects to redeem $90 million in aggregate principal amount of the 2018 Notes at a redemption price of 104.563%, and pay all accrued and unpaid interest thereon, in April 2017. In addition, NRP is required to redeem any and all remaining outstanding 2018 Notes (and pay accrued and unpaid interest thereon) within 60 days after October 1, 2017.
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
As discussed in Note 3. Discontinued Operations, the Partnership sold its non-operated oil and gas working interest assets in July 2016 and exited this business. The Partnership prepared the following oil and gas information in accordance with the authoritative guidance for oil and gas extractive activities for the years ended December 31, 2015 and 2014.
Capitalized Costs for the year ended December 31, 2015 (in thousands):
|
| | | |
| Proven properties | $ | 199,404 |
|
| Unproven properties | — |
|
| Total property, plant, and equipment | 199,404 |
|
| Accumulated depreciation, depletion, and amortization | (60,542 | ) |
| Net capitalized costs | $ | 138,862 |
|
Costs incurred for property acquisitions, exploration, and development (in thousands):
|
| | | | | | | |
| | For the Years Ended
December 31, |
| | 2015 | | 2014 |
| Property acquisitions | | | |
| Proven properties | $ | — |
| | $ | 298,627 |
|
| Unproven properties | — |
| | 40,800 |
|
| Development | 29,080 |
| | 5,340 |
|
| Total | $ | 29,080 |
| | $ | 344,767 |
|
Results of Operations for Producing Activities (in thousands):
|
| | | | | | | |
| | For the Years Ended
December 31, |
| | 2015 | | 2014 |
| Production revenue | $ | 49,201 |
| | $ | 48,834 |
|
| Royalty and overriding royalty revenue (1) | 4,364 |
| | 10,732 |
|
| Total oil and gas related revenue | 53,565 |
| | 59,566 |
|
| Operating costs and expense: | | | |
| Depreciation, depletion and amortization | 40,772 |
| | 23,936 |
|
| Property, franchise and other taxes | 5,210 |
| | 5,529 |
|
| Production costs | 12,871 |
| | 12,544 |
|
| Impairment of oil and gas properties | 367,576 |
| | — |
|
| Total operating costs and expense | 426,429 |
| | 42,009 |
|
| Total income from operations | $ | (372,864 | ) | | $ | 17,557 |
|
| |
| (1) | Includes $0.4 million and $1.9 million for the years ended December 31, 2015 and 2014, respectivelyThe remaining lease term of nonproduction revenues including lease bonus payments |
Estimated Proved Reserves
Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term "reasonable certainty" implies a high degree of confidence that the quantities of crude oil, natural gas liquids and/or natural gas actually recovered will equal or exceed the estimate. The Partnership estimated proved reserves as of December 31, 2015 and 2014 were prepared by a third party independent reserve engineer. To achieve reasonable certainty, the third party engineer employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
used in the estimation of the Partnership’s proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole and production data and well test data. The third party engineer prepared its report covering properties representing 100% of the Partnership’s estimated proved reserves as of December 31 2015 and 2014. Prices were calculated using the unweighted average of the first-day-of-the-month pricing for the twelve months ended December 31, 2015 and 2014. These prices were then adjusted for transportation and other costs. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reserve engineers often arrive at different estimates for the same properties.
The following table shows our estimated domestic proved reserves and reserve additions and revisions:
|
| | | | | | | | | | | | |
| | | Crude Oil (MBbl) | | NGLs (MBbl) | | Natural Gas (MMcf)(2) | | Total Proved Reserves (MBoe)(3) |
| December 31, 2014 | | 9,983 |
| | 1,229 |
| | 14,370 |
| | 13,607 |
|
| Revisions of previous estimates | | (1,451 | ) | | 89 |
| | 701 |
| | (1,244 | ) |
| Extensions, discoveries and other additions | | 776 |
| | 60 |
| | 541 |
| | 926 |
|
| Sales of properties | | (98 | ) | | — |
| | (62 | ) | | (108 | ) |
| Production | | (1,136 | ) | | (156 | ) | | (2,226 | ) | | (1,663 | ) |
| December 31, 2015 (1) | | 8,074 |
| | 1,222 |
| | 13,324 |
| | 11,518 |
|
| | | | | | | | | |
| Proved developed reserves as of December 31, 2015 | | 7,862 |
| | 1,196 |
| | 13,157 |
| | 11,251 |
|
| Proved undeveloped reserves as of December 31, 2015 | | 212 |
| | 26 |
| | 167 |
| | 267 |
|
| |
(1) | Includes reserves attributable to the Partnership's 51% member interest in BRP LLC.operating lease is 29 years. |
| |
| (2) | Natural gas is convertedThe present value of the operating lease liability on the basisPartnership's Consolidated Balance Sheet was calculated using a 13.5% discount rate which represents the Partnership's estimated incremental borrowing rate under the lease. As the Partnership's lease does not provide an implicit rate, the Partnership estimated the incremental borrowing rate at the time the lease was entered into by utilizing the rate of six Mcfthe Partnership's secured debt and adjusting it for factors that reflect the profile of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. |
| |
(3) | Includes 10,063MBoe of estimated proved reserves attributable toborrowing over the Partnership’s non-operated working interests in oil and natural gas properties in the Williston Basin, approximately 3% of which were proved undeveloped reserves.30-year expected lease term. |
Lessor Accounting
ThePartnership owns loadout and other transportation assets at the Partnership's Macoupin property in the Illinois Basin which is operated by Foresight Energy. The standardized measureinfrastructure at the Macoupin property is leased to a subsidiary of discounted future net cash flows from our estimated proved oilForesight Energy and gas reserves is accounted for as follows foran operating lease under ASC 842. The lease with Macoupin expires in January 2108. From the yearinception of this lease in 2009 through January 2039, the lease provides that the Partnership is entitled to variable lease payments in the form of throughput fees determined based on the amount of coal transported and processed utilizing the Partnership's assets. These fees are included in transportation and processing services revenues on the Partnership's Consolidated Statements of Comprehensive Income (Loss) and were $4.8 million, $5.0 million and $4.2 million in the years ended December 31, 2015 (in thousands):
|
| | | |
| Future cash inflows | $ | 364,352 |
|
| Less related future: | |
| Production costs | (164,649 | ) |
| Development and abandonment costs | (7,826 | ) |
| Future net cash flows before 10% discount | 191,877 |
|
| Discount to present value at a 10% annual rate | (75,524 | ) |
| Total standardized measure of discounted net cash flows | $ | 116,353 |
|
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
2019, 2018 and 2017, respectively. After January 2039, the lease provides that the Partnership is entitled to an annual rent of $10 thousand per year in place of the variable lease payments.
The table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during the year ended December 31, 2015 (in thousands): |
| | | |
| Beginning of the period | $ | 305,197 |
|
| Revisions to previous estimates: | |
| Changes in prices and costs | (188,946 | ) |
| Changes in quantities | (11,750 | ) |
| Changes in future development costs | (12,202 | ) |
| Previously estimated development costs incurred during the period | 29,080 |
|
| Additions to proved reserves from extensions, discoveries and improved recovery, less related costs | 11,928 |
|
| Purchases and sales of reserves in place, net | (3,851 | ) |
| Accretion of discount | 31,795 |
|
| Sales of oil and gas, net of production costs | (35,112 | ) |
| Production timing and other | (9,786 | ) |
| Net increase (decrease) | (188,844 | ) |
| End of period | $ | 116,353 |
|
Table of Contents
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following table summarizes quarterly financial data for 2016 and 2015 (in thousands, except per unit data):2019:
|
| | | | | | | | | | | | | | | | | | | |
| (In thousands, except per unit data) | First
Quarter | | Second
Quarter (1) | | Third
Quarter | | Fourth
Quarter (2) | | Total
2019 |
| Revenues | $ | 66,785 |
| | $ | 81,223 |
| | $ | 57,602 |
| | $ | 51,827 |
| | $ | 257,437 |
|
| Gain (loss) on asset sales and disposals | 256 |
| | 246 |
| | 6,107 |
| | (111 | ) | | 6,498 |
|
| Asset impairments | — |
| | — |
| | 484 |
| | 147,730 |
| | 148,214 |
|
| Income (loss) from operations | 49,939 |
| | 60,844 |
| | 49,594 |
| | (109,056 | ) | | 51,321 |
|
| Loss on extinguishment of debt | — |
| | 29,282 |
| | — |
| | — |
| | 29,282 |
|
| Net income (loss) from continuing operations | 35,765 |
| | 19,106 |
| | 39,163 |
| | (119,448 | ) | | (25,414 | ) |
| Income (loss) from discontinued operations | (46 | ) | | 245 |
| | 7 |
| | 750 |
| | 956 |
|
| Net income (loss) | 35,719 |
| | 19,351 |
| | 39,170 |
| | (118,698 | ) | | (24,458 | ) |
| Net income (loss) attributable to NRP | 35,719 |
| | 19,351 |
| | 39,170 |
| | (118,698 | ) | | (24,458 | ) |
| Net income (loss) attributable to common unitholders and general partner | 28,219 |
| | 11,851 |
| | 31,670 |
| | (126,198 | ) | | (54,458 | ) |
| Income (loss) from continuing operations per common unit | | | | | | | | | |
| Basic | $ | 2.26 |
| | $ | 0.93 |
| | $ | 2.53 |
| | $ | (10.15 | ) | | $ | (4.43 | ) |
| Diluted | 1.75 |
| | 0.85 |
| | 1.66 |
| | (10.15 | ) | | (4.43 | ) |
| Net income (loss) per common unit | | | | | | | | | |
| Basic | $ | 2.26 |
| | $ | 0.95 |
| | $ | 2.53 |
| | $ | (10.09 | ) | | $ | (4.35 | ) |
| Diluted | 1.75 |
| | 0.87 |
| | 1.66 |
| | (10.09 | ) | | (4.35 | ) |
| | | | | | | | | | |
| Weighted average number of common units outstanding (basic) | 12,255 |
| | 12,261 |
| | 12,261 |
| | 12,261 |
| | 12,260 |
|
| Weighted average number of common units outstanding (diluted) | 20,015 |
| | 13,388 |
| | 23,157 |
| | 12,261 |
| | 12,260 |
|
| |
| (1) | During the second quarter of 2019 the Partnership incurred a $29.3 million loss on extinguishment of debt related to the 105.250% premium paid to redeem the 2022 Senior Notes as well as the write-off of unamortized debt issuance costs and debt discount related to the 2022 Senior Notes. See Note 12. Debt, Net for more information. |
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following table summarizes quarterly financial data for 2018:
|
| | | | | | | | | | | | | | | | | | | |
| | First
Quarter (1) | | Second
Quarter | | Third
Quarter | | Fourth
Quarter | | Total
2016 |
| 2016 | | | | | | | | | |
| Revenues (including affiliates) | $ | 73,902 |
| | $ | 119,317 |
| | $ | 91,448 |
| | $ | 86,311 |
| | $ | 370,978 |
|
Gains on asset sales (2) | 21,925 |
| | (1,071 | ) | | 6,426 |
| | 1,801 |
| | 29,081 |
|
Depreciation, depletion and amortization (including affiliates) | 10,502 |
| | 11,176 |
| | 12,831 |
| | 11,763 |
| | 46,272 |
|
| Asset impairment | 1,893 |
| | 91 |
| | 5,697 |
| | 9,245 |
| | 16,926 |
|
| Income from operations | 48,991 |
| | 70,741 |
| | 38,907 |
| | 27,106 |
| | 185,745 |
|
| Net income from continuing operations | 26,351 |
| | 48,633 |
| | 16,419 |
| | 3,811 |
| | 95,214 |
|
| Net income (loss) from discontinued operations | (2,924 | ) | | (2,187 | ) | | 7,112 |
| | (323 | ) | | 1,678 |
|
| Net income from continuing operations per limited partner unit | $ | 2.11 |
| | $ | 3.90 |
| | $ | 1.32 |
| | $ | 0.31 |
| | $ | 7.65 |
|
| Net income (loss) from discontinued operations per limited partner unit | $ | (0.23 | ) | | $ | (0.18 | ) | | $ | 0.57 |
| | $ | (0.03 | ) | | $ | 0.13 |
|
| Weighted average number of common units outstanding | 12,232 |
| | 12,232 |
| | 12,232 |
| | 12,232 |
| | 12,232 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | First
Quarter (1) | | Second
Quarter | | Third
Quarter | | Fourth
Quarter (3) | | Total
2015 |
| 2015 | | | | | | | | | |
| Revenues (including affiliates) | $ | 94,447 |
| | $ | 120,228 |
| | $ | 112,199 |
| | $ | 105,874 |
| | $ | 432,748 |
|
| Gains on asset sales | 1,615 |
| | 3,455 |
| | 1,833 |
| | (3 | ) | | 6,900 |
|
Depreciation, depletion and amortization (including affiliates) | 11,514 |
| | 19,077 |
| | 16,437 |
| | 13,888 |
| | 60,916 |
|
Asset impairment (4) | — |
| | 3,803 |
| | 361,703 |
| | 19,039 |
| | 384,545 |
|
| Income (loss) from operations | 46,499 |
| | 58,324 |
| | (307,831 | ) | | 32,581 |
| | (170,427 | ) |
| Net income (loss) from continuing operations | 24,379 |
| | 36,389 |
| | (330,736 | ) | | 9,797 |
| | (260,171 | ) |
| Net income (loss) from discontinued operations | (6,890 | ) | | (3,811 | ) | | (269,265 | ) | | (31,583 | ) | | (311,549 | ) |
| Net income (loss) from continuing operations per limited partner unit | $ | 1.95 |
| | $ | 2.82 |
| | $ | (26.34 | ) | | $ | 0.78 |
| | $ | (20.78 | ) |
| Net income (loss) from discontinued operations per limited partner unit | $ | (0.55 | ) | | $ | (0.31 | ) | | $ | (21.57 | ) | | $ | (2.53 | ) | | $ | (24.97 | ) |
| Weighted average number of common units outstanding | 12,232 |
| | 12,232 |
| | 12,232 |
| | 12,232 |
| | 12,232 |
|
|
| | | | | | | | | | | | | | | | | | | |
| (In thousands, except per unit data) | First
Quarter | | Second
Quarter | | Third
Quarter | | Fourth
Quarter (1)(2)(3) | | Total
2018 |
| Revenues | $ | 59,478 |
| | $ | 69,451 |
| | $ | 58,207 |
| | $ | 63,935 |
| | $ | 251,071 |
|
| Gain on litigation settlement | — |
| | — |
| | — |
| | 25,000 |
| | 25,000 |
|
| Gain on asset sales and disposals | 651 |
| | 168 |
| | — |
| | 1,622 |
| | 2,441 |
|
| Asset impairments | 242 |
| | — |
| | — |
| | 18,038 |
| | 18,280 |
|
| Income from operations | 44,236 |
| | 52,863 |
| | 43,346 |
| | 52,093 |
| | 192,538 |
|
| Net income from continuing operations | 26,286 |
| | 35,129 |
| | 25,853 |
| | 35,092 |
| | 122,360 |
|
| Income (loss) from discontinued operations | (1,948 | ) | | 2,981 |
| | 2,688 |
| | 13,966 |
| | 17,687 |
|
| Net income | 24,338 |
| | 38,110 |
| | 28,541 |
| | 49,058 |
| | 140,047 |
|
| Net income attributable to NRP | 24,338 |
| | 37,241 |
| | 28,900 |
| | 49,058 |
| | 139,537 |
|
| Net income attributable to common unitholders and general partner | 16,838 |
| | 29,741 |
| | 21,400 |
| | 41,558 |
| | 109,537 |
|
| Income from continuing operations per common unit | | | | | | | | | |
| Basic | $ | 1.50 |
| | $ | 2.14 |
| | $ | 1.50 |
| | $ | 2.21 |
| | $ | 7.35 |
|
| Diluted | 1.16 |
| | 1.57 |
| | 1.18 |
| | 1.69 |
| | 5.90 |
|
| Net income per common unit | | | | | | | | | |
| Basic | $ | 1.35 |
| | $ | 2.38 |
| | $ | 1.71 |
| | $ | 3.33 |
| | $ | 8.77 |
|
| Diluted | 1.08 |
| | 1.71 |
| | 1.30 |
| | 2.36 |
| | 6.76 |
|
| | | | | | | | | | |
| Weighted average number of common units outstanding (basic) | 12,238 |
| | 12,246 |
| | 12,246 |
| | 12,247 |
| | 12,244 |
|
| Weighted average number of common units outstanding (diluted) | 22,125 |
| | 21,383 |
| | 21,840 |
| | 20,394 |
| | 20,234 |
|
| |
| (1) | As a resultDuring the fourth quarter of the sale of its non-operated oil and gas working interest business effective April 1, 2016,2018 the Partnership classified the operating results and cash flows of its non-operated oil and gas working interest assets as discontinued operationsrecorded $25 million in its consolidated statements of comprehensiveother income subsequentrelated to the filing of the First Quarter 2016 Form 10-Q. See below for a reconciliation to the amounts reported in the First Quarter 2016 Form 10-Q.Hillsboro litigation settlement. |
| |
| (2) | During the firstfourth quarter of 20162018 the Partnership sold oilits construction aggregates business for $205 million, before customary purchase price adjustments and gas royaltytransaction expenses, and aggregates royalty assets forrecorded a cumulative gain of $21.9 million. During$13.1 million included in income from discontinued operations on the third quarterPartnership's Consolidated Statements of 2016 the Partnership sold assets in multiple sale transactionsComprehensive Income (Loss). See Note 4. Discontinued Operations for a net gain of $6.4 million primarily related to eminent domain transactions with governmental agencies.more information. |
| |
| (3) | As a resultDuring the fourth quarter of the sale of its non-operated oil and gas working interest business effective April 1, 2016,2018 the Partnership classified the operating resultsrecorded $18.0 million in aggregates and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated statements of comprehensive income subsequent to the filing of the 2015 Form 10-K where this quarter's results were previously reported. See below for a reconciliation to the amounts reported in the 2015 Form 10-K. |
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following table reconciles previously reported quarterly information to the quarterly financial data disclosed above (in thousands, except per unit data):
|
| | | | | | | | | | | | |
| | | As Previously Reported | | Reclassified to Discontinued Operations | | Revised |
| First Quarter 2016 | | | | | | |
| Revenues | | $ | 80,826 |
| | $ | (6,924 | ) | | $ | 73,902 |
|
| Gains on asset sales | | 21,925 |
| | — |
| | 21,925 |
|
| Depreciation, depletion and amortization | | 14,743 |
| | (4,241 | ) | | 10,502 |
|
| Asset impairment | | 2,030 |
| | (137 | ) | | 1,893 |
|
| Income from operations | | 47,156 |
| | 1,835 |
| | 48,991 |
|
| Net income from continuing operations | | 23,427 |
| | 2,924 |
| | 26,351 |
|
| Net income (loss) from discontinued operations | | — |
| | (2,924 | ) | | (2,924 | ) |
| Net income from continuing operations per limited partner unit | | $ | 1.88 |
| | $ | 0.23 |
| | $ | 2.11 |
|
| Net income (loss) from discontinued operations per limited partner unit | | $ | — |
| | $ | (0.23 | ) | | $ | (0.23 | ) |
| Weighted average number of common units outstanding | | 12,232 |
| | | | 12,232 |
|
| | | | | | | |
| First Quarter 2015 | | | | | | |
| Revenues | | $ | 107,611 |
| | $ | (13,164 | ) | | $ | 94,447 |
|
| Gains on asset sales | | 2,066 |
| | (451 | ) | | 1,615 |
|
| Depreciation, depletion and amortization | | 25,392 |
| | (13,878 | ) | | 11,514 |
|
| Asset impairment | | — |
| | — |
| | — |
|
| Income from operations | | 40,417 |
| | 6,082 |
| | 46,499 |
|
| Net income from continuing operations | | 17,489 |
| | 6,890 |
| | 24,379 |
|
| Net income (loss) from discontinued operations | | — |
| | (6,890 | ) | | (6,890 | ) |
| Net income from continuing operations per limited partner unit | | $ | 1.40 |
| | $ | 0.55 |
| | $ | 1.95 |
|
| Net income (loss) from discontinued operations per limited partner unit | | $ | — |
| | $ | (0.55 | ) | | $ | (0.55 | ) |
| Weighted average number of common units outstanding | | 12,232 |
| | | | 12,232 |
|
|
| | | | | | | | | | | | | | | |
| | As Reported | | Presentation Reclassification | | Reclassified to Discontinued Operations | | As Revised |
| Fourth Quarter 2015 | | | | | | | |
| Revenues | $ | 116,063 |
| | $ | 3 |
| | $ | (10,192 | ) | | $ | 105,874 |
|
| Gains on asset sales | — |
| | (3 | ) | | — |
| | (3 | ) |
| Depreciation, depletion and amortization | 18,152 |
| | — |
| | (4,264 | ) | | 13,888 |
|
| Asset impairment | 50,953 |
| | — |
| | (31,914 | ) | | 19,039 |
|
| Income from operations | 2,042 |
| | — |
| | 30,539 |
| | 32,581 |
|
| Net income from continuing operations | (21,786 | ) | | — |
| | 31,583 |
| | 9,797 |
|
| Net income (loss) from discontinued operations | — |
| | — |
| | (31,583 | ) | | (31,583 | ) |
| Net income from continuing operations per limited partner unit | $ | (1.75 | ) | | $ | — |
| | $ | 2.53 |
| | $ | 0.78 |
|
| Net income (loss) from discontinued operations per limited partner unit | $ | — |
| | $ | — |
| | $ | (2.53 | ) | | $ | (2.53 | ) |
| Weighted average number of common units outstanding | 12,232 |
| | | | | | 12,232 |
|
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2016.2019. This evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures were effective as of December 31, 20162019 at the reasonable assurance level in producing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosures.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 20162019 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission "2013 Framework" (COSO). Based on that evaluation, as of December 31, 2019, our management concluded that our internal control over financial reporting was effective as of December 31, 2016.at a reasonable assurance level based on those criteria. No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s consolidated financial statements included in this Annual Report on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting, which is included herein.
Report of Independent Registered Public Accounting Firm
The Partners of Natural Resource Partners L.P.
Opinion on Internal Control Over Financial Reporting
We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2016,2019, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Natural Resource Partners L.P.’s (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2019 and 2018, the related consolidated statements of comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and our report dated February 27, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’sPartnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.
In our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2016 and 2015, and the related consolidated statements of comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2016 and our report dated March 6, 2017 expressed an unqualified opinion there thereon.
/s/ Ernst & Young LLP
Houston, Texas
March 6, 2017February 27, 2020
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER AND CORPORATE GOVERNANCE
As a master limited partnership we do not employ any of the people responsible for the management of our properties. Instead, we reimburse affiliates of our managing general partner, GP Natural Resource Partners LLC, for their services. The following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC as of the date of this Annual Report on Form 10-K. Each officer and director is elected for their respective office or directorship on an annual basis. Unless otherwise noted below, the individuals served as officers or directors of the partnership since the initial public offering. Subject to the Investor Rights Agreement with Adena Minerals, LLC, and the Board Representation and Observation Rights Agreement with Blackstone and GoldenTree.GoldenTree, Mr. Robertson is entitled to nominate eleven directors toappoint the members of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, and the right to nominateappoint one director to Blackstone.
|
| | | | | |
| Name | | Age | | Position with the General Partner |
| Corbin J. Robertson, Jr. | | 6972 |
| | Chairman of the Board and Chief Executive Officer |
Wyatt L. HoganCraig W. Nunez | | 4558 |
| | President and Chief Operating Officer |
Craig W. NunezChristopher J. Zolas | | 5545 |
| | Chief Financial Officer and Treasurer |
Christopher J. Zolas | | 42 |
| | Chief Accounting Officer |
| Kevin J. Craig | | 4851 |
| | Executive Vice President, Coal |
Kathy H. Roberts | | 65 |
| | Vice President, Investor Relations |
| Kathryn S. Wilson | | 4245 |
| | Vice President, General Counsel and Secretary |
| Gregory F. Wooten | | 6163 |
| | Vice President, Chief Engineer |
Robert T. BlakelyGaldino J. Claro | | 7560 |
| | Director |
| Russell D. Gordy | | 6669 |
| | Director |
L. G. (Trey) Jackson IIIAlexander D. Greene | | 41 |
| | Director |
Robert B. Karn III | | 75 |
| | Director |
Jasvinder S. Khaira | | 3561 |
| | Director |
| S. Reed Morian | | 7174 |
| | Director |
| Paul B. Murphy, Jr. | | 60 |
| | Director |
| Richard A. Navarre | | 5659 |
| | Director |
| Corbin J. Robertson, III | | 4649 |
| | Director |
| Stephen P. Smith | | 5658 |
| | Director |
| Leo A. Vecellio, Jr. | | 7073 |
| | Director |
Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC since 2002. Mr. Robertson has vast business experience having founded and served as a director and as an officer of multiple companies, both private and public, and has served on the boards of numerous non-profit organizations. He has served as the Chief Executive Officer and Chairman of the Board of the general partner of Great Northern Properties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978, as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986, and the general partner of Western Pocahontas Properties Limited Partnership since 1986. In addition, Mr. Robertson served as Chief Executive Officer of the general partner of Western Pocahontas Properties Limited Partnership from 1986 until 2008 and currently serves on the Board of Managers of Premium Resources, LLC. He also serves as a Principal with Quintana Capital Group, Chairman of the Board of the Cullen Trust for Higher Education and on the boards of the American Petroleum Institute, the National Petroleum Council, the Baylor College of Medicine and the Spirit Golf Association. In 2006, Mr. Robertson was inducted into the Texas Business Hall of Fame. Mr. Robertson is the father of Corbin J. Robertson, III.
Wyatt L. HoganCraig W. Nunez has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since March 2015. From September 2014 through February 2015, Mr. Hogan served as President of GP Natural Resource Partners LLC. Mr. Hogan was Executive Vice President of GP Natural Resource Partners from December 2013 through August 20142017 and Vice President, General Counsel and Secretary of GP Natural Resource Partners from May 2003 to December 2013. Mr. Hogan joined NRP in 2003 from Vinson & Elkins L.L.P., where he practiced corporate and securities law from August 2000 through April 2003. Mr. Hogan also serves as Executive Vice President of Quintana Minerals Corporation, New Gauley Coal Corporation, the general
partner of Western Pocahontas Properties Limited Partnership and the general partner of Great Northern Properties Limited Partnership, and from 2003 to October 2013, Mr. Hogan served as General Counsel and Secretary of those entities. He is also a member of the Board of Directors of Quintana Minerals Corporation and represents NRP as one of its appointees to the Board of Managers of Ciner Wyoming LLC. Mr. Hogan also serves as a member of the Board of the National Mining Association and the American Coalition for Clean Coal Electricity. Mr. Hogan has been involved in numerous charitable organizations and currently serves on the Boards of Kids' Meals, Inc. and the Kinkaid Investment Foundation and serves as Chairman of the Board of the Kinkaid Alumni Association.
Craig W. Nunez haspreviously served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC sincefrom January 2015.2015 to August 2017. Prior to joining NRP, Mr. Nunez was an owner and Chief Executive Officer of Bocage Group, a private investment company specializing in energy, natural resources and master limited partnerships since March 2012. In addition, until joining NRP, he was a FINRA-registered Investment Advisor Representative with Searle & Co since July 2012 and served as an Executive Advisor to Capital One Asset Management since January 2014. From September 2011 through March 2012, Mr. Nunez served as the Executive Vice President and Chief Financial Officer of Quicksilver Resources Canada, Inc. Mr. Nunez was Senior Vice President and Treasurer of Halliburton Company from January 2007 until September 2011, and Vice President and Treasurer of Halliburton Company from February 2006 to January 2007. Prior to that, he was Treasurer of Colonial Pipeline Company from November 1995 to February 2006. Mr. Nunez has been involved in numerous charitable organizations and currently serves on the boards of Goodwill Industries of Houston and Medical Bridges, Inc.
Christopher J. Zolas has served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC since August 2017 and previously served as Chief Accounting Officer of GP Natural Resource Partners sincefrom March 2015.2015 to August 2017. Prior to joining NRP, Mr. Zolas served as Director of Financial Reporting at Cheniere Energy, Inc., a publicly traded energy company, where he performed financial statement preparation and analysis, technical accounting and SEC reporting for five separate SEC registrants, including a master limited partnership. Mr. Zolas joined Cheniere Energy, Inc. in 2007 as Manager of SEC Reporting and Technical Accounting and was promoted to Director in 2009. Prior to joining Cheniere Energy, Inc., Mr. Zolas worked in public accounting with KPMG LLP from 2002 to 2007.
Kevin J. Craig has served as Executive Vice President, Coal of GP Natural Resource Partners since September 2014. Mr. Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr. Craig also represents NRP as one of its appointees to the Board of Managers of Ciner Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX Transportation, where he served as Terminal Manager for the West Virginia Coalfields. He has extensive marketing, finance and operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates having been elected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate Craig served as Chairman of the Committee on Energy. Mr. Craig did not seek re-election in 2014 and his term ended January 2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig has served as the Chairman of the Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber of Commerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He is involved in numerous state coal associations and serves as a member of the Board of Directors of BrickStreet Mutual Insurance Company.
Kathy H. Roberts is Vice President, Investor Relations of GP Natural Resource Partners LLC. Ms. Roberts joined NRP in July 2002. She was the Principal of IR Consulting Associates from 2001 to July 2002 and from 1980 through 2000 held various financial and investor relations positions with Santa Fe Energy Resources, most recently as Vice President-Public Affairs. She is a Certified Public Accountant. Ms. Roberts currently serves on the Board of Directors of the Master Limited Partnership Association and has served on the local board of directors of the National Investor Relations Institute. She has also served on the Executive Committee and as a National Vice President of the Institute of Management Accountants.
Kathryn S. Wilson has served as Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC since December 2013. Ms. Wilson served as Associate General Counsel from March 2013 to December 2013. Since October 2013, Ms. Wilson has also served as General Counsel and Secretary of each of Quintana Minerals Corporation, New Gauley Coal Corporation and the general partner of Western Pocahontas Properties Limited Partnership,Partnership. She served as General Counsel of Quintana Minerals Corporation from October 2013 to November 2018 and as General Counsel of the general partnerGeneral Partner of Great Northern Properties Limited Partnership. Ms. Wilson also represents NRP as one of its appointeesPartnership from October 2013 to the Board of Managers of Ciner Wyoming LLC.June 2019. Ms. Wilson practiced corporate and securities law with Vinson & Elkins L.L.P. from September 2001 to February 2010 and from November 2011 to February 2013. Ms. Wilson served as General Counsel of Antero Resources Corporation from March 2010 to June 2011. Ms. Wilson also represents NRP as one of its appointees to the Board of Managers of Ciner Wyoming LLC.
Gregory F. Wooten has served as Vice President, Chief Engineer of GP Natural Resource Partners LLC since December 2013. Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP, Mr. Wooten served as Vice President, COOChief Operating Officer and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties from 1982 until 2007. Prior to 1982, Mr. Wooten workedhas over 35 years of experience in the coal industry, working as a planning and production engineer in the coal industry and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers. Mr. Wooten has servedalso serves as Chairmanthe President of the National Council of Coal Lessors since 2015.and is a board member of the West Virginia, Kentucky, Indiana and Montana Coal Associations. He also serves on the board of the Cabell-Huntington Hospital.
Robert T. BlakelyGaldino J. Claro joined the Board of Directors of GP Natural Resource Partners LLC in January 2003.March 2018. Mr. BlakelyClaro has extensive public company30 years of worldwide executive leadership experience havingin the primary and secondary metals industries. From October 2013 to August 2017, Mr. Claro served as the Group Chief Executive Vice PresidentOfficer and Managing Director of Sims Metal Management where he was also a member of the Safety, Health, Environment and Sustainability Committee, the Nomination Governance Committee and the Finance Investment Committee. Before joining Sims Metal Management, Mr. Claro served for four years as the Chief FinancialExecutive Officer for several companies. From January 2006 until August 2007,of Harsco Metals and Minerals. He joined Harsco from Aleris, where he served as ExecutiveCEO of Aleris Americas. Before that, he was the CEO of the Metals Processing Group of Heico Companies LLC. During his career with Alcoa Inc., Mr. Claro served for five years as the President of Alcoa China and for six years in Europe as the Vice President of Soft Alloys Extrusions and Chief Financial Officerthe President of Fannie Mae,Alcoa Europe Extrusions. While in South America, Mr. Claro worked for several different divisions of Alcoa Alumni SA as plant manager, technology manager, new products development director and from August 2007 to January 2008 as an Executive Vice PresidentManaging Director of Alcoa Cargo-Van. Before joining Alcoa in 1985, Mr. Claro started his career at Fannie Mae. From mid-2003 through January 2006, he was Executive Vice President and Chief Financial Officer of MCI, Inc. He previously served as Executive Vice President and Chief Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco, Inc. from 1981 until 1999 as wellHonda-Motogear as a Managing Director at Morgan Stanley. He served until December 31, 2011 as a Trustee of the Financial Accounting Foundation and is a trustee emeritus of Cornell University. He has served on the Board of Westlake Chemical Corporation since August 2004. In 2009, Mr. Blakely joined the Boards of Directors of Greenhill & Co. and Ally Financial (formerly GMAC, Inc.),Quality Control Manager where he serves as Chairmanworked for three years in both Brazil and Japan.
Russell D. Gordy joined the Board of Directors of GP Natural Resource Partners in October 2013. Mr. Gordy brings extensive oil and gas industry, mineral interest and land ownership and financial experience to the Board. Mr. Gordy is currently managing partner and majority owner in SG Interests, a producer of oil and coal bed methane gas, RGGS, which controls mineral acres currently producing oil and gas, coal, iron ore, limestone, and copper, and Rock Creek Ranch. He is also President of Gordy Oil Company, an oil and gas exploration company in the Gulf Coast of Texas and Louisiana, and Gordy Gas Corporation, an oil and gas exploration company in the San Juan Basin of Colorado and New Mexico. Prior to forming SG Interests in 1989, Mr. Gordy was a founding partner of Northwind Exploration Company an exploration company created in 1981 with former Houston Oil and Minerals employees. Mr. Gordy served on the board of directors of Houston Exploration Company from 1987 until 2001.
L. G. (Trey) Jackson IIIAlexander D. Greene joined the Board of Directors of GP Natural Resource Partners LLC in April 2016.March 2019. Mr. JacksonGreene brings financialextensive corporate finance and coal industryprivate equity experience to his role on the Board, with more than 35 years investing in businesses where operational improvement and strategic guidance were primary drivers of value creation and as a financial advisor to large and mid-cap companies, boards of directors and other constituencies in complex leveraged finance, merger and acquisition and recapitalization transactions. Mr. Greene is a director of Ambac Financial Group, Inc., Element Fleet Management Corp. and is Chairman of the Board of Directors.USA Truck, Inc. In addition, Mr. Jackson is currently the Managing Director of the Cline Group, a group of companies affiliated with Christopher Cline, having served in that capacity since March 2011, where he has responsibility for mergers and acquisitions, deal structuring and certain other commercial activities. Also during this time, from June 2013 until August 2015, Mr. JacksonGreene recently served as the PresidentChairman of Convent Marine Terminal. Prior to joining Mr. Cline’s management group, Mr. Jackson served in various capacities at two energy private equity firms and a boutique investment bank. Mr. Jackson also serves on the Board of DirectorsModular Space Corporation prior to its sale to Williams Scotsman in 2018. From 2005 to 2014 he was a Managing Partner and head of Material Sciences Corp.
Robert B. Karn III joined the BoardU.S. Private Equity at Brookfield Asset Management, a global asset management company. Prior to Brookfield, Mr. Greene was a Managing Director and co-head of Directors of GP Natural ResourceCarlyle Strategic Partners, LLC in 2002.a private equity fund, and a Managing Director and investment banker at Wasserstein Perella & Co. and Whitman Heffernan Rhein & Co. Mr. Karn brings extensive financial and coal industry experience to the Board of Directors. He currentlyGreene is a consultantvolunteer firefighter and president of the Armonk Independent Fire Company and serves on the BoardBudget and Finance Advisory Committee for the Town of Directors of various entities. He was the partner in charge of the coal mining practice worldwide for Arthur Andersen from 1981 until his retirement in 1998. He retired as Managing Partner of the St. Louis office’s Financial and Economic Consulting Practice.North Castle, New York. Mr. Karn is a Certified Public Accountant, Certified Fraud Examiner and has served as president of numerous organizations. He also currently serves on the Board of Directors of Peabody Energy Corporation, Kennedy Capital Management, Inc. and the Board of Trustees of numerous publicly listed closed-end, mutual and exchange traded funds of the Guggenheim family of funds.
Jasvinder S. Khaira joined the Board of Directors of GP Natural Resource Partners LLC in March 2017. Mr. Khaira brings extensive financial and investing experience to the Board of Directors. Mr. Khaira currently is a Senior Managing Director in the Tactical Opportunities group at The Blackstone Group L.P. Mr. Khaira joined Blackstone as a member of its Private Equity Group in 2004. Mr. KhairaGreene has been designated to serve as a director of GP Natural Resource Partners LLC by Blackstone Tactical Opportunities, pursuant to its right to designate a director to the Board of Directors of GP Natural Resource Partners LLC. Since joining Blackstone, Mr. Khaira has been involved in a variety of investments and strategic business initiatives at Blackstone.
S. Reed Morian joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive business experience having served as Chairman and Chief Executive Officer of several companies since the early 1980s and serving on the board of other companies. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian also serves on the Board of Managers of Premium Resources, LLC since 2006. Mr. Morian worked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief
Executive Officer from 1981 to 2006. He has also served as Chairman, Chief Executive Officer and President of DX Holding Company since 1989. He formerly served on the Board of Directors for the Federal Reserve Bank of Dallas-Houston Branch from April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March 2005 until April 2009.
Paul B. Murphy, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Murphy is the Chairman and Chief Executive Officer and a Director of Cadence Bancorporation and Chairman of Cadence Bank, N.A. He has served at Cadence and its predecessors since December 2009. Cadence is a $17 billion bank holding company headquartered in Houston and it is traded on the NYSE (CADE). Previously, Mr. Murphy spent 20 years at Amegy Bank of Texas, helping to steer that institution from $75 million in assets and a single location to assets of $11 billion and 85 banking centers at the time of his departure as the Chief Executive Officer and a Director in 2009. Mr. Murphy is an advocate of the community and is a board member of Oceaneering International, Inc., Hope and Healing Center and Institute, Houston Hispanic Chamber of Commerce, and the City of Houston Complete Advisory Board.
Richard A. Navarre joined the Board of Directors of GP Natural Resource Partners LLC in October 2013. Mr. Navarre brings extensive financial, strategic planning, public company and coal industry experience to the Board of Directors. Mr. Navarre is Chairman, President and CEO of Covia Corporation. From 1993 until 2012, Mr. Navarre held several executive positions with Peabody Energy Corporation, including President-Americas from March 2012 to June 2012, President and Chief Commercial Officer from January 2008 to March 2012, Executive Vice President of Corporate Development and Chief Financial Officer from July 2006 to January 2008 and Chief Financial Officer from October 1999 to June 2008. Since his retirement from Peabody Energy in 2012, Mr. Navarre has provided advisory services to the coal industry and private equity firms. Mr. Navarre serves on the Board of Directors of Civeo Corporation, where he serves as Chairman, of the Audit Committee,Covia Corporation, where he serves as Chairman, and Arch Coal, where he serves onas Chairman of the Audit committee.Compensation Committee and member of the Nominating and Governance Committee. He is a member of the Hall of Fame of the College of Business and a member of the Board of Advisors of the College of Business and Administration of Southern Illinois University Carbondale. He is a member of the Board of Directors of the Foreign Policy Association and is the former Chairman of the Bituminous Coal Operators’ Association and former advisor to the New York Mercantile Exchange.Association. Mr. Navarre is a Certified Public Accountant. Mr. Navarre also has been involved in numerous civic and charitable organizations throughout his career.
Corbin J. Robertson, III joined the Board of Directors of GP Natural Resource Partners LLC in May 2013. Mr. Robertson has experience with investments in a variety of energy businesses, having served both in management of private equity firms and having served on several boards of directors. Mr. Robertson has served as a Co-Managing Partner of LKCM Headwater Investments GP, LLC, and LKCM Headwater Investments I, L.P., aLKCM Headwater Investments II, LP, LKCM Headwater Investments II Sidecar, LP, LKCM Headwater Investments III, private equity fund, sincefunds that began June 2011. He has served as the Chief Executive Officer of the general partner of Western Pocahontas Properties Limited Partnership since May 2008, and has served on the Board of Directors of Quintana Minerals Corporation since 2007 and Western Pocahontas since October 2012. Mr. Robertson also has served on the Board of Managers of Premium Resources, LLC since 2016. Mr. Robertson also co-founded Quintana Energy Partners, an energy-focused private equity firm in 2006, and served as a Managing Director thereof from 2006 until December 2010. Mr. Robertson has served on the Board of Directors for Quintana Minerals Corporation since October 2007, and previously served as Vice President-Acquisitions for GP Natural Resource Partners LLC from 2003 until 2005. Mr. Robertson also serves on the Board of Directors of the general partner of Genesis Energy L.P., a publicly traded master limited partnership, as well as CorsaQuality Magnetite, Quinwood Coal Corp, Buckhorn Energy Services and LL&B Minerals, each of which is in the energy business. Mr. Robertson is the son of Corbin J. Robertson, Jr.
Stephen P. Smith joined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive public company financial experience in the power and energy industries to the Board of Directors. Mr. Smith formerly served as Chief Financial Officer, and Chief Accounting Officer and Director of the general partner of Columbia Pipeline Partners L.P. from December 2014 and as a Director from September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and Chief Financial Officer of Columbia Pipeline Group.Group from July 2015 to June 2016. Mr. Smith served as Executive Vice President and Chief Financial Officer for NiSource, Inc. from JuneAugust 2008 to June 2015. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc, including Senior Vice President - Shared Services from January 2008 to June 2008, Senior Vice President and Treasurer from January 2004 to December 2007, and Senior Vice President - Finance from April 2003 to December 2003. From November 2000 to January 2003, Mr. Smith served as President and Chief Operating Officer - Corporate Services for NiSource Inc. Prior to joining NiSource, Mr. Smith served as Deputy Chief Financial Officer for Columbia Energy Group from November 1999 to November 2000 and Chief Financial Officer for Columbia Gas Transmission Corporation and Columbia Gulf Transmission Company from 1996 to 1999.
Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings extensive experience in the aggregates and coal mine development industry to the Board of Directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the late 1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer, contractor and oil terminal developer/operator in the Mid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with Vecellio & Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996 to November 2002. Mr. Vecellio is the former Chairman of the American Road and Transportation Builders and is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations.
Corporate Governance
Board Meetings and Executive Sessions
The Board met 16eight times in 2016.2019. During 2016,2019, our non-management directors met in executive session several times. The presiding director was Mr. Blakely,Vecellio, the Chairman of our Compensation, Nominating and Governance Committee, or CNG Committee. In addition, our independent directors met one time in executive session in December 2016.2019. Mr. BlakelyVecellio was the presiding director at that meeting. Interested parties may communicate with our non-management directors by writing a letter to the Chairman of the CNG Committee, NRP Board of Directors, 1201 Louisiana Street, Suite 3400, Houston, Texas 77002.
In April 2016, Donald R. Holcomb resigned from the Board of Directors of GP Natural Resource Partners LLC, and L.G. (Trey) Jackson, III was appointed to the Board. In March 2017, Jasvinder Khaira was appointed to the Board by Blackstone.
Independence of Directors
The Board of Directors has affirmatively determined that Messrs. Blakely,Claro, Gordy, Karn, Navarre, Smith and Vecellio are independent based on all facts and circumstances considered by the Board, including the standards set forth in Section 303A.02(a) of the NYSE’s listing standards. Although we had a majority of independent directors in 2016, becauseBecause we are a limited partnership as defined in Section 303A of the NYSE’s listing standards, we are not required to do so.have a majority of independent directors on the Board. The Board has an Audit Committee, a Compensation, Nominating and Governance Committee, and a Conflicts Committee, each of which is staffed solely by independent directors.
Audit Committee
Our Audit Committee is comprised of Robert B. Karn III,Mr. Smith, who serves as chairman, Robert T. Blakely, Richard A. NavarreMr. Claro and Stephen P. Smith. Mr. Karn,Navarre. Mr. Blakely,Smith and Mr. Navarre and Mr. Smith are "Audit Committee Financial Experts" as determined pursuant to Item 407 of Regulation S-K. During 2016,2019, the Audit Committee met seven times.
Report of the Audit Committee
Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements of the New York Stock Exchange. The Audit Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements. The Audit Committee Charter is available on our website at www.nrplp.com and is available in print upon request.
During 2016,2019, at each of its meetings, the Audit Committee met with the senior members of our financial management team, our general counsel and our independent auditors. The Audit Committee had private sessions at certain of its meetings with our independent auditors and the senior members of our financial management team and the general counsel at which candid discussions of financial management, accounting and internal control and legal issues took place.
The Audit Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 20162019 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our financial reporting.
Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference for conservative policies when a range of accounting options is available.
The Audit Committee alsohas discussed with the independent auditors otherthe matters required to be discussed by the auditorsapplicable requirements of the Public Company Accounting Oversight Board (“PCAOB”) and the Commission. The Audit Committee has received the written disclosures and the letter from the independent accountant required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the Audit Committee by PCAOB Auditing Standard No. 16, Communications With Audit Committees. The Committee receivedconcerning independence, and has discussed with the auditors their annual written report on their independence fromindependent accountant the partnership and its management, which is made under
Rule 3526, Communication With Audit Committees Concerning Independence, and considered with the auditors whether the provision of non-audit services provided by them to the partnership during 2016 was compatible with the auditors’independent accountant’s independence.
In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Audit Committee reviews our Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K prior to filing with the Securities and Exchange Commission. In 2016,2019, the Audit Committee also reviewed quarterly earnings announcements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Audit Committee relies on the work and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report, express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting principles.
In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, and the Board has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2016,2019, for filing with the Securities and Exchange Commission.
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| | | | |
| | | | Robert B. Karn III,Stephen P. Smith, Chairman | |
| | | | Robert T. BlakelyGaldino J. Claro | |
| | | | Richard A. Navarre | |
| | | Stephen P. Smith | |
Compensation, Nominating and Governance Committee
Executive officer compensation is administered by the CNG Committee, which is currently comprised of four members. Mr. Blakely, the Chairman, has served on the CNG Committee since 2003. Mr. Karn has served on the CNG Committee since 2002.three members: Mr. Vecellio, joined the Committee in 2007,as Chairman, Mr. Gordy and Mr. Gordy joined the CNG Committee in 2013.Smith. The CNG Committee has reviewed and approved the compensation arrangements described in the Compensation Discussion and Analysis section of this Annual Report on Form 10-K. During 2016,2019, the CNG Committee met four times. Our Board of Directors appoints the CNG Committee and delegates to the CNG Committee responsibility for:
reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates to our business;
reviewing and recommending the annual and long-term incentive plans in which our executive officers participate;participate and approving awards thereunder; and
reviewing and approving compensation for the Board of Directors.
Our Board of Directors has determined that each CNG Committee member is independent under the listing standards of the NYSE and the rules of the SEC.
Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the design and implementation of compensation programs for directors and executive officers and other data that the CNG Committee considers as appropriate. In addition, the CNG Committee has the sole authority to retain and terminate any outside counsel or other experts or consultants engaged to assist it in the evaluation of compensation of our directors and executive officers. The CNG Committee Charter is available in print upon request.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the NYSE initial reports of ownership and reports of changes in ownership of their equity securities. These people 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 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required for transactions occurring in 2015, and we believe that our officers and directors and persons who beneficially own more than ten percent of a registered class of our equity securities complied with all filing requirements with respect to transactions in our equity securities during 2016.
Partnership Agreement
Investors may view our partnership agreement and the amendments to the partnership agreement on our website at www.nrplp.com. The partnership agreement and the amendments areis also filed with the SEC and areis available in print to any unitholder that requests them.
Corporate Governance Guidelines and Code of Business Conduct and Ethics
We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that applies to our management, and complies with Item 406 of Regulation S-K. Our Corporate Governance Guidelines and our Code of Business Conduct and Ethics are available on our website at www.nrplp.com and are available in print upon request.
NYSE Certification
Pursuant to Section 303A of the NYSE Listed Company Manual, in 2016,2019, Corbin J. Robertson, Jr. certified to the NYSE that he was not aware of any violation by the Partnership of NYSE corporate governance listing standards.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Overview
As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. We have no employees, other than at the VantaCore operations, and ourOur executive officers based in Houston, Texas are employed by Quintana Minerals Corporation (“Quintana”), and our executive officers based in Huntington, West Virginia are employed by Western Pocahontas Properties Limited Partnership both(“Western Pocahontas”). Quintana and Western Pocahontas are controlled by our Chairman and Chief Executive Officer and are affiliates of whichNRP. While our executive officers are our affiliates.employed by affiliates of NRP, each of them has been appointed to serve as an executive officer of GP Natural Resource Partners LLC (“GP LLC”), the general partner of NRP (GP) LLC (“NRP GP”), the general partner of NRP. For a more detailed description of our structure, see "Item"Items 1. Business—and 2. Business and Properties—Partnership Structure and Management"Management" in this Annual Report on Form 10-K.
Although our executives’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse those companies based on the time allocated to NRP by each executive officer. Our reimbursement for the compensation of executive officers is governed by our partnership agreement. For purposes of this Compensation Discussion and Analysis, our “named executive officers” are:
Corbin J. Robertson, Jr.—Chairman and Chief Executive Officer
Craig W. Nunez—President and Chief Operating Officer
Christopher J. Zolas—Chief Financial Officer and Treasurer
Kathryn S. Wilson—Vice President, General Counsel and Secretary
Kevin J. Craig—Executive Vice President, Coal
Executive Officer Compensation Strategy and Philosophy
Under our partnership agreement, we are required to distribute all of our available cash each quarter. Historically, our primary business objective was to generate cash flows at levels that could sustain long-term quarterly cash distributions to our investors. However, given the difficult coal markets over the past few years, coupled with the limitations on our ability to access capital from additional sources, our current objective is to preserve long-term equity value for our unitholders by using our excess free cash flow to reduce our leverage. Our objective in determining the compensation of our executive officers is to retain qualified people to manage the business through a difficult market cycle. Although we historically have not tied our compensation to achievement of specific financial targets or fixed performance criteria, we have reevaluated that strategy in light ofunder current market conditions. See "—Evaluation of 2016 Performance; Incentive compensation for the year ended December 31, 2019 was discretionary but certain performance criteria were considered as factors, as further described under “—Components of Compensation-Long-Term Incentive Compensation-2016 Cash Long-Term Incentive Plan" below.Compensation.”
The 20162019 compensation for executive officers consisted of four primary components:
base salaries;
annualshort-term cash incentive awards, including cash payments made by our general partner based on the cash distributions it receives from the common units that it owns (which we refer to herein as "GP Bonus Awards");compensation;
long-term equity and cash incentive compensation; and
perquisites and other benefits.
In December 2015, our CNG Committee reviewedTo the performance of the executive officers and the amount of time expected to be spent by each NRP officer on NRP business, and determined the salaries for each officer for 2016. All ofextent our named executive officers other than Corbin J. Robertson, Jr., our Chairman and Chief Executive Officer and Kathryn S. Wilson, our Vice President, General Counsel and Secretary, spent 100%(with the exception of theirMr. Robertson) spend time on NRPnon-NRP matters, during 2016, and NRP bears only the proportionate cost of their time. Mr. Robertson has historically spent approximately 50% of his time on NRP matters. Mr. Robertson does not receive a salary or an annual bonus in his capacity as Chief Executive Officer. Rather, Mr. Robertson has historically beenis compensated exclusively through short-term cash and long-term equity incentive awards, and through GP Bonus Awards. Mr. Robertson also directly or indirectly owns in excessall of 20% of the outstanding common units of NRP, and thus his interests are directly aligned with our unitholders. In 2016, Ms. Wilson spent approximately 94% of her time on NRP matters and the rest of her time on private Robertson family owned company matters, and her time has beenwhich is allocated to NRP accordingly.NRP.
Historically, inIn February of each year, the CNG Committee has approvedapproves the year-end bonusesshort-term cash incentive award for the year just ended and long-term incentive awards for the executive officers. The CNG Committee considers the performance of the partnership, the performance of the individuals and the outlook for the future in determining the amounts of the awards. Because we are a partnership, tax and accounting conventions make it more costly for us to issue additional common units or options as incentive compensation. Consequently, we have no outstanding options or restricted units and currently have no plans to issue options or restricted units in the future. Instead, prior to 2016, we issued phantom units, coupled with tandem distribution equivalent rights ("DERs"), to our executive officers that are paid in cash based on the average closing price
During 2015, given the sharp decline in NRP’s unit price, the Board of Directors recognized that the value of the executive officers’ phantom unit awards and the decreased GP Bonus Awards no longer provided long-term incentive or retention value to management. Accordingly, the Board authorized and directed
Each February, the CNG Committee to begin a reviewalso makes awards of options for a new long-term incentive program for NRP managementphantom units to be adoptedsettled in 2016. Upon the conclusion of this review, in February 2016, the CNG Committee elected not to award additional phantomcommon units under the long-term incentive plan and instead adopted a new cash long-term incentive plan and recommended the new plan and forms of award agreements thereunder to the Board for approval. The Board approved the new plan and awards in February 2016 and approved awards to officers under the plan in March 2016. In MarchNatural Resource Partners 2017 the Board determined that the conditions to the vesting of the performance awards had been met as a result of the completion of the 2017 recapitalization transactions described elsewhere in this Annual Report on Form 10-K. See "—Evaluation of 2016 Performance; Components of Compensation-Long-Term Incentive Compensation-2016 Cash Long-Term Incentive Plan" below.
In lightPlan (the “2017 Plan”) to NRP’s officers in order to incentivize management while also aligning the long-term interests of management with the recently completed recapitalization transactions, the CNG Committee is evaluating a new long-term incentive program that best reflects the current outlook for NRP. Accordingly, no long-term incentive awards have yet been made during 2017. The CNG Committee and the Board may determine to award additional cash incentive awards, phantom unit awards or other formsinterests of long-term incentive compensation during 2017.NRP’s unitholders.
Role of Compensation Experts
Historically,In 2019, the CNG Committee periodically has utilized consultantsengaged Longnecker & Associates (“L&A”) to get a basic sensereview our compensation practices for named executive officers and directors relative to our peers. The CNG Committee, with input from L&A, selected our peer group (the “Peer Group”) after reviewing annual revenue, market capitalization, total enterprise value and total assets of relevant public companies to determine which companies were representative of the market, but has consideredmarketplace for talent within which we compete. The CNG Committee will review the advicePeer Group annually to ensure continued appropriateness for comparative purposes. The CNG Committee determined that the companies below reflect an appropriate Peer Group for 2019:
|
| | |
| Amplify Energy Corp. | Enviva Partner, LP | Ramaco Resources, Inc. |
| Black Stone Minerals, L.P. | Falcon Minerals Corporation | Rosehill Resources Inc. |
| Callon Petroleum Company | Hi-Crush Inc. | SilverBow Resources, Inc. |
| CatchMark Timber Trust, Inc. | Kimbell Royalty Partners, LP | SunCoke Energy, Inc. |
| Ciner Resources LP | NACCO Industries, Inc. | Talos Energy Inc. |
| CONSOL Coal Resources LP | Panhandle Oil and Gas, Inc. | W&T Offshore, Inc. |
| Earthstone Energy, Inc. | Penn Virginia Corporation | |
Using the Peer Group, L&A conducted compensation analyses for all components of the consultant as only one of many factors among the other items discussed in this compensation discussion and analysis. For a more detailed description ofprovided the CNG Committee with its findings after such time. The findings indicated that base salaries and its responsibilities, see "Item 10. Directors and Executive Officersshort-term incentive compensation of each of the Managing General Partner and Corporate Governance"five named executive officers was generally in this Annual Report on Form 10-K.
During 2015, atline with the direction of the Board, the CNG Committee retained Meridian Compensation Partners ("Meridian") to advise on a newPeer Group median, but that long-term incentive strategy to be implemented in 2016 in order to incentivizecompensation was well below the Peer Group median. While L&A provided recommendations for 2019 short-term cash incentive compensation, 2019 base salaries and retain management in light of the significant decrease in phantom unit award value and GP Bonus Awards. See "—Evaluation of 2016 Performance; Components of Compensation-Long-Term Incentive Compensation-2016 Cash Long-Term Incentive Plan" below. In selecting Meridian as itslong-term incentive compensation consultant, the CNG Committee assessed the independence of Meridian pursuant to SEC rules and considered, among other things, whether Meridian provides any other services to NRP, the policies of Meridian that are designed to prevent any conflict of interest between Meridian, the CNG Committee and NRP, any personal or business relationship between Meridian and a member of the CNG Committee or one of NRP’s executive officers and whether Meridian owned any of NRP’s common units. In addition to the foregoing, the CNG Committee received documentation from Meridian addressing the firm’s independence. Meridian was engaged directlygrants were determined by the CNG Committee reported exclusivelyprior to engaging L&A. Accordingly, the CNG Committee and does not provide any additional services to NRP. The CNG Committee concluded that Meridian is independent and did not have any conflicts of interest. While management did cooperate with Meridian in collecting dataL&A recommendations will be used prospectively with respect to NRP’slong-term incentive compensation, programs,with the CNG Committee determined that management had not attempted to influence Meridian’s review or recommendations.goal of bringing long-term incentive compensation more in line with the Peer Group over the next few years.
Role of Our Executive Officers in the Compensation Process
With respect to 2019 salaries and short-term cash incentive awards and long-term equity incentive awards, Mr. Hogan,Nunez, our President and Chief Operating Officer, provided Mr. Robertson with recommendations relating to the executive officers other than himself in connection with the evaluation of the 2016 compensation programs.himself. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of the executive officers other than himself. Mr.Messrs. Robertson relied on his personal experience in setting compensation over a number of years in determining the appropriate amounts for each employee, and Nunez considered each of the factors described elsewhere in this compensation discussion and analysis. Mr.analysis in recommending, in their discretion, the appropriate amounts for each named executive officer. Messrs. Robertson and Mr. HoganNunez attended the CNG Committee meetings at which the Committee deliberated and approved the compensation,2019 salaries, short-term cash incentive awards and long-term equity incentive awards but were excused from the meetings when the CNG Committee discussed their compensation. Mr. Nunez and Ms. Wilson also participated in the meetings with Meridian and the CNG Committee with respect to the design and implementation of the 2016 Cash Long-Term Incentive Plan.
Evaluation of 2016 Performance; Components of Compensation
2016 Performance
Our Board of Directors considers Adjusted EBITDA, distributable cash flow and overall leverage to be the critical measures in evaluating NRP’s performance. Despite the continued depressed coal and oil and gas markets in 2016, we recorded Adjusted EBITDA in 2016 of $255.5 million, which was essentially flat compared to our Adjusted EBITDA in 2015, and distributable cash flow of $271.4 million, which increased from $176.6 million in 2015 primarily as a result of cash proceeds from asset sales in 2016.
Other factors considered by the CNG Committee in determining total management compensation for 2016 included:
the sale of approximately $181 million of assets during 2016, including $116.1 million of oil and gas working interests and royalty interests that marked NRP’s strategic exit from the non-operated oil and gas working interest business;
the permanent reduction in NRP’s debt of approximately $248 million during 2016;
the extension in 2016 of the maturity date under Opco’s revolving credit facility to June 2018;
the increase in the trading price of NRP’s common units of over 300% during 2016;
overall cost reductions; and
additional revenue of $40 million recognized in connection with lease amendments in the coal segment.
Base Salaries
With the exception of Mr. Robertson, who as described above, does not receive a salary for his services as Chief Executive Officer, our executive officers are paid an annual base salary by Quintana Minerals Corporation ("Quintana") or Western Pocahontas Properties Limited Partnership ("Western Pocahontas") for services rendered to us by the executive officers during the fiscal year. We then reimburse Quintana and Western Pocahontas based on the time allocated by each executive officer to our business. The base salaries of our named executive officers are reviewed on an annual basis as well as at the time of a promotion or other material change in responsibilities. The CNG Committee reviews and approves the full salaries paid to each executive officer by Quintana and Western Pocahontas, based on both the actual time allocations to NRP in the prior year and the anticipated time allocations in the coming year. Adjustments in base salary are based on an evaluation of individual performance, our partnership’s overall performance during the fiscal year and the individual’s contribution to our overall performance.
In determining salaries for NRP’s executive officers for 2016,2019, at the December 20152018 meeting, the CNG Committee considered the financial performance of NRP for the nine months ended September 30, 20152018 as well as the projected financial performance of NRP for the fourth quarter of 20152018 and for the year ending December 31, 2016.2019. The CNG Committee also considered the individual performance of each member of the executive management team during 2015 and the changes to the management team that became effective during the year. Based on its review, the CNG Committee approved the salaries disclosed2018. Salaries for 2019 are shown in the Summary Compensation Table below.
AnnualShort-Term Cash Incentive AwardsCompensation
Each named executive officer participated in tworeceived a discretionary short-term cash incentive programs in 2016, with the exception of Mr. Robertson who did not participate in the cash bonus program. The first program is a discretionary cash bonus award approved in February 20172020 by the CNG Committee based on similar criteria used to evaluate the annual base salaries.Committee. The bonusesamounts awarded with respect to 20162019 under this program are disclosed in the Summary Compensation Table under the Bonus column. As with the base salaries, there are no formulas or specific performance targets related to these awards. The bonuses for Mr. Hogan, Mr. Nunez, Ms. Wilson and Mr. Zolas were increased over the prior year in part to offset the declines in other components of their compensation and in recognition of their contributions to NRP.
Under the second cash incentive program (the GP Bonus Award program), our general partner has set aside the cash distributions it receives on an annual basis withWith respect to distributions on NRP’s common units held by our general partner for awards to our executive officers, including Mr. Robertson. Although Mr. Robertson has the sole discretion to determine the GP Bonus Awards allocated to each executive officer, including himself, the cash awards that our officers receive under this plan are
reviewed by2019, the CNG Committee, and taken into account when making determinationsusing recommendations from L&A, determined that cash bonuses would be paid based on a percentage of base salary, with respect to salaries, bonuses and long-term incentive awards. UnlikeMr. Robertson receiving approximately two times the discretionary cash bonus award described above, the GP Bonus Awards are paid by the general partner and not reimbursed by NRP. However, because the GP Bonus Awards represent compensation to executive officers related to services provided to NRP, they are recorded by NRP as general and administrative expenses and equity contributions from the general partner. Prior to 2015, we did not record the GP Bonus Awards cash compensation paid by the general partner as an expense.
The amounts received by the named executive officers under the GP Bonus Award program were significantly lower for 2016 as compared to 2015 dueamount awarded to the 87% reduction inPresident and Chief Operating Officer. In addition, the per unit distribution paid by NRP duringCNG Committee determined that it would consider certain criteria to determine bonus amounts within this range, but that the calendar year ended December 31, 2015. This decrease resulted in a decreased overall amount allocatedcriteria utilized at the time of determination, as well as the relative weight of those criteria, would be generally discretionary and subject to change based on developments at the executive officers. Mr. Robertson determined to allocate the GP Bonus Awards equally among our executive officers.company.
Long-Term Equity Incentive Compensation
AtEach named executive officer received a discretionary long-term equity incentive award in 2019 under the time of our initial public offering, we adopted2017 Plan. The 2019 awards were made in the Natural Resource Partners Long-Term Incentive Plan for our directors and all the employees who perform services for NRP, including the executive officers. Historically, we considered long-term equity-based incentive compensation to be the most important element of our compensation program for executive officers because we believed that these awards kept our officers focused on the growth of NRP, particularly the sustainability and long-term growth of quarterly distributions and their impact on our unit price, over an extended time horizon.
Our CNG Committee has historically approved annual awardsform of phantom units that will settle in NRP common units on a one-for-one basis following vesting in February 2022 and accrue DERs to be paid in cash upon settlement. We refer to these phantom units issued in 2019 as “2017 Plan Phantom Units.” The 2017 Plan Phantom Units are subject to forfeiture and will vest four years fromon an accelerated basis following death or disability of the dateaward recipient or following a change in control of grant.NRP. The amounts included in the compensation table reflect the grant date fair value of the unit awards determined2017 Plan Phantom Units awarded in accordance with FASB stock compensation authoritative guidance. NRP bears 100% of the costs of the phantom units. We structured the phantom unit awards so that our executive officers and directors directly benefited along with our unitholders when our unit price increases, and experienced reductions2019 are disclosed in the value of their incentive awards when our unit price declined. Similarly, because the awards are forfeited by the executives upon termination of employment in most instances, the long-term vesting component of these awards encouraged our senior executives and employees to remain with NRP over an extended period of time, thereby ensuring continuity in our management team. Consistent with this approach, we included DERs as a possible award to be grantedSummary Compensation Table under the plan. The DERs are contingent rights, granted"Stock Awards" column. For the 2017 Plan Phantom Units awarded in tandem with phantom units, to receive upon vesting of the related phantom units an amount in cash equal to the cash distributions made by NRP with respect to the common units during the period in which the phantom units are outstanding.
As noted below, in light of then existing market conditions, the relative low value of NRP’s common units and the strategic plan to dedicate all free cash flow towards reducing NRP’s leverage,2019, the CNG Committee determined thatgenerally awarded an amount equal to 135% to 140% of base salary, with Mr. Robertson receiving two times the phantom units and DERs awarded under the Long-Term Incentive Plan no longer held retentive value for NRP’s management team. As a result, the CNG Committee recommended, and the Board approved, the 2016 Cash Long-Term Incentive Plan described below.
2016 Cash Long-Term Incentive Plan
In February 2016, the CNG Committee adopted a new cash-based long-term incentive plan and recommended the new plan and awards thereunder to the non-management members of the Board for approval. The Board approved the new plan and the forms of long-term incentive award agreements in February 2016. Two types of cash incentive awards were made to the executive officers in March 2016: (1) time vesting awards, 50% of which vested in February 2017 and 50% of which will vest in February 2018, and (2) performance-based awards that provide that such awards vest 50% upon the repayment, refinancing or rollover of the Opco revolving credit facility that matures in April 2018 and 50% upon the repayment, refinancing or rollover of NRP’s 9.125% Senior Notes due October 2018, in each case as determined by the Board and depending upon the continued employment of the applicable executive officer. The performance awards also provide that up to an additional 100% of the amount of the performance-based awards may be awarded to the executive officers in the sole discretionPresident and Chief Operating Officer. The CNG Committee considered performance of the Board after considering additionalcompany and individual performance criteria including, but not limited to, NRP’s common unit price, projected EBITDA, and leverage ratio. The awards made in March 2016 to the named executive officers under the cash long-term incentive plan are as follows:
|
| | | | | | | | | | | | | | | | |
| 2016 Cash Incentive Awards |
| | | Performance Award Grant Amount | | Time Vesting Award Grant Amount (1) | | Total Award Grant Amount | | Total Maximum Payout Amount |
| Corbin J. Robertson, Jr. - Chairman and Chief Executive Officer | | $ | 1,500,000 |
| | $ | 500,000 |
| | $ | 2,000,000 |
| | $ | 3,500,000 |
|
| Wyatt L. Hogan - President and Chief Operating Officer | | 750,000 |
| | 250,000 |
| | 1,000,000 |
| | 1,750,000 |
|
| Craig W. Nunez - Chief Financial Officer and Treasurer | | 562,500 |
| | 187,500 |
| | 750,000 |
| | 1,312,500 |
|
| Kathryn S. Wilson - Vice President, General Counsel and Secretary | | 450,000 |
| | 150,000 |
| | 600,000 |
| | 1,050,000 |
|
| Christopher J. Zolas - Chief Accounting Officer | | 150,000 |
| | 150,000 |
| | 300,000 |
| | 450,000 |
|
| |
(1) | One-half of each time vesting award granted in 2016 vested in 2017. |
Following the completion of the March 2017 recapitalization transactions, on March 3, 2017, the Board determined that both vesting conditions of the performance awards had been met and therefore the target performance award grant amounts would be awarded to each executive officer. In addition, following consideration of additional performance criteria including, but not limited to: (1) the performance of NRP’s common units over the past twelve months and subsequent to the announcement of the transactions; (2) the 2016 and projected 2017 EBITDA for NRP; and (3) the current and projected leverage ratios for NRP and its subsidiaries, the Board determined to award an additional 100% of the amount of the performance-based awards to the executive officers. The amounts that will be paid to the named executive officers will be equal to 200% of the performance award grant amounts shown in the table above. These amounts will be paid will be paid to the officers within 30 days of the date of the Board’s determination.making these awards.
Perquisites and Other Personal Benefits
Both Quintana and Western Pocahontas maintain employee benefit plans that provide our executive officers and other employees with the opportunity to enroll in health, dental and life insurance plans. Each of these benefit plans require the employee to pay a portion of the health and dental premiums, with the company paying the remainder. These benefits are offered on the same basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee allocates time to our business.
In 2019, Quintana and Western Pocahontas also maintainmaintained tax-qualified 401(k) plans. During 2019, Quintana and defined contribution retirement plans. Quintana matchesWestern Pocahontas matched 100% of the first 4.5%6.0% of the employee contributions under thetheir respective 401(k) plan and Western Pocahontas matches the employee contributions at a level of 100% of the first 3% of the contribution and 50% of the next 3% of the contribution. In addition, each company contributes 1/12 of each employee’s base salary to the defined contribution retirement plan on an annual basis.plans. As with the other contributions, any amounts contributed by Quintana and Western Pocahontas are reimbursed by us based on the time allocated by the employee to our business. None of NRP, Quintana or Western Pocahontas maintains a pension plan or a defined benefit retirement plan.
Unit Ownership Requirements
WeNRP maintains Unit Ownership and Retention Guidelines (the “ownership guidelines”) that are administered by the CNG Committee and require NRP’s officers who are required to file ownership reports under Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and certain other officers as designated from time-to-time by the Board or the CNG Committee to retain all common units awarded under any NRP incentive plan (net of any units withheld or sold to cover tax liabilities) until certain ownership guidelines are met. The guideline for NRP’s President and Chief Operating Officer and Chief Financial Officer is for such individuals to hold common units having a value of three times his or her base salary at the date of measurement. The guideline for NRP’s Executive Vice President—Coal is for such individual to hold common units having a value of two times his or her base salary at the date of measurement. The guideline for NRP’s Vice President & General Counsel and is for such individual to hold common units having a value of one and one-half times his or her base salary at the date of measurement. There is no minimum time period required to achieve the unit ownership guidelines. Due to his substantial ownership in NRP, the ownership guidelines do not have any policycurrently apply to our Chief Executive Officer.
The ownership guidelines thatalso require specified ownership of ourdirectors who are not officers to retain common units with a value equal to three times the amount of the annual cash retainer paid to directors. Directors are required to achieve the unit ownership guideline within five years. Until the unit ownership guideline is achieved, each director is encouraged to retain all common units awarded under any NRP incentive plan (net of any units sold to cover tax liabilities).
Units that count towards the satisfaction of the officer and director guidelines include common units held directly by our directorsthe executive officer or director, common units owned indirectly by the executive officersofficer or unit retention guidelines applicable to equity-based awardsdirector (e.g., by a spouse or other immediate family member residing in the same household or a trust for the benefit of the executive officer or director or his or her family), units granted to directors or executive officers. As of December 31, 2016, our named executive officers held 21,540under NRP’s long-term incentive plans (including phantom units that have been granted as compensation. In addition, Mr. Robertson directlyrepresenting the right to receive units), and units purchased in the open market (whether purchased before or indirectly owns in excess of 20%after the effective date of the outstanding unitsownership guidelines).
Incentive Compensation Recoupment Policy
NRP maintains the Natural Resource Partners L.P. Incentive Compensation Recoupment Policy, which is administered by the CNG Committee. The policy authorizes the Board or committee thereof to recoup incentive compensation in the event of NRP.a restatement of financial statements due to material non-compliance with securities laws, fraud or misconduct.
Securities Trading Policy
Our insider trading policy states that executive officers and directors may not purchase or sell puts or calls to sell or buy our common units, engage in short sales with respect to our common units, or buy our securities on margin.
Tax Implications of Executive Compensation
Because we are a partnership, Section 162(m) of the Internal Revenue Code does not apply to compensation paid to our named executive officers and accordingly, the CNG Committee did not consider its impact in determining compensation levels in 2014, 2015 or 2016. The CNG Committee has taken into account the tax implications to the partnership in its decision to limit the long-term incentive compensation to phantom units as opposed to options or restricted units.
Accounting Implications of Executive Compensation
The CNG Committee has considered the partnership accounting implications, particularly the "book-up" cost, of issuing equity as incentive compensation, and has determined that phantom units offer the best accounting treatment for the partnership while still motivating and retaining our executive officers.
Report of the Compensation, Nominating and Governance Committee
The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management. Based on the reviews and discussions referred to in the foregoing sentence, the CNG Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2016.2019.
Robert T. Blakely,
Leo A. Vecellio, Jr., Chairman
Russell D. Gordy
Robert B. Karn III
Leo A. Vecellio, Jr.Stephen P. Smith
Summary Compensation Table
The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation for 2014, 20152017, 2018 and 2016 based on each individual’s allocation of time to Natural Resource Partners:2019:
|
| | | | | | | | | | | | | | | | | | | | | | |
Name and Principal Position (1) | | Year | | Salary | | Cash Bonus | | Phantom Unit Awards (2) | | All Other Compensation(3) | | Total |
| Corbin J. Robertson, Jr. - Chief Executive | | 2016 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Officer | | 2015 | | — |
| | — |
| | 321,912 |
| | — |
| | 321,912 |
|
| | | 2014 | | — |
| | — |
| | 595,728 |
| | — |
| | 595,728 |
|
| | | | | | | | | | | | |
|
|
| Wyatt L. Hogan - President and Chief | | 2016 | | $ | 400,000 |
| | $ | 450,000 |
| | $ | — |
| | $ | 34,383 |
| | $ | 884,383 |
|
| Operating Officer | | 2015 | | 400,000 |
| | 400,000 |
| | 160,956 |
| | 33,783 |
| | 994,739 |
|
| | | 2014 | | 377,654 |
| | 225,000 |
| | 186,165 |
| | 33,336 |
| | 822,155 |
|
| | | | | | | | | | | | |
|
|
Craig W. Nunez - Chief Financial Officer (4) | | 2016 | | $ | 375,000 |
| | $ | 425,000 |
| | $ | — |
| | $ | 34,383 |
| | $ | 834,383 |
|
| | | 2015 | | 375,000 |
| | 375,000 |
| | 446,575 |
| | 33,783 |
| | 1,230,358 |
|
| | | | | | | | | | | | | |
| Kathryn S. Wilson - Vice President, General | | 2016 | | $ | 305,500 |
| | $ | 225,000 |
| | $ | — |
| | $ | 31,631 |
| | $ | 562,131 |
|
Counsel and Secretary (5) | | 2015 | | 315,250 |
| | 175,000 |
| | 84,949 |
| | 33,413 |
| | 608,612 |
|
| | | 2014 | | 291,375 |
| | 100,000 |
| | 121,007 |
| | 30,869 |
| | 543,251 |
|
| | | | | | | | | | | | | |
| Christopher J. Zolas - Chief Accounting | | 2016 | | $ | 300,000 |
| | $ | 200,000 |
| | $ | — |
| | $ | 34,383 |
| | $ | 534,383 |
|
Officer (4) | | 2015 | | 244,932 |
| | 150,000 |
| | 239,295 |
| | 30,858 |
| | 665,085 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Name and Principal Position | | Year | | Salary ($) | | Bonus ($) | | Non-Equity Incentive Plan Compensation ($) | | Stock Awards ($) (1) | | All Other Compensation ($) (2) | | Total ($) |
| Corbin J. Robertson, Jr.—Chief Executive Officer |
| | | 2019 | | — |
| | 938,868 |
| | — |
| | 1,306,222 |
| | — |
| | 2,245,090 |
|
| | | 2018 | | — |
| | 1,208,247 |
| | 250,000 |
| | 418,836 |
| | — |
| | 1,877,083 |
|
| | | 2017 | | — |
| | — |
| | 3,250,000 |
| | — |
| | — |
| | 3,250,000 |
|
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Craig W. Nunez—President and Chief Operating Officer |
| | | 2019 | | 500,000 |
| | 408,204 |
| | — |
| | 653,111 |
| | 16,800 |
| | 1,578,115 |
|
| | | 2018 | | 447,499 |
| | 604,124 |
| | 93,750 |
| | 209,433 |
| | 16,800 |
| | 1,371,606 |
|
| | | 2017 | | 375,000 |
| | 250,000 |
| | 1,218,750 |
| | — |
| | 34,650 |
| | 1,878,400 |
|
| | | | | | | | | | | | | | | |
| Christopher J. Zolas—Chief Financial Officer |
| | | 2019 | | 355,000 |
| | 284,000 |
| | — |
| | 492,581 |
| | 16,800 |
| | 1,148,381 |
|
| | | 2018 | | 337,499 |
| | 455,624 |
| | 75,000 |
| | 167,529 |
| | 16,800 |
| | 1,052,452 |
|
| | | 2017 | | 300,000 |
| | 180,000 |
| | 375,000 |
| | — |
| | 34,650 |
| | 889,650 |
|
| | | | | | | | | | | | | | | |
Kathryn S. Wilson—Vice President, General Counsel and Secretary(3) |
| | | 2019 | | 340,271 |
| | 272,217 |
| | — |
| | 507,178 |
| | 16,128 |
| | 1,135,794 |
|
| | | 2018 | | 347,499 |
| | 469,124 |
| | 75,000 |
| | 139,622 |
| | 16,800 |
| | 1,048,045 |
|
| | | 2017 | | 321,750 |
| | 150,000 |
| | 975,000 |
| | — |
| | 34,304 |
| | 1,481,054 |
|
| | | | | | | | | | | | | | | |
Kevin J. Craig��Executive Vice President, Coal(4) |
| | | 2019 | | 310,500 |
| | 248,400 |
| | — |
| | 434,854 |
| | 15,120 |
| | 1,008,874 |
|
| | | 2018 | | 229,839 |
| | 321,775 |
| | 75,000 |
| | 145,209 |
| | 13,200 |
| | 785,023 |
|
| | | 2017 | | 172,000 |
| | 145,600 |
| | 375,000 |
| | — |
| | 22,427 |
| | 715,027 |
|
| |
| (1) | In 2016, Messrs. Robertson, Hogan, Nunez, Ms. Wilson |
| |
| (2) | Includes portions of 401(k) matching allocated to Natural Resource Partners by Quintana and Western Pocahontas. |
| |
| (3) | Ms. Wilson allocated approximately 99%, 100% and 96% of her time to NRP during the years ended December 31, 2017, 2018 and 2019, respectively, and amounts included under the "Salary," "Bonus," and "All Other Compensation" columns reflect this allocation. |
| |
| (4) | Mr. Craig allocated approximately 80%, 80% and 90% of his time to NRP during the years ended December 31, 2017, 2018 and 2019, respectively, and amounts included under the “Salary,” “Bonus,” and “All Other Compensation” columns reflect this allocation |
Grants of Plan-Based Awards in 2019
The following table shows the 2017 Plan Phantom Units granted to named executive officers during 2019. The awards in the table below will vest in February 2022, and upon settlement, an equivalent number of common units will be issued to each named executive officer, subject to withholding. The 2017 Plan Phantom Units also accrue DERs from the grant date, which will be paid out in cash upon settlement following and subject to vesting.
|
| | | | | | | | |
| | | 2017 Plan Phantom Units |
| Named Executive Officer | | Grant Date | | Number of Units | | Grant Date Fair Value |
| Corbin J. Robertson, Jr. | | 2/14/2019 | | 31,498 | | $ | 1,306,222 |
|
| Craig W. Nunez | | 2/14/2019 | | 15,749 | | 653,111 |
|
| Christopher J. Zolas | | 2/14/2019 | | 11,878 | | 492,581 |
|
| Kathryn S. Wilson | | 2/14/2019 | | 12,230 | | 507,178 |
|
| Kevin J. Craig | | 2/14/2019 | | 10,486 | | 434,854 |
|
Employment Agreements
None of our named executive officers have an employment agreement.
Phantom Units Vested in 2019
The table below shows the cash settled phantom units issued in February 2015 under our previous long-term incentive plan that vested in 2019 (the "Cash Settled Phantom Units") with respect to each named executive officer, along with value realized by each individual:
|
| | | | | | |
| Named Executive Officer | | Cash Settled Phantom Units | | Value Realized on Vesting(1) |
| Corbin J. Robertson, Jr. | | 3,600 | | $ | 166,759 |
|
| Craig W. Nunez | | 1,400 | | 64,851 |
|
| Christopher J. Zolas | | 950 | | 44,006 |
|
| Kathryn S. Wilson | | 950 | | 44,006 |
|
| Kevin J. Craig | | 950 | | 44,006 |
|
| |
| (1) | Includes DERs accrued from the issue date to the settlement date. |
Outstanding Equity Awards at December 31, 2019
The table below shows the total number of outstanding 2017 Plan Phantom Units held by each named executive officer at December 31, 2019.
|
| | | | | | |
| Named Executive Officer | | Unvested 2017 Plan Phantom Units(1) | | Market Value of Unvested 2017 Plan Phantom Units(2) |
| Corbin J. Robertson, Jr. | | 45,891 | | $ | 922,868 |
|
| Craig W. Nunez | | 22,946 | | 461,444 |
|
| Christopher J. Zolas | | 17,635 | | 354,640 |
|
| Kathryn S. Wilson | | 17,028 | | 342,433 |
|
| Kevin J. Craig | | 15,476 | | 311,222 |
|
| |
| (1) | 2017 Plan Phantom Units were awarded in February 2018 and 2019 and vest in February 2021 and 2022, respectively. |
| |
| (2) | Based on a unit price of $20.11, the closing price for the common units on December 31, 2019. |
Potential Payments upon Termination or Change in Control
Upon the occurrence of a change in control of NRP, our general partner, or GP Natural Resource Partners LLC, 2017 Plan Phantom Units held by each of our named executive officers would immediately vest and become payable. The table below indicates the estimated payments to each named executive officer following a change in control at December 31, 2019.
|
| | | | | | | | | | | | | |
| | 2017 Plan Equity Awards | | |
| Named Executive Officer | Unvested Phantom Units | | Market Value(2) | | Accumulated DERs | | Total Potential Payments |
| Corbin J. Robertson, Jr. | 45,891 | | $ | 922,868 |
| | $ | 126,868 |
| | $ | 1,049,736 |
|
| Craig W. Nunez | 22,946 | | 461,444 |
| | 63,436 |
| | 524,880 |
|
| Christopher J. Zolas | 17,635 | | 354,640 |
| | 49,160 |
| | 403,800 |
|
| Kathryn S. Wilson | 17,028 | | 342,433 |
| | 46,098 |
| | 388,531 |
|
| Kevin J. Craig | 15,476 | | 311,222 |
| | 43,029 |
| | 354,251 |
|
| |
| (1) | Calculated based on a unit price of $20.11, the closing price for the common units on December 31, 2019. |
Directors’ Compensation for the Year Ended December 31, 2019
For more information regarding the Board and committees thereof, see “Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance” elsewhere in this Annual Report on Form 10-K. Director compensation during 2019 consisted of a $75,000 cash retainer and an award of common units under the 2017 Plan. The units awarded to Board members are fully vested and not subject to forfeiture; however, the Board members had the option in advance of receipt of the award to elect to defer settlement of the award until after 90 days following such director’s retirement or earlier departure from the Board. In addition, members of Board committees received $5,000 for each committee served on, and each committee chairman received an additional $10,000 for acting as chairman.
The table below shows the directors’ compensation for the year ended December 31, 2019: |
| | | | | | | | | | | | |
| Name of Director | | Fees Earned or Paid in Cash | | 2017 Plan Common Unit Awards(1) | | Total Compensation |
| Russell D. Gordy | | $ | 80,000 |
| | $ | 81,074 |
| | $ | 161,074 |
|
Jasvinder S. Khaira(2) | | — |
| | — |
| | — |
|
| S. Reed Morian | | 75,000 |
| | 81,074 |
| | 156,074 |
|
Richard A. Navarre(3) | | 95,000 |
| | 81,074 |
| | 176,074 |
|
| Corbin J. Robertson, III | | 75,000 |
| | 81,074 |
| | 156,074 |
|
Stephen P. Smith(3) | | 95,000 |
| | 81,074 |
| | 176,074 |
|
| Leo A. Vecellio, Jr. | | 95,000 |
| | 81,074 |
| | 176,074 |
|
| Paul B. Murphy, Jr. | | 75,000 |
| | 81,074 |
| | 156,074 |
|
| Galdino J. Claro | | 85,000 |
| | 81,074 |
| | 166,074 |
|
Alexander D. Greene(2) | | — |
| | — |
| | — |
|
| |
| (1) | Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see Note 1617 to the audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. |
| |
(3)(2) | Includes portions of 401(k) matchingMr. Khaira, who was the Blackstone designee pursuant to the Board Representation and retirement contributions allocatedObservation Rights Agreement, resigned from the Board effective March 8, 2019. Effective on such date, Mr. Greene was appointed to Natural Resource Partnersthe Board by Quintana.Blackstone to replace Mr. Khaira. Messrs. Khaira and Greene did not receive Board compensation as Blackstone designees. |
| |
(4)(3) | Messrs. NunezNavarre and Zolas were not named executive officers for purposesSmith elected to defer settlement of this Summary Compensation Table during 2014. |
| |
(5) | Amounts for Ms. Wilson’s base salary and all other compensation columns representtheir common units awarded under the amounts allocated to NRP.2017 Plan in 2019 until 90 days following their respective retirements or earlier departures from the Board. |
The following table sets forth the GP Bonus Awards paid by the general partner and not reimbursed by NRP as described above. These GP Bonus Award amounts are not included in the summary compensation table:
|
| | | | | | |
| Name and Principal Position | | Year | | Amount |
| Corbin J. Robertson, Jr. - Chief Executive Officer | | 2016 | | $ | 40,114 |
|
| | | 2015 | | 160,000 |
|
| | | 2014 | | 180,000 |
|
| | | | | |
| Wyatt L. Hogan - President and Chief Operating Officer | | 2016 | | $ | 40,114 |
|
| | | 2015 | | 160,000 |
|
| | | 2014 | | 384,000 |
|
| | | | | |
| Craig W. Nunez - Chief Financial Officer | | 2016 | | $ | 40,114 |
|
| | | 2015 | | 160,000 |
|
| | | | | |
| Kathryn S. Wilson - Vice President, General Counsel and Secretary | | 2016 | | $ | 40,114 |
|
| | | 2015 | | 125,000 |
|
| | | 2014 | | 180,000 |
|
| | | | | |
| Christopher J. Zolas - Chief Accounting Officer | | 2016 | | $ | 40,114 |
|
| | | 2015 | | $ | 52,000 |
|
Grants of Plan-Based Awards in 2016
The following table sets forth the cash incentive awards granted in 2016:
|
| | | | | | | | | | | | | | |
| | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1) |
| Named Executive Officer | | Grant Date | | Threshold | | Target | | Maximum |
| Corbin J. Robertson, Jr. | | 3/10/2016 | | $ | 2,000,000 |
| | $ | 2,000,000 |
| | $ | 3,500,000 |
|
| Wyatt L. Hogan | | 3/10/2016 | | 1,000,000 |
| | 1,000,000 |
| | 1,750,000 |
|
| Craig W. Nunez | | 3/10/2016 | | 750,000 |
| | 750,000 |
| | 1,312,500 |
|
| Kathryn S. Wilson | | 3/10/2016 | | 600,000 |
| | 600,000 |
| | 1,050,000 |
|
| Christopher J. Zolas | | 3/10/2016 | | 300,000 |
| | 300,000 |
| | 450,000 |
|
| |
(1) | Amounts include both time-vesting and performance based awards granted under the 2016 cash long-term incentive plan detailed above. One-half or each time vesting award granted in 2016 vested in February 2017. |
None of our executive officers has an employment agreement, and the salary, bonus and phantom unit awards noted above are approved by the CNG Committee. See our disclosure under "—Compensation Discussion and Analysis" for a description of the factors that the CNG Committee considers in determining the amount of each component of compensation.
Subject to the rules of the exchange upon which the common units are listed at the time, the Board and the CNG Committee have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce any award to a participant without the consent of the participant.
The CNG Committee may make grants under our long-term incentive plans to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of NRP, our general partner or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the Board terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the CNG Committee provides otherwise.
As stated above under "—Compensation Discussion and Analysis," we have no outstanding option grants, and do not intend to grant any options or restricted unit awards in the future. In addition, the CNG Committee determined to make cash long-term incentive awards in 2016 in lieu of phantom unit awards as described above under "—Compensation Discussion and Analysis—2016 Cash Long-Term Incentive Plan." The CNG Committee may determine to make additional awards of phantom units in the future.
Phantom Units Vested in 2016
The table below shows the phantom unitsCash Settled Phantom Units that were granted in February 2015 and vested in 2016 with respect to each named executive officer, along with the phantom unit value realized by each individual:
|
| | | | | | | |
| Named Executive Officer | | Phantom Units Vested in 2016 (1) | | Value Realized on 2016 Vesting |
| Corbin J. Robertson, Jr. | | 3,200 |
| | $ | 220,928 |
|
| Wyatt L. Hogan | | 1,600 |
| | 110,464 |
|
| Craig W. Nunez | | 1,100 |
| | 14,344 |
|
| Kathryn S. Wilson | | 550 |
| | 25,872 |
|
| Christopher J. Zolas | | 600 |
| | 7,824 |
|
| |
(1) | The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective on February 17, 2016. |
Outstanding Equity Awards at December 31, 2016
The table below shows the total number of outstanding phantom units held by each named executive officer at December 31, 2016. The phantom units shown below were awarded in February 2013, 2014 and 2015, with a portion of the phantom units having vesting in February 2017 and the remaining portion vesting in each of 2018 and 2019.
|
| | | | | | | |
| Named Executive Officer | | Unvested Phantom Units (1) | | Market Value of Unvested Phantom Units (2) |
| Corbin J. Robertson, Jr. | | 10,160 |
| (3) | $ | 328,168 |
|
| Wyatt L. Hogan | | 5,080 |
| (4) | 164,084 |
|
| Craig W. Nunez | | 3,900 |
| (5) | 125,970 |
|
| Kathryn S. Wilson | | 2,283 |
| (6) | 73,741 |
|
| Christopher J. Zolas | | 2,400 |
| (7) | 77,520 |
|
| |
(1) | The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective on February 17, 2016. |
| |
(2) | Based on a unit price of $32.30, the closing price for the common units on December 31, 2016. |
| |
(3) | Includes 3,200 phantom units vested in February 2017, and 3,360 and 3,600 phantom units vesting in February 2018 and 2019 respectively. |
| |
(4) | Includes 1,600 phantom units vested in February 2017, and 1,680 and 1,800 phantom units vesting in February 2018 and 2019, respectively. |
| |
(5) | Includes 1,200 phantom units vested in February 2017, and 1,300 and 1,400 phantom units vesting in February 2018 and 2019, respectively. |
| |
(6) | Includes 650 phantom units vested in February 2017, and 683 and 950 phantom units vesting in February 2018 and 2019, respectively. |
| |
(7) | Includes 650 phantom units vested in February 2017, and 800 and 950 phantom units vesting in February 2018 and 2019, respectively. |
Potential Payments upon Termination or Change in Control
None of our executive officers have entered into employment agreements with Natural Resource Partners or its affiliates. Consequently, there are no severance benefits payable to any executive officer upon the termination of their employment. Upon the occurrence of a change in control of NRP, our general partner or GP Natural Resource Partners LLC, the outstanding phantom unit awards held by each of our executive officers would immediately vest. The table below indicates the impact of a change in control on (1) the outstanding cash awards under the 2016 Cash Long-Term Incentive Plan and (2) the outstanding equity-based awards at December 31, 2016, based on a unit price of $34.65, the 20-day average common unit price as of December 31, 2016, as required pursuant to the term of the phantom units.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2016 Cash Long-Term Incentive Plan Awards | | Phantom Unit Long-Term Incentive Awards | | | |
| Named Executive Officer | | Time-Based Awards (1) | | Performance-Based Awards (1) | | Unvested Phantom Units (2) | | Market Value of Unvested Phantom Units | | Accumulated DERs | | Total Potential Payments | |
| Corbin J. Robertson, Jr. | | $ | 500,000 |
| | $ | 1,500,000 |
| | 10,160 |
| | $ | 351,993 |
| | $ | 196,988 |
| | $ | 2,548,981 |
| |
| Wyatt L. Hogan | | 250,000 |
| | 750,000 |
| | 5,080 |
| | 175,997 |
| | 98,494 |
| | 1,274,491 |
| |
| Craig W. Nunez | | 187,500 |
| | 562,500 |
| | 3,900 |
| | 135,116 |
| | 15,795 |
| | 900,911 |
| (3) |
| Kathryn S. Wilson | | 150,000 |
| | 450,000 |
| | 2,283 |
| | 79,095 |
| | 40,908 |
| | 720,003 |
| |
| Christopher J. Zolas | | 150,000 |
| | 150,000 |
| | 2,400 |
| | 83,148 |
| | 9,720 |
| | 392,868 |
| (4) |
| |
(1) | The outstanding awards vest 100% upon a change in control. |
| |
(2) | The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective on February 17, 2016. |
| |
(3) | Phantom units vested in 2017 and phantom units vesting in 2018 and 2019 include accrued DERs from February 11, 2015, the date of the grant of these units to Mr. Nunez. |
| |
(4) | Phantom units vested in 2017 and phantom units vesting in 2018 and 2019 include accrued DERs from March 9, 2015, the date of the grant of these units to Mr. Zolas. |
Directors’ Compensation for the Year Ended December 31, 2016
The table below shows the directors’ compensation for the year ended December 31, 2016. As with our named executive officers, we do not grant any options or restricted units to our directors:
|
| | | | | | | | |
| Name of Director | | Fees Earned or Paid in Cash (1) | | Total (2) |
| Robert Blakely | | $ | 85,000 |
| | $ | 85,000 |
|
| Russell Gordy | | 65,000 |
| | 65,000 |
|
| Trey Jackson | | 43,022 |
| | 43,022 |
|
| Robert Karn III | | 85,000 |
| | 85,000 |
|
| S. Reed Morian | | 60,000 |
| | 60,000 |
|
| Richard Navarre | | 65,000 |
| | 65,000 |
|
| Corbin J. Robertson, III | | 60,000 |
| | 60,000 |
|
| Stephen Smith | | 80,000 |
| | 80,000 |
|
| Leo A. Vecellio, Jr. | | 65,000 |
| | 65,000 |
|
| |
(1) | In 2016, the annual retainer for the directors was $60,000, and the directors did not receive any additional fees for attending meetings. Each chairman of a committee received an annual fee of $10,000 for serving as chairman, and each committee member received $5,000 for serving on a committee. |
| |
(2) | No phantom unit awards were made to our directors in 2016. As of December 31, 2016, each director other than Mr. Jackson held 1,169 phantom units, of which 370 phantom units vested in February 2017, and 389 and 410 phantom units |
will vest in February 2018 and 2019, respectively. The awards amounts included in the foregoing sentence give effect to NRP’s one-for-ten (1:10) reverse common unit split that became effective on February 17, 2016.
The table below shows the phantom units that vested in 2016 with respect to each Director, along with the value realized by each individual:individual, including the DERs accruing from the February 2015 grant date.
|
| | | | | | | |
| Director | | Phantom Units Vested in 2016 (1) | | Value Realized on 2016 Vesting |
| Robert Blakely | | 370 |
| | $ | 25,545 |
|
| Russell Gordy | | 370 |
| | 12,336 |
|
| Trey Jackson | | — |
| | — |
|
| Robert Karn III | | 370 |
| | 25,545 |
|
| S. Reed Morian | | 370 |
| | 25,545 |
|
| Richard Navarre | | 370 |
| | 12,336 |
|
| Corbin J. Robertson, III | | 370 |
| | 14,371 |
|
| Stephen Smith | | 370 |
| | 25,545 |
|
| Leo A. Vecellio, Jr. | | 370 |
| | 25,545 |
|
|
| | | | | | |
| Name of Director | | Cash Settled Phantom Units | | Value Realized on Vesting |
| Russell D. Gordy | | 410 | | $ | 18,992 |
|
| Jasvinder S. Khaira | | — | | — |
|
| S. Reed Morian | | 410 | | 18,992 |
|
| Richard A. Navarre | | 410 | | 18,992 |
|
| Corbin J. Robertson, III | | 410 | | 18,992 |
|
| Stephen P. Smith | | 410 | | 18,992 |
|
| Leo A. Vecellio, Jr. | | 410 | | 18,992 |
|
| Paul B. Murphy, Jr. | | — | | — |
|
| Galdino J. Claro | | — | | — |
|
| Alexander D. Greene | | — | | — |
|
| |
(1) | The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective on February 17, 2016. |
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2016,2019, Messrs. Blakely,Vecellio, Gordy, Karn and VecellioSmith served on the CNG Committee. None of Messrs. Blakely,Vecellio, Gordy, Karn or Vecellioand Smith has ever been an officer or employee of NRP or GP Natural Resource Partners LLC. None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has any executive officer serving as a member of our Board or CNG Committee.
Pay Ratio Disclosure
The Securities and Exchange Commission has adopted a rule requiring annual disclosure of the ratio of the median employee’s total annual compensation to the total annual compensation of the CEO.
The personnel providing services to us, including our executive officers, are employed by Quintana or Western Pocahontas. As of December 31, 2019, 55 such persons were providing services to us. We identified a new median service provider for 2019 by examining the 2019 total taxable compensation, as reflected in our payroll records as reported to the Internal Revenue Service on Form W-2, for all individuals who provided services to us as of December 31, 2019. We did not make any assumptions, adjustments, or estimates with respect to total cash compensation or equity compensation and we did not annualize the compensation for any service providers that were not employed for all of 2019.
After identifying the median service provider based on total compensation, we calculated annual 2019 compensation for the median service provider using the same methodology used to calculate the Chief Executive Officer’s total compensation as reflected in the Summary Compensation Table above. The median service provider’s annual 2019 compensation was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | Year | | Salary | | Bonus | | Non-Equity Incentive Plan Compensation | | Phantom Unit Awards | | All Other Compensation | | Total |
| Median Service Provider | | 2019 | | $ | 85,847 |
| | $ | 23,661 |
| | $ | — |
| | $ | — |
| | $ | 5,151 |
| | $ | 114,659 |
|
Our 2019 ratio of Chief Executive Officer total compensation to our median service provider's total compensation is reasonably estimated to be 20:1.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table setstables set forth, as of March 2, 2017,February 24, 2020, the amount and percentage of our common units and preferred units beneficially held by (1) each person known to us to beneficially own 5% or more of any class of our units, (2) by each of theour directors and named executive officers and (3) by all directors and executive officers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the units shown. The information presented below gives effect to the one-for-ten reverse unit split that was effective on February 17, 2016.
|
| | | | | | |
| Name of Beneficial Owner | | Common Units | | Percentage of Common Units (1) |
Corbin J. Robertson, Jr. (2) | | 2,411,395 |
| | 19.7 | % |
Western Pocahontas Corporation (3) | | 1,739,007 |
| | 14.2 | % |
Western Pocahontas Properties Limited Partnership (4) | | 1,727,986 |
| | 14.1 | % |
JPMorgan Chase & Co. (5) | | 1,050,335 |
| | 8.6 | % |
The Goldman Sachs Group, Inc. (6) | | 835,403 |
| | 6.8 | % |
| Kevin J. Craig | | 950 |
| | * |
|
| Craig W. Nunez | | — |
| | — |
|
| Kathryn S. Wilson | | — |
| | — |
|
| Christopher J. Zolas | | — |
| | — |
|
| Galdino J. Claro | | 4,114 |
| | * |
|
Russell D. Gordy (7) | | 11,354 |
| | * |
|
| Alexander D. Greene | | — |
| | — |
|
S. Reed Morian (8) | | 620,513 |
| | 5.1 | % |
| Paul B. Murphy, Jr. | | 7,614 |
| | * |
|
| Richard A. Navarre | | 1,000 |
| | * |
|
Corbin J. Robertson III (9) | | 238,656 |
| | 1.9 | % |
Stephen P. Smith (10) | | 355 |
| | * |
|
| Leo A. Vecellio, Jr. | | 6,354 |
| | * |
|
| Directors and Officers as a Group | | 3,302,305 |
| | 26.9 | % |
|
| | | | | | |
| Name of Beneficial Owner | | Common Units | | Percentage of Common Units(1) |
| Corbin J. Robertson, Jr. (2) | | 4,128,605 |
| | 33.8 | % |
| Premium Resources LLC (3) | | 4,128,599 |
| | 33.8 | % |
| Wyatt L. Hogan (4) | | 1,250 |
| | * |
|
| Craig W. Nunez | | — |
| | — |
|
| Kevin J. Craig | | 1,800 |
| | * |
|
| Kathy H. Roberts | | 2,000 |
| | * |
|
| Kathryn S. Wilson | | — |
| | — |
|
| Gregory F. Wooten | | — |
| | — |
|
| Christopher J. Zolas | | — |
| | — |
|
| Robert T. Blakely | | 2,500 |
| | * |
|
| Russell D. Gordy(5) | | 7,000 |
| | * |
|
| L.G. (Trey) Jackson III | | — |
| | — |
|
| Robert B. Karn III | | 500 |
| | * |
|
| Jasvinder S. Khaira | | — |
| | — |
|
| S. Reed Morian | | — |
| | — |
|
| Richard A. Navarre | | 1,000 |
| | * |
|
| Corbin J. Robertson III (6) | | 172,790 |
| | 1.4 | % |
| Stephen P. Smith | | 355 |
| | * |
|
| Leo A. Vecellio, Jr. | | 2,000 |
| | * |
|
| Directors and Officers as a Group | | 4,319,550 |
| | 35.3 | % |
| |
| (1) | Percentages based upon 12,232,00612,261,199 common units issued and outstanding as of March 2, 2017.February 24, 2020. Unless otherwise noted, beneficial ownership is less than 1%. |
| |
| (2) | Mr. Robertson may be deemed to beneficially own the 4,128,599505,861 common units owned in his individual capacity, 1,739,007 common units in his capacity as controlling shareholder of Western Pocahontas Corporation, 156,000 common units in his capacity as the sole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource Partners, which is the general partner of NRP (GP) LP, 5,293 common units in his capacity as controlling shareholder of GNP Management Corporation and 5,234 common units held by Premium Resources LLC.his spouse, Barbara M. Robertson. Mr. Robertson’s address is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. |
| |
| (3) | TheseWestern Pocahontas Corporation has sole voting and sole dispositive power with respect to 11,021 common units may be deemedand shared voting and shared dispositive power with respect to be beneficially owned by Mr. Robertson.1,727,986 common units in its capacity as the general partner of Western Pocahontas Properties Limited Partnership. The business address of Premium Resources LLCWestern Pocahontas Corporation is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.5260 Irwin Road, Huntington, West Virginia 25705. |
| |
| (4) | Of theseWestern Pocahontas Properties Limited Partnership has sole voting and sole dispositive power with respect to 0 common units 50and shared voting and shared dispositive power with respect to 1,727,986 common units. The business address of Western Pocahontas Properties Limited Partnership is 5260 Irwin Road, Huntington, West Virginia 25705. |
| |
| (5) | According to a Schedule 13G filing with the SEC on January 31, 2020, JPMorgan Chase & Co. holds sole voting power and sole dispositive power with respect to 1,050,335 common units are owned byin the Anna Margaret Hogan 2002 Trust, 50 common units are owned by the Alice Elizabeth Hogan 2002 Trust, and 50 common units are held by the Ellen Catlett Hogan 2005 Trust. Mr. HoganPartnership. The business address of JPMorgan Chase & Co. is a trustee of each of these trusts.270 Park Ave., New York, NY 10017. |
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(5)(6) | According to a Schedule13G filing with the SEC on January 31, 2020, The Goldman Sachs Group holds shared voting power and shared dispositive power with respect to 835,403 common units in the Partnership. The business address of The Goldman Sachs Group is 200 West Street, New York, NY 10282. |
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| (7) | Mr. Gordy may be deemed to beneficially own 5,000 common units owned by Minion Trail, Ltd. and 2,000 common units owned by Rock Creek Ranch 1, Ltd. |
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(6)(8) | Mr. Morian may be deemed to beneficially own 344,863 common units owned by Shadder Investments and 60,097 common units owned by Mocol Properties. |
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| (9) | Mr. Robertson III may be deemed to beneficially own 9,783 common units held CIII Capital Management, LLC, 10,000 common units held by BHJ Investments, 5,04619,663 common units held by The Corbin James Robertson III 2009 Family Trust and 39 common units held by his spouse, Brooke Robertson. The address for CIII Capital Management, LLC is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002, the address for BHJ Investments is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002 and the address for The Corbin James Robertson III 2009 Family Trust is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. The following common units are pledged as collateral for loans: 51,987 common units owned by Mr. Robertson III. |
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| (10) | Mr. Smith may be deemed to beneficially own 355 common units owned by the SP Smith 2002 Revocable Trust. |
|
| | | | | | |
| Name of Beneficial Owner | | Preferred Units | | Percentage of Preferred Units |
The Blackstone Group Inc. (1) | | 142,500 |
| | 57 | % |
GoldenTree Asset Management, LP (2) | | 107,500 |
| | 43 | % |
| |
| (1) | The preferred units are owned by funds managed by The Blackstone Group Inc., whose address is 345 Park Ave, New York, NY 10154. The Blackstone Group Inc. is controlled by its founder, Stephen A. Schwarzman. |
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| (2) | The preferred units are owned by funds managed by GoldenTree Asset Management, LP, whose address is 300 Park Ave, New York, NY 10022. Steven A. Tananbaum serves as senior managing member of GoldenTree Asset Management LLC, the general partner of GoldenTree Asset Management, LP. |
Suite 2400, Houston, Texas 77002. The following common units are pledged as collateral for loans: 29,542 common units owned directly by Mr. Robertson.119
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, and Great Northern Properties Limited Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the WPP Group. Corbin J. Robertson, Jr. owns the general partner of Western Pocahontas Properties, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman and Chief Executive Officer of New Gauley Coal Corporation.
Omnibus Agreement
Non-competition Provisions
As part of the omnibus agreement entered into concurrently with the closing of our initial public offering, the WPP Group and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the GP“GP affiliates,” each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a "restricted business") in the specific circumstances described below:
the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal reserves within the United States; and
the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.
"Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group and their respective controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us.
A GP affiliate may, directly or indirectly, engage in a restricted business if:
the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under the procedures described below.
its ownership in the restricted business consists solely of a non-controlling equity interest.
For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate.
The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in by the WPP Group at closing of our initial public offering, may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be acquired.
If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a
restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer us the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph, "restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restriction summarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good
faith by the relevant GP affiliate.
If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate may operate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.
If, at the end of the two year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will be under no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned.
In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offer procedures described above will recommence.
If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly held limited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPP Group may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures described above.
The omnibus agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of the WPP Group under the omnibus agreement terminate when the WPP Group and its affiliates cease to participate in the control of the general partner.
Board Representation and Observation Rights Agreement
Effective on March 2, 2017 in connection with the closing of the issuance of the Preferred Units, pursuantwe entered into the Board Observation and Representation Rights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant to the Board Representation and Observation Rights Agreement, Blackstone appointed Jasvinder S. Khairaappoints one member to serve on the Board of Directors of GP Natural Resource Partners LLC and also appointedappoints one observer to attend meetings of the Board. Blackstone's rights to appoint a member of the Board and an observer will terminate at such time as Blackstone, together with their affiliates, no longer own at least 20% of the Minimumtotal number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold (as defined elsewhere in this Annual Report on Form 10-K)Threshold"). Following the time that Blackstone (and their affiliates) no longer own the Minimum Preferred Unit Threshold and until such time as GoldenTree (together with their affiliates) no longer own the Minimum Preferred Unit Threshold, GoldenTree shall have the one timeone-time option to appoint either one person to serve as a member of the Board or one person to serve as a Board observer. To the extent GoldenTree elects to appoint a Board member and later remove such Board member, GoldenTree may then elect to appoint a Board observer. The Board Representation and Observation Rights Agreement is filed as Exhibit 4.29 to this Annual ReportFor more information on Form 10-K and herein incorporated by reference.
Restricted Business Contribution Agreement
In connection with our partnership with Christopher Cline and his affiliates, Mr. Cline, Foresight Reserves LP and Adena (collectively, the "Cline Parties") and NRP have executed a Restricted Business Contribution Agreement. Pursuant toPreferred Units, including the termsrights of the Restricted Business Contribution Agreement, the Cline Parties and their affiliates are obligated to offer to NRP any business owned, operated or invested in by the Cline Parties, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in transportation infrastructure relating to future mine developments by the Cline Parties in Illinois. In addition, we created an area of mutual interest (the "AMI") around certain of the properties that we have acquired from Cline affiliates. During the applicable term of the Restricted Business Contribution Agreement, the Cline Parties will be obligated to contribute any coal reserves held or acquired by the Cline Parties or their affiliates within the AMI to us. In connection with the offer of mineral properties by the Cline Parties to NRP, the parties to the Restricted Business Contribution Agreement will negotiate and agree upon an area of mutual interest around such minerals, which will supplement and become a part of the AMI.
Mr. Holcomb, who was appointed to the Board in October 2013 and resigned from the Board in April 2016, previously served as Chief Financial Officer for Foresight Reserves LP and its subsidiaries. Mr. Holcomb owned a less than 1% equity interest in certain Cline affiliates until March 2013 when he fully divested from all Cline affiliates. As a result121
Mr. Holcomb is a manager of Cline Trust Company, LLC, which owns common units and 2018 Notes. The members of the Cline Trust Company are four trusts for the benefit of the children of Christopher Cline, each of which owns an approximately equal membership interest in the Cline Trust Company. Mr. Holcomb also serves as trustee of each of the four trusts.
Investor Rights Agreement
NRP and certain affiliates and Adena executed an Investor Rights Agreement pursuant to which Adena was granted certain management rights. Specifically, Adena has the right to name two directors (one of which must be independent) to the Board of Directors of our managing general partner so long as Adena beneficially owns either 5% of our limited partnership interest or 5% of our general partner’s limited partnership interest and so long as certain rights under our managing general partner’s LLC Agreement have not been exercised by Adena or Mr. Robertson. Leo A. Vecellio and L.G. (Trey) Jackson III currently serve as Adena’s two directors. Mr. Vecellio serves on our CNG Committee. Adena will also have the right, pursuant to the terms of the Investor Rights Agreement, to withhold its consent to the sale or other disposition of any entity or assets contributed by Cline affiliates to NRP, and any such sale or disposition will be void without Adena’s consent.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. NRP’s Board of Directors has adopted a formal conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by Quintana Capital. The basic tenets of the policy are set forth below.
NRP’s business strategy has historically focused on:
The ownership of natural resource properties in North America, including, but not limited to coal, aggregates and industrial minerals, and oil and gas. NRP leases these properties to mining or operating companies that mine or produce the resources and pay NRP a royalty.
The ownership and operation of transportation, storage and related logistics activities related to extracted hard minerals.
The businesses and investments described in this paragraph are referred to as the "NRP Businesses."
NRP’s acquisition strategy also includes:
The ownership of non-operating working interests in oil and gas properties.
The ownership of non-controlling equity interests in companies involved in natural resource development and extraction.
The operation of construction aggregates mining and production businesses.
The businesses and investments described in this paragraph are referred to as the "Shared Businesses."
NRP’s business strategy does not, and is not expected to, include:
The ownership of equity interests in companies involved in the mining or extraction of coal.
Investments that do not generate "qualifying income" for a publicly traded partnership under U.S. tax regulations.
Investments outside of North America.
Midstream or refining businesses that do not involve hard extracted minerals, including the gathering, processing, fractionation, refining, storage or transportation of oil, natural gas or natural gas liquids.
In addition, although NRP’s current oil and gas strategy is focused on the acquisition of minerals, royalties and non-operated working interests, NRP may also consider the acquisition of operated interests. The businesses and investments described in this paragraph are referred to as the "Non-NRP Businesses."
It is acknowledged that neither Quintana Capital nor Mr. Robertson will have any obligation to offer investments relating to Non-NRP Businesses to NRP, and that NRP will not have any obligation to refrain from pursuing a Non-NRP Business if there is a change in its business strategy.
For so long as Corbin Robertson, Jr. remains both an affiliate of Quintana Capital and an executive officer or director of NRP or an affiliate of its general partner, before making an investment in an NRP Business, Quintana Capital has agreed to adhere to the following procedures:
Quintana Capital will first offer such opportunity in its entirety to NRP. NRP may elect to pursue such investment wholly for its own account, to pursue the opportunity jointly with Quintana Capital or not to pursue such opportunity.
If NRP elects not to pursue an NRP Business investment opportunity, Quintana Capital may pursue the investment for its own account on similar terms.
NRP will undertake to advise Quintana Capital of its decision regarding a potential investment opportunity within 10 business days of the identification of such opportunity to the Conflicts Committee.
If the opportunity relates to the acquisition of a Shared Business, NRP and Quintana Capital will adhere to the following procedures:
If the opportunity is generated by individuals other than Mr. Robertson, the opportunity will belong to the entity for which those individuals are working.
If the opportunity is generated by Mr. Robertson and both NRP and Quintana Capital are interested in pursuing the opportunity, it is expected that the Conflicts Committee will work together with the relevant Limited Partner Advisory Committees for Quintana Capital to reach an equitable resolution of the conflict, which may involve investments by both parties.
In all cases above in which Mr. Robertson has a conflict of interest, investment decisions will be made on behalf of NRP by the Conflicts Committee and on behalf of Quintana Capital Group by the relevant Investment Committee, with Mr. Robertson abstaining.
A fund controlled by Quintana Capital owns an interest in Corsa Coal Corp, a coal mining company traded on the TSX Venture Exchange that is one of our lessees in Tennessee.Relationships with Entities Associated with Corbin J. Robertson, III one
Quinwood Coal Partners LP (“Quinwood”), an entity controlled by Corbin J. Robertson, III (one of our directors, is Chairman ofdirectors) leases two coal properties from us in Central Appalachia. During the Board of Corsa.year ended December 31, 2019, we recorded $0.2 million in coal royalty revenues from Quinwood and received $0.2 million in cash related to royalty and property tax payments.
For more information on our relationship with Corsa Coal, see "Item 8. Financial StatementsMr. Robertson III also owns a minority ownership interest in Industrial Minerals Group LLC (“Industrial Minerals”), which, through its subsidiaries, leases two of NRP’s coal royalty properties in Central Appalachia. During the year ended December 31, 2019, we recorded $1.7 million in coal royalty and Supplemetary Data—Note 13. Related Party Transactions—Quintana Capital Group GP, Ltd."
wheelage revenues from Industrial Minerals and received approximately $0.5 million in cash related to royalty and minimum payments.
Office Building in Huntington, West Virginia
We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The termsinitial 10-year term of the lease including $0.6expired at the end of 2018. On January 1, 2019 we entered into a new lease on the building for a five-year base term, with five additional five-year renewal options. During the year ended December 31, 2019, we paid approximately $0.8 million perto Western Pocahontas under the lease.
Relationship with Cadence Bank, N.A.
Paul B. Murphy, Jr. one of the members of the Board of Directors of GP Natural Resource Partners LLC, is the Chairman of Cadence Bank, N.A., which is a lender under NRP Operating’s revolving credit facility and has received customary fees and interest payments in connection therewith. During the year ended December 31, 2019 we paid approximately $0.1 million in lease payments, were approved by our conflicts committee.interest and fees under the credit facility to Cadence Bank, N.A.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group, the Cline entities, and their affiliates)Group) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLC have duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage our partnership in a manner beneficial to us and our unitholders. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions modifying the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the Board of Directors of our general partner of such resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:
approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or course of action that has not received approval;
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement, consider:
the relative interests of any party to such conflict and the benefits and burdens relating to such interest;
any customary or accepted industry practices or historical dealings with a particular person or entity;
generally accepted accounting practices or principles; and
such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
Blackstone has certain consent rights and board appointment and observation rights and may be deemed to be an affiliate of our general partner. In addition, GoldenTree has certain limited consent rights. In the exercise of these consent rights and board rights, conflicts of interest could arise between us on the one hand, and Blackstone or GoldenTree on the other hand.
Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
amount and timing of asset purchases and sales;
cash expenditures;
borrowings;
the issuance of additional common units; and
the creation, reduction or increase of reserves in any quarter.
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of enabling our general partner to receive distributions.
For example, in the event we have not generated sufficient cash from our operations to pay the quarterly distribution on our common units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding common units.
The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries.
Excluding VantaCore, we
We do not have any officers or employees andemployees. We rely solely on officers and employees of GP Natural Resource Partners LLC and its affiliates.
Excluding our VantaCore business, weWe do not have any officers or employees and rely solely on officers and employees of GP Natural Resource Partners LLC and its affiliates. Affiliates of GP Natural Resource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource Partners LLC are not required to work full time on our affairs. TheseCertain of these officers devote significant time to the affairs of the WPP Group or its affiliates and are compensated by these affiliates for the services rendered to them.
We reimburse our general partner and its affiliates for expenses.
We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.
Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length negotiations.
All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
We may not choose to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
Our general partner’s affiliates may compete with us.
The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement the Omnibus Agreement and the Restricted Business ContributionOmnibus Agreement, affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us.
As a result of the purchase of the Preferred Units, Blackstone has certain consent rights and board appointment and observation rights and may be deemed to be an affiliate of our general partner. In addition, GoldenTree has certain limited consent rights. In the exercise of these consent rights and board rights, conflicts of interest could arise between us and our general partner on the one hand, and Blackstone or GoldenTree on the other hand.
The Conflicts Committee Charter is available upon request.
Director Independence
Review, Approval or Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner and its affiliates (including the WPP Group, the Cline entities, Blackstone, GoldenTree, and their affiliates)Group) on the one hand, and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under "—Conflicts of Interest."
Pursuant to our Code of Business Conduct and Ethics, conflicts of interest are prohibited as a matter of policy, except under guidelines approved by the Board and as provided in the Omnibus Agreement the Restricted Business Contribution Agreement, and our partnership agreement. For the year ended December 31, 2016,2019 there were no transactions where such guidelines were not followed.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended and we engaged Ernst & Young LLP to audit our accounts and assist with tax work for fiscal 20162019 and 2015.2018. All of our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board of Directors. The following table presents fees for professional services rendered by Ernst &Young LLP:
|
| | | | | | | |
| | 2016 | | 2015 |
| Audit Fees(1) | $ | 1,010,002 |
| | $ | 1,192,306 |
|
| Tax Fees(2) | 746,463 |
| | 773,005 |
|
| All Other Fees(3) | 1,980 |
| | 2,400 |
|
|
| | | | | | | |
| | 2019 | | 2018 |
Audit Fees (1) | $ | 1,070,206 |
| | $ | 957,272 |
|
Tax Fees (2) | 533,083 |
| | 501,426 |
|
| |
| (1) | Audit fees include fees associated with the annual integrated audit of our consolidated financial statements and internal controls over financial reporting, separate audits of subsidiaries and reviews of our quarterly financial statement for inclusion in our Form 10-Q and comfort letters; consents; work related to acquisitions; assistance with and review of documents filed with the SEC. |
in our Form 10-Q and comfort letters; consents; work related to acquisitions; assistance with and review of documents filed with the SEC.
| |
| (2) | Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1. |
| |
(3) | All other fees include the subscription to EY Online research tool. |
Audit and Non-Audit Services Pre-Approval Policy
I. Statement of Principles
Under the Sarbanes-Oxley Act of 2002 (the "Act"), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the SEC has issued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the "Policy"), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor may be pre-approved.
The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee ("general pre-approval") or require the specific pre-approval of the Audit Committee ("specific pre-approval"). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficient procedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-approval by the Audit Committee.
For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The Audit Committee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiarity with our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage or control risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative.
The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
The appendices to this Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any general pre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will add or subtract to the list of general pre-approved services from time to time, based on subsequent determinations.
The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by the independent auditor to management.
Ernst & Young LLP, our independent auditor has reviewed this Policy and believes that implementation of the policy will not adversely affect its independence.
II. Delegation
As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Robert B. Karn III,Stephen P. Smith, the Chairman of the Audit Committee. Mr. KarnSmith must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.
III. Audit Services
The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annual financial statement audit (including required quarterly reviews), subsidiary audits and other procedures required to be performed by the independent auditor to be able to form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testing performed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services also include the attestation engagement for the independent auditor’s report on management’s report on internal controls for financial reporting. The Audit Committee monitors the audit services engagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in audit scope, partnership structure or other items.
In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other audit services, which are those services that only the independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits for our subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection with securities offerings.
IV. Audit-related Services
Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financial statements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does not impair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accounting consultations related to accounting, financial reporting or disclosure matters not classified as "Audit Services"; assistance with understanding and implementing new accounting and financial reporting guidance from rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal control reporting requirements.
V. Tax Services
The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advice without impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes it may grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would not impair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of the independent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officer or outside counsel to determine that the tax planning and reporting positions are consistent with this Policy.
VI. Pre-Approval Fee Levels or Budgeted Amounts
Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Any proposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overall relationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determine the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
VII. Procedures
All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submitted to the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of any such services rendered by the independent auditor.
Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the Audit Committee by both the independent auditor and the Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with the SEC’s rules on auditor independence.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (2) Financial Statements and Schedules
(a)(3) Ciner Wyoming LLC Financial Statements
The financial statements of Ciner Wyoming LLC required pursuant to Rule 3-09 of Regulation S-X are included in this filing as Exhibit 99.1.99.1.
(a)(4) Exhibits
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Exhibit Number | Description |
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2.2 | Agreement and Plan of Merger, dated as of August 18, 2014, by and among VantaCore Partners LP, VantaCore LLC, the Holders named therein, Natural Resource Partners L.P., NRP (Operating) LLC and Rubble Merger Sub, LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on August 20, 2014). |
2.3 | Interest Purchase Agreement, by and among NRP Oil and Gas LLC, Kaiser-Whiting, LLC and the Owners of Kaiser-Whiting, LLC dated as of October 5, 2014 (incorporated by reference to Current Report on Form 8-K filed on October 6, 2014). |
2.4 | Purchase and Sale Agreement dated as of June 13, 2016 by and between NRP Oil and Gas LLC and Lime Rock Resources IV-A, L.P. |
3.1 | Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of September 20, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 21, 2010). |
3.2 | |
3.3 | |
3.4 | |
3.5 | |
3.6 | |
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Exhibit
| Description |
4.4 | |
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| Form of Series B Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed June 23, 2003). |
4.11 | |
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4.12 | |
Exhibit Number | Description |
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4.13 | |
4.14 | |
4.15 | |
4.16 | |
4.17 | |
4.18 | |
4.19 | |
4.20 | Indenture, dated September 18, 2013, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as issuers, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 19, 2013). |
4.21 | Form of 9.125% Senior Notes due 2018 (contained in Exhibit 1 to Exhibit 4.20). |
4.22 | |
4.23 | |
4.24 | Indenture, dated March 2, 2017,April 29, 2019, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as issuers, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.34.1 to Current Report on Form 8-K filed on March 6, 2017)May 2, 2019). |
4.25 | |
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Exhibit
| Description |
4.26 | Registration Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P., NRP Finance Corporation, and the Initial Notes Purchasers named therein (incorporated by reference to Exhibit 4.5 to Current Report on Form 8-K filed on March 6, 2017). |
4.27 | |
4.28 | |
10.1 | |
| Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 18, 2015). |
| First Amendment, dated as of June 3, 2016, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 7, 2016). |
| Contribution Agreement, dated as of September 20, 2010, by and among Natural Resource Partners L.P., NRP (GP) LP, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and NRP Investment L.P. (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 21, 2010). |
10.4 | First Amended and Restated Omnibus Agreement, dated as of April 22, 2009, by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed May 7, 2009). |
10.5 | Restricted Business Contribution Agreement, dated January 4, 2007, by and among Christopher Cline, Foresight Reserves LP, Adena Minerals, LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January 4, 2007). |
10.6 | Investor Rights Agreement, dated January 4, 2007, by and among NRP (GP) LP, GP Natural Resource Partners LLC, Robertson Coal Management and Adena Minerals, LLC (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on January 4, 2007). |
10.7 | Waiver Agreement, dated November 12, 2009, by and among Natural Resource Partners L.P., Great Northern Properties Limited Partnership, Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on November 13, 2009). |
10.8 | |
10.9 | |
10.10 | Credit Agreement, dated as of August 12, 2013, among NRP Oil and Gas LLC, Wells Fargo Bank, N.A., as Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 13, 2013). |
10.11 | First Amendment to Credit Agreement, dated effective as of December 19, 2013, among NRP Oil and Gas LLC, Wells Fargo Bank, N.A., as Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on December 20, 2013). |
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Exhibit Number | Description |
10.12 | Second Amendment to Credit Agreement entered into effective as of November 12, 2014 among NRP Oil and Gas LLC, each of the Lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on November 14, 2014). |
10.13 | Fourth Amendment to Credit Agreement entered into effective as of March 21, 2016 among NRP Oil and Gas LLC, each of the Lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 22, 2016). |
10.14 | Second Amendment, dated as of March 2, 2017, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed on March 6, 2017). |
10.15 | Preferred UnitFourth Amendment, dated as of April 3, 2019, to Third Amended and Warrant PurchaseRestated Credit Agreement, dated as of February 22, 2017,June 16, 2015, by and among Natural Resource Partners L.P.NRP (Operating) LLC and the Purchasers named thereinlenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 6, 2017.April 9, 2019). |
10.16 | Exchange and Purchase |
10.17 | |
10.18*** | |
10.19*** | |
10.20*** | Natural Resource Partners Annual Incentive Plan |
10.21*** | Natural Resource Partners L.P. 2016 Cash Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-KS-8 filed on February 26, 2016)9, 2018). |
10.22* | |
10.23* | |
21.1* | |
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Exhibit
| Description |
23.2* | |
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95.1* | Mine Safety Disclosure. |
99.1* | |
| 101.INS* | XBRL Instance Document |
| 101.SCH* | XBRL Taxonomy Extension Schema Document |
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document |
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document |
| 101.LAB* | XBRL Taxonomy Extension Labels Linkbase Document |
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document |
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| * | Filed herewith |
| ** | Furnished herewith |
***+ | Management compensatory plan or arrangement |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | NATURAL RESOURCE PARTNERS L.P. |
| | By: | | NRP (GP) LP, its general partner |
| | By: | | GP NATURAL RESOURCE |
| | | | PARTNERS LLC, its general partner |
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Date: March 6, 2017February 27, 2020 | | |
| | By: | | /s/ CORBIN J. ROBERTSON, JR. |
| | | | Corbin J. Robertson, Jr. |
| | | | Chairman of the Board, Director and |
| | | | Chief Executive Officer |
| | | | (Principal Executive Officer) |
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Date: March 6, 2017 | | |
| By: | | /s/ CRAIG W. NUNEZ
|
| | | Craig W. Nunez |
| | | Chief Financial Officer and |
| | | Treasurer |
| | | (Principal Financial Officer) |
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Date: March 6, 2017February 27, 2020 | | |
| | By: | | /s/ CHRISTOPHER J. ZOLAS |
| | | | Christopher J. Zolas |
| | | | Chief AccountingFinancial Officer and Treasurer |
| | | | (Principal Financial and Accounting Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Date: March 6, 2017February 27, 2020 | |
| | /s/ ROBERT T. BLAKELYGALDINO J. CLARO |
| | Robert T. BlakelyGaldino J. Claro |
| | Director |
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Date: March 6, 2017February 27, 2020 | |
| | /s/ RUSSELL D. GORDY |
| | Russell D. Gordy |
| | Director |
|
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Date: March 6, 2017 | |
| |
| L. G. (Trey) Jackson III |
| Director |
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Date: March 6, 2017February 27, 2020 | |
| | /s/ ROBERT B. KARN III ALEXANDER D. GREENE |
| | Robert B. Karn IIIAlexander D. Greene |
| | Director |
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Date: March 6, 2017 | |
| |
| Jasvinder S. Khaira |
| Director |
|
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Date: March 6, 2017February 27, 2020 | |
| | /s/ S. REED MORIAN |
| | S. Reed Morian |
| | Director |
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| Date: February 27, 2020 | |
| /s/ PAUL B. MURPHY, JR. |
| Paul B. Murphy, Jr. |
| Director |
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Date: March 6, 2017February 27, 2020 | |
| | /s/ RICHARD A. NAVARRE |
| | Richard A. Navarre |
| | Director |
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Date: March 6, 2017February 27, 2020 | |
| | /s/ CORBIN J. ROBERTSON III |
| | Corbin J. Robertson III |
| | Director |
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Date: March 6, 2017February 27, 2020 | |
| | /s/ STEPHEN P. SMITH |
| | Stephen P. Smith |
| | Director |
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Date: March 6, 2017February 27, 2020 | |
| | /s/ LEO A. VECELLIO, JR. |
| | Leo A. Vecellio, Jr. |
| | Director |
