Natural Resource Partners
Annual Report 2019

Plain-text annual report

2019 Annual Report N a t u r a l R e s o u r c e P a r t n e r s L P. . 2 0 1 9 A n n u a l R e p o r t Natural Resource Partners L.P. 1201 Louisiana Street, 34th Floor Houston, Texas 77002 www.nrplp.com Natural Resource Partners L.P. 2019 Financial Highlights Unitholder Information (in thousands, except per unit) 2019 2018 (1) 2017 2016 2015 For the Years Ended December 31 Total revenues and other income Asset impairments Income (loss) from operations Net income (loss) from continuing operations Net income from continuing operations excluding impairments $ 263,935 $ $ $ 148,214 51,321 (25,414) $ 122,800 Net income (loss) from discontinued operations $ 956 Net income (loss) $ (24,458) Per common unit amounts (basic) Net income (loss) from continuing operations Net income (loss) from discontinued operations Net income (loss) Per common unit amounts (diluted) Net income (loss) from continuing operations Net income (loss) from discontinued operations Net income (loss) Distributions paid per common unit Average number of common units outstanding - basic Average number of common units outstanding - diluted Net cash provided by (used in) Operating activities of continuing operations Investing activities of continuing operations Financing activities of continuing operations Free cash flow (2) Cash flow cushion (2) Distributable cash flow (2) Adjusted EBITDA (2) $ $ $ $ $ $ $ (4.43) 0.08 (4.35) (4.43) 0.08 (4.35) 2.65 12,260 12,260 $ $ 137,319 8,221 $ (253,305) $ 139,040 $ 7,762 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 278,512 $ 246,325 $ 279,244 $ 300,635 18,280 192,538 122,360 140,640 17,687 140,047 7.35 1.42 8.77 5.90 0.86 6.76 1.80 12,244 20,234 178,282 7,607 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2,967 176,559 82,485 85,452 6,182 88,667 4.57 0.50 5.06 3.68 0.28 3.96 1.80 12,232 21,950 $ $ $ $ $ $ $ $ $ $ $ $ $ 15,861 181,157 90,626 $ 378,327 $ (170,699) $ (260,443) 106,487 $ $117,884 6,266 $ (311,277) 96,892 $ (571,720) 7.28 0.50 7.78 7.28 0.50 7.78 1.80 12,232 12,232 $ $ $ $ $ $ $ (20.80) (24.94) (45.75) (20.80) (24.94) (45.75) 2.70 12,232 12,232 112,151 9,807 $ $ 80,243 65,057 $ $ 144,907 15,805 (6,839) $ (134,149) $ (146,373) $ (166,443) 183,440 16,080 121,324 $ 75,970 9,248 $ (29,444) $ $ $ 144,210 (8,339) 157,815 $ 144,933 $ 383,980 $ 199,228 $ 230,241 121,958 211,483 $ 255,172 $ 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 Long-term deb, net Long-term lease obligations (3) Class A convertible preferred units Partners’ capital $ 45,776 $ 470,422 $ 3,506 $ 164,587 $ 338,963 $ $ $ $ $ 115,184 $ 79,740 $ 140,037 $ 80,745 557,574 $ 729,608 $ 990,234 $ 1,130,696 — 164,587 423,481 $ $ $ — 173,431 265,211 $ $ $ — — 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” in this Annual Report on Form 10-K form more information. (3) On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments and recognized assets and liabilities on its Consolidated Balance Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. Partnership Headquarters 1201 Louisiana Street Suite 3400 Houston, TX 77002 713-751-7507 Regional Offices Coal and Hard Minerals 5260 Irwin Road Huntington, WV 25705 Investor Relations Tiffany Sammis 1201 Louisiana Street Suite 3400 Houston, TX 77002 713-751-7515 Email: info@nrplp.com Stock Exchange Our units are listed on the New York Stock Exchange under the symbol NRP. Independent Auditors Ernst & Young LLP 5 Houston Center 1401 McKinney St, Suite 2400 Houston, TX 77010 Transfer Agent and Registrar American Stock Transfer and Trust Company Client Operations 6201 15th Avenue Brooklyn, NY 11219 Website: www.astfinancial.com Email:help@astfinancial.com 800-937-5449 Website www.nrplp.com Information regarding Natural Resource Partners L.P. is located on the partnership’s website. On the site is operational and financial information as well as all SEC filings and our corporate governance documents, including our Code of Business Conduct and Ethics, our Corporate Governance Guidelines and Board of Directors’ Audit Committee Charter. Requests for copies of the annual report or other data may be made through the website or by contacting Investor Relations. These requests will be provided free of charge. Contact NRP Board We have established procedures for contacting the non-management members of the NRP Board of Directors. To communicate any concerns or issues to the Board of Directors, please direct any correspondence to: Chairman of the CNG Committee NRP Board of Directors 1201 Louisiana Street, Suite 3400 Houston, TX 77002 888-252-2396 Schedule K-1 Unitholders receive Schedule K-1 packages that summarize their allocable share of the partnership’s reportable tax items for the calendar year. Generally, these K-1s are available on NRP’s website no later than mid-March. Unitholders should refer questions regarding their Schedule K-1 to the following: Natural Resource Partners L.P. Tax Package Support P.O. Box 799060 Dallas, TX 75379-9060 Fax: 1-866-554-3842 Toll Free: 1-888-334-7102 Forward-Looking Statements Statements included in this annual report may constitute 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 COVID-19, capital expenditures and acquisitions, expected commencement dates of mining, projected quantities of future production by our lessees producing from our reserves, and projected demand or supply for coal, trona and soda ash that will affect sales levels, prices and royalties realized by us. These forward-looking statements speak only as of the date hereof and are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties, including uncertainties surrounding the COVID-19 pandemic. 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. Please read “Item 1A. Risk Factors” of the Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to differ. To Our Unitholders Natural Resource Partners L.P. 2019 Annual Report 2019 was a year filled with much volatility in the coal space and financial markets. The year began with strong metallurgical coal pricing, open financial markets, steady distributions from our soda ash business and overall positive sentiment, but as the year progressed sentiment turned bearish with depressed thermal coal markets and weakened metallurgical export markets, a reduction in distributions from our soda ash business, relatively closed financial markets and multiple lessee bankruptcies. Moving into 2020, we are currently focused on navigating the evolving impact of COVID-19 that has locked down the global economy and significantly lowered energy demand, while also working through the bankruptcy of our largest lessee, Foresight Energy. Despite these strong headwinds, impressive achievements made in 2019 have better positioned us to face the challenges that lie ahead. 2019 Accomplishments: • Reduced our outstanding debt by $163 million • Refinanced and extended $300 million of long-term debt to 2025 • Extended the maturity of our $100 million revolving credit facility to 2023 • Generated $139 million in Free Cash Flow • • Resolved our only outstanding major litigation, winning in every respect with no liability to NRP Continued quarterly common unit distributions of $0.45 per unit and paid a one-time special distribution of $0.85 per unit to our common unitholders to cover unitholder tax liability on the gain from the sale of our construction aggregates business in 2018 Despite these strong headwinds, impressive achievements made in 2019 have better positioned us to face the challenges that lie ahead. 1 Business Highlights Our Coal Royalty segment generated 82% of the partnership’s Revenues and Other Income and 85% of the partnership’s Free Cash Flow in 2019. While there was a decline in metallurgical and thermal coal pricing in the second half of 2019, we believe our lessees locked in higher sales prices from the beginning of the year which minimized the negative effects of depressed pricing in the latter half of 2019. Also, I’d like to highlight we positively navigated multiple lessee bankruptcies in 2019, a continued and encouraging track record of NRP’s history at minimizing loss in the lessee bankruptcy process and ensuring economic mines emerge with relatively minimal impact to the long-term earnings power to NRP. Our Soda Ash segment received $32 million in distributions from Ciner Wyoming in 2019. Ciner Wyoming, of which we own a 49% equity interest, reached multiple production records in 2019 and continues to be one of the largest and lowest cost natural soda ash producers in the world. We remain laser focused on cash and liquidity during this time of uncertainty and believe we have ample resources to navigate these difficult circumstances for the foreseeable future. Looking Ahead It is evident through our ability to navigate the turbulent markets and multiple lessee bankruptcies, that the numerous transformative steps taken in recent years to right-size our business, fortify our financial position and streamline our cost structure have better positioned us to face the headwinds of 2020, including the ongoing uncertainty surrounding the COVID-19 pandemic. Our COVID-19 response started with prioritizing the health and safety of our employees, which included transitioning to working remotely from home and ensuring each employee is healthy and set up to work as efficiently as in the office. This transition went seamlessly, and we continue to operate safely and effectively. The coal landscape is evolving quickly due to COVID-19 with many operators temporarily idling operations. We are maintaining regular contact with our lessees to stay informed, understand the financial impact to us and minimize risks to our business. We remain laser focused on cash and liquidity during this time of uncertainty and believe we have ample resources to navigate these difficult circumstances for the foreseeable future. We know there are many headwinds facing the partnership as we enter into 2020, but with $98 million of cash on hand, $100 million of availability on our revolver and five years before our parent company bonds mature, we believe we will weather this storm while continuing to reduce debt and meet our financial obligations. Thank you to the many unitholders who have been through the highs and lows with us. We will continue to strive to create partnership value for our unitholders. Corbin J. Robertson, Jr. Chairman and Chief Executive Officer 2 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2019 or TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number: 1-31465 NATURAL RESOURCE PARTNERS L.P. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 35-2164875 (I.R.S. Employer Identification 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) Securities registered pursuant to Section 12(b) of the Act: Title of each class Common Units representing limited partner interests Trading Symbol(s) NRP Name of each exchange on which registered New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes No Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition of "accelerated filer", "large accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. Large Accelerated Filer Accelerated Filer Non-accelerated Filer Smaller Reporting Company Emerging Growth Company If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes No The aggregate market value of the common units held by non-affiliates of the registrant on June 28, 2019, was $318 million based on a closing price on that date of $35.46 per unit as reported on the New York Stock Exchange. Documents incorporated by reference: None. Table of Contents Items 1. and 2. Business and Properties TABLE OF CONTENTS PART I Item 1A. Item 1B. Item 3. Item 4. Item 5. Item 6. Item 7. Risk Factors Unresolved Staff Comments Legal Proceedings Mine Safety Disclosures PART II Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Selected Financial Data Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Item 9A. Item 9B. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. Signatures Financial Statements and Supplementary Data Changes In and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information Directors and Executive Officers of the Managing General Partner and Corporate Governance PART III Executive Compensation Security Ownership of Certain Beneficial Owners and Management Certain Relationships and Related Transactions, and Director Independence Principal Accountant Fees and Services Exhibits, Financial Statement Schedules PART IV 1 23 37 38 38 39 39 44 59 60 101 101 103 104 110 118 120 127 130 133 i Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS Statements included in this 10-K may constitute 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 financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projected production levels by our lessees; Ciner Wyoming LLC’s ("Ciner 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 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 1A. Risk 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. ii Table of Contents 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. 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 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, 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 production business. Our business is organized into two operating segments: Coal Royalty and Other—consists primarily of coal royalty properties and coal-related transportation and processing assets. Other assets include 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 Northern Powder River Basin in the United States. Our industrial minerals and aggregates properties are located in various states across the United States, our oil and gas royalty assets are primarily located in 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 and soda ash production 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. 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 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"), Mr. Robertson, Jr. is entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC and has delegated the right to appoint one director to Blackstone. The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited Partnership or Quintana Minerals Corporation, which are companies controlled by Mr. Robertson, Jr. 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. 1 Table of Contents Segment and Geographic Information The amount of 2019 revenues and other income from our two operating segments is shown below. For additional business segment information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations" and "Item 8. Financial Statements and Supplementary Data—Note 8. Segment Information" in this Annual Report on Form 10-K, which are both incorporated herein by reference. (In thousands) Coal Royalty and Other Soda Ash Total Coal Royalty and Other Segment Amount % of Total $ $ 216,846 47,089 263,935 82% 18% 100% Our coal reserves 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 based on the greater of a percentage of the sale price or fixed royalty per ton of minerals mined and sold. Lessees calculate royalty payments due to us and are required to report tons of minerals mined and sold as well as the sales prices of the extracted minerals. Therefore, to a great extent, amounts reported as royalty revenues 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 minimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments 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 costs, black lung benefits and workers’ compensation costs associated with operating the mines on our coal and aggregates properties. We pay property taxes on our properties, which are largely reimbursed by our lessees pursuant to the terms of the various lease agreements. 2 Table of Contents Coal Reserves and Production Information The following table presents coal reserves information as of December 31, 2019 for the properties that we own by major coal region: (Tons in thousands) Appalachia Basin Northern Central Southern Total Appalachia Basin Illinois Basin Northern Powder River Basin Gulf Coast Total Proven and Probable Reserves (1) Underground Surface Total 301,742 720,378 57,881 1,080,001 299,818 — — 1,379,819 3,031 242,379 19,794 265,204 5,074 163,555 1,957 435,790 304,773 962,757 77,675 1,345,205 304,892 163,555 1,957 1,815,609 (1) In excess of 90% of the reserves presented in this table are currently leased to third parties. The following table presents the type of our coal reserves by major coal region as of December 31, 2019: (Tons in thousands) Appalachia Basin Northern Central Southern Total Appalachia Basin Illinois Basin Northern Powder River Basin Gulf Coast Total Type of Coal Thermal Metallurgical (1) Total 243,939 545,949 58,554 848,442 304,892 163,555 1,875 60,834 416,808 19,121 496,763 — — 82 304,773 962,757 77,675 1,345,205 304,892 163,555 1,957 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. 3 Table of Contents The following table presents the sulfur content and the typical quality of our coal reserves by major coal region as of December 31, 2019: (Tons in thousands) Appalachia Basin Northern Central Southern Total Appalachia Basin Illinois Basin Northern Powder River Basin Gulf Coast Total Compliance Coal (2) Low (<1.0%) Sulfur Content Typical Quality (1) Medium (1.0% to 1.5%) High (>1.5%) Total Heat Content (Btu per pound) Sulfur (%) 46,307 443,313 43,382 533,002 — — 82 46,507 677,143 47,905 771,555 1,002 257,264 46,384 2,590 304,773 962,757 77,675 306,238 1,345,205 239,230 27,180 267,412 — 2,152 302,740 163,555 1,957 — — — — 304,892 163,555 1,957 533,084 937,067 269,564 608,978 1,815,609 12,977 13,238 13,405 13,189 11,476 8,800 6,964 2.61 0.91 0.96 1.30 3.29 0.65 0.69 (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 Appalachia 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. The following table presents the type of coal sales volumes by major coal region for the year ended December 31, 2019: (Tons in thousands) Appalachia Basin Northern Central Southern Total Appalachia Basin Illinois Basin Northern Powder River Basin Total Type of Coal Thermal Metallurgical Total 2,781 3,117 470 6,368 2,201 3,036 679 10,260 1,200 12,139 — — 11,605 12,139 3,460 13,377 1,670 18,507 2,201 3,036 23,744 4 Table of Contents Methodologies Used in Mineral Reserve Estimation All of the reserves reported above are recoverable proven or probable reserves as determined in accordance with the SEC’s Industry Guide 7 and are estimated by our internal geologists or independent third-party consultants. Significant internally generated reserve studies are reviewed by independent third-party consultants. The technologies and economic data used in the estimation of our proven 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 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 table provides a summary of our significant coal royalty properties by sales volumes for 2019 and is followed by additional information for each property: Region Property/Lease Name Operator(s) Coal Type 2019 Sales Volumes (Millions of Tons) Appalachia Basin Northern Northern Central Central Central Central Central Southern Illinois Basin Illinois Basin Illinois Basin Northern Powder River Basin 2.0 0.8 3.8 1.3 1.2 1.1 0.9 1.2 1.6 0.3 0.2 3.0 Hibbs Run Mettiki Coal Murray Energy Corporation Thermal Alliance Resource Partners Met/Thermal Contura-CAPP (VA) Contura Energy, Inc. Coal Mountain CM Energy Properties, LP Aracoma Elk Creek Lynch Oak Grove Macoupin Williamson Hillsboro Contura Energy, Inc. Ramaco Resources, Inc. Blackjewel, LLC; InMet, LLC Foresight Energy LP Foresight Energy LP Foresight Energy LP Murray Metallurgical Coal Holdings LLC Met Met Met Met Met Met/Thermal Thermal Thermal Thermal Thermal Western Energy Rosebud Mining, LLC 5 Table of Contents Appalachia Basin—Northern Appalachia Hibbs Run. The Hibbs Run property is located in Marion County, West Virginia. In 2019, approximately 2.0 million tons were sold from this thermal property. We lease this property to a subsidiary of Murray Energy Corporation. Coal from this property is produced from longwall 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. Mettiki Coal. The Mettiki Coal property is located in Tucker and Grant Counties, West Virginia. In 2019, approximately 0.8 million metallurgical and thermal tons were sold from this property. We lease this property to a subsidiary of Alliance Resource Partners. Production comes from this mine via a longwall operation. Coal is shipped by truck to a local utility customer and by train to metallurgical customers. NRP pays an override royalty equal to the royalty received from Mettiki to Western Pocahontas Properties Limited Partnership per the terms of the deed. The map below shows the location of our major properties in Northern Appalachia: 6 Table of Contents Appalachia Basin—Central Appalachia Contura-CAPP (VA). The Contura-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2019, approximately 3.8 million tons were sold from this property, substantially all of which was metallurgical coal. We lease this property to subsidiaries of Contura Energy, Inc ("Contura Energy"). Production comes from underground room and pillar and surface mines and is trucked to one of two preparation plants. Coal is shipped via the CSX and Norfolk Southern railroads to utility and metallurgical customers. Coal Mountain. The Coal 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 County, West Virginia. Approximately 1.2 million tons of coal, substantially all of which is metallurgical coal, were sold in 2019 from this property. We lease this property to a subsidiary of Contura Energy. Coal is produced from underground mines and transported by belt or truck to the preparation plant on the property. Coal is shipped via the CSX railroad to export 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 Ramaco 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 and Wise County, Virginia. In 2019, approximately 0.9 million tons were sold from this property. Blackjewel, LLC ("Blackjewel") operated this property until it filed for bankruptcy in the third quarter of 2019. InMet, LLC obtained lease rights to a substantial portion of this property through the Blackjewel bankruptcy process and is currently operating on this lease. Production comes from underground room and pillar and surface mines. This property has the ability to ship coal on the CSX and Norfolk Southern railroads to utility and metallurgical customers. 7 Table of Contents The map below shows the location of our major properties in Central Appalachia: 8 Table of Contents Appalachia Basin—Southern Appalachia Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2019, approximately 1.2 million tons of metallurgical coal were sold from this property. We lease this property to Murray Metallurgical Coal Holdings, LLC ("Murray Metallurgical"). The lease was transferred to Murray Metallurgical in connection with Mission Coal LLC's bankruptcy proceedings. Production comes from a longwall mine and is transported by beltline to a preparation plant. Metallurgical products are then shipped via railroad and barge to both domestic and export customers. While the mine was temporarily idled during the last quarter of 2019 and Murray Metallurgical filed bankruptcy in the first quarter of 2020, the Oak Grove mine is expected to resume production in 2020. The map below shows the location of our major property in Southern Appalachia: 9 Table of Contents 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. This property is under lease to Williamson Energy, a subsidiary of Foresight Energy. In 2019, approximately 0.3 million tons of thermal coal were sold from this property. Production comes from a longwall mine. Coal is shipped primarily via the Canadian National railroad to export customers. In 2019, we also received overriding royalties from approximately 5.5 million tons of coal sold from non-NRP property. Hillsboro. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. This property is under lease to Hillsboro Energy, a subsidiary of Foresight Energy. This property had been idled from March 2015 until production resumed in January 2019. In 2019, approximately 0.2 million tons of thermal coal were sold from this property. Production at the mine has historically come from longwall mining 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 customers. 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 are also operated by Foresight Energy. See "—Coal Transportation and Processing Assets" below for additional information on these assets. 10 Table of Contents The map below shows the location of our major properties in the Illinois Basin: 11 Table of Contents Northern Powder River Basin Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2019, approximately 3.0 million tons were sold from this property by a subsidiary of Rosebud Mining, LLC. Coal is produced by surface dragline mining methods. Coal is transported by either truck or beltline to the Colstrip generation station located at the mine mouth. The map below shows the location of our property in the Northern Powder River Basin: 12 Table of Contents Coal Transportation and Processing Assets We own transportation and processing infrastructure related to certain of our coal properties, including loadout and other transportation assets at Foresight Energy's Williamson and Macoupin mines in the Illinois 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. While we own coal reserves at the Williamson and Macoupin mines, we do not own coal reserves at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a 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, 2019, we owned an estimated 172 million tons of aggregates reserves primarily located in Kentucky and Indiana. We lease a portion of these reserves to third parties in exchange for royalty payments. The structure of these leases is similar to our coal leases, and these leases typically require minimum rental payments in addition to royalties. In addition, we hold overriding royalty interests in approximately 82 million tons of frac 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 $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, 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 in the Gulf Coast region, of which approximately 5,600 acres are leased in Louisiana, Mississippi and Texas; an overriding royalty interest of 1% (net) on approximately 25,000 mineral acres in Louisiana; copper rights in Michigan's Upper 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 or otherwise monetize these assets. 13 Table of Contents 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 in 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 seven large continuous mining machines and 14 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. 14 Table of Contents 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 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 57 years. 15 Table of Contents 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. The 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 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. Ciner Wyoming anticipates that its current deca stockpiles will be exhausted by 2023 and production rates decline approximately 200,000 short tons per year if that production is not replaced. Shipping and Logistics. All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended December 31, 2019, Ciner Wyoming shipped approximately 96.9% of its soda ash to its customers initially via a single rail line owned and controlled by Union Pacific Railroad 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 located in Texas and 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 in its agreement with ANSAC) and other of its member companies for export to its customers. ANSAC accounted for approximately 60% of Ciner Wyoming’s net sales in 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 16 Table of Contents 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 value of soda ash and related products sold at a certain stage in the mining process. These royalty payments may be subject to a minimum domestic production volume from the Green River Basin facility. Ciner Wyoming is also obligated to pay annual rentals to its lessors and licensor regardless of actual sales. In addition, Ciner Wyoming pays a production tax to Sweetwater County, and trona severance tax to the State of Wyoming that is calculated based on a formula that utilizes the volume 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 related 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 2019, 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 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. Significant Customers We have a significant concentration of revenues with Foresight Energy and its subsidiaries, with total revenues of $58.9 million in 2019 from four different mining operations, including transportation and processing services revenues, coal overriding royalty revenues and wheelage revenues. We also have a significant concentration of revenues from Contura Energy, with total revenues of $40.7 million in 2019 from several different mining operations, including wheelage revenues. For additional information on significant customers, refer to "Item 8. Financial Statements and Supplementary 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. 17 Table of Contents Ciner Wyoming's trona mining and soda ash refinery business 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 substantially all of our coal and aggregates reserves in fee as of December 31, 2019. We lease the remainder from unaffiliated third parties. Ciner Wyoming 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"). 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. 18 Table of Contents In addition, the electric utility industry, which is the most significant end-user of thermal 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 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"), 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 U.S. Environmental Protection Agency ("EPA") regulations 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 began 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 required 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. As promulgated, the rule would 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, likely resulting in a material adverse effect on the demand for coal by electric power generators. 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 CPP 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. 19 Table of Contents 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. In April 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 26% 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. In 2019, President Trump withdrew from the Paris Climate Agreement. Hazardous Materials and Waste The Federal Comprehensive Environmental Response, Compensation and Liability Act ("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” 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 Ciner Wyoming'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 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. 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 its review of permits, EPA 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. 20 Table of Contents 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”) permits requiring compliance with West Virginia’s water quality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereas others alleged that discharges of conductivity and sulfate were 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. 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. Any 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 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") 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") 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. 21 Table of Contents 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. Employees and Labor Relations As of December 31, 2019, affiliates of our general partner employed 56 people who directly supported our operations. None of these employees were subject to a collective bargaining agreement. Website Access to Partnership Reports Our Internet address is www.nrplp.com. We make available free of charge on or through our Internet 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. Information on our website is 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 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 to our principal executive office at 1201 Louisiana St., Suite 3400, Houston, Texas 77002. 22 Table of Contents ITEM 1A. RISK FACTORS Risks Related to Our Business Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of 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. We 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, our unitholders may be required to pay taxes in excess of any future distributions we make. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities. See "—Tax Risks to Our Unitholders—Our unitholders are required to pay taxes on their share of our income even if they 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 2025 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 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 "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and "Item 8. Financial Statements and Supplementary Data—Note 12. Debt, Net." Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2019, we and our subsidiaries had approximately $524.1 million of total indebtedness. The terms and conditions governing the indenture for NRP’s 2025 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; 23 Table of Contents • 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, including higher interest rates. We are required to make substantial principal repayments each year in connection with Opco’s senior notes, with approximately $46 million due thereunder during 2020. To the extent we borrow to make some of these payments, 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. In 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 business, financial condition and results of operations. For a description of the interest rate on borrowings under Opco’s revolving credit facility, see “Item 8. Financial Statements and Supplementary Data—Note 12. Debt, Net.” Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material adverse effect on our business and results of operations. Coal prices continue to be volatile and prices could decline 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 currencies; global and domestic 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. 24 Table of Contents Natural gas is the primary fuel that competes with thermal coal for power generation, and renewable energy sources continue to gain market share in power generation. The abundance and ready availability of cheap natural gas, together with increased governmental regulations on the power generation industry has caused a number of utilities to switch from thermal coal to natural gas and/or close coal-powered generation plants. This switching has resulted in a decline in thermal coal prices, and to the extent that natural gas prices remain low, thermal coal prices will also remain low. Reduced international demand for export thermal coal and increased competition from global producers has also put downward pressure on thermal coal prices. Our lessees produce a significant amount of metallurgical coal that is used for steel production domestically and internationally. Since the amount of steel that is produced is tied to global economic conditions, declines in those conditions could result in the decline of steel, coke and metallurgical coal production. Since metallurgical coal is priced higher than thermal 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. Any potential future lessee bankruptcy filings could 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. 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 to file for protection under U.S. bankruptcy and/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 rejection 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. Foresight Energy, which is our largest lessee, is currently working with its lenders and contract counterparties to evaluate restructuring options, which could result in the 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 extent we agree to amend the terms of our 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 may reduce our revenues. The level of production and costs thereof are subject to operating conditions or events beyond our or our lessees’ control including: • • • difficulties 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 the amount of rock embedded in or overlying the mineral deposit; 25 Table of Contents • 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 and trained personnel shortages; and • mine safety incidents or accidents, including hazardous conditions, roof falls, fires and explosions. While our lessees maintain insurance coverage, there is no assurance that insurance will be available or cover the costs 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 as a fuel source. In addition, 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 their operations. The occurrence of any of these events or conditions could have a material adverse effect on our business and results of operations. The 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 and a corresponding decrease in 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. 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. In addition to EPA’s greenhouse 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 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. For more information on regulation of greenhouse gas and other air pollutant emissions, see "Items 1. and 2. Business and Properties—Regulation and Environmental Matters.” 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. 26 Table of Contents 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 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. 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 mining 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 land owners that allege violations of water quality standards resulting from ongoing discharges of pollutants from reclaimed mining operations, including selenium and conductivity. Any 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. 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 activities; • • • • processing and blending minerals; expansion plans and capital expenditures; credit risk of their customers; permitting; 27 Table of Contents • • • • • 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 are exposed to operating risks that we do not experience in the royalty 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 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 28 Table of Contents 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 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 and/or other events could temporarily impair the ability of our lessees to supply coal to their 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 would 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. For the year ended December 31, 2019, Ciner Wyoming shipped approximately 96.9% of its soda ash from the Green River facility on a single rail line owned and controlled by Union Pacific. Ciner Wyoming’s current transportation contract with Union Pacific expires on December 31, 2021. There can be no assurance that this contract will be renewed on terms favorable to Ciner Wyoming 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, undue reliance should not be placed on our reserve data that is included in this report. 29 Table of Contents 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 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 of their substantial ownership in us, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates and the holders of the preferred units. 30 Table of Contents 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 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 units 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. 31 Table of Contents 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. Conflicts of interest could arise among our general partner and us or the unitholders. These conflicts may include the following: • We 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, 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. 32 Table of Contents 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 Our 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 unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for U.S. federal income tax purposes. 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 our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because tax would be imposed upon us as a corporation, our cash available for distribution to our 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 unitholders, likely causing a substantial reduction in the value of our 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 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 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. Any 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 similar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal the qualifying income exception within Section 7704(d)(1)(E) of the Code upon which we rely for our status as a partnership for U.S. federal income tax purposes. 33 Table of Contents In addition, the Treasury Department has issued, and in the future 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 the qualifying income rules in a manner that could impact our ability to qualify as a publicly traded partnership in the future. 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 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. 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 units. We are not aware of any current proposals with regard to these changes. Our unitholders are required to pay taxes on their share of our income even if they 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. Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, our unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them 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 royalty businesses) and passive activities (such as our soda ash 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 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, our unitholders' share of our portfolio income may be subject to federal income tax, regardless of other losses they 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 their units. We 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, our 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 of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as ordinary taxable income. Our unitholders may be allocated income and gain from these transactions, and income tax liabilities arising therefrom may exceed any distributions we make to 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. Our unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against 34 Table of Contents any capital losses attributable to the unitholder’s ultimate disposition of its units. Our unitholders are encouraged to consult their tax advisors with respect to the consequences to them If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. 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 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 . 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 these rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder 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. Tax gain or loss on the disposition of our common units could be more or less than expected. If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Distributions in excess of a common unitholder's allocable share of our net taxable income result in a decrease in the tax basis in such unitholder's common units. Accordingly, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income to our common unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. 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. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted 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 business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their 35 Table of Contents ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them. Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. 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 a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on 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 we 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 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 recently 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 broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’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 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 our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our 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 36 Table of Contents 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 units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their 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 units. As a result of investing in our units, our 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, our 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 our unitholders do not live in any of those jurisdictions. Our 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, our 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 the unitholder's responsibility to file all U.S. federal, state and local tax 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. 37 Table of Contents 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, management believes these ordinary 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 2019, the trial court ruled in our favor in all respects, including that the internal restructuring that occurred did not trigger an acceleration of the contingent 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 us. ITEM 4. MINE SAFETY DISCLOSURES None. 38 Table of Contents ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES PART II NRP Common Units Our common units are listed and traded on the NYSE under the symbol "NRP." As of February 10, 2020, there were approximately 13,180 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 shows the securities authorized for issuance under our 2017 Long-Term Incentive Plan at December 31, 2019. The initial number of common units authorized for issuance pursuant to awards under the plan was 800,000. Plan Category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total 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)) (a) (b) (c) — n/a — — n/a — 613,018 (1) n/a 613,018 (1) As of December 31, 2019, 157,789 phantom units were outstanding under the plan. Each phantom unit represents the right to receive one common unit, together with associated distribution equivalent rights. ITEM 6. SELECTED FINANCIAL DATA The following table shows selected historical financial data for Natural Resource Partners L.P. for the periods and as of the dates indicated. We derived the information in the following tables from, and the information should be read together with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in "Item 8. Financial Statements and Supplementary Data" in this and previously filed Annual Reports on Form 10-K. These tables should be read together with "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations." 39 Table of Contents (In thousands, except per unit data) Total revenues and other income Asset impairments Income (loss) from operations Net income (loss) from continuing operations Net income from continuing operations excluding impairments Net income (loss) from discontinued operations Net income (loss) Per common unit amounts (basic) Net income (loss) from continuing operations Net income (loss) from discontinued operations Net income (loss) Per common unit amounts (diluted) Net income (loss) from continuing operations Net income (loss) from discontinued operations Net income (loss) Distributions paid per common unit Average number of common units outstanding - basic Average number of common units outstanding - diluted Net cash provided by (used in) Operating activities of continuing operations Investing activities of continuing operations Financing activities of continuing operations Distributable cash flow (2) Free cash flow (2) Cash flow cushion (2) Adjusted EBITDA (2) Cash, cash equivalents and restricted cash Total assets Current portion of long-term debt, net Long-term debt, net Long-term lease obligations (3) Class A convertible preferred units Partners’ capital $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ For the Year Ended December 31, 2019 263,935 148,214 51,321 $ $ $ 2018 (1) 278,512 18,280 192,538 (25,414) $ 122,360 122,800 $ 140,640 956 $ (24,458) $ 17,687 140,047 (4.43) $ 0.08 $ (4.35) $ (4.43) $ 0.08 $ (4.35) $ $ 2.65 7.35 1.42 8.77 5.90 0.86 6.76 1.80 12,260 12,260 12,244 20,234 137,319 8,221 $ $ 178,282 7,607 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ (253,305) $ $ 144,933 $ 139,040 $ 7,762 $ 199,228 $ 98,265 $ 1,085,907 $ 45,776 $ 470,422 $ 3,506 $ 164,587 $ 338,963 383,980 183,440 16,080 230,241 206,030 1,341,647 115,184 557,574 (6,839) $ $ $ $ $ $ $ $ $ — $ $ $ 164,587 423,481 2017 246,325 2,967 176,559 82,485 85,452 6,182 88,667 4.57 0.50 5.06 3.68 0.28 3.96 1.80 12,232 21,950 112,151 9,807 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2016 279,244 15,861 181,157 90,626 106,487 6,266 96,892 7.28 0.50 7.78 7.28 0.50 7.78 1.80 12,232 12,232 80,243 65,057 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ (134,149) $ $ 121,958 $ 121,324 $ 9,248 $ 211,483 $ 26,980 $ 1,389,164 $ 79,740 $ 729,608 — $ $ $ 173,431 265,211 (146,373) $ $ 255,172 $ 75,970 (29,444) $ $ 235,273 $ 39,171 $ 1,448,649 $ 140,037 $ 990,234 — $ — $ $ 151,530 2015 300,635 378,327 (170,699) (260,443) 117,884 (311,277) (571,720) (20.80) (24.94) (45.75) (20.80) (24.94) (45.75) 2.70 12,232 12,232 144,907 15,805 (166,443) 157,815 144,210 (8,339) 240,553 40,244 1,674,865 80,745 1,130,696 — — 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. (3) On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments and recognized assets and liabilities on its Consolidated Balance Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. 40 Table of Contents Non-GAAP Financial Measures Distributable Cash Flow Distributable cash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings, proceeds from asset sales and disposals, including sales of discontinued operations, and return of long-term contract 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 asses 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 or redeem preferred units. 41 Table of Contents The following table reconciles net cash provided by operating activities of continuing operations (the most comparable GAAP financial measure) to DCF, FCF and cash flow cushion for the years ended December 31, 2019, 2018, 2017, 2016, and 2015: Distributable cash flow $ 144,933 $ 383,980 $ 121,958 $ 255,172 $ (In thousands) Net cash provided by operating activities of continuing operations Add: distributions from unconsolidated investment in excess of cumulative earnings Add: proceeds from asset sales and disposals Add: proceeds from sale of discontinued operations Add: return of long-term contract receivables Less: maintenance capital expenditures Less: distributions to non- controlling interest Less: proceeds from asset sales and disposals Less: proceeds from sale of discontinued operations Less: expansion capital expenditures Less: acquisition costs classified as financing activities Less: cash flow from one-time Hillsboro litigation settlement Less: mandatory Opco debt repayments Less: preferred unit distributions and redemption of PIK units Less: common unit distributions 2019 2018 2017 2016 2015 For the Year Ended December 31, $ 137,319 $ 178,282 $ 112,151 $ 80,243 $ 144,907 — 6,500 2,097 2,449 5,646 1,151 — — 62,117 13,605 (629) 198,091 — 109,872 1,743 3,061 3,010 2,968 — — — — — — (28) — — 2,463 (416) (2,744) 157,815 (6,500) (2,449) (1,151) (62,117) (13,605) 629 (198,091) (22) — — — — — 517 (109,872) — (7,213) 75,970 — — — $ 144,210 — (25,000) — — — (68,128) (80,765) (80,765) (82,949) (80,791) (30,000) (33,150) (39,109) (22,486) 16,080 $ (8,844) (22,467) 9,248 $ — (22,465) (29,444) $ — (71,758) (8,339) Free cash flow $ 139,040 $ 183,440 $ 121,324 $ Cash flow cushion $ 7,762 $ 42 Table of Contents 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 swap; plus total distributions from 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 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, and 2015: (In thousands) Net income (loss) from continuing operations Less: equity earnings from unconsolidated investment Less: net income attributable to non-controlling interest Less: gain on reserve swap Add: total distributions from unconsolidated investment Add: interest expense, net Add: debt modification expense Add: loss on extinguishment of debt Add: depreciation, depletion and amortization Add: asset impairments Adjusted EBITDA 2019 2018 2017 2016 2015 For the Year Ended December 31, $ (25,414) $ 122,360 $ 82,485 $ 90,626 $ (260,443) (47,089) (48,306) (40,457) (40,061) (49,918) — — 31,850 47,453 — 29,282 14,932 148,214 (510) — 46,550 70,178 — — 21,689 18,280 — — 49,000 82,028 7,939 4,107 23,414 2,967 — — 46,550 90,531 — — 31,766 15,861 $ 199,228 $ 230,241 $ 211,483 $ 235,273 $ — (9,290) 46,795 89,744 — — 45,338 378,327 240,553 43 Table of Contents 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. 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 2025 (the "2025 Senior Notes"). 44 Table of Contents 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 production business. Our common units trade on the New York Stock Exchange under the symbol "NRP." Our business is organized into two operating segments: Coal Royalty and Other—consists primarily of coal royalty properties and coal-related transportation and processing assets. Other assets include 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 Northern Powder River Basin in the United States. Our industrial minerals and aggregates properties are located in various states across the United States, our oil and gas royalty assets are primarily located in 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 and soda ash production 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. 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. We 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 key objectives. Our financial results by segment for the year ended December 31, 2019 are as follows: Operating Segments (In thousands) Revenues and other income Net income (loss) from continuing operations Asset impairments Net income (loss) from continuing operations excluding asset impairments Adjusted EBITDA (1) Cash flow provided by (used in) continuing operations Operating activities Investing activities Financing activities Distributable cash flow (1) Free cash flow (1) Cash flow cushion (1) Coal Royalty and Other $ 216,846 $ 21,211 148,214 $ 169,425 $ 184,357 $ 178,863 8,221 $ $ — $ $ 187,106 $ 180,584 $ $ N/A $ $ $ $ $ $ Soda Ash Corporate and Financing Total 47,089 46,840 — — $ 263,935 $ $ (93,465) $ (25,414) 148,214 — 46,840 31,601 $ (93,465) $ 122,800 $ (16,730) $ 199,228 31,601 $ (73,145) $ 137,319 — $ 8,221 — $ — $ (253,305) $ (253,305) $ (73,145) $ 144,933 $ (73,145) $ 139,040 7,762 N/A $ 31,601 31,601 N/A (1) See "Item 6. Selected Financial Data" for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures. 45 Table of Contents Current Results/Market Commentary Coal Royalty and Other Business Segment Our lessees sold 23.7 million tons of coal from our properties in 2019 and we derived approximately 65% of our coal royalty revenues and approximately 50% of our coal royalty sales volumes from metallurgical coal during the 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 market for thermal coal remains challenged by low natural gas prices, pressure over emissions and climate change and increasing use of renewable energy. In addition, the export market for thermal coal has weakened due to 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 U.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 domestic and global coal markets generally. The current price environment along with limited access to capital has taken a toll on a number of producers. Four of our lessees filed for protection under the U.S. Bankruptcy Code in 2019, and other lessees continue to face challenges. Foresight Energy LP ("Foresight Energy"), which is our largest lessee, has agreed to a forbearance period with its lenders and is engaging with other contract counterparties to evaluate restructuring options. To the extent Foresight Energy 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 extent we agree to amend the terms of our leases with 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 balance sheet. Soda Ash Business Segment Ciner Wyoming's results are primarily affected by the global supply of and demand for soda ash, which in turn directly impacts the prices Ciner Wyoming and other producers charge for its products. Demand for soda ash in the United States is driven in a large part by economic growth and activity levels in the end markets that the glass-making industry serve, such as the automotive and construction industries. Because the United States is a well-developed market for soda ash, we expect that domestic supply of and demand for soda ash will remain stable for the near future. Soda ash demand in international markets has continued to grow in conjunction with GDP. We expect that future global economic growth will positively influence global demand and pricing over the long term, which will likely result in increased exports, primarily from the United States, Turkey and to 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 planned exit from ANSAC at the end of 2021. While the performance 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 partners. As a result, we expect for the cash 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 distributions from Ciner Wyoming’s operations following completion of 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. 46 Table of Contents Results of Operations Year Ended December 31, 2019 and 2018 Compared Revenues and Other Income The following table includes our revenues and other income by operating segment: Operating Segment (In thousands) Coal Royalty and Other Soda Ash Total For the Year Ended December 31, 2019 2018 Increase (Decrease) Percentage Change $ $ 216,846 47,089 263,935 $ $ 230,206 48,306 278,512 $ $ (13,360) (1,217) (14,577) (6)% (3)% (5)% The changes in revenues and other income is discussed for each of the operating segments below: 47 Table of Contents Coal Royalty and Other The 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 income: For the Year Ended December 31, 2019 2018 Increase (Decrease) Percentage Change (In thousands, except per ton data) Coal sales volumes (tons) Appalachia Northern Central Southern Total Appalachia Illinois Basin Northern Powder River Basin Total coal sales volumes Coal royalty revenue per ton Appalachia Northern Central Southern Illinois Basin Northern Powder River Basin Combined average coal royalty revenue per ton Coal royalty revenues Appalachia Northern Central Southern Total Appalachia Illinois Basin Northern Powder River Basin Unadjusted coal royalty revenues Coal royalty adjustment for minimum leases Total coal royalty revenues Other revenues Production lease minimum revenues Minimum lease straight-line revenues Property tax revenues Wheelage revenues Coal overriding royalty revenues Lease amendment revenues Aggregates royalty revenues Oil and gas royalty revenues Other revenues Total other revenues Coal royalty and other Transportation and processing services revenues Gain on litigation settlement Gain on asset sales and disposals Total Coal Royalty and Other segment revenues and other income $ 48 3,460 13,377 1,670 18,507 2,201 3,036 23,744 1.96 5.53 6.69 4.66 2.90 4.67 6,775 73,960 11,169 91,904 10,255 8,809 110,968 (1,356) 109,612 24,068 14,910 6,287 5,880 13,496 7,991 4,265 3,031 1,529 81,457 191,069 19,279 — 6,498 216,846 $ $ $ $ $ $ $ 3,187 14,997 1,710 19,894 2,739 4,313 26,946 2.74 5.62 7.20 4.63 2.65 4.80 8,719 84,302 12,312 105,333 12,673 11,445 129,451 (110) 129,341 8,207 2,362 5,422 6,484 13,878 — 4,739 6,608 1,837 49,537 178,878 23,887 25,000 2,441 230,206 $ $ $ $ $ $ $ 273 (1,620) (40) (1,387) (538) (1,277) (3,202) (0.78) (0.09) (0.51) 0.03 0.25 (0.13) (1,944) (10,342) (1,143) (13,429) (2,418) (2,636) (18,483) (1,246) (19,729) 15,861 12,548 865 (604) (382) 7,991 (474) (3,577) (308) 31,920 12,191 (4,608) (25,000) 4,057 (13,360) 9 % (11)% (2)% (7)% (20)% (30)% (12)% (28)% (2)% (7)% 1 % 9 % (3)% (22)% (12)% (9)% (13)% (19)% (23)% (14)% (1,133)% (15)% 193 % 531 % 16 % (9)% (3)% 100 % (10)% (54)% (17)% 64 % 7 % (19)% (100)% 166 % (6)% $ $ $ $ $ $ Table of Contents 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 Hillsboro 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 Processing Services Revenues Transportation and processing services revenues decreased $4.6 million primarily 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, 2018 related to a one-time payment of $25.0 million we received from Foresight Energy to settle the Hillsboro lawsuit. Gain on Asset Sales and Disposals Gain on asset sales and disposals increased $4.1 million from 2018 to 2019 primarily due to a disposal of certain mineral right assets during the third quarter of 2019. Soda Ash Revenues and other income related to our Soda Ash segment decreased $1.2 million primarily due to Ciner Wyoming's settlement of a royalty dispute in the second quarter of 2018 that resulted in $12.7 million of 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, 2019 compared to the prior year. 49 Table of Contents Operating and Other Expenses The following table presents the significant categories of our consolidated operating and other expenses: (In thousands) Operating expenses Operating and maintenance expenses Depreciation, depletion and amortization General and administrative expenses Asset impairments Total operating expenses Other expenses, net Interest expense, net Loss on extinguishment of debt Total other expenses, net For the Year Ended December 31, 2019 2018 Increase (Decrease) Percentage Change $ $ 32,738 14,932 16,730 148,214 $ 29,509 21,689 16,496 18,280 3,229 (6,757) 234 129,934 $ 212,614 $ 85,974 $ 126,640 $ $ 47,453 29,282 76,735 $ $ 70,178 — 70,178 $ $ (22,725) 29,282 6,557 11 % (31)% 1 % 711 % 147 % (32)% 100 % 9 % Total operating expenses increased by $126.6 million primarily due to the following: • Asset impairments increased $129.9 million from 2018 to 2019. Asset impairments in the year ended December 31, 2019 primarily resulted from 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 mineral rights and intangible assets. Asset impairments in the year ended December 31, 2018 primarily related to a $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, 2018 in addition to $4.7 million of income generated by this business in 2018 prior to the sale. 50 Table of Contents Adjusted EBITDA (Non-GAAP Financial Measure) The following table reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment: For the Year Ended (In thousands) December 31, 2019 Operating Segments Coal Royalty and Other Soda Ash Corporate and Financing Total Net income (loss) from continuing operations $ 21,211 $ Less: equity earnings from unconsolidated investment Add: total distributions from unconsolidated investment Add: interest expense, net Add: loss on extinguishment of debt Add: depreciation, depletion and amortization Add: asset impairments — — — — 14,932 148,214 $ 46,840 (47,089) 31,850 — — — — Adjusted EBITDA December 31, 2018 $ 184,357 $ 31,601 $ (93,465) $ — — 47,453 29,282 — — (16,730) $ Net income (loss) from continuing operations $ 160,728 $ Less: equity earnings from unconsolidated investment Less: net income attributable to non-controlling interest Add: total distributions from unconsolidated investment Add: interest expense, net Add: depreciation, depletion and amortization Add: asset impairments Adjusted EBITDA — (510) — — 21,689 18,280 48,306 (48,306) — 46,550 — — — $ (86,674) $ — — — 70,178 — — (16,496) $ $ 200,187 $ 46,550 $ (25,414) (47,089) 31,850 47,453 29,282 14,932 148,214 199,228 122,360 (48,306) (510) 46,550 70,178 21,689 18,280 230,241 Adjusted EBITDA decreased $31.0 million primarily due to the following: • Coal Royalty and Other 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. See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of Adjusted EBITDA. 51 Table of Contents Distributable Cash Flow ("DCF"), Free Cash Flow ("FCF") and Cash Flow Cushion (Non-GAAP Financial Measures) The following table presents the three major categories of the statement of cash flows by business segment: For the Year Ended (In thousands) December 31, 2019 Cash flow provided by (used in) continuing operations Operating Segments Coal Royalty and Other Soda Ash Corporate and Financing Total Operating activities Investing activities Financing activities $ 178,863 $ 31,601 $ 8,221 — — — (73,145) $ — (253,305) 137,319 8,221 (253,305) December 31, 2018 Cash flow provided by (used in) continuing operations Operating activities Investing activities Financing activities $ $ 212,394 5,510 — $ 44,453 2,097 — (78,565) $ — (6,839) 178,282 7,607 (6,839) The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCF, FCF and cash flow cushion: For the Year Ended (In thousands) December 31, 2019 Net cash provided by (used in) operating activities of continuing operations Add: proceeds from asset sales and disposals Add: proceeds from sale of discontinued operations Add: return of long-term contract receivable Distributable cash flow Less: proceeds from asset sales and disposals Less: proceeds from sale of discontinued operations Less: expansion capital expenditures Free cash flow Less: mandatory Opco debt repayments Less: preferred unit distributions Less: common unit distributions Cash flow cushion Operating Segments Coal Royalty and Other Soda Ash Corporate and Financing Total $ 178,863 $ 31,601 $ 6,500 — 1,743 187,106 (6,500) — (22) 180,584 $ $ — — — $ 31,601 $ — — — $ 31,601 $ (73,145) $ — — — (73,145) $ — — — (73,145) $ $ 137,319 6,500 (629) 1,743 144,933 (6,500) 629 (22) 139,040 (68,128) (30,000) (33,150) 7,762 52 Table of Contents For the Year Ended (In thousands) December 31, 2018 Net cash provided by (used in) operating activities of continuing operations Add: distributions from unconsolidated investment in excess of cumulative earnings Add: proceeds from asset sales and disposals Add: proceeds from sale of discontinued operations Add: return of long-term contract receivable Distributable cash flow Less: proceeds from asset sales and disposals Less: proceeds from sale of discontinued operations Free cash flow Less: cash flow from one-time Hillsboro litigation settlement Less: mandatory Opco debt repayments Less: preferred unit distributions and redemption of PIK units Less: common unit distributions Cash flow cushion Operating Segments Coal Royalty and Other Soda Ash Corporate and Financing Total $ 212,394 $ 44,453 $ (78,565) $ 178,282 — 2,449 — 3,061 2,097 — — — $ 217,904 $ 46,550 $ (2,449) — — — $ 215,455 $ 46,550 $ — — — — (78,565) $ 2,097 2,449 198,091 3,061 383,980 — (2,449) — (78,565) $ (198,091) 183,440 (25,000) (80,765) (39,109) (22,486) 16,080 $ DCF and FCF decreased $239.0 million and $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, 2018 was also impacted by the $198.1 million proceeds from the sale of our construction aggregates business in 2018. Cash flow cushion decreased $8.3 million as a result of the decrease in FCF 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 flow cushion were partially offset by a $12.6 million decrease in mandatory Opco debt repayments as a result of the lower principal balances on the Opco Senior Notes and a $9.1 million decrease in preferred unit distributions primarily as a result of the $8.8 million redemption of PIK units in 2018. See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of distributable cash flow, free cash flow and cash flow cushion. 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." 53 Table of Contents Liquidity and Capital Resources Current Liquidity As of December 31, 2019, we had total liquidity of $198.3 million, consisting of $98.3 million of cash and cash equivalents and $100.0 million in borrowing capacity under our Opco Credit Facility. Cash Flows Year Ended December 31, 2019 and 2018 Compared Cash flows provided by operating activities decreased $51.6 million, from $188.9 million in the year ended December 31, 2018 to $137.3 million in the year ended December 31, 2019 primarily related to a one-time $25 million payment we received from Foresight Energy in 2018 to settle the Hillsboro lawsuit, $12.6 million of lower cash distributions received from Ciner Wyoming in 2019, $10.6 million lower cash provided as a result of the sale of our construction aggregates business in the fourth quarter of 2018 and lower coal royalty revenues driven by weakened coal markets and the temporary idling of certain mines. These decreases in cash provided 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 debt balances in 2019. Cash flows provided by investing activities decreased $183.0 million, from $190.6 million in the year ended December 31, 2018 to $7.6 million in the year ended December 31, 2019. Cash flows from discontinued operations decreased $183.7 million as a result of the $198.1 million proceeds received from the sale of our construction aggregates business in December 2018, partially offset by $10.9 million of construction aggregates capital expenditures during 2018. Cash flows from continuing operations was relatively flat year-over-year as the $4.1 million increase in proceeds from asset sales and disposals was partially offset by 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 flows used in financing activities increased $49.3 million, from $203.3 million in the year ended December 31, 2018 to $252.7 million in the year ended December 31, 2019. 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 the net proceeds from this offering, together with $76 million of cash on hand to redeem all of our 2022 Senior Notes. As a result of these transactions, our outstanding debt was reduced, our annual interest expense has decreased, and our debt maturities were extended. Significant increases in cash flow used in financing activities included the following: • • • • • $345.6 million used for the redemption of our 2022 Senior Notes in the second quarter of 2019; $36.7 million increase in payments on the Opco Senior Notes primarily as a result of the prepayment made using proceeds from the sale of our construction aggregates business; $35.0 million less borrowings on our Opco Credit Facility in 2019 compared to the 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 2025 Senior Notes in 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. For discussion of our Cash Flows 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." 54 Table of Contents Capital Resources and Obligations Debt, Net We had the following debt outstanding as of December 31, 2019 and 2018: (In thousands) Current portion of long-term debt, net Long-term debt, net Total debt, net December 31, 2019 2018 $ $ 45,776 470,422 516,198 $ $ 115,184 557,574 672,758 We have been and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information regarding our debt and the agreements governing our debt, including the covenants contained therein, see "Item 8. Financial Statements and Supplementary Data—Note 12. Debt, Net" in this Annual Report on Form 10-K. Long-Term Contractual Obligations The following table reflects our long-term, non-cancelable contractual obligations as of December 31, 2019: Contractual Obligations (In thousands) NRP: Long-term debt principal payments (1) Long-term debt interest payments (1) Opco: Long-term debt principal payments (including current maturities) (2) Long-term debt interest payments (3) Rental leases (4) Total Total 2020 2021 2022 2023 2024 Thereafter Payments Due by Period $ 300,000 $ — $ — $ — $ — $ — $ 300,000 150,563 27,375 27,375 27,375 27,375 27,375 13,688 224,056 39,865 14,012 46,176 12,447 483 39,396 39,396 39,396 31,028 9,868 483 7,631 483 5,020 483 2,724 483 28,664 2,175 11,597 $ 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 2025 Senior Notes. (2) The amounts indicated in the table include principal due on Opco’s senior notes. (3) The amounts indicated in the table include interest due on Opco’s senior notes and 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) On January 1, 2019, Opco entered into a lease agreement for the rental 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 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. 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. 55 Table of Contents 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, 2019, 2018 and 2017. Environmental Regulation For additional information on environmental regulation that may have a material impact on our business, see "Items 1. and 2. Business and Properties—Regulation and Environmental Matters." Related Party Transactions The information required by this Item is included under "Item 8. Financial Statements and Supplementary Data—Note 14. Related Party Transactions" and "Item 13. Certain Relationships and Related Transactions, and Director Independence" in this Annual Report on Form 10-K and is incorporated by reference herein. 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, liabilities, revenues and expenses. See "Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies" in the audited Consolidated 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 Segment Revenues Royalty-based leases. Approximately two-thirds of the 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. For these types of 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 mined and sold. Most of our coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts, either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods 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 was 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 result of this evaluation, revenue recognition 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 from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment 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 consideration amount as minimum lease straight-line revenues. 56 Table of Contents This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease. Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenues 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 of Ciner Wyoming. We account for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. Our 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 attributed to net tangible assets and is amortized over its estimated useful life. The carrying value in Ciner Wyoming is recognized in equity in unconsolidated investment on our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming and amortization of the basis difference is recognized in equity in earnings of Ciner Wyoming on the Consolidated Statements of Comprehensive Income (Loss). We decrease our investment 57 Table of Contents 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 aggregates 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 evaluate our long-lived assets for possible impairment 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 not limited to, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an 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 asset'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 asset's net book value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants. 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 For a discussion of recent accounting pronouncements, see the applicable section of "Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies" in the audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. 58 Table of Contents 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 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. 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 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, 2019 we did not have any borrowings outstanding under 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. 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. We use available market data and valuation methodologies to estimate the fair value of our debt and contract receivable. The following table shows the carrying amount and estimated fair value of our debt and contract receivable: (In thousands) Debt: NRP 2025 Senior Notes NRP 2022 Senior Notes Opco Senior Notes Opco Credit Facility Assets: Contract receivable (current and long-term) December 31, 2019 2018 Fair Value Hierarchy Level Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value $ $ 294,084 — 222,114 — 269,250 — 201,090 — $ — $ 334,024 338,734 — — 356,871 352,599 — $ 38,945 $ 33,460 $ 40,776 $ 34,704 1 1 3 3 3 59 Table of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Ernst & Young LLP, Independent Registered Public Accounting Firm Report of Deloitte & Touche, LLP, Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2019 and 2018 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2019, 2018 and 2017 Consolidated Statements of Partners’ Capital for the years ended December 31, 2019, 2018 and 2017 Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017 Notes to Consolidated Financial Statements Page 61 62 63 64 65 66 68 60 Table of Contents Report 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, 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 (collectively referred to as the “consolidated financial statements”). In our opinion, based on our 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 company in which the Partnership has a 49% interest. In the consolidated financial statements, the Partnership’s investment in Ciner Wyoming is stated at $263 million and $247 million as of December 31, 2019 and 2018, respectively, and the Partnership’s equity in the net income of Ciner Wyoming is stated at $47 million in 2019, $48 million in 2018 and $40 million in 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, 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 PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion. /s/ Ernst & Young LLP We have served as the Partnership’s auditor since 2002. Houston, Texas February 27, 2020 61 Table of Contents 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”) as of December 31, 2019 and 2018, 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, 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 the 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 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, 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. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ Deloitte & Touche LLP Atlanta, Georgia February 27, 2020 We have served as the Company’s auditor since 2008. 62 NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED BALANCE SHEETS (In thousands, except unit data) Current assets ASSETS Cash and cash equivalents Restricted cash Accounts receivable, net Prepaid expenses and other, net Current assets of discontinued operations Total current assets Land Mineral rights, net Intangible assets, net Equity in unconsolidated investment Long-term contract receivable Other assets, net Total assets LIABILITIES AND CAPITAL Current liabilities Accounts payable Accrued liabilities Accrued interest Current portion of deferred revenue Current portion of long-term debt, net Current liabilities of discontinued operations Total current liabilities Deferred revenue Long-term debt, net Other non-current liabilities Total liabilities 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) Partners’ capital Common unitholders’ interest (12,261,199 and 12,249,469 units issued and outstanding at December 31, 2019 and 2018, respectively) General partner’s interest Warrant holders’ interest Accumulated other comprehensive loss Total partners’ capital Non-controlling interest Total capital Total liabilities and capital December 31, 2019 2018 98,265 — 30,869 1,244 1,706 132,084 24,008 605,096 17,687 263,080 36,963 6,989 1,085,907 1,179 8,764 2,316 4,608 45,776 65 62,708 47,213 470,422 4,949 585,292 $ $ $ $ $ $ 101,839 104,191 32,058 3,462 993 242,543 24,008 743,112 42,513 247,051 38,945 3,475 1,341,647 2,414 12,347 14,345 3,509 115,184 947 148,746 49,044 557,574 1,150 756,514 164,587 $ 164,587 271,471 3,270 66,816 (2,594) 338,963 (2,935) 336,028 1,085,907 $ $ $ $ 355,113 5,014 66,816 (3,462) 423,481 (2,935) 420,546 1,341,647 $ $ $ $ $ $ $ $ $ $ $ The accompanying notes are an integral part of these consolidated financial statements. 63 NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands, except per unit data) Revenues and other income Coal royalty and other Transportation and processing services Equity in earnings of Ciner Wyoming Gain on litigation settlement Gain on asset sales and disposals Total revenues and other income Operating expenses Operating and maintenance expenses Depreciation, depletion and amortization General and administrative expenses Asset impairments Total operating expenses Income from operations Other expenses, net Interest expense, net Debt modification expense Loss on extinguishment of debt Total other expenses, net Net income (loss) from continuing operations Income from discontinued operations (see Note 4) Net income (loss) Net income attributable to non-controlling interest Net income (loss) attributable to NRP Less: income attributable to preferred unitholders Net income (loss) attributable to common unitholders and general partner Net income (loss) attributable to common unitholders Net income (loss) attributable to the general partner Income (loss) from continuing operations per common unit (see Note 7) Basic Diluted Net income (loss) per common unit (see Note 7) Basic Diluted Net income (loss) Comprehensive income (loss) from unconsolidated investment and other Comprehensive income (loss) Comprehensive income attributable to non-controlling interest Comprehensive income (loss) attributable to NRP $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ For the Years Ended December 31, 2019 2018 2017 191,069 19,279 47,089 — 6,498 263,935 32,738 14,932 16,730 148,214 212,614 51,321 $ $ $ $ $ (47,453) $ — (29,282) (76,735) $ (25,414) $ 956 (24,458) $ — (24,458) $ (30,000) 178,878 23,887 48,306 25,000 2,441 278,512 29,509 21,689 16,496 18,280 85,974 192,538 $ $ $ $ $ (70,178) $ — — (70,178) $ 122,360 17,687 140,047 (510) 139,537 (30,000) $ $ $ $ $ $ $ 181,801 20,522 40,457 — 3,545 246,325 24,883 23,414 18,502 2,967 69,766 176,559 (82,028) (7,939) (4,107) (94,074) 82,485 6,182 88,667 — 88,667 (25,453) 63,214 61,950 1,264 4.57 3.68 5.06 3.96 (54,458) $ 109,537 (53,369) $ (1,089) 107,346 2,191 (4.43) $ (4.43) (4.35) $ (4.35) 7.35 5.90 8.77 6.76 (24,458) $ 140,047 $ 88,667 868 (23,590) $ — (23,590) $ (149) 139,898 (510) 139,388 $ $ (1,647) 87,020 — 87,020 The accompanying notes are an integral part of these consolidated financial statements. 64 NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (In thousands) Balance at December 31, 2016 Net income (1) Distributions to common unitholders and general partner Distributions to preferred unitholders Issuance of warrants Comprehensive loss from unconsolidated investment and other Common Unitholders Units Amounts General Partner Warrant Holders Accumulated Other Comprehensive Loss Partners' Capital Excluding Non- Controlling Interest Non- Controlling Interest Total Capital 12,232 — $152,309 86,894 $ 887 1,773 $ — $ — (1,666) $ 151,530 88,667 — $ (3,394) $ 148,136 88,667 — — (22,018) (449) — (17,334) (354) — — — 66,816 — — — — — — — (22,467) — (22,467) (17,688) 66,816 — (17,688) — 66,816 — — (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 Net income (2) Distributions to common unitholders and general partner Distributions to preferred unitholders Issuance of unit-based awards Unit-based awards amortization and vesting Comprehensive income (loss) from unconsolidated investment and other — 69,057 — 136,746 1,409 2,791 — (22,036) (450) — (29,660) (605) 17 — — 546 560 49 — — 12 — — — — — — — — — — — — — 70,466 139,537 — 510 70,466 140,047 (22,486) — (22,486) (30,265) — (30,265) 546 560 — — 546 560 (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) Distributions to common unitholders and general partner Distributions to preferred unitholders Issuance of unit-based awards Unit-based awards amortization and vesting Comprehensive income (loss) from unconsolidated investment and other — (23,969) (489) — (32,487) (663) — (29,400) 486 12 — — 1,804 (76) (600) — — 8 — — — — — — — — — — — (30,000) 486 1,804 868 800 (24,458) — (24,458) (33,150) — (33,150) — (30,000) — — — 486 1,804 800 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. 65 NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31, 2019 2018 2017 $ (24,458) $ 140,047 $ 88,667 14,932 31,850 (47,089) (6,498) — 29,282 (956) 148,214 7,462 2,361 3,687 (6,035) (1,234) (3,656) (12,029) (732) 2,218 137,319 (8) 137,311 $ $ — $ 6,500 1,743 (22) 21,689 44,453 (48,306) (2,441) — — (17,687) 18,280 (62) 1,434 7,133 (6,062) 1,138 19 (1,138) 19,465 320 178,282 10,641 188,923 2,097 2,449 3,061 — $ $ $ 8,221 $ 7,607 $ (629) 7,592 $ 183,021 190,628 $ 23,414 43,354 (40,457) (3,545) 7,939 4,107 (6,182) 2,967 2,353 18 10,284 3,919 (184) (7,963) (105) (15,957) (478) 112,151 14,988 127,139 5,646 1,151 3,010 — 9,807 (6,264) 3,543 (In thousands) Cash flows from operating activities Net income (loss) Adjustments to reconcile net income (loss) to net cash provided by operating activities of continuing operations: Depreciation, depletion and amortization Distributions from unconsolidated investment Equity earnings from unconsolidated investment Gain on asset sales and disposals Debt modification expense Loss on extinguishment of debt Income from discontinued operations Asset impairments Bad debt expense Unit-based compensation expense Amortization of debt issuance costs and other Change in operating assets and liabilities: Accounts receivable Accounts payable Accrued liabilities Accrued interest Deferred revenue Other items, net Net cash provided by operating activities of continuing operations Net cash provided by (used in) operating activities of discontinued operations Net cash provided by operating activities Cash flows from investing activities Distributions from unconsolidated investment in excess of cumulative earnings Proceeds from asset sales and disposals Return of long-term contract receivables Acquisition of mineral rights Net cash provided by investing activities of continuing operations Net cash provided by (used in) investing activities of discontinued operations Net cash provided by investing activities $ $ $ $ $ 66 NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Cash flows from financing activities Proceeds from issuance of preferred units and warrants, net Debt borrowings Debt repayments Redemption of preferred units paid-in-kind Distributions to common unitholders and general partner Distributions to preferred unitholders Contributions from (to) discontinued operations Debt issuance costs and other Net cash used in financing activities of continuing operations Net cash provided by (used in) financing activities of discontinued operations Net cash used in financing activities Net increase (decrease) in cash, cash equivalents and restricted cash Cash, cash equivalents and restricted cash of continuing operations at beginning of period Cash and cash equivalents of discontinued operations at beginning of period Cash, cash equivalents and restricted cash at beginning of period Cash, cash equivalents and restricted cash at end of period Less: cash and cash equivalents of discontinued operations at end of period Cash, cash equivalents and restricted cash of continuing operations at end of period Supplemental cash flow information: Cash paid during the period for interest of continuing operations Non-cash investing and financing activities: Issuance of 2022 Senior Notes in exchange for 2018 Senior Notes $ $ $ $ $ $ $ $ $ $ Years Ended December 31, 2019 2018 2017 — $ — $ 300,000 (463,082) — (33,150) (30,000) (637) (26,436) 35,000 (175,706) (8,844) (22,486) (30,265) 195,690 (228) (253,305) $ (6,839) $ 637 (252,668) $ (107,765) $ (196,509) (203,348) $ 176,203 $ $ $ $ 206,030 — 206,030 98,265 — $ $ $ 26,980 2,847 29,827 206,030 — 242,100 180,688 (492,319) — (22,467) (8,844) 5,784 (39,091) (134,149) (7,077) (141,226) (10,544) 39,171 1,200 40,371 29,827 (2,847) 98,265 $ 206,030 $ 26,980 58,597 $ 64,991 $ 72,850 — $ — $ 240,638 The accompanying notes are an integral part of these consolidated financial statements. 67 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, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal 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 two operating segments further described in Note 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. Subject 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 appoint the directors of the Board of Directors of GP Natural Resource Partners LLC (the "Board of Directors"). RCM has delegated the right to appoint one director to 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 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 and is accounted for using the equity method. Intercompany transactions and balances have been eliminated. Certain reclassifications have been made to prior year amounts on the Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Cash Flows to conform with current year presentation. These reclassifications had no impact on previously reported total assets, total liabilities, partners' capital, net income (loss) or cash flows from operating, investing or financing activities. Use of Estimates Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities on 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 on the accompanying Consolidated Statements of Comprehensive Income (Loss) during the reporting period. Actual results could differ from those estimates. The most significant estimates pertain to coal 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 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 13. Fair Value Measurements for further details. 68 Table of Contents 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. • 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 assets 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, 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 The Partnership records an allowance for doubtful accounts for its accounts receivables and notes receivables which it determines to be uncollectible based on the specific identification method. Receivables are written off when collection efforts are exhausted 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 Consolidated Balance Sheets, respectively. The allowance for doubtful accounts related to accounts receivables was $0.4 million at December 31, 2019. The allowance for doubtful accounts related to notes receivables was $1.2 million at December 31, 2019 and 2018. The Partnership recorded bad debt expense of $7.5 million, $(0.1) million and $2.4 million included in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2019, 2018 and 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 aggregates 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 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 value 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 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 evaluate its long-lived assets for possible impairment 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 not 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 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 asset'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 flows compared to the asset's net book value. The Partnership believes its estimates of cash flows and discount rates are consistent with those of principal market participants. 69 Table of Contents 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 (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 Segment Revenues Royalty-based leases. Approximately two-thirds of the Partnership's 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. For these types of leases, the lessees generally make payments to NRP based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral mined and sold. Most of NRP’s coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts, either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods 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 was 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 providing 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 recognition 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 from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment 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 consideration amount as minimum lease straight-line revenues. This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease. Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenues 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. 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. 70 Table of Contents 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. The Partnership 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 of Ciner Wyoming The Partnership accounts for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. The Partnership'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 attributed to net tangible assets and is amortized over its estimated useful life. The carrying value in Ciner Wyoming is recognized in equity in unconsolidated investment on the Partnership's Consolidated Balance Sheets. The Partnership's adjusted share of the earnings or losses of Ciner Wyoming and amortization of the basis difference is recognized 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 operating cash inflows unless the cumulative distributions received exceed the Partnership's cumulative equity in earnings. The excess of cumulative distributions received over the Partnership's cumulative equity in earnings are considered returns of investment and classified as investing cash inflows. 71 Table of Contents Property Taxes NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 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 operating and maintenance expenses and in coal royalty and other revenues, respectively, on the Consolidated Statements of Comprehensive Income (Loss). Transportation Revenues and Expenses The Partnership records transportation and processing revenues and pays transportation and processing costs to an affiliate of Foresight Energy LP to operate equipment on behalf of the Partnership. The revenues and expenses related to these transactions are recorded as transportation and processing services revenues and operating and maintenance expenses, respectively, on the Consolidated Statements of Comprehensive Income (Loss). See Note 14. Related Party Transactions for more information. Unit-Based Compensation The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units. Compensation cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. 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 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 debt. These costs are amortized over the term of the respective line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's revolving credit facility are included in other assets, net on the Partnership's Consolidated Balance Sheets. Deferred financing costs related to the Partnership's note agreements are included as a direct deduction from the carrying amount of the debt liability in current portion of long-term debt, net or long-term debt, net on the Partnership's Consolidated Balance Sheets. Income Taxes The Partnership is not subject to federal or material state income taxes as the unitholders 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 basis and financial reporting basis of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the unitholders could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities. Recently Adopted Accounting Standards Leases On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments (the “new lease standard” and "ASC 842") and recognized assets and liabilities on its 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 required disclosures designed to give financial statement users information on the amount, timing and uncertainty of cash flows arising from leases. The guidance was adopted by NRP on January 1, 2019 using a modified retrospective approach. The Partnership is a lessee in one lease that is accounted for as an operating lease under the new lease standard, and the adoption of the new 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 ASC 842, the Partnership elected to not combine lease and non-lease components. See Note 19. Leases for more information. 72 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Recently Issued Accounting Standards Credit Losses In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326). The new standard changes 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 entities to estimate an expected lifetime credit loss on financial assets, including trade accounts receivable. The guidance is effective for annual and interim periods beginning after December 15, 2019 and is to be adopted using a modified retrospective approach. As a result of implementation of the new 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 standard to have a material effect on its Consolidated Financial Statements subsequent to adoption. 3. Revenues from Contracts with Customers The following table represents the Partnership's Coal Royalty and Other segment revenues by major source: (In thousands) Coal royalty revenues Production lease minimum revenues Minimum lease straight-line revenues Property tax revenues Wheelage revenues Coal overriding royalty revenues Lease amendment revenues Aggregates royalty revenues Oil and gas royalty revenues Other revenues Year Ended December 31, 2019 2018 $ 109,612 $ 129,341 24,068 14,910 6,287 5,880 13,496 7,991 4,265 3,031 1,529 8,207 2,362 5,422 6,484 13,878 — 4,739 6,608 1,837 178,878 23,887 202,765 Coal royalty and other revenues (1) Transportation and processing services revenues (2) Total Coal royalty and Other segment revenues $ $ 191,069 19,279 210,348 $ $ (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. 73 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED The following table details the Partnership's Coal Royalty and Other segment receivables and liabilities resulting from contracts with customers: (In thousands) Receivables Accounts receivable, net Prepaid expenses and other (1) Contract liabilities Current portion of deferred revenue Deferred revenue December 31, 2019 2018 $ $ 27,915 $ 90 4,608 $ 47,213 29,001 2,483 3,509 49,044 (1) Prepaid expenses and 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: (In thousands) Balance at end of prior period (current and non-current) Cumulative adjustment for change in accounting principle Balance at beginning of period (current and non-current) Increase due to minimums and lease amendment fees Recognition of previously deferred revenue Balance at end of period (current and non-current) Year Ended December 31, 2019 2018 52,553 — 52,553 47,038 (47,770) 51,821 $ $ $ 100,605 (65,591) 35,014 37,781 (20,242) 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) 0 - 5 years 5 - 10 years 10+ years Total Weighted Average Remaining Years as of December 31, 2019 Annual Minimum Payments (2) 2.3 6.2 11.9 9.1 $ $ 13,812 9,718 44,757 68,287 (1) Lease term does not include renewal periods. (2) Annual minimum payments do not include $5.0 million from a coal infrastructure lease that is accounted for as a financing transaction. See Note 18. Financing Transaction for additional 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 Partnership'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 flows of these businesses as discontinued operations on its Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Cash Flows for all periods presented. 74 Table of Contents 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: (In thousands) Current assets ASSETS Accounts receivable, net Total assets of discontinued operations LIABILITIES Current liabilities Accounts payable Accrued liabilities Total liabilities of discontinued operations December 31, 2019 2018 Construction Aggregates NRP Oil and Gas Total Construction Aggregates NRP Oil and Gas Total $ $ $ $ — $ 1,706 — $ 1,706 $ $ 1,706 1,706 $ 42 23 — $ — 42 23 $ $ $ $ $ $ 5 5 181 766 988 988 $ $ — $ — 65 $ — $ 65 $ 947 $ — $ 993 993 181 766 947 The following tables present summarized financial results of the Partnership's discontinued operations on the Consolidated Statements of Comprehensive Income (Loss): (In thousands) Revenues and other income Oil and gas Gain on asset sales and disposals Total revenues and other income Operating expenses Operating and maintenance expenses Total operating expenses Other income Income from discontinued operations For the Year Ended December 31, 2019 Construction Aggregates NRP Oil and Gas Total $ $ $ $ $ $ — $ 280 280 27 27 $ $ $ — $ 253 $ 2 — 2 16 16 717 703 $ $ $ $ $ $ 2 280 282 43 43 717 956 75 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED (In thousands) Revenues and other income Construction aggregates Road construction and asphalt paving services Oil and gas Gain on asset sales and disposals Total revenues and other income Operating expenses Operating and maintenance expenses Depreciation, depletion and amortization Asset impairments Total operating expenses Interest expense Income (loss) from discontinued operations (In thousands) Revenues and other income Construction aggregates Road construction and asphalt paving services Oil and gas Gain (loss) on asset sales and disposals Total revenues and other income Operating expenses Operating and maintenance expenses Depreciation, depletion and amortization Asset impairments Total operating expenses Interest expense Income (loss) from discontinued operations For the Year Ended December 31, 2018 Construction Aggregates NRP Oil and Gas Total 116,066 $ 18,400 — 13,414 147,880 $ — $ — (3) — (3) $ 117,568 $ 134 $ 12,218 232 — — 116,066 18,400 (3) 13,414 147,877 117,702 12,218 232 130,018 $ 134 $ 130,152 (38) $ $ 17,824 — $ (137) $ (38) 17,687 For the Year Ended December 31, 2017 Construction Aggregates NRP Oil and Gas Total 112,970 $ 18,411 — 311 131,692 $ — $ — 38 (289) (251) $ 111,633 $ 290 $ 12,579 64 124,276 $ (693) $ $ 6,723 — — 290 $ — $ (541) $ 112,970 18,411 38 22 131,441 111,923 12,579 64 124,566 (693) 6,182 $ $ $ $ $ $ $ $ $ $ $ $ Capital expenditures related to the Partnership's discontinued operations were $10.9 million and $7.6 million during the years ended December 31, 2018 and 2017, respectively, of which $0.9 million and $0.3 million were funded with accounts payable or accrued liabilities during 2018 and 2017, respectively. 76 Table of Contents 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. 77 Table of Contents 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) Transaction price, gross Structuring, origination and other fees to preferred purchasers Transaction costs to other third parties Transaction price, net Allocation of net transaction price Preferred units, net Warrant holders interest, net Transaction price, net March 2, 2017 250,000 (7,900) (10,697) 231,403 164,587 66,816 231,403 $ $ $ $ 78 Table of Contents 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) Balance at December 31, 2016 Issuance of preferred units, net Distribution paid-in-kind Balance at December 31, 2017 Redemption of PIK units Balance at December 31, 2018 and 2019 Units Outstanding Financial Position — $ 250,000 8,844 258,844 (8,844) 250,000 $ $ — 164,587 8,844 173,431 (8,844) 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 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. 79 Table of Contents 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: Date Paid Period Covered by Distribution 2019 February 2019 October 1 - December 31, 2018 $ May 2019 May 2019 (2) August 2019 January 1 - March 31, 2019 Special Distribution April 1 - June 30, 2019 November 2019 July 1 - September 30, 2019 2018 February 2018 May 2018 August 2018 October 1 - December 31, 2017 $ January 1 - March 31, 2018 April 1 - June 30, 2018 November 2018 July 1 - September 30, 2018 2017 February 2017 May 2017 August 2017 October 1 - December 31, 2016 $ January 1 - March 31, 2017 April 1 - June 30, 2017 November 2017 July 1 - September 30, 2017 Common Units Preferred Units Distribution per Unit Total Distribution (1) (In thousands) Distribution per Unit Total Distribution (In thousands) 0.45 0.45 0.85 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 $ 5,625 $ 30.00 $ 5,630 10,635 5,630 5,630 30.00 — 30.00 30.00 $ 5,617 $ 30.00 $ 5,623 5,623 5,623 30.00 30.00 30.00 $ 5,615 $ — $ 5,619 5,616 5,617 5.00 15.00 15.00 7,500 7,500 — 7,500 7,500 7,765 7,500 7,500 7,500 — 2,500 7,538 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. 80 Table of Contents 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: (In thousands, except per unit data) Allocation of net income (loss) Net income (loss) from continuing operations Less: net income attributable to non-controlling interest Less: income attributable to preferred unitholders Net income (loss) from continuing operations attributable to common unitholders and general partner Add (less): net loss (income) from continuing operations attributable to the general partner Net income (loss) from continuing operations attributable to common unitholders Net income from discontinued operations Less: net income from discontinued operations attributable to the general partner Net income from discontinued operations attributable to common unitholders Net income (loss) Less: net income attributable to non-controlling interest Less: income attributable to preferred unitholders Net income (loss) attributable to common unitholders and general partner Add (less): net loss (income) attributable to the general partner Net income (loss) attributable to common unitholders Basic income (loss) per common unit Weighted average common units—basic Basic net income (loss) from continuing operations per common unit Basic net income from discontinued operations per common unit Basic net income (loss) per common unit Year Ended December 31, 2019 2018 2017 $ (25,414) $ — (30,000) 122,360 (510) (30,000) $ 82,485 — (25,453) $ (55,414) $ 91,850 $ 57,032 1,108 (1,837) (1,141) $ $ $ $ $ $ $ $ $ (54,306) $ 90,013 956 $ 17,687 (19) (354) 937 $ 17,333 (24,458) $ — (30,000) (54,458) $ 1,089 (53,369) $ 140,047 (510) (30,000) 109,537 (2,191) 107,346 12,260 12,244 (4.43) $ 0.08 $ (4.35) $ 7.35 1.42 8.77 $ $ $ $ $ $ $ $ $ 55,891 6,182 (123) 6,059 88,667 — (25,453) 63,214 (1,264) 61,950 12,232 4.57 0.50 5.06 81 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED (In thousands, except per unit data) Diluted income (loss) per common unit Weighted average common units—basic Plus: dilutive effect of preferred units Plus: dilutive effect of warrants Plus: dilutive effect of unvested unit-based awards Weighted average common units—diluted Net income (loss) from continuing operations Less: net income attributable to non-controlling interest Less: net income attributable to preferred unitholders Diluted net income (loss) from continuing operations attributable to common unitholders and general partner Add (less): net loss (income) from continuing operations attributable to the general partner Diluted net income (loss) from continuing operations attributable to common unitholders Diluted net income from discontinued operations attributable to common unitholders Net income (loss) Less: net income attributable to non-controlling interest Less: net income attributable to preferred unitholders Diluted net income (loss) attributable to common unitholders and general partner Add (less): diluted net loss (income) attributable to the general partner Diluted net income (loss) attributable to common unitholders Diluted net income (loss) from continuing operations per common unit Diluted net income from discontinued operations per common unit Diluted net income (loss) per common unit Year Ended December 31, 2019 2018 2017 12,260 — — — 12,244 7,479 511 — 12,232 9,418 300 — 12,260 20,234 21,950 $ (25,414) $ — (30,000) 122,360 (510) — $ 82,485 — — $ (55,414) $ 121,850 $ 82,485 1,108 (2,437) (1,650) (54,306) $ 119,413 $ 80,835 937 $ 17,333 (24,458) $ — (30,000) 140,047 (510) — $ $ 6,059 88,667 — — (54,458) $ 139,537 $ 88,667 1,089 (53,369) $ (2,791) 136,746 (4.43) $ 0.08 $ (4.35) $ 5.90 0.86 6.76 (1,773) 86,894 3.68 0.28 3.96 $ $ $ $ $ $ $ $ $ $ $ $ 82 Table of Contents 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 customers in different geographies within the U.S. and that are managed accordingly. NRP has the following two operating segments: Coal Royalty and Other—consists primarily of coal royalty properties and coal-related transportation and processing assets. Other assets include 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 Northern Powder River Basin in the United States. The Partnership's industrial minerals and aggregates properties are located in various states across the United States. The Partnership's oil and gas royalty assets are primarily located in 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 to the glass and chemicals industries. Direct segment costs and certain other costs incurred at the corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments accordingly. These allocated costs generally include salaries and benefits, insurance, property taxes, legal, royalty, information technology and shared facilities services and are included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive 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, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment and are included in general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). 83 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED The following table summarizes certain financial information for each of the Partnership's business segments: (In thousands) For the Year Ended December 31, 2019 Revenues Gain on asset sales and disposals Operating and maintenance expenses Depreciation, depletion and amortization General and administrative expenses Asset impairments Other expenses, net Net income (loss) from continuing operations Income from discontinued operations As of December 31, 2019 Total assets of continuing operations Total assets of discontinued operations For the Year Ended December 31, 2018 Revenues Gain on litigation settlement Gain on asset sales and disposals Operating and maintenance expenses Depreciation, depletion and amortization General and administrative expenses Asset impairments Other expenses, net Net income (loss) from continuing operations Income from discontinued operations As of December 31, 2018 Total assets of continuing operations Total assets of discontinued operations For the Year Ended December 31, 2017 Revenues Gain on asset sales and disposals Operating and maintenance expenses Depreciation, depletion and amortization General and administrative expenses Asset impairments Other expenses, net Net income (loss) from continuing operations Income from discontinued operations Operating Segments Coal Royalty and Other Soda Ash Corporate and Financing Total $ $ 210,348 6,498 32,489 14,932 — 148,214 — 21,211 — 47,089 — 249 — — — — 46,840 — $ 817,768 — $ 263,080 — $ $ 202,765 25,000 2,441 29,509 21,689 — 18,280 — 160,728 — 48,306 — — — — — — — 48,306 — $ $ $ — $ 257,437 6,498 — 32,738 — 14,932 — 16,730 16,730 148,214 — 76,735 76,735 (25,414) (93,465) 956 — 3,353 — $1,084,201 1,706 — $ 251,071 25,000 — 2,441 — 29,509 — 21,689 — 16,496 16,496 18,280 — 70,178 70,178 (86,674) 122,360 17,687 — $ 986,680 — $ 247,051 — $ 106,923 — $1,340,654 993 $ $ 202,323 3,545 24,883 23,414 — 2,967 — 154,604 — 40,457 — — — — — — 40,457 — $ — $ 242,780 3,545 — 24,883 — 23,414 — 18,502 18,502 2,967 — 94,074 94,074 (112,576) 82,485 6,182 — 84 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 9. Equity Investment The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Activity related to this investment is as follows: (In thousands) Balance at beginning of period Income allocation to NRP’s equity interests (1) Amortization of basis difference Other comprehensive income (loss) Distribution Balance at end of period For the Year Ended December 31, 2019 2018 2017 $ 247,051 $ 245,433 $ 255,901 52,016 (4,927) 790 (31,850) 263,080 $ 53,095 (4,789) (138) (46,550) 247,051 $ 44,846 (4,389) (1,925) (49,000) 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 $135.8 million and $140.8 million as of December 31, 2019 and 2018, respectively. This excess basis relates to property, plant 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 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: (In thousands) Net sales Gross profit Net income The financial position of Ciner Wyoming is summarized as follows: (In thousands) Current assets Noncurrent assets Current liabilities Noncurrent liabilities For the Year Ended December 31, 2019 2018 2017 $ 522,843 $ 486,759 $ 131,712 106,155 104,053 108,357 497,340 114,202 91,523 December 31, 2019 2018 $ 170,696 $ 282,387 55,339 138,087 138,080 252,743 64,012 109,921 85 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 10. Mineral Rights, Net The Partnership’s mineral rights consist of the following: December 31, 2019 2018 (In thousands) Coal properties Aggregates properties Oil and gas royalty properties Other Carrying Value Accumulated Depletion Net Book Value Carrying Value Accumulated Depletion Net Book Value $ 981,352 41,486 12,395 13,156 $ (420,448) $ (13,357) (7,887) (1,601) 560,904 $ 1,164,845 28,129 4,508 11,555 24,920 12,395 13,158 $ (451,210) $ (11,814) (7,632) (1,550) 713,635 13,106 4,763 11,608 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 $12.1 million, $17.0 million and $20.1 million for the years ended December 31, 2019, 2018 and 2017, respectively. Sales of Mineral Rights During the year ended December 31, 2019, the Partnership recorded a gain of $6.5 million included in gain on asset sales and 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 During the years ended December 31, 2019, 2018 and 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) Coal properties (1) Aggregates and timber royalty properties (2) Total For the Year Ended December 31, 2019 2018 2017 $ $ 125,806 103 125,909 $ $ 5,259 13,021 18,280 $ $ 595 2,372 2,967 (1) The Partnership recorded $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, 2018 primarily as a result of lease terminations, of which it recorded $5.0 million of impairment expense to fully impair certain coal properties during the three months ended December 31, 2018. 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 86 Table of 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. (2) The Partnership recorded $0.1 million of aggregates royalty property impairments during the year ended December 31, 2019. During the three months ended December 31, 2018, the Partnership recorded $13.0 million of impairment expense related to an aggregates property that 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, 2017. 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 used 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 cash flows. 11. Intangible Assets, Net The Partnership's intangible assets consist of above-market coal royalty and related 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) Intangible assets at cost Less: accumulated amortization Total intangible assets, net December 31, 2019 2018 $ $ 53,878 (36,191) 17,687 $ $ 81,109 (38,596) 42,513 Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of Comprehensive Income (Loss) was $2.5 million, $4.3 million and $3.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. During the year ended December 31, 2019, the Partnership identified facts and circumstances that indicated that the carrying value of certain of its above-market contracts exceed future cash flows from those assets and recorded a non-cash impairment expense of $22.3 million to fully impair these assets. These impairments are included in asset impairments on the Partnership's Consolidated Statements of Comprehensive 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 years ended December 31, as indicated below, are based on current mining plans and are subject to revision as those plans change in future periods. (In thousands) 2020 2021 2022 2023 2024 87 $ Estimated Amortization Expense 508 913 738 765 1,006 Table of Contents 12. Debt, Net NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED The Partnership's debt consists of the following: (In thousands) 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") 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") 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 5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020 5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 Total Opco Senior Notes Total debt at face value Net unamortized debt discount Net unamortized debt issuance costs Total debt, net Less: current portion of long-term debt Total long-term debt, net NRP LP Debt 2025 Senior Notes December 31, 2019 2018 $ 300,000 $ — — 345,638 — $ — — $ 21,319 6,780 9,458 24,016 63,423 20,059 79,945 20,375 224,056 524,056 — (7,858) 516,198 (45,776) 470,422 $ $ $ $ 15,290 13,414 37,195 89,529 27,185 107,013 30,555 341,500 687,138 (1,266) (13,114) 672,758 (115,184) 557,574 $ $ $ $ $ $ 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. 88 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED NRP and NRP Finance have the option to redeem the 2025 Senior Notes, in whole or in part, at any time on or after October 30, 2021, at the redemption prices (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 date of redemption. Furthermore, before October 30, 2021, NRP may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2025 Senior Notes with the net proceeds of certain public or private equity offerings at a redemption price of 109.125% of the principal amount of 2025 Senior 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 2025 Senior Notes issued under the 2025 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 2025 Indenture, the holders of the 2025 Senior Notes may require us to purchase their 2025 Senior Notes at a purchase price equal to 101% of the principal amount of the 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 unpaid interest. In connection with the early redemption, the Partnership paid an $18.1 million call premium and also wrote off $10.4 million of unamortized debt issuance costs and debt discount. These expenses are included in loss on extinguishment of debt on the Partnership's 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 of December 31, 2019 and 2018, Opco was in compliance with the terms of the financial covenants contained in its debt agreements. Opco Credit Facility In April 2019, the Partnership entered into the Fourth Amendment (the “Fourth Amendment”) to the Opco Credit Facility (the "Opco Credit Facility"). The Fourth Amendment extends the term of the Opco Credit Facility until April 2023. Lender commitments under the Opco Credit Facility remain at $100.0 million. Indebtedness 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 rate for the borrowings outstanding under the Opco Credit Facility during the year ended December 31, 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. 89 Table of Contents 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. The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $399.7 million and $548.9 million classified as mineral rights, net and other assets, net on the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 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, and (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, 2019 and 2018, the Opco Senior Notes had cumulative principal balances of $224.1 million and $341.5 million, respectively. Opco made mandatory principal payments 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, 2019 included a $49.3 million pre-payment as a result of the 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 8.92% Opco Senior Notes also provides 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, 2019. 90 Table of Contents 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: • • until 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 after 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. Consolidated Principal Payments The consolidated principal payments due are set forth below: (In thousands) 2020 2021 2022 2023 2024 Thereafter NRP LP Opco Senior Notes Senior Notes Credit Facility Total $ — $ 46,176 $ — $ — — — — 300,000 39,396 39,396 39,396 31,028 28,664 — — — — — 46,176 39,396 39,396 39,396 31,028 328,664 $ 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. 91 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED The following table shows the carrying amount and estimated fair value of the Partnership's debt and contract receivable: (In thousands) Debt: NRP 2025 Senior Notes NRP 2022 Senior Notes Opco Senior Notes Opco Credit Facility Assets: Contract receivable (current and long- term) December 31, 2019 2018 Fair Value Hierarchy Level Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value 1 1 3 3 3 $ 294,084 $ 269,250 $ — $ — — 222,114 201,090 — — 334,024 338,734 — — 356,871 352,599 — $ 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. 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. 14. Related Party Transactions Affiliates of our General Partner The Partnership’s general partner does not receive any management fee or other compensation for its management of 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. These QMC and WPPLP employee management service costs are presented as operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain rent, information technology, 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 operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). Direct general and administrative expenses charged to the Partnership by QMC and WPPLP are included on the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows: (In thousands) Operating and maintenance expenses General and administrative expenses For the Year Ended December 31, 2019 2018 2017 $ 6,436 $ 6,170 $ 3,548 3,658 6,184 4,989 92 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED The Partnership had accounts payable to QMC of $0.4 million and $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 recognized $4.0 million, $5.4 million and $1.5 million in operating and maintenance expenses, respectively, on its Consolidated Statements of Comprehensive Income (Loss) related to an overriding royalty agreement with WPPLP. At December 31, 2019 and 2018, the Partnership had $0.1 million and $1.4 million, respectively of accounts payable on its Consolidated Balance Sheets to WPPLP for this agreement. Industrial Minerals Group LLC Corbin J. Robertson, III, a Director of GP Natural Resource Partners LLC, 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. Coal royalty related revenues from Industrial Minerals totaled $1.7 million, $0.8 million and $0.7 million for the years ended December 31, 2019, 2018 and 2017, respectively. The Partnership had accounts receivable from Industrial Minerals of $0.7 million and $0.1 million on its Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. Quinwood Coal Company Royalty In 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 $0.9 million for the years ended December 31, 2019, 2018 and 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, 2019, a fund controlled by Quintana Capital owned a substantial interest in Corsa Coal Corp. ("Corsa"), a coal mining company traded on the TSX Venture Exchange that was one of the Partnership’s lessees in Tennessee. During the second quarter of 2018, Corsa assigned its lease with NRP to a third party and is no longer deemed a related party as of such date. Coal related revenues from Corsa totaled $0.5 million and $1.3 million for the years ended December 31, 2018 and 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 a result, all transactions (including revenues, expenses and cash flows) after May 9, 2017 with the various companies affiliated with Chris Cline, including Foresight Energy, are considered to be third-party transactions. 93 Table of Contents 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: (In thousands) Revenues: Coal royalty and other (1) Transportation and processing services (2) Total Operating and maintenance expenses (3) For the Year Ended December 31, 2019 2018 2017 $ $ $ 39,755 19,168 58,923 1,329 $ $ $ 30,777 23,818 54,595 1,761 $ $ $ 49,967 20,522 70,489 1,518 (1) (2) (3) 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. 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. 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 Other Revenues Various subsidiaries of Foresight Energy lease coal reserves from the 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 owns 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 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 subsidiary of Foresight Energy and NRP collects minimums and throughput fees, which are considered a return of a financing receivable or included in transportation and processing services revenues on the Partnership's Consolidated Statements of Comprehensive Income (Loss). See Note 18. Financing Transaction for more information. 94 Table of Contents 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: (In thousands) Foresight Energy (1) Contura Energy (1) (2) 2019 2018 2017 Revenues Percent Revenues Percent Revenues Percent $ 58,923 40,743 22.9% $ 15.8% 54,595 24,580 21.7% $ 9.8% 70,489 20,172 29.0% 8.3% For the Year Ended December 31, (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 ordinary 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. In January 2013, NRP 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 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 2019, the trial court ruled in NRP’s favor in all respects, including that the internal restructuring that occurred did not trigger an acceleration of the contingent 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 the Partnership. 95 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Environmental Compliance The operations the Partnership’s lessees conduct on its properties, as well as the 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 "Items 1. and 2. Business and Properties—Regulation and Environmental 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 will 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, 2019. The Partnership is not associated with any material environmental contamination that may require remediation costs. However, the Partnership’s lessees are 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. 17. Unit-Based Compensation 2017 Long-Term Incentive Plan In December 2017, the 2017 Long-Term Incentive Plan (the “2017 LTIP”) was approved and it became effective in January 2018. The 2017 LTIP authorizes 800,000 common units that are available for delivery by the Partnership pursuant to awards under the plan. The term is 10 years from the date of approval of the Board 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 Directors to administer the 2017 LTIP, or the date all available common units available have been delivered. Common units delivered pursuant to the 2017 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 foregoing. Employees, consultants and non-employee directors of the Partnership, the General Partner, GP LLC and their affiliates are generally eligible to receive awards under the 2017 LTIP. The 2017 LTIP provides for the issuance of a variety 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 Compensation, Nominating and Governance Committee ("CNG Committee") of the Board of Directors, which determines the terms and conditions of awards granted under the 2017 LTIP. The Partnership recognizes forfeitures for any awards 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 continue to accumulate distribution equivalent rights ("DERs") until issuance. In connection with the phantom unit awards, the CNG Committee also granted tandem 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. 96 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED The awards granted in 2019 and 2018 were valued using the closing price of NRP's units as of the grant date. The grant date fair value of these awards granted during the years ended December 31, 2019 and 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: (In thousands) Outstanding grants at January 1, 2019 Granted Fully vested and issued Forfeitures Outstanding at December 31, 2019 18. Financing Transaction Common Units Weighted Average Exercise Price 55 $ 129 $ (12) $ (15) $ $ 157 29.10 41.41 41.47 37.33 37.48 The Partnership owns rail loadout and associated 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 lease term. The Partnership is also entitled to variable payments in the form of throughput fees determined based on the amount of coal transported and processed utilizing the Partnership'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 related to the Partnership's Sugar Camp lease through 2032: (In thousands) Accounts receivable Contract receivable (current and long-term) Unearned income Projected remaining payments 19. Leases Lessee Accounting December 31, 2019 2018 540 $ 38,945 21,889 61,374 $ 661 40,776 25,058 66,495 $ $ 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's right-of-use asset and lease liability included within other assets and other non-current liabilities, respectively, on its Consolidated Balance Sheet totaled $3.5 million at both January 1, 2019 and December 31, 2019. During the year ended December 31, 2019, the Partnership incurred total operating lease expenses of $0.5 million, included in both operating and maintenance expenses and general and administrative expenses on its Consolidated Statement of Comprehensive Income (Loss). 97 Table of Contents NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED The following table details the maturity analysis of the Partnership's operating lease liability and reconciles the undiscounted cash flows to the operating lease liability included on its Consolidated Balance Sheet: Remaining Annual Lease Payments (In thousands) 2020 2021 2022 2023 2024 After 2024 Total lease payments (1) Less: present value adjustment (2) Total operating lease liability December 31, 2019 483 483 483 483 483 11,597 14,012 (10,506) 3,506 $ $ $ (1) The remaining lease term of the Partnership's operating lease is 29 years. (2) The present value of the operating lease liability on the Partnership'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 the Partnership's secured debt and adjusting it for factors that reflect the profile of borrowing over the 30-year expected lease term. Lessor Accounting The Partnership owns loadout and other transportation assets at the Partnership's Macoupin property in the Illinois Basin which is operated by Foresight Energy. The infrastructure at the Macoupin property is leased to a subsidiary of Foresight Energy and is accounted for as an operating lease under ASC 842. The lease with Macoupin expires in January 2108. From the inception 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, 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. 98 Table of Contents Quarterly Financial Data NATURAL RESOURCE PARTNERS L.P. SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) The following table summarizes quarterly financial data for 2019: (In thousands, except per unit data) Revenues Gain (loss) on asset sales and disposals Asset impairments Income (loss) from operations Loss on extinguishment of debt Net income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Net income (loss) attributable to NRP Net income (loss) attributable to common unitholders and general partner Income (loss) from continuing operations per common unit Basic Diluted Net income (loss) per common unit Basic Diluted Weighted average number of common units outstanding (basic) Weighted average number of common units outstanding (diluted) First Quarter Second Quarter (1) Third Quarter Fourth Quarter (2) $ 66,785 $ 81,223 $ 57,602 $ 256 — 49,939 — 35,765 (46) 35,719 35,719 246 — 60,844 29,282 19,106 245 19,351 19,351 6,107 484 49,594 — 39,163 7 39,170 39,170 $ 51,827 (111) 147,730 (109,056) — (119,448) 750 (118,698) (118,698) Total 2019 257,437 6,498 148,214 51,321 29,282 (25,414) 956 (24,458) (24,458) 28,219 11,851 31,670 (126,198) (54,458) $ $ $ $ 2.26 1.75 2.26 1.75 $ $ 0.93 0.85 0.95 0.87 $ $ 2.53 1.66 2.53 1.66 (10.15) $ (10.15) (10.09) $ (10.09) (4.43) (4.43) (4.35) (4.35) 12,255 12,261 12,261 12,261 12,260 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. (2) During the fourth quarter of 2019 the Partnership recorded $147.7 million of asset impairments primarily related to its coal royalty properties and intangible assets. See Note 10. Mineral Rights, Net and Note 11. Intangible Assets, Net for more information. 99 Table of Contents NATURAL RESOURCE PARTNERS L.P. SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) The following table summarizes quarterly financial data for 2018: (In thousands, except per unit data) Revenues Gain on litigation settlement Gain on asset sales and disposals Asset impairments Income from operations Net income from continuing operations Income (loss) from discontinued operations Net income Net income attributable to NRP Net income attributable to common unitholders and general partner Income from continuing operations per common unit Basic Diluted Net income per common unit Basic Diluted Weighted average number of common units outstanding (basic) Weighted average number of common units outstanding (diluted) First Quarter Second Quarter Third Quarter Fourth Quarter (1)(2)(3) Total 2018 $ 59,478 $ 69,451 $ 58,207 $ 63,935 $ 251,071 — 651 242 44,236 26,286 (1,948) 24,338 24,338 — 168 — 52,863 35,129 2,981 38,110 37,241 — — — 43,346 25,853 2,688 28,541 28,900 25,000 1,622 18,038 52,093 35,092 13,966 49,058 49,058 25,000 2,441 18,280 192,538 122,360 17,687 140,047 139,537 16,838 29,741 21,400 41,558 109,537 $ $ $ $ 1.50 1.16 1.35 1.08 $ $ 2.14 1.57 2.38 1.71 $ $ 1.50 1.18 1.71 1.30 $ $ 2.21 1.69 3.33 2.36 7.35 5.90 8.77 6.76 12,238 12,246 12,246 12,247 12,244 22,125 21,383 21,840 20,394 20,234 (1) During the fourth quarter of 2018 the Partnership recorded $25 million in other income related to the Hillsboro litigation settlement. (2) During the fourth quarter of 2018 the Partnership sold its construction aggregates business for $205 million, before customary purchase price adjustments and transaction expenses, and recorded a gain of $13.1 million included in income from discontinued operations on the Partnership's Consolidated Statements of Comprehensive Income (Loss). See Note 4. Discontinued Operations for more information. (3) During the fourth quarter of 2018 the Partnership recorded $18.0 million in aggregates and coal property impairments. See Note 10. Mineral Rights, Net for more information. 100 Table of Contents 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, 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, 2019 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, 2019 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 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. 101 Table of Contents 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, 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. (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 Partnership’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 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. /s/ Ernst & Young LLP Houston, Texas February 27, 2020 102 Table of Contents ITEM 9B. OTHER INFORMATION None. 103 Table of Contents 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. Subject to Board Representation and Observation Rights Agreement with Blackstone and GoldenTree, Mr. Robertson is entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to appoint one director to Blackstone. Name Corbin J. Robertson, Jr. Craig W. Nunez Christopher J. Zolas Kevin J. Craig Kathryn S. Wilson Gregory F. Wooten Galdino J. Claro Russell D. Gordy Alexander D. Greene S. Reed Morian Paul B. Murphy, Jr. Richard A. Navarre Corbin J. Robertson, III Stephen P. Smith Leo A. Vecellio, Jr. Age Position with the General Partner 72 Chairman of the Board and Chief Executive Officer 58 President and Chief Operating Officer 45 Chief Financial Officer and Treasurer 51 Executive Vice President, Coal 45 Vice President, General Counsel and Secretary 63 Vice President, Chief Engineer 60 Director 69 Director 61 Director 74 Director 60 Director 59 Director 49 Director 58 Director 73 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. Craig W. Nunez has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since August 2017 and previously served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC from January 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. 104 Table of Contents 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 from March 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. 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 New Gauley Coal Corporation and the general partner of Western Pocahontas Properties Limited Partnership. She served as General Counsel of Quintana Minerals Corporation from October 2013 to November 2018 and as General Counsel of the General Partner of Great Northern Properties Limited Partnership from October 2013 to 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. 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, Chief Operating Officer and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties from 1982 until 2007. Mr. Wooten has over 35 years of experience in the coal industry, working as a planning and production engineer and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers. Mr. Wooten also serves as the President of the National Council of Coal Lessors 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. Galdino J. Claro joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Claro has 30 years of worldwide executive leadership experience in the primary and secondary metals industries. From October 2013 to August 2017, Mr. Claro served as the Group Chief Executive Officer 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 Executive Officer of Harsco Metals and Minerals. He joined Harsco from Aleris, where he served as CEO 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 the President of 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 Managing Director of Alcoa Cargo-Van. Before joining Alcoa in 1985, Mr. Claro started his career at Honda-Motogear as a Quality Control Manager where he worked for three years in both Brazil and Japan. 105 Table of Contents 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. Alexander D. Greene joined the Board of Directors of GP Natural Resource Partners LLC in March 2019. Mr. Greene brings extensive corporate finance and private 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 USA Truck, Inc. In addition, Mr. Greene recently served as Chairman of the Board of Modular Space Corporation prior to its sale to Williams Scotsman in 2018. From 2005 to 2014 he was a Managing Partner and head of U.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 Carlyle Strategic Partners, a private equity fund, and a Managing Director and investment banker at Wasserstein Perella & Co. and Whitman Heffernan Rhein & Co. Mr. Greene is a volunteer firefighter and president of the Armonk Independent Fire Company and serves on the Budget and Finance Advisory Committee for the Town of North Castle, New York. Mr. Greene 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. 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. Mr. Navarre serves on the Board of Directors of Civeo Corporation, where he serves as Chairman, Covia Corporation, where he serves as Chairman, and Arch Coal, where he serves as Chairman of the 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 the former Chairman of the Bituminous Coal Operators’ Association. Mr. Navarre is a Certified Public Accountant. Mr. Navarre also has been involved in numerous civic and charitable organizations throughout his career. 106 Table of Contents 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, LKCM Headwater Investments I, L.P., LKCM Headwater Investments II, LP, LKCM Headwater Investments II Sidecar, LP, LKCM Headwater Investments III, private equity funds 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 Quality Magnetite, Quinwood Coal 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, Chief Accounting Officer and Director of the general partner of Columbia Pipeline Partners L.P. from September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and Chief Financial Officer of Columbia Pipeline Group from July 2015 to June 2016. Mr. Smith served as Executive Vice President and Chief Financial Officer for NiSource, Inc. from August 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. 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 eight times in 2019. During 2019, our non-management directors met in executive session several times. The presiding director was Mr. 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 2019. Mr. Vecellio 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. Independence of Directors The Board of Directors has affirmatively determined that Messrs. Claro, Gordy, 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. Because we are a limited partnership as defined in Section 303A of the NYSE’s listing standards, we are not required to 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 Mr. Smith, who serves as chairman, Mr. Claro and Mr. Navarre. Mr. Smith and Mr. Navarre are "Audit Committee Financial Experts" as determined pursuant to Item 407 of Regulation S-K. During 2019, the Audit Committee met seven times. 107 Table of Contents 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 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, 2019 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 has discussed with the independent auditors the matters required to be discussed by the applicable 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 concerning independence, and has discussed with the independent accountant the 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 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, 2019, for filing with the Securities and Exchange Commission. Stephen P. Smith, Chairman Galdino J. Claro Richard A. Navarre 108 Table of Contents Compensation, Nominating and Governance Committee Executive officer compensation is administered by the CNG Committee, which is currently comprised of three members: Mr. Vecellio, as Chairman, Mr. Gordy and Mr. 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 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 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. 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 is also filed with the SEC and is 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 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. 109 Table of Contents 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. Our 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 (“Western Pocahontas”). Quintana and Western Pocahontas are controlled by our Chairman and Chief Executive Officer and are affiliates of NRP. While our executive officers are 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 "Items 1. and 2. Business and Properties—Partnership Structure and 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 under current market conditions. 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.” The 2019 compensation for executive officers consisted of four primary components: • • • • base salaries; short-term cash incentive compensation; long-term equity incentive compensation; and perquisites and other benefits. To the extent our named executive officers (with the exception of Mr. Robertson) spend time on non-NRP matters, NRP bears only the proportionate cost of their time. Mr. Robertson does not receive a salary in his capacity as Chief Executive Officer. Mr. Robertson is compensated through short-term cash and long-term equity incentive awards, all of which is allocated to NRP. In February of each year, the CNG Committee approves the short-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. 110 Table of Contents Each February, the CNG Committee also makes awards of phantom units to be settled in common units under the Natural Resource Partners 2017 Long-Term Incentive Plan (the “2017 Plan”) to NRP’s officers in order to incentivize management while also aligning the long-term interests of management with the interests of NRP’s unitholders. Role of Compensation Experts In 2019, the CNG Committee engaged Longnecker & Associates (“L&A”) to review 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 marketplace for talent within which we compete. The CNG Committee will review the Peer 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. Black Stone Minerals, L.P. Callon Petroleum Company CatchMark Timber Trust, Inc. Ciner Resources LP CONSOL Coal Resources LP Earthstone Energy, Inc. Enviva Partner, LP Falcon Minerals Corporation Hi-Crush Inc. Kimbell Royalty Partners, LP NACCO Industries, Inc. Panhandle Oil and Gas, Inc. Penn Virginia Corporation Ramaco Resources, Inc. Rosehill Resources Inc. SilverBow Resources, Inc. SunCoke Energy, Inc. Talos Energy Inc. W&T Offshore, Inc. Using the Peer Group, L&A conducted compensation analyses for all components of compensation and provided the CNG Committee with its findings after such time. The findings indicated that base salaries and short-term incentive compensation of each of the five named executive officers was generally in line with the Peer Group median, but that long-term incentive compensation was well below the Peer Group median. While L&A provided recommendations for 2019 short-term cash incentive compensation, 2019 base salaries and long-term incentive compensation grants were determined by the CNG Committee prior to engaging L&A. Accordingly, the L&A recommendations will be used prospectively with respect to long-term incentive compensation, with the 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. Nunez, our President and Chief Operating Officer, provided Mr. Robertson with recommendations relating to the executive officers other than himself. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of the executive officers other than himself. Messrs. Robertson and Nunez considered the factors described elsewhere in this compensation discussion and analysis in recommending, in their discretion, the appropriate amounts for each named executive officer. Messrs. Robertson and Nunez attended the CNG Committee meetings at which the Committee deliberated and approved 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. Components of Compensation Base Salaries With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our executive officers are paid an annual base salary by Quintana or 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. 111 Table of Contents In determining salaries for NRP’s executive officers for 2019, at the December 2018 meeting, the CNG Committee considered the financial performance of NRP for the nine months ended September 30, 2018 as well as the projected financial performance of NRP for the fourth quarter of 2018 and for the year ending December 31, 2019. The CNG Committee also considered the individual performance of each member of the executive management team during 2018. Salaries for 2019 are shown in the Summary Compensation Table below. Short-Term Cash Incentive Compensation Each named executive officer received a discretionary short-term cash incentive award approved in February 2020 by the CNG Committee. The amounts awarded with respect to 2019 under this program are disclosed in the Summary Compensation Table under the Bonus column. With respect to 2019, the CNG Committee, using recommendations from L&A, determined that cash bonuses would be paid based on a percentage of base salary, with Mr. Robertson receiving approximately two times the amount awarded to the President and Chief Operating Officer. In addition, the CNG Committee determined that it would consider certain criteria to determine bonus amounts within this range, but that the criteria 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 company. Long-Term Equity Incentive Compensation Each named executive officer received a discretionary long-term equity incentive award in 2019 under the 2017 Plan. The 2019 awards were made in the form 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 on an accelerated basis following death or disability of the award recipient or following a change in control of NRP. The grant date fair value of the 2017 Plan Phantom Units awarded in 2019 are disclosed in the Summary Compensation Table under the "Stock Awards" column. For the 2017 Plan Phantom Units awarded in 2019, the CNG Committee generally awarded an amount equal to 135% to 140% of base salary, with Mr. Robertson receiving two times the amount awarded to the President and Chief Operating Officer. The CNG Committee considered performance of the company and individual performance in 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 maintained tax-qualified 401(k) plans. During 2019, Quintana and Western Pocahontas matched 100% of the first 6.0% of the employee contributions under their respective 401(k) 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 NRP 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 currently apply to our Chief Executive Officer. 112 Table of Contents The ownership guidelines also require directors 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 the executive officer or director, common units owned indirectly by the executive officer or director (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 under NRP’s long-term incentive plans (including phantom units representing the right to receive units), and units purchased in the open market (whether purchased before or after the effective date of the ownership 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 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. 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, 2019. Leo A. Vecellio, Jr., Chairman Russell D. Gordy Stephen P. Smith 113 Table of Contents Summary Compensation Table The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation for 2017, 2018 and 2019: Name and Principal Position Year Salary ($) Bonus ($) Corbin J. Robertson, Jr.—Chief Executive Officer 938,868 — — 1,208,247 — — 2019 2018 2017 Non-Equity Incentive Plan Compensation ($) Stock Awards ($) (1) All Other Compensation ($) (2) Total ($) — 1,306,222 418,836 — 250,000 3,250,000 — — — 2,245,090 1,877,083 3,250,000 Craig W. Nunez—President and Chief Operating Officer 2019 2018 2017 500,000 447,499 375,000 408,204 604,124 250,000 — 93,750 1,218,750 653,111 209,433 — 16,800 16,800 34,650 1,578,115 1,371,606 1,878,400 Christopher J. Zolas—Chief Financial Officer 2019 2018 2017 355,000 337,499 300,000 284,000 455,624 180,000 — 75,000 375,000 492,581 167,529 — 16,800 16,800 34,650 1,148,381 1,052,452 889,650 Kathryn S. Wilson—Vice President, General Counsel and Secretary(3) 2019 2018 2017 272,217 469,124 150,000 340,271 347,499 321,750 — 75,000 975,000 507,178 139,622 — 16,128 16,800 34,304 1,135,794 1,048,045 1,481,054 Kevin J. Craig—Executive Vice President, Coal(4) 310,500 229,839 172,000 2019 2018 2017 248,400 321,775 145,600 — 75,000 375,000 434,854 145,209 — 15,120 13,200 22,427 1,008,874 785,023 715,027 (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 "Item 8. Financial Statements and Supplementary Data—Note 17. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K for more information. (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 114 Table of Contents 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. Named Executive Officer Corbin J. Robertson, Jr. Craig W. Nunez Christopher J. Zolas Kathryn S. Wilson Kevin J. Craig Employment Agreements Grant Date 2/14/2019 2/14/2019 2/14/2019 2/14/2019 2/14/2019 2017 Plan Phantom Units Number of Units 31,498 15,749 11,878 12,230 10,486 Grant Date Fair Value 1,306,222 $ 653,111 492,581 507,178 434,854 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 Corbin J. Robertson, Jr. Craig W. Nunez Christopher J. Zolas Kathryn S. Wilson Kevin J. Craig $ Cash Settled Phantom Units 3,600 1,400 950 950 950 Value Realized on Vesting(1) 166,759 64,851 44,006 44,006 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 Corbin J. Robertson, Jr. Craig W. Nunez Christopher J. Zolas Kathryn S. Wilson Kevin J. Craig $ Unvested 2017 Plan Phantom Units(1) 45,891 22,946 17,635 17,028 15,476 Market Value of Unvested 2017 Plan Phantom Units(2) 922,868 461,444 354,640 342,433 311,222 (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. 115 Table of Contents 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. Named Executive Officer Corbin J. Robertson, Jr. Craig W. Nunez Christopher J. Zolas Kathryn S. Wilson Kevin J. Craig 2017 Plan Equity Awards $ Unvested Phantom Units 45,891 22,946 17,635 17,028 15,476 Market Value(2) Accumulated DERs Total Potential Payments $ 922,868 461,444 354,640 342,433 311,222 $ 126,868 63,436 49,160 46,098 43,029 1,049,736 524,880 403,800 388,531 354,251 (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 Russell D. Gordy Jasvinder S. Khaira(2) S. Reed Morian Richard A. Navarre(3) Corbin J. Robertson, III Stephen P. Smith(3) Leo A. Vecellio, Jr. Paul B. Murphy, Jr. Galdino J. Claro Alexander D. Greene(2) Fees Earned or Paid in Cash 2017 Plan Common Unit Awards(1) Total Compensation $ 80,000 $ 81,074 $ — 75,000 95,000 75,000 95,000 95,000 75,000 85,000 — — 81,074 81,074 81,074 81,074 81,074 81,074 81,074 — 161,074 — 156,074 176,074 156,074 176,074 176,074 156,074 166,074 — (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 17 to the audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. (2) Mr. Khaira, who was the Blackstone designee pursuant to the Board Representation and Observation Rights Agreement, resigned from the Board effective March 8, 2019. Effective on such date, Mr. Greene was appointed to the Board by Blackstone to replace Mr. Khaira. Messrs. Khaira and Greene did not receive Board compensation as Blackstone designees. (3) Messrs. Navarre and Smith elected to defer settlement of their common units awarded under the 2017 Plan in 2019 until 90 days following their respective retirements or earlier departures from the Board. 116 Table of Contents The table below shows the Cash Settled Phantom Units that were granted in February 2015 and vested in 2019 with respect to each Director, along with the value realized by each individual, including the DERs accruing from the February 2015 grant date. Name of Director Russell D. Gordy Jasvinder S. Khaira S. Reed Morian Richard A. Navarre Corbin J. Robertson, III Stephen P. Smith Leo A. Vecellio, Jr. Paul B. Murphy, Jr. Galdino J. Claro Alexander D. Greene $ Cash Settled Phantom Units 410 — 410 410 410 410 410 — — — Value Realized on Vesting 18,992 — 18,992 18,992 18,992 18,992 18,992 — — — Compensation Committee Interlocks and Insider Participation During the year ended December 31, 2019, Messrs. Vecellio, Gordy, and Smith served on the CNG Committee. None of Messrs. Vecellio, Gordy, and 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 Median Service Provider Year 2019 Salary Bonus Non-Equity Incentive Plan Compensation Phantom Unit Awards All Other Compensation $ 85,847 $ 23,661 $ — $ — $ 5,151 Total $ 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. 117 Table of Contents ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following tables set forth, as of 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 our 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. Name of Beneficial Owner Corbin J. Robertson, Jr. (2) Western Pocahontas Corporation (3) Western Pocahontas Properties Limited Partnership (4) JPMorgan Chase & Co. (5) The Goldman Sachs Group, Inc. (6) Kevin J. Craig Craig W. Nunez Kathryn S. Wilson Christopher J. Zolas Galdino J. Claro Russell D. Gordy (7) Alexander D. Greene S. Reed Morian (8) Paul B. Murphy, Jr. Richard A. Navarre Corbin J. Robertson III (9) Stephen P. Smith (10) Leo A. Vecellio, Jr. Directors and Officers as a Group * Less than one percent. Common Units Percentage of Common Units (1) 2,411,395 1,739,007 1,727,986 1,050,335 835,403 950 — — — 4,114 11,354 — 620,513 7,614 1,000 238,656 355 6,354 19.7% 14.2% 14.1% 8.6% 6.8% — — — * * * — 5.1% * * 1.9% * * 3,302,305 26.9% (1) Percentages based upon 12,261,199 common units issued and outstanding as of February 24, 2020. Unless otherwise noted, beneficial ownership is less than 1%. (2) Mr. Robertson may be deemed to beneficially own 505,861 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 his spouse, Barbara M. Robertson. Mr. Robertson’s address is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. (3) Western Pocahontas Corporation has sole voting and sole dispositive power with respect to 11,021 common units and shared voting and shared dispositive power with respect to 1,727,986 common units in its capacity as the general partner of Western Pocahontas Properties Limited Partnership. The business address of Western Pocahontas Corporation is 5260 Irwin Road, Huntington, West Virginia 25705. (4) Western Pocahontas Properties Limited Partnership has sole voting and sole dispositive power with respect to 0 common units and 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. 118 Table of Contents (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 in the Partnership. The business address of JPMorgan Chase & Co. is 270 Park Ave., New York, NY 10017. (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. (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. (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. (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, 19,663 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. (10) Mr. Smith may be deemed to beneficially own 355 common units owned by the SP Smith 2002 Revocable Trust. Name of Beneficial Owner The Blackstone Group Inc. (1) GoldenTree Asset Management, LP (2) Preferred Units Percentage of Preferred Units 142,500 107,500 57% 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. (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. 119 Table of Contents 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 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 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 120 Table of Contents 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, we entered into the Board Observation and Representation Rights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant to the Board Rights Agreement, Blackstone appoints one member to serve on the Board of Directors of GP Natural Resource Partners LLC and also appoints 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 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"). 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-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. For more information on the Preferred Units, including the rights of the holders thereof, see "Item 8. Financial Statements and Supplementary Data—Note 5. Class A Convertible Preferred Units and Warrants" elsewhere in this Annual Report on Form 10-K. 121 Table of Contents 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. 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. 122 Table of Contents • 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. Relationships with Entities Associated with Corbin J. Robertson, III Quinwood Coal Partners LP (“Quinwood”), an entity controlled by Corbin J. Robertson, III (one of our directors) leases two coal properties from us in Central Appalachia. During the 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. Mr. 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 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 initial 10-year term of the lease expired 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 to 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 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) 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. 123 Table of Contents 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. 124 Table of Contents We do not have any officers or employees. We rely on officers and employees of GP Natural Resource Partners LLC and its affiliates. We do not have any officers or employees and rely 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. Certain 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. 125 Table of Contents 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 and the Omnibus Agreement, affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us. The Conflicts Committee Charter is available upon request. Director Independence For a discussion of the independence of the members of the Board of Directors of our managing general partner under applicable standards, see "Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance —Corporate Governance—Independence of Directors," which is incorporated by reference into this Item 13. 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) 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 and our partnership agreement. For the year ended December 31, 2019 there were no transactions where such guidelines were not followed. 126 Table of Contents 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 2019 and 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: Audit Fees (1) Tax Fees (2) 2019 2018 $ 1,070,206 $ 533,083 957,272 501,426 (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. (2) Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1. 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. 127 Table of Contents 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 Stephen P. Smith, the Chairman of the Audit Committee. Mr. Smith 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 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. 128 Table of Contents 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. 129 Table of Contents PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a)(1) and (2) Financial Statements and Schedules See "Item 8. Financial Statements and Supplementary Data. " (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. (a)(4) Exhibits Exhibit Number 2.1 3.1 3.2 3.3 3.4 3.5 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 Description Purchase Agreement, dated as of January 23, 2013, by and among Anadarko Holding Company, Big Island Trona Company, NRP Trona LLC and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on January 25, 2013). Fifth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of March 2, 2017 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on March 6, 2017). Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on December 16, 2011). Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of October 31, 2013 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on October 31, 2013). Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of Annual Report on Form 10-K for the year ended December 31, 2002). Certificate of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 filed April 19, 2002, File No. 333-86582). Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed June 23, 2003). First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on July 20, 2005). Second Amendment, dated as of March 28, 2007, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 29, 2007). First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on July 20, 2005). Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 29, 2007). Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 26, 2009). Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April 21, 2011). Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to Current Report on Form 8-K filed June 23, 2003). Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed June 23, 2003). Form of Series D Note (incorporated by reference to Exhibit 4.12 to Annual Report on Form 10-K filed February 28, 2007). 130 Table of Contents Exhibit Number 4.11 4.12 4.13 4.14 4.15 4.16 4.17 4.18 4.19 4.20 4.21 4.22 4.23 4.24 4.25* 10.1 10.2 10.3 10.4 10.5 Description Form of Series E Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed March 29, 2007). Form of Series F Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 7, 2009). Form of Series G Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 7, 2009). Form of Series H Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 5, 2011). Form of Series I Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 5, 2011). Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 15, 2011). Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on October 3, 2011). Registration Rights Agreement, dated as of January 23, 2013, by and among Natural Resource Partners L.P. and the Investors named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on January 25, 2013). Third Amendment, dated as of June 16, 2015, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 18, 2015). Fourth Amendment, dated as of September 9, 2016, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 12, 2016). Indenture, dated 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 4.1 to Current Report on Form 8-K filed on May 2, 2019). Form of 9.125% Senior Notes due 2025 (contained in Exhibit 1 to Exhibit 4.21). Registration Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 6, 2017). Form of Warrant to Purchase Common Units (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 6, 2017). Description of Equity Securities of Natural Resource Partners L.P. 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). 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). Limited Liability Company Agreement of Ciner Wyoming LLC, dated June 30, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed by Ciner Resources LP on July 2, 2014). Amendment No. 1 to the Limited Liability Company Agreement of Ciner Wyoming LLC dated November 5, 2015 (incorporated by reference to Exhibit 10.22 to Annual Report on Form 10-K filed by Ciner Resources LP on March 11, 2016). 131 Table of Contents Exhibit Number 10.6 10.7 10.8 10.9 10.10+ 10.11+ 10.12+ 10.13+* 10.14+* 10.15+* 21.1* 23.1* 23.2* 31.1* 31.2* 32.1** 32.2** 99.1* Description 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). Fourth Amendment, dated as of April 3, 2019, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on April 9, 2019). New Lender Agreement, dated as of April 8, 2019, by and among NRP (Operating) LLC and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on April 9, 2019). Board Representation and Observation Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P., Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, BTO Carbon Holdings L.P. and the GoldenTree Purchasers named therein (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March 6, 2017) Natural Resource Partners L.P. 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January 17, 2018). Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-8 filed on February 9, 2018). Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 filed on February 9, 2018). Form of Phantom Unit Award Agreement (Employees and Service Providers) Form of Phantom Unit Award Agreement (Directors) Form of Phantom Unit Award Agreement (Directors with Deferral Election) List of Subsidiaries of Natural Resource Partners L.P. Consent of Ernst & Young LLP. Consent of Deloitte & Touche LLP. Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley. Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley. Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350. Financial Statements of Ciner Wyoming LLC as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017. 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 * ** + Filed herewith Furnished herewith Management compensatory plan or arrangement 132 Table of Contents 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. SIGNATURES Date: February 27, 2020 Date: February 27, 2020 NATURAL RESOURCE PARTNERS L.P. By: NRP (GP) LP, its general partner By: GP NATURAL RESOURCE PARTNERS LLC, its general partner By: /s/ CORBIN J. ROBERTSON, JR. Corbin J. Robertson, Jr. Chairman of the Board, Director and Chief Executive Officer (Principal Executive Officer) By: /s/ CHRISTOPHER J. ZOLAS Christopher J. Zolas Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) 133 Table of Contents 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. Date: February 27, 2020 Date: February 27, 2020 Date: February 27, 2020 Date: February 27, 2020 Date: February 27, 2020 Date: February 27, 2020 Date: February 27, 2020 Date: February 27, 2020 Date: February 27, 2020 /s/ GALDINO J. CLARO Galdino J. Claro Director /s/ RUSSELL D. GORDY Russell D. Gordy Director /s/ ALEXANDER D. GREENE Alexander D. Greene Director /s/ S. REED MORIAN S. Reed Morian Director /s/ PAUL B. MURPHY, JR. Paul B. Murphy, Jr. Director /s/ RICHARD A. NAVARRE Richard A. Navarre Director /s/ CORBIN J. ROBERTSON III Corbin J. Robertson III Director /s/ STEPHEN P. SMITH Stephen P. Smith Director /s/ LEO A. VECELLIO, JR. Leo A. Vecellio, Jr. Director 134 Exhibit 4.25 DESCRIPTION OF EQUITY SECURITIES OF NATURAL RESOURCE PARTNERS L.P. Common Units The common units represent limited partner interests in Natural Resource Partners L.P. that entitle the holders to participate in our cash distributions and to exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units, preferred units and our general partner in and to partnership distributions, see “—Cash Distributions.” Our outstanding common units are listed on the New York Stock Exchange under the symbol “NRP.” The transfer agent and registrar for our common units is American Stock Transfer & Trust Company. Status as Limited Partner or Assignee Except as described under “—The Partnership Agreement—Limited Liability,” the common units will be fully paid, and the unitholders will not be required to make additional capital contributions to us. Transfer of Common Units Each purchaser of common units offered by this prospectus must execute a transfer application. By executing and delivering a transfer application, the purchaser of common units: • • • • • becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner; automatically requests admission as a substituted limited partner in our partnership; agrees to be bound by the terms and conditions of, and executes, our partnership agreement; represents that he has the capacity, power and authority to enter into the partnership agreement; grants powers of attorney to officers of the general partner and any liquidator of our partnership as specified in the partnership agreement; and • makes the consents and waivers contained in the partnership agreement. An assignee will become a substituted limited partner of our partnership for the transferred units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records as soon as practicable following any transfer. Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder. Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the purchased common units. A purchaser of common units who does not execute and deliver a transfer application obtains only: • • the right to assign the common unit to a purchaser or transferee; and the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased common units. Thus, a purchaser of common units who does not execute and deliver a transfer application: • will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and • may not receive some federal income tax information or reports furnished to record holders of common units. 1 Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations. Class A Convertible Preferred Units In March 2017, we issued 250,000 Class A Convertible Preferred Units (the “preferred 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”) (together the “Preferred Purchasers”) at a price of $1,000 per preferred unit (the “Per Unit Purchase Price”). The preferred units represent limited partner interests in Natural Resource Partners L.P. that entitle the holders to receive cumulative distributions at a rate of 12% per year, up to one half of which we 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. For a description of the relative rights and preferences of holders of common units, preferred units and our general partner in and to partnership distributions, see “—Cash Distributions.” Conversion 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 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 by March 2, 2029, 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. Redemption 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 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. Voting and Approval The holders of the preferred units have the right to vote together with holders of NRP’s common units, as a single class, on an as-converted basis and have other customary approval rights with respect to changes of the terms of the preferred units. See “—The Partnership Agreement—Voting Rights.” In addition, Blackstone and GoldenTree have certain non- transferrable approval rights over certain matters. See “—The Partnership Agreement—Special Approval Rights of Blackstone and GoldenTree.” 2 The Partnership Agreement The following is a summary of the material provisions of our partnership agreement. This summary does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our partnership agreement, which is filed as an exhibit our Annual Report on Form 10-K. Organization and Duration Our partnership was formed on April 9, 2002 and will remain in existence until dissolved in accordance with our partnership agreement. Purpose Our purpose under our partnership agreement is limited to serving as a member of the operating company and engaging in any business activities that may be engaged in by the operating company or its subsidiaries or that are approved by our general partner. The limited liability company agreement of the operating company provides that the operating company may, directly or indirectly, engage in: • • its operations as conducted immediately before our initial public offering; any other activity approved by our general partner but only to the extent that our general partner reasonably determines that, as of the date of the acquisition or commencement of the activity, the activity generates “qualifying income” as this term is defined in Section 7704 of the Internal Revenue Code; and • any activity that enhances the operations of an activity that is described in either of the preceding two clauses. Our partnership agreement also permits us to engage directly in or enter into any form of corporation, partnership, joint venture, limited liability company or other arrangement to engage in any business activity that is approved by our general partner and that may be conducted lawfully by a Delaware limited partnership. Notwithstanding the foregoing, our general partner does not have the authority to cause us to engage, directly or indirectly, in any business activity that it reasonably determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. Our general partner is authorized in general to perform all acts deemed necessary to carry out our purposes and to conduct our business. Power of Attorney Each limited partner and each person who acquires a unit from a unitholder and executes and delivers a transfer application grants to our general partner (and, if appointed, a liquidator), a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, and in accordance with, our partnership agreement. Capital Contributions Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.” Limited Liability Participation in the Control of Our Partnership. Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group: 3 • • • to remove or replace the general partner; to approve some amendments to our partnership agreement; or to take other action under our partnership agreement; constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under Delaware law to the same extent as the general partner. This liability would extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law. Unlawful Partnership Distributions. Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement. Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business. Our subsidiaries currently conduct business in a number of states. Maintenance of limited liability for Natural Resource Partners, as the sole member of the operating companies, may require compliance with legal requirements in the jurisdictions in which the operating companies conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of members for the obligations of a limited liability company have not been clearly established in many jurisdictions. If it were determined that we were, by virtue of our member interests in the operating companies or otherwise, conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners. 4 Voting Rights The following matters require the unitholder vote specified below: Issuance of additional units Amendment of partnership agreement Except as described below under “—Special Approval Rights of Blackstone and GoldenTree,” no approval right. Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority and/or a preferred unit majority. See “— Amendment of the Partnership Agreement.” Unit majority. See “—Merger, Sale or Other Disposition of Assets.” Merger of our partnership or the sale of all or substantially all of our assets. Amendment of the limited liability company agreement and other action taken by us as sole member of the operating company Dissolution of our partnership Reconstitution of our partnership upon dissolution Withdrawal of the general partner Our general partner may withdraw as general partner without approval Unit majority if such amendment or other action would adversely affect our limited partners (or any particular class of limited partners) in any material respect. See “—Action Relating to Operating Company.” Unit majority. See “—Termination and Dissolution.” Unit majority. See “—Termination and Dissolution” e of additional units Removal of the general partner Transfer of the general partner interest Transfer of ownership interests in the general partner of our unitholders by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. See “—Withdrawal or Removal of the General Partner.” Not less than 66 2/3% of the outstanding units, including units held by our general partner and its affiliates; provided, however, that after the eighth anniversary of March 2, 2017, the holders of preferred units (or common units issued upon conversion thereof) may, if they hold 66 2/3% of the common units (or would, on conversion of all preferred units), act by written consent to remove the general partner. See “— Withdrawal or Removal of the General Partner.” The general partner may transfer any or all of its general partner interest without a vote of our unitholders. See “—Transfer of General Partner Interest. No approval required at any time. See “—Transfer of Ownership Interests in the General Partner.” Matters requiring the approval of a “unit majority” require the approval of a majority of the common units and preferred units, on an as-converted basis, voting as a single class. For a description of the terms for conversion of the preferred units into common units, see “—Class A Preferred Units—Conversion.” Except as otherwise described in our partnership agreement, matters requiring the approval of a “preferred unit majority” require the approval of a majority of the preferred units, voting separately as a class with one vote per preferred unit. Special Approval Rights of Blackstone and GoldenTree Blackstone has certain non-transferrable approval rights over certain matters, including: • the incurrence of new indebtedness or issuance of securities that rank senior to or pari passu with the preferred units, subject to certain exceptions; • material changes to NRP’s business; • • • • acquisitions, divestitures and capital expenditures 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. 5 In addition, GoldenTree has certain more limited approval rights, but will gain additional approval rights under certain circumstances. The approval rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with its affiliates) or Golden Tree (together with its affiliates), as applicable, no longer own at least 20% of the total number of preferred units issued on March 2, 2017, together with all PIK units that have been issued but not redeemed (the “Minimum Preferred Unit Threshold”). To the extent any preferred units have converted into common units that are still held by Blackstone (or its affiliates) or GoldenTree (or its affiliates), as applicable, 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. Issuance of Additional Securities Except as described above under “—Special Approval Rights of Blackstone and GoldenTree,” our partnership agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by our general partner in its sole discretion without the approval of any limited partners. It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership common units or other equity securities may dilute the value of the interests of the then-existing holders of common units in our net assets. Except as described above under “—Special Approval Rights of Blackstone and GoldenTree,” in accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, in the sole discretion of our general partner, may have special voting rights to which the common units are not entitled. Upon issuance of additional partnership securities, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units that existed immediately prior to each issuance. The holders of common units do not have preemptive rights to acquire additional common units or other partnership securities. Certain holders of preferred units have preemptive rights with respect to the issuance of partnership securities, subject to certain exceptions, including the issuance of securities to the owners of another entity in connection with the acquisition of such entity, the issuance of securities in an at-the-market offering program, the issuance of securities in a firm commitment underwritten public offering in certain circumstances or the issuance of securities pursuant to any plan or program authorized by our general partner or any dividend, split or other reclassification, provided that with respect to any dividend, split or reclassification of parity securities, the preferred units are given ratable treatment. The holders of the warrants shall have preemptive rights (proportional to their common unit ownership on an as exercised basis) with respect to any issuance of common units and rights, options or warrants to purchase common units, and convertible securities (other than PIK units) by NRP, subject to certain exceptions, including the issuance of securities to the owners of another entity in connection with the acquisition of such entity, the issuance of securities in an at-the-market offering program, the issuance of securities in a firm commitment underwritten public offering in certain circumstances or the issuance of securities pursuant to any plan or program authorized by our general partner or any dividend, split or other reclassification. Amendment of Partnership Agreement General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner, which consent may be given or withheld in its sole discretion. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority. Prohibited Amendments. No amendment may be made that would: • enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; 6 • • • • enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld in its sole discretion; change the duration of our partnership; provide that we are not dissolved upon an election to dissolve our partnership by our general partner that is approved by a unit majority; or give any person the right to dissolve our partnership other than our general partner’s right to dissolve our partnership with the approval of a unit majority. The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting together as a single class (including units owned by the general partner and its affiliates). No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect: • • • • • • • • • • • a change in our name, the location of our principal place of our business, our registered agent or our registered office; the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement; a change that, in the sole discretion of our general partner, is necessary or advisable for us to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, the operating companies nor any of their subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes; an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed; an amendment that in the discretion of our general partner is necessary or advisable for the authorization of additional partnership securities or rights to acquire partnership securities; any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone; an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement; any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement; a change in our fiscal year or taxable year and related changes; a merger, conversion or conveyance effected in accordance with the partnership agreement; and any other amendments substantially similar to any of the matters described in the clauses above. In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee if those amendments, in the discretion of our general partner: • • • do not adversely affect the limited partners (including any particular class of limited partners as compared to other classes of partnership interests) in any material respect; are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in the best interests of us and our limited partners; 7 • • are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or are required to effect the intent expressed in the prospectus relating to our initial public offering or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement. Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any limited partner in our partnership. Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Actions Relating to Operating Company Without the approval of a unit majority, our general partner is prohibited from consenting on our behalf as the sole member of the operating company to any amendment to the limited liability company agreement of our operating company or taking any action on our behalf permitted to be taken by a member of our operating company, in each case that would adversely affect our limited partners (or any particular class of limited partners as compared to other classes of limited partners) in any material respect. Merger, Sale or Other Disposition of Assets Our general partner is generally prohibited, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale exchange or other disposition of all or substantially all of the assets of our subsidiaries; provided that, except as described above under “—Special Approval Rights of Blackstone and GoldenTree,” our general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Except as described above under “— Special Approval Rights of Blackstone and GoldenTree,” our general partner may also sell all or substantially all our assets under a foreclosure or other realization upon the encumbrances above without that approval. If the conditions specified in the partnership agreement are satisfied, our general partner may merge our partnership or any of its subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of all or substantially all of our assets or any other transaction or event. Termination and Dissolution We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon: • • • • the election of our general partner to dissolve us, if approved by the holders of a unit majority; the sale, exchange or other disposition of all or substantially all of the assets and properties of our partnership and the subsidiaries; the entry of a decree of judicial dissolution of our partnership; or the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor. 8 Upon a dissolution under the last clause above, a unit majority may also elect, within specific time limitations, to reconstitute our partnership and continue its business on the same terms and conditions described in our partnership agreement by forming a new limited partnership on terms identical to those in our partnership agreement and having as general partner an entity approved by a unit majority, subject to our receipt of an opinion of counsel to the effect that: • • the action would not result in the loss of limited liability of any limited partner; and neither our partnership, the reconstituted limited partnership, our operating company nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue. Liquidation and Distribution of Proceeds Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “—Cash Distributions—Distributions of Cash upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners. Withdrawal or Removal of the General Partner Our general partner may withdraw as general partner without first obtaining approval of our unitholders by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. At any time, the partners of our general partner may sell or transfer all or part of their partnership interests in our general partner interests in our partnership without the approval of the unitholders. See “—Transfer of General Partner Interest.” Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of the outstanding common units agree in writing to continue the business of Natural Resource Partners and to appoint a successor general partner. See “—Termination and Dissolution.” Except as described below, our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. After March 2, 2025, the holders of preferred units (or common units issued upon conversion thereof) may, if they hold 66 2/3% of the common units (or would, on conversion of all preferred units), act by written consent to remove the general partner and provide for the election of a successor general partner. Our partnership agreement also provides that if NRP (GP) LP is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal, the general partner will have the right to convert its general partner interest into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time. In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to the fair market value of that interest. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market 9 value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value. If the above-described options are not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of that interest as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph. In addition, we will be required to reimburse the departing general partner for all amounts due to the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit. Transfer of General Partner Interest Our general partner may transfer all or any part of its general partner interest without first obtaining approval of any unitholder, and that transfer will not constitute a violation of our partnership agreement. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters. Transfer of Ownership Interests in the General Partner At any time, the partners of our general partner may sell or transfer all or part of their partnership interests in our general partner without the approval of the unitholders. Change of Management Provisions Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove NRP (GP) LP as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to (i) any person or group that acquires the units from our general partner or its affiliates, (ii) any transferees of that person or group approved by our general partner, (iii) any person or group who acquires the units with the prior approval of the board of directors of our general partner, (iv) Blackstone or GoldenTree (or their affiliates) and each of their respective transferees with respect to their ownership of preferred units, (v) Blackstone or GoldenTree (or their affiliates) and each of their respective transferees with respect to their ownership of common units issued upon conversion of preferred units, common units issued upon exercise of the warrants or common units otherwise owned on the date of conversion or exercise, (vi) any holder of preferred units in connection with any vote, consent or approval of the holders of the preferred units as a separate class or (vii) any group if the majority of units held by such group are held by Blackstone or GoldenTree (or their respective affiliates) and each of their respective transferees of preferred units with respect to their ownership common units issued upon conversion of preferred units, common units issued upon exercise of the warrants or common units otherwise owned on the date of conversion or exercise. Our partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist, our general partner will have the right to convert its general partner interest into common units or to receive cash in exchange for those interests. Limited Call Right If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, excluding preferred units, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class, excluding preferred units, held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of: • the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and • the current market price as of the date three days before the date the notice is mailed. 10 As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Meetings; Voting Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, shall be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast. Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage. Each record holder of a common unit or a preferred unit has one vote per unit, with the preferred units being voted on an as-converted basis, although additional limited partner interests having special voting rights could be issued. See “—Issuance of Additional Securities.” However, if at any time any person or group, other than (i) our general partner and its affiliates, (ii) a direct or subsequently approved transferee of our general partner or its affiliates, (iii) a person or group who acquires the units with the prior approval of the board of directors, (iv) Blackstone or GoldenTree (or their affiliates) and each of their respective transferees with respect to their ownership of preferred units, (v) Blackstone or GoldenTree (or their affiliates) and each of their respective transferees with respect to their ownership of common units issued upon conversion of preferred units, common units issued upon exercise of the warrants or common units otherwise owned on the date of conversion or exercise, (vi) any holder of preferred units in connection with any vote, consent or approval of the holders of the preferred units as a separate class or (vii) any group if the majority of units held by such group are held by Blackstone or GoldenTree (or their respective affiliates) and each of their respective transferees of preferred units with respect to their ownership common units issued upon conversion of preferred units, common units issued upon exercise of the warrants or common units otherwise owned on the date of conversion or exercise, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, the person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name accounts will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent. Status as Limited Partner or Assignee Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions. An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee who has not become a substitute limited partner at the written direction of the assignee. See “—Meetings; Voting.” Transferees who do not execute and deliver a transfer application will be treated neither as assignees 11 nor as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports furnished to holders of common units. See “—Common Units—Transfer of Common Units.” Non-Citizen Assignees; Redemption If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem, upon 30 days’ advance notice, the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Indemnification Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events: • • • • • our general partner; any departing general partner; any person who is or was an affiliate of a general partner or any departing general partner; any person who is or was a member, partner, officer, director, employee, agent or trustee of any of our subsidiaries, a general partner or any departing general partner or any affiliate of any of our subsidiaries, a general partner or any departing general partner; or any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner as an officer, director, employee, member, partner, agent or trustee of another person. Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees in its sole discretion, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement. Reimbursement of Expenses Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other necessary appropriate expenses allocable to us or otherwise reasonably incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated our general partner by its affiliates. The general partner is entitled to determine expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Books and Records Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year. We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter. 12 We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information. Right to Inspect Our Books and Records Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him: • • • • • • a current list of the name and last known address of each partner; a copy of our tax returns; information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner; copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed; information regarding the status of our business and financial condition; and any other information regarding our affairs as is just and reasonable. Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential. Registration Rights Under our partnership agreement, we have agreed to register for sale under the Securities Act of 1933 and applicable state securities laws any common units or other partnership securities proposed to be sold by our general partner or any of its affiliates if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We have also agreed to include any partnership securities held by our general partner or its affiliates in any registration statement that we file to offer partnership securities for cash, except an offering relating solely to an employee benefit plan, for the same period. We are obligated to pay all expenses incidental to the registration of common units for sale, excluding underwriting discounts and commissions. Cash Distributions Distributions of Available Cash General. Within approximately 60 days after the end of each quarter, we will distribute all available cash to our general partner and our unitholders of record on the applicable record date. First, we will make distributions on the preferred units at a rate of 12% per year, up to one half of which we may make in PIK units. We will use all remaining available cash to pay distributions to our general partner and our common unitholders pro rata. Definition of Available Cash. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter: • less the amount of cash reserves that the general partner determines in its reasonable discretion is necessary or appropriate to: • • • provide for the proper conduct of our business; comply with applicable law, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner; 13 • plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. 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 our partnership agreement) is greater than 3.25x, or (ii) the ratio of our Distributable Cash Flow (as defined in our 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), 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. Distributions of Cash Upon Liquidation If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation. Manner of Adjustment for Gain. The manner of the adjustment is set forth in the partnership agreement. If our liquidation occurs, we will allocate any gain to the partners in the following manner: • First, to our general partner in the amount of certain prior loss allocations to the general partner; and • Second, to our general partner and our unitholders (other than holders of preferred units), pro rata. Manner of Adjustment for Loss. The manner of the adjustment is set forth in the partnership agreement. If our liquidation occurs, we will allocate any loss to the partners in the following manner: • First, to our general partner and our unitholders (other than holders of preferred units) in proportion to the positive balance in their capital accounts until the capital accounts of the general partner and the unitholders have been reduced to zero without regard to any preferred units then held by the unitholders; • • Second, to our unitholders (other than holders of preferred units) to the extent of and in proportion to the positive balances in their capital accounts; Third, to the holders of our preferred units, to the extent of and in proportion to the positive balances in their capital accounts; and • Fourth, to our general partner. Manner of Adjustment for Preferred Units. Notwithstanding the foregoing, the partnership agreement provides that if our liquidation occurs and the per unit capital amount of each preferred unit does not equal or exceed the Liquidation Value (as defined in the partnership agreement) after taking into account all other applicable adjustments, then items of income, gain, loss and deduction shall be allocated (or reallocated, as necessary) among the general partner and the unitholders in a manner determined appropriate by the general partner so as to cause, to the maximum extent possible, the per unit capital amount of each preferred unit to equal the Liquidation Value. To the extent the Liquidation Value of a preferred unit exceeds the capital account balance with respect to the preferred unit, the holder of the preferred unit will be entitled to a guaranteed payment in an amount equal to such excess prior to the making of liquidating distributions. Adjustments to Capital Accounts Upon the Issuance of Additional Units. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive interim adjustments to the capital accounts, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or distributions of property or upon liquidation in a manner which results, to the extent possible, in the capital account balance of the general partner equaling the amount which would have been in its capital account if no earlier positive adjustments to the capital accounts had been made. 14 Exhibit 10.13 Form of Phantom Unit Award Agreement (Employees and Service Providers) This Phantom Unit Award Agreement (this “Agreement”) is made and entered into as of [ ] (the “Date of Grant”) by and between GP Natural Resource Partners LLC, a Delaware limited liability company (“GP LLC”), and [ ] (“you” or “Service Provider”). Capitalized terms used but not specifically defined herein shall have the meanings specified in the Natural Resource Partners L.P. 2017 Long Term Incentive Plan (the “Plan”). WHEREAS, Natural Resource Partners L.P., a Delaware limited partnership (the “Partnership”), acting through the Board of Directors of GP LLC (the “Board”), the general partner of NRP (GP) LP, a Delaware limited partnership, the general partner of the Partnership (the “General Partner”), GP LLC has adopted the Plan under which GP LLC is authorized to grant Phantom Units to certain Service Providers of the Partnership; WHEREAS, the Partnership, in order to induce you to enter into and to continue to dedicate service to the Partnership and to materially contribute to the success of the Partnership, agrees to grant you the Phantom Unit Award; WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of this Agreement as if fully set forth herein; and WHEREAS, you desire to accept the Phantom Unit Award made pursuant to this Agreement. NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for other valuable consideration hereinafter set forth, the parties agree as follows: 1. The Grant. Subject to the conditions set forth below, the Partnership hereby grants you effective as of the Date of Grant, as a matter of separate inducement but not in lieu of any salary or other compensation for your services to the Partnership, an Award consisting of [ ] Phantom Units (the “Phantom Unit Award”) in accordance with the terms and conditions set forth in this Agreement and the Plan, whereby each Phantom Unit represents the right to receive one Unit on the date the Forfeiture Restrictions expire with respect to such Phantom Unit. 2. Phantom Unit Account. The Partnership shall establish and maintain a bookkeeping account on its records for you (a “Phantom Unit Account”) and shall record in such Phantom Unit Account: (a) the number of Phantom Units granted to you, (b) the amount deliverable to you at settlement on account of Phantom Units that have vested and (c) the amount of any distribution equivalent rights credited to you in accordance with Section 5 hereof. You shall not have any interest in any fund or specific assets of the Partnership by reason of this Award or the Phantom Unit Account established for you. 3. Rights of Service Provider. No Units shall be issued to you at the time the grant is made, and you shall not be, nor have any of the rights and privileges of, a unitholder or limited partner of the Partnership with respect to any Phantom Units recorded in the Phantom Unit Account. You shall have no voting rights with respect to the Phantom Units. 1 4. Vesting of Phantom Units. The Phantom Units are restricted in that they may be forfeited by the Service Provider and in that they may not, except as otherwise provided in the Plan, be transferred or otherwise disposed of by the Service Provider. Subject to the terms and conditions of this Agreement, the restrictions with respect to the Phantom Unit Award (including any associated DERs) will expire and such Phantom Units will become vested and nonforfeitable as set forth on Schedule I hereto; provided, however, that the restrictions will expire on such date(s) only if your service relationship with GP LLC, the General Partner, the Partnership, or any of the Partnership’s subsidiaries (collectively, the “Partnership Group”) continues from the Date of Grant through the applicable vesting date. 5. Distribution Equivalent Rights. The Partnership hereby grants to you rights to dividend equivalents with respect to the Phantom Units granted pursuant to this Agreement (“DERs”). The DERs awarded to you under this Section 5 shall entitle you to the payment, with respect to each Unit that is subject to a Phantom Unit granted pursuant to this Agreement that has not been cancelled or forfeited, of an amount in cash equal to the amount of any cash dividend or Unit distribution paid by the GP LLC with respect to one Unit while such Phantom Unit remains outstanding. Such amount shall be subject to the same vesting schedule as the Phantom Unit to which it relates and shall be paid to you in cash on the date that the Phantom Unit to which it relates is settled in accordance with Section 8 hereof. No interest shall be payable or otherwise owed with respect to such DERs for the period of time beginning on the date a distribution is paid to the Partnership’s unitholders and ending on the date the DERs are paid to you pursuant to this Agreement. Any DERs which relate to a Phantom Unit that do not become vested shall be forfeited at the same time the related Phantom Unit is forfeited. 6. Terminations of Services. Except as otherwise provided in Sections 6(a), (b), (c), and (d) below, if your service relationship with the Partnership Group is terminated for any reason, then the portion of the Phantom Unit Award (and any associated DERs) for which the Forfeiture Restrictions have not lapsed as of the date of termination shall become null and void and such Phantom Units shall be forfeited. The portion of the Phantom Unit Award for which the Forfeiture Restrictions have lapsed as of the date of such termination shall not be forfeited. a. Death or Disability. If your service relationship with the Partnership Group is terminated due to your death or Disability, then the Forfeiture Restrictions on the Phantom Unit Award shall immediately lapse, and the Phantom Unit Award will be fully vested as of such termination. For purposes of this Phantom Unit Award, “Disability” shall have the meaning given such term in any employment agreement between you and the Partnership or its Affiliates. Provided, however, that if there is no existing employment agreement between you and the Partnership or its Affiliates, the term “Disability” shall mean that you are unable to engage in substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. b. Change of Control. In the event of a Change of Control, the Forfeiture Restrictions on the Phantom Unit Award shall immediately lapse, and the Phantom Unit Award will be fully vested as of the date of such Change of Control. 2 c. Termination of Service Provider Without Cause. If your service relationship with the Partnership Group is terminated by the Partnership or any of its Affiliates for any reason other than for Cause, then the Forfeiture Restrictions on the Phantom Unit Award shall immediately lapse, and the Phantom Unit Award will be fully vested as of such termination. “Cause” means one or more of the following events: (i) a Service Provider’s continued failure, after written notice is given and a reasonable opportunity to cure has been granted, to comply with the reasonable written directives of the Partnership or any of its Affiliates, (ii) a Service Provider’s failure to comply in any material respect with the written terms of employment with the Partnership or any of its Affiliates, (iii) a Service Provider’s willful misconduct resulting in material and demonstrable damage to the Partnership or any of its Affiliates, including, without limitation, theft, embezzlement or material misrepresentations or concealments on any written reports submitted to such the Partnership or any of its Affiliates, (iv) Service Provider’s conviction of, or plea of nolo contendere to, any felony or to any crime or offense involving acts of theft, fraud, embezzlement or similar conduct or (v) Service Provider’s material breach of written policies of the Partnership or any of its Affiliates concerning employee discrimination or harassment, after written notice is given and a reasonable opportunity to cure been granted, if such breach is capable of being cured without penalty or damages to the Partnership or any of its Affiliates. d. Termination by Service Provider for Good Reason. If your service relationship with the Partnership Group is terminated due to Good Reason, then the Forfeiture Restrictions on the Phantom Unit Award shall immediately lapse, and the Phantom Unit Award will be fully vested as of such termination. “Good Reason” means the occurrence, without the Service Provider’s express written consent of (i) a reduction in Service Provider’s then current annual base salary of 10% or more; or (ii) a material diminution in Service Provider’s authority, duties or responsibilities (other than a mere change in the person or persons to whom Service Provider reports); provided, however, that Service Provider must give written notice to the Partnership Group of the existence of such a condition described in (i) or (ii) above within ninety (90) days of the initial existence of the condition, and the Partnership Group shall have thirty (30) days from the date when such notice is provided to cure the condition (if such condition can be cured) without being required to accelerate vesting for unvested awards due to termination of employment. To the extent that notice is provided in accordance with the foregoing sentence and the condition is not cured within the 30-day period, then Service Provider must actually terminate such Service Provider’s relationship with the Partnership Group within six (6) months of the initial occurrence of any of the conditions above for such termination to qualify as Good Reason. 7. Leave of Absence. With respect to the Phantom Unit Award, the Partnership may, in its sole discretion, determine that if you are on a leave of absence for any reason, you will be considered to still be a Service Provider to the Partnership Group; provided, that rights to the Phantom Unit Award during a leave of absence will be limited to the extent to which those rights were earned or vested when the leave of absence began. 8. Settlement Date; Manner of Settlement. Promptly following the expiration of the Forfeiture Restrictions and upon receipt by the Partnership of any tax withholding as may be required pursuant to Section 9, but in no event later than the first March 15 following the date the Forfeiture Restrictions expire with respect to a Phantom Unit, the Partnership shall deliver to you the number 3 of Units equal to the number of Phantom Units granted to you hereunder as to which the Forfeiture Restrictions have lapsed. In addition, the Partnership shall deliver to you an amount of cash equal to the DERs that relate to the Phantom Units as to which the Forfeiture Restrictions have lapsed. The amounts deliverable pursuant to this Section 8 shall not bear any interest owing to the passage of time. 9. Payment of Taxes. The Partnership may require you to pay to the Partnership (or a Partnership Affiliate if you are a Service Provider to a Partnership Affiliate) an amount the Partnership deems necessary to satisfy its (or its Affiliate’s) current or future obligation to withhold federal, state or local income or other taxes that you incur as a result of the Phantom Unit Award. With respect to any required tax withholding, the Partnership (or its Affiliate) may withhold from the amount deliverable to you under this Agreement the amount necessary or appropriate to satisfy the Partnership’s (or its Affiliate’s) obligation to withhold taxes. 10. Clawback. Notwithstanding any provisions in the Plan or this Agreement to the contrary, any portion of the payments and benefits provided under this Agreement shall be subject to any clawback policy adopted by GP LLC, including any such policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission, and including any such clawback policies adopted with retroactive effect. 11. Right of the Partnership and its Affiliates to Terminate Services. Nothing in this Agreement confers upon you the right to continue as a Service Provider to the Partnership Group, or interfere in any way with the rights of any member of the Partnership Group to terminate your service relationship at any time. 12. Furnish Information. You agree to furnish to the Partnership all information requested by the Partnership to enable it to comply with any reporting or other requirements imposed upon the Partnership by or under any applicable statute or regulation. 13. No Liability for Good Faith Determinations. The Partnership and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Phantom Unit Award. 14. Executions of Receipts and Releases. Any payment of cash or other property to you, or to your legal representative, heir, legatee or distributee in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Partnership may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefor in such form as it shall determine. 15. No Guarantee of Interests. The Board and the Partnership do not guarantee the Phantom Units from loss or depreciation. 16. Partnership Records. Records of the Partnership or its Affiliates regarding your period of service, termination of service and the reason(s) therefor, leaves of absence, re- 4 employment, and other matters shall be conclusive for all purposes hereunder, unless determined by the Partnership to be incorrect. 17. Notice. All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the Person to whom it is properly addressed or if earlier, the date it is sent via certified United States mail or reputable overnight delivery service (charges prepaid). 18. Waiver of Notice. Any Person entitled to notice hereunder may waive such notice in writing. 19. Successors. The Partnership may assign any of its rights under this Agreement without your consent. This Agreement shall be binding upon and inure to the benefit of the successors and assigns of GP LLC, the General Partner and the Partnership. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement and the Forfeiture Restrictions shall be binding upon and enforceable against you and your beneficiaries, executors, administrators and the person(s) to whom the Phantom Unit Award may be transferred by will or the laws of descent or distribution. 20. Tax Consultation. Service Provider acknowledges and agrees that (a) Service Provider is not relying upon any determination by GP LLC, the General Partner, the Partnership, any of their respective Affiliates, or any of their respective employees, directors, officers, attorneys, or agents (collectively, the “Partnership Parties”) of the Fair Market Value of the Units on the Date of Grant, (b) Service Provider is not relying upon any written or oral statement or representation of the Partnership Parties regarding the tax effects associated with your execution of the Agreement and his or her receipt, holding and vesting of the Phantom Unit Award, and (c) in deciding to enter into this Agreement, Service Provider is relying on his or her own judgment and the judgment of the professionals of Service Provider’s choice with whom he or she has consulted. Service Provider hereby releases, acquits and forever discharges the Partnership Parties from all actions, causes of actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the tax effects associated with Service Provider’s execution of the Agreement and his or her receipt, holding and exercise of the Phantom Unit Award. 21. Severability. If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein. 22. Partnership or Committee Action. Any action required of GP LLC, the Partnership or the General Partner shall be by resolution of the Board or Committee or by a Person or entity authorized to act by resolution of the Board or Committee. 23. Headings. The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof. 5 24. Governing Law. All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of the State of Delaware, without giving any effect to any conflict of law provisions thereof, except to the extent Delaware state law is preempted by federal law. 25. Consent to Electronic Delivery; Electronic Signature. In lieu of receiving documents in paper format, the Service Provider hereby consents to receive documents from the Partnership, GP LLC, the General Partner, and any plan administrator by means of electronic delivery, provided that such delivery complies with the rules, regulations and guidance issued by the Securities and Exchange Commission and any other applicable government agency. This consent shall be effective for the entire time that the Service Provider is a participant in the Plan. 26. Consent to Jurisdiction and Venue. You hereby consent and agree that state courts located in Harris County, Texas and the United States District Court for the Southern District of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Partnership (or its Affiliate) arising in connection with the Phantom Unit Award or this Agreement. In any dispute with the Partnership (or its Affiliate), you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum. 27. Amendment. This Agreement may be amended by the Board or by the Committee at any time in a manner consistent with Section 7(a) of the Plan. 28. Terms of Agreement. This Agreement is subject to all the terms, conditions, limitations and restrictions contained in this Agreement and the Plan. Except as provided in Section 6 of this Agreement, together, the Agreement and Plan constitute the entire agreement of the parties with regard to the subject matter hereof, and contain all the covenants, promises, representations, warranties and agreements between the parties with respect to the Phantom Units granted hereby. Without limiting the scope of the preceding sentence, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. 6 IN WITNESS HEREOF, GP LLC has caused this Agreement to be executed by its officer thereto duly authorized, and Service Provider has set his or her hand as to the date and year first written above. GP Natural Resource Partners LLC, a Delaware limited liability company By: Name: Title: [SERVICE PROVIDER NAME] 7 SCHEDULE I Vesting Date Number of Phantom Units 8 Exhibit 10.14 Form of Phantom Unit Award Agreement (Non-Employee Director without Deferral Election) This Phantom Unit Award Agreement (this “Agreement”) is made and entered into as of [ ] (the “Date of Grant”) by and between GP Natural Resource Partners LLC, a Delaware limited liability company (“GP LLC”), and [ ] (“you” or “Service Provider”). Capitalized terms used but not specifically defined herein shall have the meanings specified in the Natural Resource Partners L.P. 2017 Long Term Incentive Plan (the “Plan”). WHEREAS, Natural Resource Partners L.P., a Delaware limited partnership (the “Partnership”), acting through the Board of Directors of GP LLC (the “Board”), the general partner of NRP (GP) LP, a Delaware limited partnership, the general partner of the Partnership (the “General Partner”), GP LLC has adopted the Plan under which GP LLC is authorized to grant Phantom Units to certain Service Providers of the Partnership; WHEREAS, the Partnership, in order to induce you to enter into and to continue to dedicate service to the Partnership and to materially contribute to the success of the Partnership, agrees to grant you the Phantom Unit Award; WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of this Agreement as if fully set forth herein; and WHEREAS, you desire to accept the Phantom Unit Award made pursuant to this Agreement. NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for other valuable consideration hereinafter set forth, the parties agree as follows: 1. The Grant. Subject to the conditions set forth below, the Partnership hereby grants you effective as of the Date of Grant, as a matter of separate inducement but not in lieu of any salary or other compensation for your services to the Partnership, an Award consisting of [ ] Phantom Units (the “Phantom Unit Award”) in accordance with the terms and conditions set forth in this Agreement and the Plan, whereby each Phantom Unit represents the right to receive one Unit on the date the Forfeiture Restrictions expire with respect to such Phantom Unit. 2. Phantom Unit Account. The Partnership shall establish and maintain a bookkeeping account on its records for you (a “Phantom Unit Account”) and shall record in such Phantom Unit Account: (a) the number of Phantom Units granted to you, (b) the amount deliverable to you at settlement, and (c) the amount of any distribution equivalent rights credited to you in accordance with Section 5 hereof. You shall not have any interest in any fund or specific assets of the Partnership by reason of this Award or the Phantom Unit Account established for you. 3. Rights of Service Provider. No Units shall be issued to you at the time the grant is made, and you shall not be, nor have any of the rights and privileges of, a unitholder or limited partner of the Partnership with respect to any Phantom Units recorded in the Phantom Unit Account. You shall have no voting rights with respect to the Phantom Units. 4. Vesting and Transferability. The Phantom Units are restricted in that they may be forfeited by the Service Provider and in that they may not, except as otherwise provided in the Plan, be transferred or otherwise disposed of by the Service Provider. Subject to the terms and conditions of this Agreement, the restrictions with respect to the Phantom Unit Award (including any associated DERs) will expire and such Phantom Units will become vested and nonforfeitable on the one year anniversary of the Date of Grant; provided, however, that the restrictions will expire on such date only if you remain a member of the Board continuously from the Date of Grant through the vesting date. 5. Distribution Equivalent Rights. The Partnership hereby grants to you rights to dividend equivalents with respect to the Phantom Units granted pursuant to this Agreement (“DERs”). The DERs awarded to you under this Section 5 shall entitle you to the payment, with respect to each Unit that is subject to a Phantom Unit granted pursuant to this Agreement, of an amount in cash equal to the amount of any cash dividend or Unit distribution paid by the GP LLC with respect to one Unit while such Phantom Unit remains outstanding. Such amount shall be subject to the same vesting schedule as the Phantom Unit to which it relates and shall be paid to you in cash on the date that the Phantom Unit to which it relates is settled in accordance with Section 8 hereof. No interest shall be payable or otherwise owed with respect to such DERs for the period of time beginning on the date a distribution is paid to the Partnership’s unitholders and ending on the date the DERs are paid to you pursuant to this Agreement. 6. Termination of Board Service. If your service as a member of the Board terminates for any reason, then the portion of the Phantom Unit Award (and any associated DERs) for which the Forfeiture Restrictions have not lapsed as of the date of termination shall become null and void and such Phantom Units shall be forfeited. 7. Leave of Absence. With respect to the Phantom Unit Award, the Partnership may, in its sole discretion, determine that if you are on a leave of absence for any reason, you will be considered to still be a Service Provider to the Partnership Group; provided, that rights to the Phantom Unit Award during a leave of absence will be limited to the extent to which those rights were earned or vested when the leave of absence began. 8. Settlement Date; Manner of Settlement. Promptly following the expiration of the Forfeiture Restrictions, but in no event later than the first March 15 following the date the Forfeiture Restrictions expire with respect to a Phantom Unit, the Partnership shall deliver to you the number of Units equal to the number of Phantom Units granted to you hereunder as to which the Forfeiture Restrictions have lapsed. In addition, the Partnership shall deliver to you an amount of cash equal to the DERs that relate to the Phantom Units as to which the Forfeiture Restrictions have lapsed. The amounts deliverable pursuant to this Section 8 shall not bear any interest owing to the passage of time. 9. Right of the Partnership and its Affiliates to Terminate Services. Nothing in this Agreement confers upon you the right to continue as a Service Provider for the Partnership or its Affiliates, or interfere in any way with the rights of the Partnership or its Affiliates to terminate your service relationship at any time. 2 10. Furnish Information. You agree to furnish to the Partnership all information requested by the Partnership to enable it to comply with any reporting or other requirements imposed upon the Partnership by or under any applicable statute or regulation. 11. No Liability for Good Faith Determinations. The Partnership and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Phantom Unit Award. 12. Executions of Receipts and Releases. Any payment of cash or other property to you, or to your legal representative, heir, legatee or distributee in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Partnership may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefor in such form as it shall determine. 13. No Guarantee of Interests. The Board and the Partnership do not guarantee the Phantom Units from loss or depreciation. 14. Partnership Records. Records of the Partnership or its Affiliates regarding your period of service, termination of service and the reason(s) therefor, leaves of absence, re- employment, and other matters shall be conclusive for all purposes hereunder, unless determined by the Partnership to be incorrect. 15. Notice. All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the Person to whom it is properly addressed or if earlier, the date it is sent via certified United States mail or reputable overnight delivery service (charges prepaid). 16. Waiver of Notice. Any Person entitled to notice hereunder may waive such notice in writing. 17. Successors. The Partnership may assign any of its rights under this Agreement without your consent. This Agreement shall be binding upon and inure to the benefit of the successors and assigns of GP LLC, the General Partner and the Partnership. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement shall be binding upon and enforceable against you and your beneficiaries, executors, administrators and the person(s) to whom the Phantom Unit Award may be transferred by will or the laws of descent or distribution. 18. Tax Consultation. Service Provider acknowledges and agrees that (a) Service Provider is not relying upon any determination by GP LLC, the General Partner, the Partnership, any of their respective Affiliates, or any of their respective employees, directors, officers, attorneys, or agents (collectively, the “Partnership Parties”) of the Fair Market Value of the Units on the Date of Grant, (b) Service Provider is not relying upon any written or oral statement or representation of the Partnership Parties regarding the tax effects associated with your execution of the Agreement and his or her receipt, holding and vesting of the Phantom Unit Award, and (c) in deciding to enter into this Agreement, Service Provider is relying on his or her own judgment and the judgment of 3 the professionals of Service Provider’s choice with whom he or she has consulted. Service Provider hereby releases, acquits and forever discharges the Partnership Parties from all actions, causes of actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the tax effects associated with Service Provider’s execution of the Agreement and his or her receipt, holding and exercise of the Phantom Unit Award. 19. Severability. If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein. 20. Partnership or Committee Action. Any action required of GP LLC, the Partnership or the General Partner shall be by resolution of the Board or Committee or by a Person or entity authorized to act by resolution of the Board or Committee. 21. Headings. The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof. 22. Governing Law. All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of the State of Delaware, without giving any effect to any conflict of law provisions thereof, except to the extent Delaware state law is preempted by federal law. 23. Consent to Electronic Delivery; Electronic Signature. In lieu of receiving documents in paper format, the Service Provider hereby consents to receive documents from the Partnership, GP LLC, the General Partner, and any plan administrator by means of electronic delivery, provided that such delivery complies with the rules, regulations and guidance issued by the Securities and Exchange Commission and any other applicable government agency. This consent shall be effective for the entire time that the Service Provider is a participant in the Plan. 24. Consent to Jurisdiction and Venue. You hereby consent and agree that state courts located in Harris County, Texas and the United States District Court for the Southern District of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Partnership (or its Affiliate) arising in connection with the Phantom Unit Award or this Agreement. In any dispute with the Partnership (or its Affiliate), you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum. 25. Amendment. This Agreement may be amended by the Board or by the Committee at any time in a manner consistent with Section 7(a) of the Plan. 26. Terms of Agreement. This Agreement is subject to all the terms, conditions, limitations and restrictions contained in this Agreement and the Plan. Together, this Agreement and the Plan constitute the entire agreement of the parties with regard to the subject matter hereof, and contain all the covenants, promises, representations, warranties and agreements between the parties with respect to the Phantom Units granted hereby. Without limiting the scope of the preceding 4 sentence, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. 5 IN WITNESS HEREOF, GP LLC has caused this Agreement to be executed by its officer thereto duly authorized, and Service Provider has set his or her hand as to the date and year first written above. GP Natural Resource Partners LLC, a Delaware limited liability company By: Name: Title: [NON-EMPLOYEE DIRECTOR] 6 Exhibit 10.15 Form of Phantom Unit Award Agreement (Non-Employee Director with Deferral) This Phantom Unit Award Agreement (this “Agreement”) is made and entered into as of [ ] (the “Date of Grant”) by and between GP Natural Resource Partners LLC, a Delaware limited liability company (“GP LLC”), and [ ] (“you” or “Service Provider”). Capitalized terms used but not specifically defined herein shall have the meanings specified in the Natural Resource Partners L.P. 2017 Long Term Incentive Plan (the “Plan”). WHEREAS, Natural Resource Partners L.P., a Delaware limited partnership (the “Partnership”), acting through the Board of Directors of GP LLC (the “Board”), the general partner of NRP (GP) LP, a Delaware limited partnership, the general partner of the Partnership (the “General Partner”), GP LLC has adopted the Plan under which GP LLC is authorized to grant Phantom Units to certain Service Providers of the Partnership; WHEREAS, the Partnership, in order to induce you to enter into and to continue to dedicate service to the Partnership and to materially contribute to the success of the Partnership, agrees to grant you the Phantom Unit Award; WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of this Agreement as if fully set forth herein; and WHEREAS, pursuant to that certain Natural Resource Partners L.P. 2017 Director Time of Settlement Election Form entered into between GP LLC and Service Provider, effective as of December 29, 2017 (the “Deferral Election Form”), the Service Provider has elected to receive this Phantom Unit Award; and WHEREAS, you desire to accept the Phantom Unit Award made pursuant to this Agreement. NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for other valuable consideration hereinafter set forth, the parties agree as follows: 1. The Grant. Subject to the conditions set forth below, the Partnership hereby grants you effective as of the Date of Grant, as a matter of separate inducement but not in lieu of any salary or other compensation for your services to the Partnership, an Award consisting of [ ] Phantom Units (the “Phantom Unit Award”) in accordance with the terms and conditions set forth in this Agreement and the Plan, whereby each Phantom Unit represents the right to receive one Unit on the date the deferral period, as contained in the Deferral Election Form (the “Deferral Period”) ends with respect to such Phantom Unit. 2. Phantom Unit Account. The Partnership shall establish and maintain a bookkeeping account on its records for you (a “Phantom Unit Account”) and shall record in such Phantom Unit Account: (a) the number of Phantom Units granted to you, (b) the amount deliverable to you at settlement, and (c) the amount of any distribution equivalent rights credited to you in accordance with Section 5 hereof. You shall not have any interest in any fund or specific assets of the Partnership by reason of this Award or the Phantom Unit Account established for you. 1 3. Rights of Service Provider. No Units shall be issued to you at the time the grant is made, and you shall not be, nor have any of the rights and privileges of, a unitholder or limited partner of the Partnership with respect to any Phantom Units recorded in the Phantom Unit Account. You shall have no voting rights with respect to the Phantom Units. 4. Vesting and Transferability. The Phantom Units are restricted in that they may be forfeited by the Service Provider and in that they may not, except as otherwise provided in the Plan, be transferred or otherwise disposed of by the Service Provider. Subject to the terms and conditions of this Agreement, the restrictions with respect to the Phantom Unit Award (including any associated DERs) will expire and such Phantom Units will become vested and nonforfeitable on the one year anniversary of the Date of Grant; provided, however, that the restrictions will expire on such date only if you remain a member of the Board continuously from the Date of Grant through the vesting date. 5. Distribution Equivalent Rights. The Partnership hereby grants to you rights to dividend equivalents with respect to the Phantom Units granted pursuant to this Agreement (“DERs”). The DERs awarded to you under this Section 5 shall entitle you to the payment, with respect to each Unit that is subject to a Phantom Unit granted pursuant to this Agreement, of an amount in cash equal to the amount of any cash dividend or Unit distribution paid by the GP LLC with respect to one Unit while such Phantom Unit remains outstanding. . Such amount shall be subject to the same vesting schedule as the Phantom Unit to which it relates and shall be paid to you in cash on the date that the Phantom Unit to which it relates is settled in accordance with Section 8 hereof. No interest shall be payable or otherwise owed with respect to such DERs for the period of time beginning on the date a distribution is paid to the Partnership’s unitholders and ending on the date the DERs are paid to you pursuant to this Agreement. 6. Termination of Board Service. If your service as a member of the Board terminates for any reason, then the portion of the Phantom Unit Award (and any associated DERs) for which the Forfeiture Restrictions have not lapsed as of the date of termination shall become null and void and such Phantom Units shall be forfeited. 7. Leave of Absence. With respect to the Phantom Unit Award, the Partnership may, in its sole discretion, determine that if you are on a leave of absence for any reason, you will be considered to still be a Service Provider to the Partnership Group; provided, that rights to the Phantom Unit Award during a leave of absence will be limited to the extent to which those rights were earned or vested when the leave of absence began. 8. Settlement Date; Manner of Settlement. Provided the Phantom Units have not been forfeited pursuant to Section 6, promptly (but no later than 30 days) following the time of settlement set forth in your Deferral Election Form, the Partnership shall deliver to you the number of Units equal to the number of Phantom Units granted to you hereunder as to which the Deferral Period has ended. In addition, the Partnership shall deliver to you an amount of cash equal to the DERs that relate to the Phantom Units being settled. The amounts deliverable pursuant to this Section 8 shall not bear any interest owing to the passage of time. 2 9. Right of the Partnership and its Affiliates to Terminate Services. Nothing in this Agreement confers upon you the right to continue as a Service Provider for the Partnership or its Affiliates, or interfere in any way with the rights of the Partnership or its Affiliates to terminate your service relationship at any time. 10. Furnish Information. You agree to furnish to the Partnership all information requested by the Partnership to enable it to comply with any reporting or other requirements imposed upon the Partnership by or under any applicable statute or regulation. 11. No Liability for Good Faith Determinations. The Partnership and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Phantom Unit Award. 12. Executions of Receipts and Releases. Any payment of cash or other property to you, or to your legal representative, heir, legatee or distributee in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Partnership may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefor in such form as it shall determine. 13. No Guarantee of Interests. The Board and the Partnership do not guarantee the Phantom Units from loss or depreciation. 14. Partnership Records. Records of the Partnership or its Affiliates regarding your period of service, termination of service and the reason(s) therefor, leaves of absence, re- employment, and other matters shall be conclusive for all purposes hereunder, unless determined by the Partnership to be incorrect. 15. Notice. All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the Person to whom it is properly addressed or if earlier, the date it is sent via certified United States mail or reputable overnight delivery service (charges prepaid). 16. Waiver of Notice. Any Person entitled to notice hereunder may waive such notice in writing. 17. Successors. The Partnership may assign any of its rights under this Agreement without your consent. This Agreement shall be binding upon and inure to the benefit of the successors and assigns of GP LLC, the General Partner and the Partnership. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement shall be binding upon and enforceable against you and your beneficiaries, executors, administrators and the person(s) to whom the Phantom Unit Award may be transferred by will or the laws of descent or distribution. 18. Tax Consultation. Service Provider acknowledges and agrees that (a) Service Provider is not relying upon any determination by GP LLC, the General Partner, the Partnership, any of their respective Affiliates, or any of their respective employees, directors, officers, attorneys, 3 or agents (collectively, the “Partnership Parties”) of the Fair Market Value of the Units on the Date of Grant, (b) Service Provider is not relying upon any written or oral statement or representation of the Partnership Parties regarding the tax effects associated with your execution of the Agreement and his or her receipt, holding and vesting of the Phantom Unit Award, and (c) in deciding to enter into this Agreement, Service Provider is relying on his or her own judgment and the judgment of the professionals of Service Provider’s choice with whom he or she has consulted. Service Provider hereby releases, acquits and forever discharges the Partnership Parties from all actions, causes of actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the tax effects associated with Service Provider’s execution of the Agreement and his or her receipt, holding and exercise of the Phantom Unit Award. 19. Severability. If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein. 20. Partnership or Committee Action. Any action required of GP LLC, the Partnership or the General Partner shall be by resolution of the Board or Committee or by a Person or entity authorized to act by resolution of the Board or Committee. 21. Headings. The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof. 22. Governing Law. All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of the State of Delaware, without giving any effect to any conflict of law provisions thereof, except to the extent Delaware state law is preempted by federal law. 23. Consent to Electronic Delivery; Electronic Signature. In lieu of receiving documents in paper format, the Service Provider hereby consents to receive documents from the Partnership, GP LLC, the General Partner, and any plan administrator by means of electronic delivery, provided that such delivery complies with the rules, regulations and guidance issued by the Securities and Exchange Commission and any other applicable government agency. This consent shall be effective for the entire time that the Service Provider is a participant in the Plan. 24. Consent to Jurisdiction and Venue. You hereby consent and agree that state courts located in Harris County, Texas and the United States District Court for the Southern District of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Partnership (or its Affiliate) arising in connection with the Phantom Unit Award or this Agreement. In any dispute with the Partnership (or its Affiliate), you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum. 25. Amendment. This Agreement may be amended by the Board or by the Committee at any time in a manner consistent with Section 7(a) of the Plan. 4 26. Terms of Agreement. This Agreement is subject to all the terms, conditions, limitations and restrictions contained in this Agreement, the Deferral Election Form and the Plan. Together, this Agreement, the Deferral Election Form and the Plan constitute the entire agreement of the parties with regard to the subject matter hereof, and contain all the covenants, promises, representations, warranties and agreements between the parties with respect to the Phantom Units granted hereby. Without limiting the scope of the preceding sentence, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. 5 IN WITNESS HEREOF, GP LLC has caused this Agreement to be executed by its officer thereto duly authorized, and Service Provider has set his or her hand as to the date and year first written above. GP Natural Resource Partners LLC, a Delaware limited liability company By: Name: Title: [NON-EMPLOYEE DIRECTOR] 6 Exhibit 21.1 List of Subsidiaries of Natural Resource Partners L.P. NRP (Operating) LLC NRP Oil and Gas LLC NRP Finance Corporation WPP LLC ACIN LLC WBRD LLC Hod LLC Shepard Boone Coal Company LLC Gatling Mineral, LLC Independence Land Company, LLC Williamson Transport, LLC Little River Transport, LLC Rivervista Mining, LLC Deepwater Transportation, LLC NRP Trona LLC BRP LLC (51% interest) CoVal Leasing Company, LLC (51% interest) Consent of Independent Registered Public Accounting Firm Exhibit 23.1 We consent to the incorporation by reference in the following Registration Statements: 1) Registration Statement (Form S-3 No. 333-217205) of Natural Resource Partners L.P., 2) Registration Statement (Form S-3 No. 333-187883) of Natural Resource Partners L.P., and 3) Registration Statement (Form S-8 No. 333-222970) pertaining to the Natural Resource Partners L.P. 2017 Long-Term Incentive Plan; of our reports dated February 27, 2020, with respect to the consolidated financial statements of Natural Resource Partners L.P., and the effectiveness of internal control over financial reporting of Natural Resource Partners L.P., included in this Annual Report (Form 10-K) of Natural Resource Partners L.P. for the year ended December 31, 2019. /s/ Ernst & Young LLP Houston, Texas February 27, 2020 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement Nos. 333-217205 and 333-187883 on Form S-3 and Registration Statement No. 333-222970 Form S-8 of Natural Resource Partners LP, of our report dated February 27, 2020, relating to the financial statements of Ciner Wyoming LLC as of December 31, 2019 and 2018, and for the three years in the period ended December 31, 2019, appearing in this Annual Report on Form 10-K of Natural Resource Partners LP for the year ended December 31, 2019. Exhibit 23.2 /s/ Deloitte & Touche LLP Atlanta, Georgia February 27, 2020 Exhibit 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER I, Corbin J. Robertson, Jr., certify that: 1 2 3 4 I have reviewed this report on Form 10-K of Natural Resource Partners L.P. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. b. c. d. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5 The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions); a. b. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. By: /s/ Corbin J. Robertson, Jr. Corbin J. Robertson, Jr. Chief Executive Officer Date: February 27, 2020 Exhibit 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER I, Christopher J. Zolas, certify that: 1. 2. 3. 4. I have reviewed this report on Form 10-K of Natural Resource Partners L.P. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. b. c. d. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions); a. b. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. By: /s/ Christopher J. Zolas Christopher J. Zolas Chief Financial Officer Date: February 27, 2020 Exhibit 32.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER OF GP NATURAL RESOURCE PARTNERS LLC PURSUANT TO 18 U.S.C. § 1350 In connection with the accompanying report on Form 10-K for the year ended December 31, 2019 filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Corbin J. Robertson, Jr., Chief Executive Officer of GP Natural Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the “Company”), hereby certify, to my knowledge, that: 1. 2. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. By: /s/ Corbin J. Robertson, Jr. Corbin J. Robertson, Jr. Chief Executive Officer Date: February 27, 2020 Exhibit 32.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER OF GP NATURAL RESOURCE PARTNERS LLC PURSUANT TO 18 U.S.C. § 1350 In connection with the accompanying report on Form 10-K for the year ended December 31, 2019 filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Christopher J. Zolas, Chief Financial Officer of GP Natural Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the “Company”), hereby certify, to my knowledge, that: 1. 2. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. By: /s/ Christopher J. Zolas Christopher J. Zolas Chief Financial Officer Date: February 27, 2020 Exhibit 99.1 Ciner Wyoming LLC (A Majority-Owned Subsidiary of Ciner Resources LP) Financial Statements as of December 31, 2019 and 2018 and for the Years Ended December 31, 2019, 2018, and 2017, and Report of Independent Registered Public Accounting Firm 1 CINER WYOMING LLC (A Majority Owned Subsidiary of Ciner Resources LP) TABLE OF CONTENTS REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM BALANCE SHEETS AS OF DECEMBER 31, 2019 AND 2018 STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017 STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 2019, 2018 AND 2017 STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017 NOTES TO THE FINANCIAL STATEMENTS Page Number 3 4 5 6 7 8 2 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”) as of December 31, 2019 and 2018, 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, 2019, and the related notes (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 the 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 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, 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. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ Deloitte & Touche LLP Atlanta, Georgia February 27, 2020 We have served as the Company’s auditor since 2008. 3 CINER WYOMING LLC (A Majority Owned Subsidiary of Ciner Resources LP) BALANCE SHEETS AS OF DECEMBER 31, 2019 AND 2018 (In thousands of dollars) ASSETS CURRENT ASSETS: Cash and cash equivalents Accounts receivable - affiliates Accounts receivable, net Inventory Other current assets Total current assets PROPERTY, PLANT, AND EQUIPMENT, NET OTHER NON-CURRENT ASSETS TOTAL ASSETS LIABILITIES AND MEMBERS' EQUITY CURRENT LIABILITIES: Accounts payable Due to affiliates Accrued expenses Total current liabilities LONG-TERM DEBT OTHER NON-CURRENT LIABILITIES Total liabilities COMMITMENTS AND CONTINGENCIES (See Note 12) MEMBERS' EQUITY: Members’ equity — Ciner Resources LP Members’ equity — Natural Resource Partners LP Accumulated other comprehensive loss Total members' equity 2019 2018 $ $ 13,684 95,115 35,963 24,193 1,741 7,124 70,359 36,870 22,275 1,452 170,696 138,080 258,121 226,411 24,266 26,332 $ 453,083 $ 390,823 $ $ 14,163 3,215 37,961 55,339 129,500 8,587 17,478 2,843 43,691 64,012 99,000 10,921 193,426 173,933 135,423 130,113 (5,879) 114,434 109,947 (7,491) 259,657 216,890 TOTAL LIABILITIES AND MEMBERS' EQUITY $ 453,083 $ 390,823 See notes to financial statements. 4 CINER WYOMING LLC (A Majority Owned Subsidiary of Ciner Resources LP) STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017 (In thousands of dollars) SALES - AFFILIATES SALES - OTHERS Total net sales COST OF PRODUCTS SOLD FREIGHT COSTS Total cost of products sold GROSS PROFIT 2019 2018 2017 $ 315,847 206,996 522,843 247,790 143,341 391,131 131,712 $ $ 253,345 233,414 486,759 243,562 139,144 304,497 192,843 497,340 237,445 145,693 382,706 383,138 104,053 114,202 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES 18,404 17,698 16,520 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS LOSS ON DISPOSAL OF ASSETS, NET LITIGATION SETTLEMENT GAIN OPERATING INCOME OTHER INCOME (EXPENSE): Interest income Interest expense Other expense, net Total other expense NET INCOME OTHER COMPREHENSIVE INCOME (LOSS) 1,553 — — 2,106 — (27,500) 1,543 1,569 — 111,755 111,749 94,570 350 (5,893) (57) 1,871 (5,058) (205) 1,663 (4,531) (179) (5,600) (3,392) (3,047) 106,155 108,357 91,523 Income (loss) on derivative financial instruments 1,612 (282) (3,930) COMPREHENSIVE INCOME $ 107,767 $ 108,075 $ 87,593 See notes to financial statements. 5 CINER WYOMING LLC (A Majority Owned Subsidiary of Ciner Resources LP) STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017 (In thousands of dollars) Balance at December 31, 2016 Allocation of net income Capital distribution to members Other comprehensive loss Balance at December 31, 2017 Allocation of net income Capital distribution to members Other comprehensive loss Balance at December 31, 2018 Allocation of net income Capital distribution to members Other comprehensive income Balance at December 31, 2019 Ciner Resources LP Natural Resource Partners LP Accumulated Other Comprehensive (Loss) Income Total Members' Equity $ $ $ $ 111,945 $ 107,556 $ (3,279) $ 216,222 46,677 (51,000) — 44,846 (49,000) — — — (3,930) 91,523 (100,000) (3,930) 107,622 $ 103,402 $ (7,209) $ 203,815 55,262 (48,450) — 53,095 (46,550) — — — (282) 108,357 (95,000) (282) 114,434 $ 109,947 $ (7,491) $ 216,890 54,139 (33,150) — 52,016 (31,850) — — — 1,612 106,155 (65,000) 1,612 135,423 $ 130,113 $ (5,879) $ 259,657 See notes to financial statements. 6 CINER WYOMING LLC (A Majority Owned Subsidiary of Ciner Resources LP) STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017 (In thousands of dollars) CASH FLOWS FROM OPERATING ACTIVITIES: Net income Adjustments to reconcile net income to net cash provided by operating activities: $ 106,155 $ 108,357 $ 91,523 2019 2018 2017 Depreciation, depletion and amortization Loss on disposal of assets, net Other non-cash items (Increase) decrease in: Accounts receivable - affiliates Accounts receivable, net Inventory Other current and non-current assets Increase (decrease) in: Accounts payable Accrued expenses and other liabilities Due to affiliates 26,440 642 304 (24,756) 907 (385) (123) (3,073) (73) 372 27,996 — 448 28,152 (2,683) (3,025) (228) 2,350 4,067 (240) Net cash provided by operating activities 106,410 165,194 26,827 1,569 299 (36,691) (792) 498 (189) 1,679 (1,124) (1,124) 82,475 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on revolving credit facility Repayments on revolving credit facility Repayments on other long-term debt Debt issuance costs Cash distribution to members Net cash used in financing activities (65,350) (39,419) (24,757) (65,350) (39,419) (24,757) 102,000 (71,500) — — (65,000) 104,000 (143,000) (11,400) — (95,000) 88,500 (28,500) (8,600) (1,097) (100,000) (34,500) (145,400) (49,697) NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 6,560 (19,625) 8,021 CASH AND CASH EQUIVALENTS: Beginning of year End of year SUPPLEMENTAL DISLCOSURES OF CASH FLOW INFORMATION: Interest paid during the year SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES : Capital expenditures on account 7,124 26,749 18,728 13,684 $ 7,124 $ 26,749 5,476 $ 5,141 $ 4,097 6,786 $ 14,002 $ 1,034 $ $ $ See notes to financial statements. 7 CINER WYOMING LLC (A Majority Owned Subsidiary of Ciner Resources LP) NOTES TO FINANCIAL STATEMENTS AS OF DECEMBER 31, 2019 AND 2018 AND FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017 (Dollars in thousands) 1. Corporate Structure A 51% membership interest in Ciner Wyoming LLC (the "Company," "Ciner Wyoming," "we," "us," or "our") is owned by Ciner Resources LP ("Ciner Resources" or the "Partnership"). NRP Trona LLC, a wholly owned subsidiary of Natural Resource Partners LP ("NRP") owns a 49% membership interest in the Company. Ciner Resources is a master limited partnership traded on the New York Stock Exchange and is currently owned approximately 72% by Ciner Wyoming Holding Co. ("Ciner Holdings"), approximately 2% by Ciner Resource Partners LLC (our “general partner” or “Ciner GP”) and approximately 26% by the general public. Ciner Holdings is 100% owned by Ciner Resources Corporation ("Ciner Corp") which is 100% owned by Ciner Enterprises, Inc. ("Ciner Enterprises"). As of December 31, 2019, Ciner Enterprises was 100% owned by WE Soda Ltd., a U.K. corporation (“WE Soda”). WE Soda is a direct wholly-owned subsidiary of KEW Soda Ltd., a U.K. corporation (“KEW Soda”), which is a direct wholly-owned subsidiary of Akkan Enerji ve Madencilik Anonim irketi ("Akkan"), which is 100% owned by Turgay Ciner, the Chairman of the Ciner Group, a Turkish conglomerate of companies engaged in energy and mining (including soda ash mining), media and shipping markets. On February 22, 2018, Akkan transferred its direct 100% ownership in Ciner Enterprises to KEW Soda, a U.K. company, which transferred such ownership to WE Soda, a U.K. company. WE Soda is 100% owned by KEW Soda, and KEW Soda is wholly owned by Akkan. This reorganization is a part of Ciner Group’s strategy to combine the global soda ash business under a common structure in the U.K. 2. Nature of Operations and Summary of Significant Accounting Policies Nature of Operations The Company's operations consist of the mining of trona ore, which, when processed, becomes soda ash. All our soda ash processed is sold to various domestic customers, and to American Natural Soda Ash Corporation ("ANSAC"), which is an affiliate for export sales. All mining and processing activities take place in one facility located in Green River, Wyoming. The Company began selling soda ash in late 2016 to Ciner Ic ve Dis Ticaret Anonim Sirketi ("CIDT"), an affiliate for export sales, and continued into 2017. However, there were no sales to CIDT during the years ended December 31, 2019 and December 31, 2018, as the contract with CIDT terminated in 2017. ANSAC Exit - On November 9, 2018, Ciner Resources Corporation delivered a notice to terminate its membership in ANSAC, a cooperative that serves as the primary international distribution channel for the Company as well as two other U.S. manufacturers of trona-based soda ash. The effective termination date of Ciner Corp’s membership in ANSAC is December 31, 2021 (the “ANSAC termination date”). 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. Potential liabilities associated with exiting ANSAC are not currently probable or estimable. ANSAC was the Company's largest customer for the years ended December 31, 2019, 2018 and 2017, accounting for 60.4%, 52.0% and 44.7%, respectively, of the Company's net sales. Although ANSAC has been the Company's largest customer for the years ended December 31, 2019, 2018, and 2017, the Company anticipates that the impact of such termination on its net sales, net income and liquidity will be limited. The Company made this determination primarily 8 based upon the belief that it will continue to be one of the lowest cost producers of soda ash in the global market that has historically seen demand for soda ash exceed supply of soda ash. After the ANSAC termination date, the Company expects Ciner Corp will begin marketing soda ash directly on the Company's behalf into international markets which are currently being served by ANSAC and intends to utilize the distribution network that has already been established by the global Ciner Group. The Company believes that by combining its volumes with Ciner Group’s soda ash exports from Turkey, Ciner Corp's withdrawal from ANSAC will allow the Company to leverage the larger, global Ciner Group’s soda ash operations which the Company expects will eventually lower its cost position and improve its ability to optimize our market share both domestically and internationally. Further, being able to work with the global Ciner Group will provide the Company the opportunity to attract and efficiently serve larger global customers. In addition, the Company will need access to an international logistics infrastructure that includes, among other things, a domestic port for export capabilities. These export capabilities are currently being developed by Ciner Enterprises and options being evaluated range from continued outsourcing in the near term to developing its own port capabilities in the longer term. The development costs of export capabilities are currently being paid by Ciner Enterprises, who are evaluating how these costs might be allocated to the Company, which could include ownership by the Company and repayment for the development costs and related assets or a service agreement model for logistics services which includes reimbursements for development costs. Since a decision to allocate costs to the Company has not been made yet and the Company is not currently using any Ciner Enterprises export services, none of these development costs have been recorded by the Company through December 31, 2019. A summary of the significant accounting policies is as follows: Basis of Presentation - The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Use of Estimates - The preparation of financial statements, in accordance with accounting principles generally accepted in the United States of America, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the dates of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Revenue Recognition - On May 28, 2014 the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customer, that requires companies to recognize revenue when a customer obtains control rather than when companies have transferred substantially all risks and rewards of a good or service. The Company adopted this ASC effective January 1, 2018, as permitted by the ASC, using the modified retrospective method and we have not made any adjustment to opening retained earnings. The Company has applied the provisions of this ASC and notes that our adoption of ASC 606 does not materially change the amount or timing of revenues recognized by us, nor does it materially affect our financial position. The majority of our revenues generated are recognized upon delivery and transfer of title to the product to our customers. The time at which delivery and transfer of title occurs, for the majority of our contracts with customers, is the point when the product leaves our facility, thereby rendering our performance obligation fulfilled. Additionally, the Company has made an accounting policy election to account for shipping and handling activities as fulfillment costs. Freight Costs - The Company includes freight costs billed to customers for shipments administered by the Company in gross sales. The related freight costs along with cost of products sold are deducted from gross sales to determine gross profit. Cash and Cash Equivalents - The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Cash equivalents consist primarily of money market deposit accounts. Accounts Receivable - Accounts receivable are carried at the original invoice amount less an estimate for doubtful receivables. We generally do not require collateral against outstanding accounts receivable. The allowance for doubtful 9 accounts is based on specifically identified amounts that the Company believes to be uncollectible. An additional allowance is recorded based on certain percentages of aged receivables, which are determined based on management’s assessment of the general financial conditions affecting the Company’s customer base. We determined that no allowance for doubtful accounts was required against receivables from affiliates as of December 31, 2019 and 2018. If actual collection experience changes, revisions to the allowance may be required. Accounts receivable are written off when deemed uncollectible. Recoveries of accounts receivable previously written off are recorded when received. During the years ended December 31, 2019, 2018 and 2017, there were no significant accounts receivable bad debt expenses, write- offs or recoveries. Inventory - Inventory is carried at the lower of cost or market. Cost is determined using the first-in, first-out method for raw material and finished goods inventory and the weighted average cost method for stores inventory. Costs include raw materials, direct labor and manufacturing overhead. Market is based on current replacement cost for raw materials and net realizable value for stores inventory and finished goods. • Raw material inventory includes material, chemicals and natural resources being used in the mining and refining process. • Finished goods inventory is the finished product soda ash. • Stores inventory includes parts, materials and operating supplies which are typically consumed in the production of soda ash and currently available for future use. Inventory expected to be consumed within the year is classified as current assets and remainder is classified as non-current assets. Property, Plant, and Equipment - Property, plant, and equipment are stated at cost less accumulated depreciation. Depreciation is computed over the estimated useful lives of depreciable assets, using the straight-line method. The estimated useful lives applied to depreciable assets are as follows: Land improvements Depletable land Buildings and building improvements Computer hardware Machinery and equipment Furniture and fixtures Useful Lives 10 years 15-60 years 10-30 years 3-5 years 5-20 years 10 years The Company's policy is to evaluate property, plant, and equipment for impairment whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. An indicator of potential impairment would include situations when the estimated future undiscounted cash flows are less than the carrying value. The amount of any impairment then recognized would be calculated as the difference between estimated fair value and the carrying value of the asset. Derivative Instruments and Hedging Activities - The Company may enter into derivative contracts from time to time to manage exposure to the risk of exchange rate changes on its foreign currency transactions, the risk of changes in natural gas prices, and the risk of the variability in interest rates on borrowings. Gains and losses on derivative contracts qualifying for hedge accounting are reported as a component of the underlying transactions. The Company follows hedge accounting for its hedging activities. All derivative instruments are recorded on the balance sheet at their fair values. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. The Company designates its derivatives based upon criteria established for hedge accounting under generally accepted accounting principles. For a derivative designated as a fair value hedge, the gain or loss is recognized in earnings in the period of change together with the offsetting gain or loss on the hedged item attributed to the risk being 10 hedged. For a derivative designated as a cash flow hedge, the effective portion of the derivative’s gain or loss is initially reported as a component of accumulated other comprehensive income (loss) and subsequently reclassified into earnings when the hedged exposure affects earnings. Any significant ineffective portion of the gain or loss is reported in earnings immediately. For derivatives not designated as hedges, the gain or loss is reported in earnings in the period of change. The natural gas physical forward contracts are accounted for under the normal purchases and normal sales scope exception. The Company has interest rate swap contracts, designated as cash flow hedges, to mitigate our exposure to possible increases in interest rates. The swap contracts consist of four individual $12,500 swaps with an aggregate notional value of $50,000 at both December 31, 2019 and December 31, 2018, and have various maturities through 2023. At December 31, 2019, it is anticipated that approximately $855 of losses currently recorded in accumulated other comprehensive income (loss) will be reclassified into earnings within the next twelve months. The Company has entered into financial natural gas forward contracts, designed as cash flow hedges, to mitigate volatility in the price of the natural gas the Company consumes. These contracts generally have various maturities through 2024. These contracts had an aggregate notional value of $31,196 and $41,206 at December 31, 2019 and December 31, 2018 respectively. Refer to footnote 12 for details surrounding both the physical and financial portions of our natural gas forward contracts. At December 31, 2019, it was anticipated that $2,264 of losses currently recorded in accumulated other comprehensive income (loss) will be reclassified into earnings within the next twelve months. The following table presents the fair value of derivative assets and liabilities and the respective balance sheet locations as of: Assets Liabilities December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedges: Interest rate swap contracts - current Natural gas forward contracts - current Natural gas forward contracts - non-current Total derivatives designated as hedging instruments Other current assets Other Non- current assets $ — 136 155 291 $ $ $ Accrued Expenses Accrued Expenses Other non- current liabilities $ 855 2,400 2,915 Accrued Expenses Accrued Expenses Other non- current liabilities $ 319 1,617 5,555 $ 6,170 $ 7,491 — — — — Income Tax - The Company is organized as a pass-through entity for federal and most state income tax purposes. Taxes assessed by states on the Company are de minimis. As a result, the members are responsible for federal income taxes based on their respective share of taxable income. Net income for financial statement purposes may differ significantly from taxable income reportable to members as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the membership agreement. Reclamation Costs - The Company is obligated to return the land beneath its refinery and tailings ponds to its natural condition upon completion of operations and is required to return the land beneath its rail yard to its natural condition upon termination of the various lease agreements. The Company accounts for its land reclamation liability as an asset retirement obligation, which requires that obligations associated with the retirement of a tangible long-lived asset be recorded as a liability when those obligations are incurred, 11 with the amount of the liability initially measured at fair value. Upon initially recognizing a liability for an asset retirement obligation, an entity must capitalize the cost by recognizing an increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The estimated original liability calculated in 1996 for the refinery and tailing ponds was calculated based on the estimated useful life of the mine, which was 80 years, and on external and internal estimates as to the cost to restore the land in the future and state regulatory requirements. During 2019, 2018 and 2017 the estimated remaining estimated useful life of the mine was 59 years, 60 years and 66 years, respectively. In 2020, the mining reserve will be amortized over a remaining life of 58 years. The decline in estimated mining reserves estimated remaining life is based on the results of an independent mine reserve analysis conducted as of December 31, 2017. The independent mine reserve analysis is routine and performed approximately every three years. The liability was discounted using a weighted average credit-adjusted risk-free rates of approximately 6% and is being accreted throughout the estimated life of the related assets to equal the total estimated costs with a corresponding charge being recorded to cost of products sold. During 2011, the Company constructed a rail yard to facilitate loading and switching of rail cars. The Company is required to restore the land on which the rail yard is constructed to its natural conditions. The original estimated liability for restoring the rail yard to its natural condition was calculated based on the land lease life of 30 years and on external and internal estimates as to the cost to restore the land in the future. The liability is discounted using a credit-adjusted risk-free rate of 4.25% and is being accreted throughout the estimated life of the related assets to equal the total estimated costs with a corresponding charge being recorded to cost of products sold. Fair Value of Financial Instruments - The following methods and assumptions were used to estimate the fair values of each class of financial instruments: Financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, derivative financial instruments and long-term debt. The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses approximate their fair value because of the nature of such instruments. Our long-term debt and derivative financial instruments are measured at their fair values with Level 2 inputs based on quoted market values for similar but not identical financial instruments. Long-Term Debt - The carrying value of our long-term debt materially reflects the fair value of our long-term debt as rates are variable and its key terms are similar to indebtedness with similar amounts, durations and credit risks. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Fair value accounting requires that these financial assets and liabilities be classified into one of the following three categories: • Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for an identical asset or liability in an active market. • Level 2-inputs to the valuation methodology include quoted prices for a similar asset or liability in an active market or model-derived valuations in which all significant inputs are observable for substantially the full term of the asset or liability. • Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement of the asset or liability. Subsequent Events - The Company has evaluated all subsequent events through February 27, 2020, the date the financial statements were available to be issued. See Note 16 - Subsequent Event for additional information. 12 Recently Issued Accounting Standards - In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) to increase the transparency and comparability of leases among entities. Additional ASUs have been issued subsequent to ASU 2016-02 to provide supplementary clarification and implementation guidance for leases related to, among other things, the application of certain practical expedients, the rate implicit in the lease, lessee reassessment of lease classification, lessor reassessment of lease term and purchase options, variable payments that depend on an index or rate and certain transition adjustments. ASU 2016-02 and these additional ASUs are now codified as ASC 842. Pursuant to these updates, accounting for leases by lessors remains largely unchanged from current guidance. The update requires that lessees recognize a lease liability and a right of use asset for all leases (with the exception of short-term leases) at the commencement date of the lease and disclose key information about leasing arrangements. For leases less than 12 months, an entity is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The Company made this election upon adoption. The Company adopted ASC 842 effective January 1, 2019 using a modified retrospective approach under which prior comparative periods were not adjusted, as permitted by the guidance. The Company has determined that the adoption of the new standard did not have a material impact on the balance sheet or statement of operations because the Company has no material long term leases that are subject to ASC 842. Ciner Corp was determined to be the ultimate lessee for rail car lease agreements under ASC 842, and the Company will continue to incur an allocation of rent expense in relation to the use of rail cars leased by Ciner Corp. In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (“ASU Topic 815”) - Targeted Improvements to Accounting for Hedging Activities. ASU Topic 815 aims to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, ASU Topic 815 makes certain targeted improvements to simplify the application of the existing hedge accounting guidance. The Company adopted ASU Topic 815 effective January 1, 2019 and concluded there was no material impact to the Company’s financial statements. Recent Guidance Not Adopted Yet - In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses (Topic 326)” ("ASU 2016-13"). This ASU introduces the current expected credit loss (CECL) model, which will require an entity to measure credit losses for certain financial instruments and financial assets, including trade receivables. Under this update, on initial recognition and at each reporting period, an entity will be required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. ASU 2016-13 is effective for periods beginning after December 15, 2019. The Company continues to evaluate ASU 2016-13 but does not expect a material impact to the Company’s financial statements. In August 2018, the FASB issued ASU 2018-15, “Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force)” (“ASU 2018-15”), which amends ASC 350-40 to address a customer’s accounting for implementation costs incurred in a cloud computing arrangement (“CCA”) that is a service contract. ASU 2018-15 amends ASC 350 and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a CCA. ASU 2018-15 does not expand on existing disclosure requirements except to require a description of the nature of hosting arrangements that are service contracts. Entities are permitted to apply either a retrospective or prospective transition approach to adopt the guidance. ASU 2018-15 is effective for periods beginning after December 15, 2019. The Company continues to evaluate ASU 2018-15 but does not expect a material impact to the Company’s financial statements. 13 3. ACCOUNTS RECEIVABLE, NET Accounts receivable, net as of December 31, 2019 and 2018 consisted of the following: 2019 2018 Trade receivables Other receivables Allowance for doubtful accounts Total 4. INVENTORY Inventory as of December 31, 2019 and 2018 consisted of the following: Raw materials Finished goods Stores inventory, current Total $ $ $ $ 30,281 5,742 36,023 (60) 35,963 2019 8,672 6,894 8,627 24,193 5. PROPERTY, PLANT, AND EQUIPMENT, NET Property, plant, and equipment as of December 31, 2019 and 2018 consisted of the following: Land and land improvements Depletable land Buildings and building improvements Computer hardware Machinery and equipment Total Less accumulated depreciation, depletion and amortization Total net book value Construction in progress Property, plant, and equipment, net 2019 192 2,957 137,937 4,734 644,132 789,952 (622,545) 167,407 90,714 258,121 $ $ $ $ $ $ $ $ 30,993 5,897 36,890 (20) 36,870 2018 10,867 5,112 6,296 22,275 2018 192 2,957 137,176 4,680 649,488 794,493 (614,415) 180,078 46,333 226,411 Depreciation, depletion and amortization expense on property, plant and equipment was $26,175, $27,731 and $26,418 for the years ended December 31, 2019, 2018 and 2017, respectively. The increase in construction in progress from December 31, 2018 to December 31, 2019 is due to construction on a co- generation facility which we are planning to be operational by the end of the first quarter of 2020 and the execution of the early phases for a Green River Expansion Project that we believe will significantly increase production levels of soda ash. 6. OTHER NON-CURRENT ASSETS Other non-current assets as of December 31, 2019 and 2018 consisted of the following: Stores inventory, non-current Internal-use software, net of accumulated amortization Deferred financing costs and other Total 2019 2018 17,571 6,088 607 24,266 $ $ 19,394 6,191 747 26,332 $ $ During the years ended December 31, 2019, 2018 and 2017, in accordance with ASC 350-40, Internal Use Software, we capitalized $596, $6,191 and $0, respectively, of certain internal use software development costs. Software development 14 activities generally consist of three stages (i) the research and planning stage, (ii) the application and infrastructure development stage, and (iii) the post-implementation stage. Costs incurred in the planning and post-implementation stages of software development, or other maintenance and development expenses that do not meet the qualification for capitalization are expensed as incurred. Costs incurred in the application and infrastructure development stage, including significant enhancements and upgrades, are capitalized. These software development costs are amortized on a straight- line basis over the estimated useful life of five to ten years under depreciation and amortization expense which is included in the cost of products sold financial statement line item of the statements of operations. During the years ended December 31, 2019, 2018 and 2017, we amortized internal use software development costs of $699, $0 and $0, respectively. Amortization for these internal use software development costs are expected to be approximately $699 per year during the amortization period. 7. ACCRUED EXPENSES Accrued expenses as of December 31, 2019 and 2018 consisted of the following: Accrued capital expenditures Accrued employee compensation & benefits Accrued energy costs Accrued royalty costs Accrued other taxes Accrued derivatives Other accruals Total 8. DEBT 2019 2018 $ $ 6,156 6,898 5,654 7,143 4,801 3,255 4,054 37,961 $ $ 13,131 7,083 6,592 6,529 4,747 1,936 3,673 43,691 Long-term debt as of December 31, 2019 and 2018 consisted of the following: Ciner Wyoming Credit Facility, unsecured principal expiring on August 1, 2022, variable interest rate as a weighted average rate of 3.27% and 3.99% at December 31, 2019 and 2018, respectively Total long-term debt $ $ 129,500 129,500 $ $ 99,000 99,000 2019 2018 Aggregate maturities required on long-term debt at December 31, 2019 are due in future years as follows: 2020 - 2021 2022 2023 and thereafter Total Ciner Wyoming Credit Facility $ $ — 129,500 — 129,500 On August 1, 2017, Ciner Wyoming entered into a Credit Agreement (“Ciner Wyoming Credit Facility”) with each of the lenders listed on the respective signature pages thereof and PNC Bank, National Association, as administrative agent, swing line lender and a Letter of Credit (“L/C”) issuer. The Ciner Wyoming Credit Facility replaces the former Credit Facility (“Former Ciner Wyoming Credit Facility”), dated as of July 18, 2013, by and among Ciner Wyoming, the lenders party thereto and Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, as amended, which was terminated on August 1, 2017 upon entry into the Ciner Wyoming Credit Facility. This arrangement was accounted for as a modification of debt in accordance with ASC 470-50. The Ciner Wyoming Credit Facility is a $225,000 senior unsecured revolving credit facility with a syndicate of lenders, which will mature on the fifth anniversary of the closing date of such credit facility. The Ciner Wyoming Credit Facility 15 provides for revolving loans to fund working capital requirements, capital expenditures, to consummate permitted acquisitions and for all other lawful purposes. The Ciner Wyoming Credit Facility has an accordion feature that allows Ciner Wyoming to increase the available revolving borrowings under the facility by up to an additional $75,000, subject to Ciner Wyoming receiving increased commitments from existing lenders or new commitments from new lenders and the satisfaction of certain other conditions. In addition, the Ciner Wyoming Credit Facility includes a sublimit up to $20,000 for same-day swing line advances and a sublimit up to $40,000 for letters of credit. Ciner Wyoming’s obligations under the Ciner Wyoming Credit Facility are unsecured. The Ciner Wyoming Credit Facility contains various covenants and restrictive provisions that limit (subject to certain exceptions) Ciner Wyoming’s ability to: • make distributions on or redeem or repurchase units; • incur or guarantee additional debt; • make certain investments and acquisitions; • incur certain liens or permit them to exist; • enter into certain types of transactions with affiliates of Ciner Wyoming; • merge or consolidate with another company; and • transfer, sell or otherwise dispose of assets. The Ciner Wyoming Credit Facility also requires quarterly maintenance of a leverage ratio (as defined in the Ciner Wyoming Credit Facility) of not more than 3.00 to 1.00 and an interest coverage ratio (as defined in the Ciner Wyoming Credit Facility) of not less than 3.00 to 1.00. The Ciner Wyoming Credit Facility contains events of default customary for transactions of this nature, including (i) failure to make payments required under the Ciner Wyoming Credit Facility, (ii) events of default resulting from failure to comply with covenants and financial ratios in the Ciner Wyoming Credit Facility, (iii) the occurrence of a change of control, (iv) the institution of insolvency or similar proceedings against Ciner Wyoming and (v) the occurrence of a default under any other material indebtedness Ciner Wyoming may have. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Ciner Wyoming Credit Facility, the administrative agent shall, at the request of the Required Lenders (as defined in the Ciner Wyoming Credit Facility), or may, with the consent of the Required Lenders, terminate all outstanding commitments under the Ciner Wyoming Credit Facility and may declare any outstanding principal of the Ciner Wyoming Credit Facility debt, together with accrued and unpaid interest, to be immediately due and payable. Under the Ciner Wyoming Credit Facility, a change of control is triggered if Ciner Corp and its wholly-owned subsidiaries, directly or indirectly, cease to own all of the equity interests, or cease to have the ability to elect a majority of the board of directors (or similar governing body) of our general partner (or any entity that performs the functions of the Partnership’s general partner). In addition, a change of control would be triggered if the Partnership ceases to own at least 50.1% of the economic interests in Ciner Wyoming or ceases to have the ability to elect a majority of the members of Ciner Wyoming’s board of managers. Loans under the Ciner Wyoming Credit Facility bear interest at Ciner Wyoming’s option at either: • a Base Rate, which equals the highest of (i) the federal funds rate in effect on such day plus 0.50%, (ii) the administrative agent’s prime rate in effect on such day or (iii) one-month LIBOR plus 1.0%, in each case, plus an applicable margin; or 16 • Eurodollar Rate plus an applicable margin. The unused portion of the Ciner Wyoming Credit Facility is subject to an unused line fee ranging from 0.225% to 0.300% per annum based on Ciner Wyoming’s then current leverage ratio. At December 31, 2019, Ciner Wyoming was in compliance with all financial covenants of the Ciner Wyoming Credit Facility. WE Soda and Ciner Enterprises Facilities Agreement On August 1, 2018, Ciner Enterprises, the entity that indirectly owns and controls Ciner Wyoming, refinanced its existing credit agreement and entered into a new facilities agreement, to which WE Soda and Ciner Enterprises (as borrowers), and KEW Soda, WE Soda, certain related parties and Ciner Enterprises, Ciner Holdings and Ciner Corp (as original guarantors and together with the borrowers, the “Ciner obligors”), are parties (as amended and restated or otherwise modified, the “Facilities Agreement”), and certain related finance documents. The Facilities Agreement expires on August 1, 2025. Even though Ciner Wyoming is not a party or a guarantor under the Facilities Agreement, while any amounts are outstanding under the Facilities Agreement we will be indirectly affected by certain affirmative and restrictive covenants that apply to WE Soda and its subsidiaries (which includes us). Besides the customary covenants and restrictions, the Facilities Agreement includes provisions that, without a waiver or amendment approved by lenders whose commitments are more than 66-2/3% of the total commitments under the Facilities Agreement to undertake such action, would (i) prevent transactions with our affiliates that could reasonably be expected to materially and adversely affect the interests of certain finance parties, (ii) restrict the ability to amend the Company's agreement or Ciner Holdings' company agreement or Company's other constituency documents if such amendment could reasonably be expected to materially and adversely affect the interests of the lenders to the Facilities Agreement; and (iii) prevent actions that enable certain restrictions or prohibitions on our ability to upstream cash (including via distributions) to the borrowers under the Facilities Agreement. In addition, Ciner Enterprises’ ownership in Ciner Holdings, is subject to a lien under the Facilities Agreement, which enables the lenders under the Facilities Agreement to foreclose on such collateral and take control of Ciner Holdings if any of WE Soda or KEW Soda or certain of their related parties, or Ciner Enterprises, Ciner Corp or Ciner Holdings is unable to satisfy its respective obligations under the Facilities Agreement. 17 9. OTHER NON-CURRENT LIABILITIES Other non-current liabilities as of December 31, 2019 and 2018 consisted of the following: Reclamation reserve Derivative instruments and hedges, fair value liabilities Total Details of the reclamation reserve shown above are as follows: Reclamation reserve at beginning of year Accretion expense Reclamation reserve at end of year 10. EMPLOYEE BENEFIT PLANS 2019 2018 5,672 2,915 8,587 2019 5,366 306 5,672 $ $ $ $ 5,366 5,555 10,921 2018 5,080 286 5,366 $ $ $ $ The Company participates in various benefit plans offered and administered by Ciner Corp and is allocated its portions of the annual costs related thereto. The specific plans are as follows: Retirement Plans - Benefits provided under the pension plan for salaried employees and pension plan for hourly employees (collectively, the “Retirement Plans”) are based upon years of service and average compensation for the highest 60 consecutive months of the employee’s last 120 months of service, as defined. Each Retirement Plan covers substantially all full-time employees hired before May 1, 2001. Ciner Corp’s Retirement Plans had a net unfunded liability balance of $54,800 and $56,883 at December 31, 2019 and December 31, 2018, respectively. Ciner Corp’s current funding policy is to contribute an amount within the range of the minimum required and the maximum tax- deductible contribution. The Company's allocated portion of the pension plans' net periodic pension costs was $994, $412 and $1,358 for the years ended December 31, 2019, 2018 and 2017, respectively. The increase in pension costs in 2019 was driven by asset changes from the prior year. Savings Plan - The 401(k) retirement plan (the “401(k) Plan”) covers all eligible hourly and salaried employees. Eligibility is limited to all domestic residents and any foreign expatriates who are in the United States indefinitely. The 401(k) Plan permits employees to contribute specified percentages of their compensation, while the Company makes contributions based upon specified percentages of employee contributions. Participants hired on or subsequent to May 1, 2001, will receive an additional contribution from the Company based on a percentage of the participant’s base pay. Contributions made to the 401(k) Plan for the years ended December 31, 2019, 2018 and 2017 were $3,032, $2,833 and $3,735, respectively. Postretirement Benefits - Most of the Company's employees are eligible for postretirement benefits other than pensions if they reach retirement age while still employed. The postretirement benefits are accounted for by Ciner Corp on an accrual basis over an employee’s period of service. The postretirement plan, excluding pensions, is not funded, and Ciner Corp has the right to modify or terminate the plan. The post-retirement plan had a net unfunded liability of $13,757 and $9,851 at December 31, 2019 and 2018, respectively. The increase in the obligation as of December 31, 2019 as compared to December 31, 2018 is due to Ciner Corp amending its postretirement benefit plan, updating it’s per capita claims costs to reflect increased benefit payments and a decrease in the discount rate used to determine benefit obligations at December 31, 2019. The Company's allocated portion of postretirement (benefit) costs was $(2,152), $(2,940) and $(2,823) for the years ended December 31, 2019, 2018 and 2017, respectively. The postretirement benefit for the Company in 2019, 2018 and 2017 is due to the aforementioned changes made to the postretirement benefit plan. 18 11. ACCUMULATED OTHER COMPREHENSIVE LOSS Accumulated other comprehensive loss as of December 31, 2019, 2018 and 2017 consisted of the following: BALANCE at December 31, 2016 Other comprehensive income (loss) before reclassification Amounts reclassified from accumulated other comprehensive loss Net current-period other comprehensive income (loss) Interest Rate Swap Contract Natural Gas Forwards Contracts Total $ (439) $ (2,840) $ (3,279) 61 376 437 (5,411) 1,044 (5,350) 1,420 (4,367) (3,930) BALANCE at December 31, 2017 $ (2) $ (7,207) $ (7,209) Other comprehensive loss before reclassification Amounts reclassified from accumulated other comprehensive loss Net current-period other comprehensive (loss) income (354) 37 (317) (1,002) 1,037 (1,356) 1,074 35 (282) BALANCE at December 31, 2018 $ (319) $ (7,172) $ (7,491) Other comprehensive (loss) income before reclassification Amounts reclassified from accumulated other comprehensive loss Net current-period other comprehensive (loss) income (711) 175 (536) 1,085 1,063 2,148 374 1,238 1,612 BALANCE at December 31, 2019 $ (855) $ (5,024) $ (5,879) The components of other comprehensive income/(loss), attributable to the Company, that have been reclassified out of Accumulated other comprehensive loss consisted of the following: 2019 2018 2017 Affected Line Items on the Statements of Operations and Comprehensive Income Details about other comprehensive income/ (loss) components: Gains on cash flow hedges: Interest rate swap contracts Commodity hedge contracts Total reclassifications for the period $ $ 175 1,063 1,238 $ $ 37 1,037 1,074 $ $ 376 1,044 1,420 Interest expense Cost of products sold 12. COMMITMENTS AND CONTINGENCIES The Company leases and licenses mineral rights from the U.S. Bureau of Land Management, the state of Wyoming, Rock Springs Royalty Company, LLC (“RSRC”) an affiliate of Occidental Petroleum Corporation (formerly an affiliate of Anadarko Petroleum Corporation), and other private parties which provide for royalties based upon production volume. The Company has a perpetual right of first refusal with respect to these leases and license and intends to continue renewing the leases and license as has been its practice. The Company entered into a 10 year rail yard switching and maintenance agreement with a third party, Watco Companies, LLC (“Watco”), on December 1, 2011. Under the agreement, Watco provides rail-switching services at the Company’s rail yard. The Company’s rail yard is constructed on land leased by Watco from Rock Springs Grazing Association and on land by which Watco holds an easement from Anadarko Land Corp; the Rock Springs Grazing Association land lease is renewable every five years for a total period of thirty years, while the Anadarko Land Corp. easement lease is perpetual. 19 The Company has an option agreement with Watco to assign these leases to the Company at any time during the land lease term. An annual rental of $15 is paid under the easement and an annual rental of $60 is paid under the lease. The Company entered into two track lease agreements, collectively expiring in 2021, with Union Pacific Company for certain rail tracks used in connection with the rail yard. As of December 31, 2019, the total minimum contractual rental commitments under the Company’s various operating leases, including renewal periods were as follows: 2020 2021 2022 2023 2024 Thereafter Total Leased Land 75 $ 75 75 75 75 1,200 1,575 $ Track Leases 70 $ 33 — — — — 103 $ $ $ Total 145 108 75 75 75 1,200 1,678 Ciner Corp typically enters into operating lease contracts with various lessors for rail cars to transport product to customer locations and warehouses. Rail car leases under these contractual commitments range for periods from one to ten years. Ciner Corp's obligations related to these rail car leases are $11,134 in 2020, $8,485 in 2021, $5,568 in 2022, $2,586 in 2023, $2,255 in 2024 and $4,038 in 2025 and thereafter. Total lease expense allocated to the Company from Ciner Corp was approximately $11,770, $13,919 and $14,628 for the years ended December 31, 2019, 2018 and 2017, respectively, and is recorded in cost of products sold. Purchase Commitments - The Company has both physical and financial natural gas supply contracts to mitigate volatility in the price of natural gas. As of December 31, 2019, these contracts totaled approximately $37,500 for the purchase of a portion of our natural gas requirements over approximately the next five years. The supply purchase agreements have specific commitments of $16,095 in 2020, $9,974 in 2021, $6,213 in 2022, $4,317 in 2023 and $864 in 2024. The Company has a separate contract that expires in 2021 and renews annually thereafter, for transportation of natural gas with an average annual cost of approximately $3,928 per year. Legal and Environmental - From time to time we are party to various claims and legal proceedings related to our business. Although the outcome of these proceedings cannot be predicted with certainty, management does not currently expect any of the legal proceedings we are involved in to have a material effect on our business, financial condition and results of operations. We cannot predict the nature of any future claims or proceedings, nor the ultimate size or outcome of existing claims and legal proceedings and whether any damages resulting from them will be covered by insurance. Litigation Settlement- On February 2, 2016, amended on January 3, 2017, Ciner Wyoming filed suit against RSRC in the Third Judicial District Court in Sweetwater County, Wyoming, Case No. C-16-77-L, seeking, among other things, to recover approximately $32,000 in royalty overpayments. The royalty payments arose under our license with RSRC, an affiliate of Occidental Petroleum Corporation, to mine sodium minerals from lands located in Sweetwater County, Wyoming (“License”). The License sets the applicable royalty rate based on a most favored nation clause, where either the royalty rate is set at the same royalty rate we pay to other licensors in Sweetwater County for sodium minerals, or, if certain conditions are met, the royalty rate is set by the rate paid by a third party to an affiliate of Occidental Petroleum Corporation under a separate license. In the lawsuit, we claimed that RSRC had, for at least the last ten years, been charging an arbitrarily high royalty rate in contradiction of the License terms. In addition, we sought a modification of the expiration term of the License land-lease between Ciner Wyoming and RSRC to those terms granted to other licensors in accordance with the most favored nation clause. On June 28, 2018, RSRC and Ciner Wyoming signed a Settlement Agreement and Release (the “Settlement Agreement”) which among other things (i) required RSRC to pay Ciner Wyoming $27,500 which was received on July 2, 2018, and (ii) 20 concurrently amended selected sections of the License land-lease including among other things, (a) extension of the term of the License Agreement to July 18, 2061 and for so long thereafter as Ciner Wyoming continuously conducts operations to mine and remove sodium minerals from the licensed premises in commercial quantities; and (b) revises the production royalty rate for each sale of sodium mineral products produced from ore extracted from the licensed premises at the royalty rate of eight percent (8%) of the net sales of such sodium mineral products. There are no unresolved conditions or uncertainties associated with the Settlement Agreement and management determined the $27,500 settlement payment was related to the historical overpayment of royalties. The $27,500 litigation settlement was realized in the second quarter of 2018. Off-Balance Sheet Arrangements - We have a self-bond agreement with the Wyoming Department of Environmental Quality (“WDEQ”) under which we commit to pay directly for reclamation costs at our Green River, Wyoming plant site. The amount of the bond was $36,200 and $32,900 as of December 31, 2019 and December 31, 2018, respectively, the former of which is the amount we would need to pay the State of Wyoming for reclamation costs if we cease mining operations currently. The amount of this self-bond is subject to change upon periodic re-evaluation by the Land Quality Division. In May 2019, the State of Wyoming enacted legislation that limits our and other mine operators’ ability to self- bond, which will require the Company to seek other acceptable financial instruments to provide additional assurance for its reclamation obligations. The Company expects to provide such assurances by securing a third-party surety bond no later than November 2020. As of the date of this Report, the Company anticipates that any such impact on the Company’s net income and liquidity will be limited. The amount of such surety guarantee is subject to change upon periodic re- evaluation by the WDEQ’s Land Quality Division. 13. AFFILIATE TRANSACTIONS Ciner Corp is the exclusive sales agent for the Company and through its membership in ANSAC, Ciner Corp is responsible for promoting and increasing the use and sale of soda ash and other refined or processed sodium products produced. ANSAC operates on a cooperative service-at-cost basis to its members such that typically any annual profit or loss is passed through to the members. On November 9, 2018, Ciner Corp delivered a notice to terminate its membership in ANSAC. See Note 2 - Nature of Operations and Summary of Significant Accounting Policies - ANSAC Exit for more information regarding the notice to terminate. All actual sales and marketing costs incurred by Ciner Corp are charged directly to the Company. Selling, general and administrative expenses also include amounts charged to the Company by Ciner Corp principally consisting of salaries, benefits, office supplies, professional fees, travel, rent and other costs of certain assets used by the Company. Ciner Corp has agreed to provide the Company with certain corporate, selling, marketing, and general and administrative services, in return for which the Company has agreed to pay Ciner Corp an annual management fee and reimburse Ciner Corp for certain third-party costs incurred in connection with providing such services. In addition, under the limited liability company agreement of the Company, as amended, the Company reimburses the Partnership for employees who operate the Company’s assets and for support provided to the Company. These transactions do not necessarily represent arm's length transactions and may not represent all costs if the Company operated on a standalone basis. The total selling, general and administrative costs charged to the Company by affiliates for the years ended December 31, 2019, 2018 and 2017 were as follows: Ciner Corp ANSAC (1) Ciner Resources Total selling, general and administrative expenses - affiliates 2019 2018 2017 $ $ 14,233 3,508 663 18,404 $ $ 13,728 2,998 972 17,698 $ $ 13,549 2,487 484 16,520 (1) ANSAC allocates its expenses to its members using a pro rata calculation based on sales. 21 Cost of products sold includes an allocation of Ciner Corp's rail car lease expense (refer to Note 12) and charges for logistics services provided by ANSAC. For the years ended December 31, 2019, 2018 and 2017, these ANSAC logistics costs were $0, $0 and $19,573, respectively. When we elect to use ANSAC to provide freight services for our other non- ANSAC international sales, ANSAC separately and directly charges the Company for such services. During the year ended 2019 and 2018 we did not use ANSAC for non-ANSAC international sales. The decrease in freight costs charged by ANSAC was due to a decrease in non-ANSAC international sales, to CIDT, during the years ended December 31, 2019 and December 31, 2018 when compared to 2017. There were no sales to CIDT during the years ended December 31, 2019 and December 31, 2018, as the previous contract concluded in the 2017 year. Net sales to affiliates for the years ended December 31, 2019, 2018 and 2017 were as follows: ANSAC CIDT Total 2019 315,847 — 315,847 $ $ 2018 253,345 — 253,345 $ $ 2017 222,231 82,266 304,497 $ $ As of December 31, 2019 and 2018, the Company had due from/to with affiliates as follows: ANSAC CIDT Ciner Corp Other Total 2019 2018 Due from Affiliates Due to Affiliates Due from Affiliates Due to Affiliates $ $ 53,859 5,468 35,713 75 95,115 $ $ 1,614 — 1,423 178 3,215 $ $ 48,707 7,116 14,324 212 70,359 $ $ 743 — 2,014 86 2,843 The increase in due from Ciner Corp from December 31, 2018 to December 31, 2019 is due to timing of funding of pension and postretirement plans offered and administered by Ciner Corp. 14. MAJOR CUSTOMERS AND SEGMENT REPORTING Our operations are similar in geography, nature of products we provide and type of customers we serve. As the Company earns substantially all of its revenues through the sale of soda ash mined at a single location, we have concluded that we have one operating segment for reporting purposes. The net sales by geographic area for the years ended December 31, 2019, 2018 and 2017 were as follows: Domestic International: ANSAC CIDT Total international Total net sales 15. REVENUE 2019 206,996 315,847 — 315,847 522,843 $ $ 2018 233,414 253,345 — 253,345 486,759 $ $ 2017 192,843 222,231 82,266 304,497 497,340 $ $ The Company has one reportable segment and our revenue is derived from the sale of soda ash which is our sole and primary good and service. We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers. Performance Obligations. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in ASC 606. A contract's transaction price is allocated to each distinct performance 22 obligation and recognized as revenue when, or as, the performance obligation is satisfied. At contract inception, we assess the goods and services promised in contracts with customers and identify performance obligations for each promise to transfer to the customer, a good or service that is distinct. To identify the performance obligations, the Company considers all goods and services promised in the contract regardless of whether they are explicitly stated or are implied by customary business practices. From its analysis, the Company determined that the sale of soda ash is currently its only performance obligation. Many of our customer volume commitments are short-term and our performance obligations for the sale of soda ash are generally limited to single purchase orders. When performance obligations are satisfied. Substantially all of our revenue is recognized at a point-in-time when control of goods transfers to the customer. Transfer of Goods. The Company uses standard shipping terms across each customer contract with very few exceptions. Shipments to customers are made with terms stated as Free on Board (“FOB”) Shipping Point. Control typically transfers when goods are delivered to the carrier for shipment, which is the point at which the customer has the ability to direct the use of and obtain substantially all remaining benefits from the asset. Payment Terms. Our payment terms vary by the type and location of our customers. The term between invoicing and when payment is due is not significant and consistent with typical terms in the industry. Variable Consideration. We recognize revenue as the amount of consideration that we expect to receive in exchange for transferring promised goods or services to customers. We do not adjust the transaction price for the effects of a significant financing component, as the time period between control transfer of goods and services and expected payment is one year or less. At the time of sale, we estimate provisions for different forms of variable consideration (discounts, rebates, and pricing adjustments) based on historical experience, current conditions and contractual obligations, as applicable. The estimated transaction price is typically not subject to significant reversals. We adjust these estimates when the most likely amount of consideration we expect to receive changes, although these changes are typically immaterial. Returns, Refunds and Warranties. In the normal course of business, the Company does not accept returns, nor does it typically provide customers with the right to a refund. Freight. In accordance with ASC 606, the Company made a policy election to treat freight and related costs that occur after control of the related good transfers to the customer as fulfillment activities instead of separate performance obligations. Therefore freight is recognized at the point in which control of soda ash has transferred to the customer. Revenue disaggregation. In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with customers into geographical regions. The Company determined that disaggregating revenue into these categories achieved the disclosure objectives to depict how the nature, timing, amount and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 14, “Major Customers and Segment Reporting” for revenue disaggregated into geographical regions. Contract Balances. The timing of revenue recognition, billings and cash collections results in billed receivables, unbilled receivables (contract assets), and customer advances and deposits (contract liabilities). Contract Assets. At the point of shipping, the Company has an unconditional right to payment that is only dependent on the passage of time. In general, customers are billed and a receivable is recorded as goods are shipped. These billed receivables are reported as “Accounts Receivable, net” on the Balance Sheet as of December 31, 2019 and December 31, 2018. There were no contract assets as of December 31, 2019 or December 31, 2018. Contract Liabilities. There may be situations where customers are required to prepay for freight and insurance prior to shipment. The Company has elected the practical expedient for its treatment of freight and therefore, such prepayments 23 are considered a part of the single obligation to provide soda ash. In such instances, a contract liability for prepaid freight will be recorded. For the twelve months ended December 31, 2019, there were no customers that required prepaid freight. There were no contract liabilities as of December 31, 2019 or as of the date of adoption of ASC 606. Practical and Expedients Exceptions Incremental costs of obtaining contracts. We generally expense costs related to sales, including sales force salaries and marketing expenses, when incurred because the amortization period would have been one year or less. These costs are recorded within sales and marketing expenses. Unsatisfied performance obligations. We do not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less. 16. SUBSEQUENT EVENT On February 18, 2020, the members of the Board of Managers of Ciner Wyoming, approved a cash distribution to the members of Ciner Wyoming in the aggregate amount of $14,500. This distribution was paid on February 20, 2020. ****** 24 2019 Financial Highlights Unitholder Information (in thousands, except per unit) 2019 2018 (1) 2017 2016 2015 For the Years Ended December 31 Total revenues and other income Asset impairments Income (loss) from operations Net income (loss) from continuing operations Net income from continuing operations excluding impairments $ 263,935 $ $ $ 148,214 51,321 (25,414) $ 122,800 Net income (loss) from discontinued operations $ 956 Net income (loss) $ (24,458) Per common unit amounts (basic) Net income (loss) from continuing operations Net income (loss) from discontinued operations Net income (loss) Per common unit amounts (diluted) Net income (loss) from continuing operations Net income (loss) from discontinued operations Net income (loss) Distributions paid per common unit Average number of common units outstanding - basic Average number of common units outstanding - diluted Net cash provided by (used in) Operating activities of continuing operations Investing activities of continuing operations Financing activities of continuing operations Free cash flow (2) Cash flow cushion (2) Distributable cash flow (2) Adjusted EBITDA (2) $ $ $ $ $ $ $ (4.43) 0.08 (4.35) (4.43) 0.08 (4.35) 2.65 12,260 12,260 $ $ 137,319 8,221 $ (253,305) $ 139,040 $ 7,762 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 278,512 $ 246,325 $ 279,244 $ 300,635 18,280 192,538 122,360 140,640 17,687 140,047 7.35 1.42 8.77 5.90 0.86 6.76 1.80 12,244 20,234 178,282 7,607 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2,967 176,559 82,485 85,452 6,182 88,667 4.57 0.50 5.06 3.68 0.28 3.96 1.80 12,232 21,950 $ $ $ $ $ $ $ $ $ $ $ $ $ 15,861 181,157 90,626 $ 378,327 $ (170,699) $ (260,443) 106,487 $ $117,884 6,266 $ (311,277) 96,892 $ (571,720) 7.28 0.50 7.78 7.28 0.50 7.78 1.80 12,232 12,232 $ $ $ $ $ $ $ (20.80) (24.94) (45.75) (20.80) (24.94) (45.75) 2.70 12,232 12,232 112,151 9,807 $ $ 80,243 65,057 $ $ 144,907 15,805 (6,839) $ (134,149) $ (146,373) $ (166,443) 183,440 16,080 121,324 $ 75,970 9,248 $ (29,444) $ $ $ 144,210 (8,339) 157,815 $ 144,933 $ 383,980 $ 199,228 $ 230,241 121,958 211,483 $ 255,172 $ 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 Long-term deb, net Long-term lease obligations (3) Class A convertible preferred units Partners’ capital $ 45,776 $ 470,422 $ 3,506 $ 164,587 $ 338,963 $ $ $ $ $ 115,184 $ 79,740 $ 140,037 $ 80,745 557,574 $ 729,608 $ 990,234 $ 1,130,696 — 164,587 423,481 $ $ $ — 173,431 265,211 $ $ $ — — 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” in this Annual Report on Form 10-K form more information. (3) On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments and recognized assets and liabilities on its Consolidated Balance Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. Partnership Headquarters 1201 Louisiana Street Suite 3400 Houston, TX 77002 713-751-7507 Regional Offices Coal and Hard Minerals 5260 Irwin Road Huntington, WV 25705 Investor Relations Tiffany Sammis 1201 Louisiana Street Suite 3400 Houston, TX 77002 713-751-7515 Email: info@nrplp.com Stock Exchange Our units are listed on the New York Stock Exchange under the symbol NRP. Independent Auditors Ernst & Young LLP 5 Houston Center 1401 McKinney St, Suite 2400 Houston, TX 77010 Transfer Agent and Registrar American Stock Transfer and Trust Company Client Operations 6201 15th Avenue Brooklyn, NY 11219 Website: www.astfinancial.com Email:help@astfinancial.com 800-937-5449 Website www.nrplp.com Information regarding Natural Resource Partners L.P. is located on the partnership’s website. On the site is operational and financial information as well as all SEC filings and our corporate governance documents, including our Code of Business Conduct and Ethics, our Corporate Governance Guidelines and Board of Directors’ Audit Committee Charter. Requests for copies of the annual report or other data may be made through the website or by contacting Investor Relations. These requests will be provided free of charge. Contact NRP Board We have established procedures for contacting the non-management members of the NRP Board of Directors. To communicate any concerns or issues to the Board of Directors, please direct any correspondence to: Chairman of the CNG Committee NRP Board of Directors 1201 Louisiana Street, Suite 3400 Houston, TX 77002 888-252-2396 Schedule K-1 Unitholders receive Schedule K-1 packages that summarize their allocable share of the partnership’s reportable tax items for the calendar year. Generally, these K-1s are available on NRP’s website no later than mid-March. Unitholders should refer questions regarding their Schedule K-1 to the following: Natural Resource Partners L.P. Tax Package Support P.O. Box 799060 Dallas, TX 75379-9060 Fax: 1-866-554-3842 Toll Free: 1-888-334-7102 Forward-Looking Statements Statements included in this annual report may constitute 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 COVID-19, capital expenditures and acquisitions, expected commencement dates of mining, projected quantities of future production by our lessees producing from our reserves, and projected demand or supply for coal, trona and soda ash that will affect sales levels, prices and royalties realized by us. These forward-looking statements speak only as of the date hereof and are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties, including uncertainties surrounding the COVID-19 pandemic. 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. Please read “Item 1A. Risk Factors” of the Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to differ. 2019 Annual Report N a t u r a l R e s o u r c e P a r t n e r s L P. . 2 0 1 9 A n n u a l R e p o r t Natural Resource Partners L.P. 1201 Louisiana Street, 34th Floor Houston, Texas 77002 www.nrplp.com Natural Resource Partners L.P. 

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