NRP 10-K Fiscal year ended Dec. 31, 2019

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(1)	In excess of 90% of the reserves presented in this table are currently leased to third parties.

(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.

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(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.

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•	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.

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•	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;

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•	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.

•	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.

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•	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;

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•	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.

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•	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;

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•	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.

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•	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.

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•	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.

•	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.

•	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.

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•	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.

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(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.

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(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.

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(1)	See " Item 6. Selected Financial Data " for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.

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•

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.

•	$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.

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•

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.

•	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.

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•	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.

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•	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.

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•	$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.

•	$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.

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(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.

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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.

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(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.

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•	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.

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•

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.

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(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.

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(1)	Prepaid expenses and other includes notes receivable from contracts with customers.

(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.

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(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.

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(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.

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(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

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(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.

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•	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% .

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•	A leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 4.0 x; 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 4.0 x to 3.0 x; 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.

•	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.

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•	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.

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(1)	Included in 2017 coal royalty and other revenues was $21.2 million of related party revenues earned from Foresight Energy prior to May 9, 2017.

(2)	Included in 2017 transportation and processing services revenues was $6.0 million of related party revenues earned from Foresight Energy prior to May 9, 2017.

(3)	Included in 2017 operating and maintenance expenses was $0.5 million of related party expenses incurred from Foresight Energy prior to May 9, 2017.

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(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.

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(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.

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(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.

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(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.

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•	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.

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•	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

•	base salaries;

•	short-term cash incentive compensation;

•	long-term equity incentive compensation; and

•	perquisites and other benefits.

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(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

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(1)	Includes DERs accrued from the issue date to the settlement date.

(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.

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(1)	Calculated based on a unit price of $20.11, the closing price for the common units on December 31, 2019.

(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.

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(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.

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(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.

(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.

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•	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.

•	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.

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•	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 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 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.

•	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 is generated by individuals other than Mr. Robertson, the opportunity will belong to the entity for which those individuals are working.

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•	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.

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•	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.

•	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.

•	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.

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(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.

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