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
•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").
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. 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 and cash flow used in acquisition costs classified as investing or financing activities. 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 investing or financing activities, one-time beneficial items, mandatory Opco debt repayments, preferred unit distributions and redemption of PIK units, common unit distributions and warrant cash settlements. 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.
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 11. 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.
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 Sisecam Wyoming LLC ("Sisecam Wyoming"), formerly known as 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:
Mineral Rights (formerly named Coal Royalty and Other segment)—consists of approximately 13 million acres of mineral interests and other subsurface rights across the United States. If combined in a single tract, our ownership would cover roughly 20,000 square miles. Our ownership provides critical inputs for the manufacturing of steel, electricity and basic building materials, as well as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energy economy in the years to come.
Soda Ash—consists of our 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining and soda ash production business located in the Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold 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.
Our financial results by segment for the year ended December 31, 2021 are as follows:
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| | Operating Segments | | | | |
(In thousands) | | Mineral Rights | | Soda Ash | | Corporate and Financing | | Total |
Revenues and other income | | $ | 194,493 | | | $ | 21,871 | | | $ | — | | | $ | 216,364 | |
Net income (loss) from continuing operations | | $ | 143,412 | | | $ | 21,702 | | | $ | (56,212) | | | $ | 108,902 | |
Asset impairments | | 5,102 | | | — | | | — | | | 5,102 | |
Net income (loss) from continuing operations excluding asset impairments | | $ | 148,514 | | | $ | 21,702 | | | $ | (56,212) | | | $ | 114,004 | |
Adjusted EBITDA (1) | | $ | 167,613 | | | $ | 11,101 | | | $ | (17,360) | | | $ | 161,354 | |
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Cash flow provided by (used in) continuing operations | | | | | | | | |
Operating activities | | $ | 159,845 | | | $ | 11,106 | | | $ | (49,147) | | | $ | 121,804 | |
Investing activities | | $ | 2,412 | | | $ | — | | | $ | — | | | $ | 2,412 | |
Financing activities | | $ | (1,132) | | | $ | — | | | $ | (87,354) | | | $ | (88,486) | |
Distributable cash flow (1) | | $ | 162,257 | | | $ | 11,106 | | | $ | (49,147) | | | $ | 124,216 | |
Free cash flow (1) | | $ | 161,008 | | | $ | 11,106 | | | $ | (49,147) | | | $ | 122,967 | |
Cash flow cushion (1) | | N/A | | N/A | | N/A | | $ | 36,172 | |
(1)See "—Results of Operations" below for reconciliations to the most comparable GAAP financial measures.
Current Results/Market Commentary
Business Outlook and Quarterly Distributions
We generated $121.8 million of net cash provided by operating activities and $123.0 million of free cash flow during the year ended December 31, 2021 and ended the year with $235.5 million of liquidity consisting of $135.5 million of cash and cash equivalents and $100 million of borrowing capacity under our Opco Credit Facility.
The indenture governing our 2025 parent company notes restricts us from paying more than one-half of the quarterly distribution on our preferred units in cash if our consolidated leverage ratio exceeds 3.75x. Accordingly, the Board of Directors of our general partner had declared a distribution on our preferred units to be paid one-half in kind through the issuance of additional preferred units (“PIK units”) in 2021 when our leverage ratio exceeded 3.75x. Our consolidated leverage ratio fell below 3.75x during the fourth quarter of 2021 to 2.7x at December 31, 2021, allowing us to fully redeem at par all 19,321 paid-in-kind preferred units for $19.6 million in cash in accordance with their terms and including accrued interest, and to continue to pay common unit distributions in the first quarter of 2022. Therefore, as of the date of this report, no paid-in-kind preferred units remain outstanding and $250 million of 12.0% Class A Convertible Preferred Units remain outstanding. While our leverage ratio is expected to stay below 3.75x for the foreseeable future, future distributions on our common and preferred units will be determined on a quarterly basis by the Board of Directors. The Board of Directors considers numerous factors each quarter in determining cash distributions, including profitability, cash flow, debt service obligations, market conditions and outlook, estimated unitholder income tax liability and the level of cash reserves that the Board determines is necessary for future operating and capital needs.
Mineral Rights Business Segment
We have changed the name of our Coal Royalty and Other business segment to Mineral Rights. This name change highlights our vast mineral ownership interests as well as our intensifying focus on leveraging the Partnership's asset footprint across the United States, including subsurface carbon sequestration rights, to become a key player in the transitional energy economy for the years to come. There has been no change to the composition of this reportable business segment or the structure of our internal organization in connection with this name change.
Metallurgical coal markets have rebounded significantly from the lows seen in 2020 to record high pricing and the outlook remains strong as steel demand driven by global economic recovery is more than offsetting challenges related to the COVID-19 pandemic. Domestic and export thermal coal markets have also significantly improved from the lows seen in 2020, however we did not have meaningful sensitivity to thermal coal price movements in 2021 since the substantial majority of our thermal cash flows were fixed pursuant to a contract with Foresight Energy Resources LLC ("Foresight") that went into effect as they emerged from bankruptcy in 2020. That contract expired at the end of 2021 and we began receiving traditional royalty payments in January 2022. While we may benefit from improved thermal coal demand and pricing in the near term, thermal coal markets still face the long-term challenges presented by competition from natural gas and the secular shift to renewable energy.
Our lessees sold 27.8 million tons of coal from our properties in 2021 and we derived approximately 65% of our coal royalty revenues and approximately 50% of our coal royalty sales volumes from metallurgical coal during the same period. Revenues and other income in 2021 were higher by $64.9 million as compared to the prior year. This increase is primarily a result of stronger metallurgical coal demand and pricing in 2021.
We continue to identify alternative revenue sources across our large portfolio of land, mineral and timber assets. The types of opportunities include the sequestration of carbon dioxide underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy. We executed our first carbon neutral project in the fourth quarter of 2021 through the sale of 1.1 million carbon offset credits which represents 1.1 million tonnes of carbon sequestered in approximately 39,000 acres of our forestland in West Virginia. In the first quarter of 2022, we were able to execute another such project through the previously announced partnership with Denbury which provides opportunity for development of a world-class subsurface CO2 sequestration hub on Alabama's Gulf Coast. The agreement provides Denbury with the exclusive rights to develop a subsurface CO2 sequestration site on approximately 75,000 acres of underground pore space controlled by us in Baldwin County, near Mobile, Alabama, with estimated CO2 storage potential of over 300 million metric tons.
We expect this 75,000-acre project, if developed, to be the first of what will potentially be numerous subsurface sequestration projects conducted on the approximately 3.5 million acres where we own the rights to sequester CO2 underground across the United States. Our ability to create value and provide important benefits to the environment through alternative revenue sources continues to expand through transactions such as these and we are pleased to be on the forefront of subsurface carbon sequestration. While the timing and likelihood of additional cash flows being realized from further activities is uncertain, we believe our large ownership footprint throughout the United States will provide additional opportunities to create value in this regard with minimal capital investment.
Soda Ash Business Segment
In December, a publicly-traded Turkish conglomerate named Sisecam acquired a majority stake in the managing partner of our soda ash business, which is now known as Sisecam Wyoming LLC. Sisecam brings extensive experience and knowledge to our soda ash partnership given its soda ash operating experience in Turkey, Bulgaria and Europe, as well as its container and flat glass manufacturing around the world. We look forward to working with Sisecam to build on the significant value realized by the soda ash partnership with the Ciner Group, which continues to own a minority stake in the partnership.
Sisecam Wyoming's business continues to recover to pre-COVID-19 levels. While we believe Sisecam Wyoming's facility is competitively positioned as one of the lowest cost producers of soda ash in the world, we expect the market to remain volatile as a result of ongoing uncertainties with the COVID-19 pandemic.
Soda ash revenues and other income in 2021 were higher by $11.1 million compared to the prior year period as demand and pricing for soda ash continues to improve globally from the lows caused by the COVID-19 pandemic.
As a result of the soda ash segment's improved performance, Sisecam Wyoming reinstated regular quarterly cash distributions in the fourth quarter of 2021, which were previously suspended since the third quarter of 2020. Accordingly, we received a $7.4 million distribution in the fourth quarter of 2021. We also received a special distribution of $3.9 million in the first quarter of 2021, for $11.3 million in total distributions from Sisecam Wyoming in 2021 as compared to $14.2 million of regular quarterly distributions received in 2020. In addition, strong fourth quarter 2021 soda ash demand and pricing resulted in further improved operating results and we received a $13.2 million quarterly distribution with respect to these strong fourth quarter 2021 operating results in February 2022.
Results of Operations
Year Ended December 31, 2021 and 2020 Compared
Revenues and Other Income
The following table includes our revenues and other income by operating segment:
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| | For the Year Ended December 31, | | | | |
Operating Segment (In thousands) | | 2021 | | 2020 | | Increase | | Percentage Change |
Mineral Rights | | $ | 194,493 | | | $ | 129,592 | | | $ | 64,901 | | | 50 | % |
Soda Ash | | 21,871 | | | 10,728 | | | 11,143 | | | 104 | % |
Total | | $ | 216,364 | | | $ | 140,320 | | | $ | 76,044 | | | 54 | % |
The changes in revenues and other income is discussed for each of the operating segments below:
Mineral Rights
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:
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| For the Year Ended December 31, | | Increase (Decrease) | | Percentage Change |
(In thousands, except per ton data) | 2021 | | 2020 | |
Coal sales volumes (tons) | | | | | | | |
Appalachia | | | | | | | |
Northern | 1,335 | | | 647 | | | 688 | | | 106 | % |
Central | 12,279 | | | 10,111 | | | 2,168 | | | 21 | % |
Southern | 1,571 | | | 889 | | | 682 | | | 77 | % |
Total Appalachia | 15,185 | | | 11,647 | | | 3,538 | | | 30 | % |
Illinois Basin | 9,388 | | | 3,381 | | | 6,007 | | | 178 | % |
Northern Powder River Basin | 3,151 | | | 1,738 | | | 1,413 | | | 81 | % |
Gulf Coast | 55 | | | — | | | 55 | | | 100 | % |
Total coal sales volumes | 27,779 | | | 16,766 | | | 11,013 | | | 66 | % |
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Coal royalty revenue per ton | | | | | | | |
Appalachia | | | | | | | |
Northern | $ | 6.51 | | | $ | 2.36 | | | $ | 4.15 | | | 176 | % |
Central | 5.71 | | | 4.17 | | | 1.54 | | | 37 | % |
Southern | 9.14 | | | 4.75 | | | 4.39 | | | 92 | % |
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Illinois Basin | 2.12 | | | 2.36 | | | (0.24) | | | (10) | % |
Northern Powder River Basin | 3.54 | | | 3.50 | | | 0.04 | | | 1 | % |
Gulf Coast | 0.60 | | | — | | | 0.60 | | | 100 | % |
Combined average coal royalty revenue per ton | 4.47 | | | 3.70 | | | 0.77 | | | 21 | % |
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Coal royalty revenues | | | | | | | |
Appalachia | | | | | | | |
Northern | $ | 8,691 | | | $ | 1,526 | | | $ | 7,165 | | | 470 | % |
Central | 70,149 | | | 42,207 | | | 27,942 | | | 66 | % |
Southern | 14,355 | | | 4,221 | | | 10,134 | | | 240 | % |
Total Appalachia | 93,195 | | | 47,954 | | | 45,241 | | | 94 | % |
Illinois Basin | 19,917 | | | 7,973 | | | 11,944 | | | 150 | % |
Northern Powder River Basin | 11,151 | | | 6,086 | | | 5,065 | | | 83 | % |
Gulf Coast | 33 | | | — | | | 33 | | | 100 | % |
Unadjusted coal royalty revenues | 124,296 | | | 62,013 | | | 62,283 | | | 100 | % |
Coal royalty adjustment for minimum leases | (20,207) | | | (10,145) | | | (10,062) | | | (99) | % |
Total coal royalty revenues | $ | 104,089 | | | $ | 51,868 | | | $ | 52,221 | | | 101 | % |
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Other revenues | | | | | | | |
Production lease minimum revenues | $ | 14,269 | | | $ | 21,749 | | | $ | (7,480) | | | (34) | % |
Minimum lease straight-line revenues | 20,564 | | | 16,796 | | | 3,768 | | | 22 | % |
Forest CO2 sequestration revenues | 13,790 | | | — | | | 13,790 | | | 100 | % |
Wheelage revenues | 10,065 | | | 7,025 | | | 3,040 | | | 43 | % |
Property tax revenues | 6,028 | | | 5,786 | | | 242 | | | 4 | % |
Coal overriding royalty revenues | 4,367 | | | 4,977 | | | (610) | | | (12) | % |
Lease amendment revenues | 4,696 | | | 3,450 | | | 1,246 | | | 36 | % |
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Aggregates royalty revenues | 1,889 | | | 1,717 | | | 172 | | | 10 | % |
Oil and gas royalty revenues | 4,506 | | | 5,816 | | | (1,310) | | | (23) | % |
Other revenues | 933 | | | 982 | | | (49) | | | (5) | % |
Total other revenues | $ | 81,107 | | | $ | 68,298 | | | $ | 12,809 | | | 19 | % |
Royalty and other mineral rights | $ | 185,196 | | | $ | 120,166 | | | $ | 65,030 | | | 54 | % |
Transportation and processing services revenues | 9,052 | | | 8,845 | | | 207 | | | 2 | % |
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Gain on asset sales and disposals | 245 | | | 581 | | | (336) | | | (58) | % |
Total Mineral Rights segment revenues and other income | $ | 194,493 | | | $ | 129,592 | | | $ | 64,901 | | | 50 | % |
Coal Royalty Revenues
Approximately 65% of coal royalty revenues and approximately 50% of coal royalty sales volumes were derived from metallurgical coal during the year ended December 31, 2021. Total coal royalty revenues increased $52.2 million from 2020 to 2021 primarily as a result of stronger metallurgical coal demand and pricing in 2021. The discussion of these increases by region is as follows:
•Appalachia: Coal royalty revenues increased $45.2 million primarily due to a 30% increase in sales volumes in addition to higher sales prices as compared to the prior year.
•Illinois Basin: Coal royalty revenues increased $11.9 million primarily due to a 178% increase in sales volumes. In the second quarter of 2020, we entered into lease amendments with Foresight pursuant to which Foresight agreed to pay us fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreements between us and Foresight for calendar years 2020 and 2021. As a result of these amendments, actual revenues recognized from Foresight were flat period-over-period.
•Northern Powder River Basin: Coal royalty revenues increased $5.1 million primarily due to an 81% increase in sales volumes as our lessee mined on our property more during 2021 as compared to 2020.
Other Revenues
Other revenues increased $12.8 million from 2020 to 2021 primarily due to $13.8 million of forest CO2 sequestration revenues recognized in 2021 as a result of the sale of 1.1 million carbon offset credits which represents 1.1 million tonnes of carbon sequestered in our forestland in West Virginia. This increase was partially offset by a decrease in production lease minimum revenues as a result of lower breakage revenues recognized in 2021.
Soda Ash
Revenues and other income related to our Soda Ash segment increased $11.1 million compared to the prior year as demand and pricing for soda ash continues to improve globally from the lows caused by the COVID-19 pandemic.
Operating Expenses
The following table presents the significant categories of our consolidated operating expenses:
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| | For the Year Ended December 31, | | Increase (Decrease) | | Percentage Change |
(In thousands) | | 2021 | | 2020 | | |
Operating expenses | | | | | | | | |
Operating and maintenance expenses | | $ | 27,049 | | | $ | 24,795 | | | $ | 2,254 | | | 9 | % |
Depreciation, depletion and amortization | | 19,075 | | | 9,198 | | | 9,877 | | | 107 | % |
General and administrative expenses | | 17,360 | | | 14,293 | | | 3,067 | | | 21 | % |
Asset impairments | | 5,102 | | | 135,885 | | | (130,783) | | | (96) | % |
Total operating expenses | | $ | 68,586 | | | $ | 184,171 | | | $ | (115,585) | | | (63) | % |
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Total operating expenses decreased by $115.6 million primarily due to a $130.8 million decrease in asset impairments. Asset impairments in 2021 primarily related to a lease termination while asset impairments in 2020 were due to weakened coal markets that resulted in termination of certain coal leases, changes to lessee mine plans resulting in permanent moves off certain of our coal properties and decreased oil and gas drilling activity which negatively impacted the outlook for NRP's frac sand properties. This decrease was partially offset by a $9.9 million increase in depreciation, depletion and amortization expense primarily as a result of increased production at certain Illinois Basin coal properties. The remaining cost increases primarily related to increased incentive compensation expense as a result of significantly improved Partnership operating results year-over-year and increased overriding royalty expense due to higher coal sales and royalty revenue in 2021.
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:
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| | Operating Segments | | | | |
For the Year Ended (In thousands) | | Mineral Rights | | Soda Ash | | Corporate and Financing | | Total |
December 31, 2021 | | | | | | | | |
Net income (loss) from continuing operations | | $ | 143,412 | | | $ | 21,702 | | | $ | (56,212) | | | $ | 108,902 | |
Less: equity earnings from unconsolidated investment | | — | | | (21,871) | | | — | | | (21,871) | |
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Add: total distributions from unconsolidated investment | | — | | | 11,270 | | | — | | | 11,270 | |
Add: interest expense, net | | 24 | | | — | | | 38,852 | | | 38,876 | |
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Add: depreciation, depletion and amortization | | 19,075 | | | — | | | — | | | 19,075 | |
Add: asset impairments | | 5,102 | | | — | | | — | | | 5,102 | |
Adjusted EBITDA | | $ | 167,613 | | | $ | 11,101 | | | $ | (17,360) | | | $ | 161,354 | |
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December 31, 2020 | | | | | | | | |
Net income (loss) from continuing operations | | $ | (40,180) | | | $ | 10,543 | | | $ | (55,182) | | | $ | (84,819) | |
Less: equity earnings from unconsolidated investment | | — | | | (10,728) | | | — | | | (10,728) | |
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Add: total distributions from unconsolidated investment | | — | | | 14,210 | | | — | | | 14,210 | |
Add: interest expense, net | | 79 | | | — | | | 40,889 | | | 40,968 | |
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Add: depreciation, depletion and amortization | | 9,198 | | | — | | | — | | | 9,198 | |
Add: asset impairments | | 135,885 | | | — | | | — | | | 135,885 | |
Adjusted EBITDA | | $ | 104,982 | | | $ | 14,025 | | | $ | (14,293) | | | $ | 104,714 | |
Adjusted EBITDA increased $56.6 million primarily due to a $62.6 million increase in Adjusted EBITDA within our Mineral Rights segment as a result of higher revenues and other income during the year ended December 31, 2021 as discussed above. This increase was partially offset by a $2.9 million decrease in Adjusted EBITDA within our Soda Ash segment as a result of lower cash distributions received from Sisecam Wyoming during the year ended December 31, 2021 as compared to the prior year and a $3.1 million decrease in Adjusted EBITDA within our Corporate and Financing segment as a result of increased general and administrative costs primarily due to increased incentive compensation as a result of significantly improved Partnership operating results year-over-year.
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:
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| | Operating Segments | | | | |
For the Year Ended (In thousands) | | Mineral Rights | | Soda Ash | | Corporate and Financing | | Total |
December 31, 2021 | | | | | | | | |
Cash flow provided by (used in) continuing operations | | | | | | | | |
Operating activities | | $ | 159,845 | | | $ | 11,106 | | | $ | (49,147) | | | $ | 121,804 | |
Investing activities | | 2,412 | | | — | | | — | | | 2,412 | |
Financing activities | | (1,132) | | | — | | | (87,354) | | | (88,486) | |
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December 31, 2020 | | | | | | | | |
Cash flow provided by (used in) continuing operations | | | | | | | | |
Operating activities | | $ | 124,737 | | | $ | 14,037 | | | $ | (51,206) | | | $ | 87,568 | |
Investing activities | | 1,745 | | | — | | | — | | | 1,745 | |
Financing activities | | — | | | — | | | (87,788) | | | (87,788) | |
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:
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| | Operating Segments | | | | |
For the Year Ended (In thousands) | | Mineral Rights | | Soda Ash | | Corporate and Financing | | Total |
December 31, 2021 | | | | | | | | |
Net cash provided by (used in) operating activities of continuing operations | | $ | 159,845 | | | $ | 11,106 | | | $ | (49,147) | | | $ | 121,804 | |
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Add: proceeds from asset sales and disposals | | 249 | | | — | | | — | | | 249 | |
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Add: return of long-term contract receivable | | 2,163 | | | — | | | — | | | 2,163 | |
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Distributable cash flow | | $ | 162,257 | | | $ | 11,106 | | | $ | (49,147) | | | $ | 124,216 | |
Less: proceeds from asset sales and disposals | | (249) | | | — | | | — | | | (249) | |
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Less: acquisition costs | | (1,000) | | | — | | | — | | | (1,000) | |
Free cash flow | | $ | 161,008 | | | $ | 11,106 | | | $ | (49,147) | | | $ | 122,967 | |
Less: mandatory Opco debt repayments | | | | | | | | (39,396) | |
Less: preferred unit distributions | | | | | | | | (15,571) | |
Less: common unit distributions | | | | | | | | (22,645) | |
Less: warrant cash settlement | | | | | | | | (9,183) | |
Cash flow cushion | | | | | | | | $ | 36,172 | |
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For the Year Ended (In thousands) | | Mineral Rights | | Soda Ash | | Corporate and Financing | | Total |
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December 31, 2020 | | | | | | | | |
Net cash provided by (used in) operating activities of continuing operations | | $ | 124,737 | | | $ | 14,037 | | | $ | (51,206) | | | $ | 87,568 | |
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Add: proceeds from asset sales and disposals | | 623 | | | — | | | — | | | 623 | |
Add: proceeds from sale of discontinued operations | | — | | | — | | | — | | | (65) | |
Add: return of long-term contract receivable | | 2,122 | | | — | | | — | | | 2,122 | |
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Distributable cash flow | | $ | 127,482 | | | $ | 14,037 | | | $ | (51,206) | | | $ | 90,248 | |
Less: proceeds from asset sales and disposals | | (623) | | | — | | | — | | | (623) | |
Less: proceeds from sale of discontinued operations | | — | | | — | | | — | | | 65 | |
Less: acquisition costs | | (1,000) | | | — | | | — | | | (1,000) | |
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Free cash flow | | $ | 125,859 | | | $ | 14,037 | | | $ | (51,206) | | | $ | 88,690 | |
Less: mandatory Opco debt repayments | | | | | | | | (46,176) | |
Less: preferred unit distributions | | | | | | | | (26,363) | |
Less: common unit distributions | | | | | | | | (16,890) | |
Cash flow cushion | | | | | | | | $ | (739) | |
DCF and FCF increased $34.0 million and $34.3 million, respectively, primarily due to the increase in Mineral Rights segment DCF and FCF of $34.8 million and $35.1 million, respectively. The increase in Mineral Rights DCF and FCF was primarily driven by stronger metallurgical coal demand and pricing in 2021 and $13.8 million of cash received in the fourth quarter of 2021 as a result of the sale of 1.1 million forest carbon offset credits.
Cash flow cushion increased $36.9 million as a result of the increase in FCF discussed above in addition to:
•$10.8 million lower preferred unit distributions in 2021 as we paid one-half of the distributions in kind through the issuance of PIK units during the year ended December 31, 2021; and
•$6.8 million lower mandatory Opco debt repayments in 2021 as one series of Opco Senior Notes was fully repaid in 2020.
These increases in cash flow cushion were partially offset by:
•$9.2 million of cash used to settle the exercise of certain of our warrants in 2021; and
•$5.8 million higher common unit distributions in 2021 as we suspended our common unit distribution for one quarter in 2020.
Liquidity and Capital Resources
Current Liquidity
As of December 31, 2021, we had total liquidity of $235.5 million, consisting of $135.5 million of cash and cash equivalents and $100 million in borrowing capacity under our Opco Credit Facility. We have significant debt service obligations, including approximately $40 million of principal repayments on Opco’s senior notes in 2022. We believe our liquidity position provides us with the flexibility to continue paying down debt and manage our business through the current market environment.
Cash Flows
Year Ended December 31, 2021 and 2020 Compared
Cash flows provided by operating activities increased $32.5 million, from $89.3 million in the year ended December 31, 2020 to $121.8 million in the year ended December 31, 2021 primarily related to increased coal royalty cash flow in 2021 as a result of stronger metallurgical coal demand and pricing in 2021, the sale of 1.1 million forest carbon offset credits in 2021 and lower cash paid for interest year-over-year. These increases in cash provided by operating activities were partially offset by lower distributions from Sisecam Wyoming year-over-year.
Cash flows used in financing activities decreased $0.9 million, from $89.4 million in the year ended December 31, 2020 to $88.5 million in the year ended December 31, 2021 primarily due to a $10.8 million decrease in cash distributions to preferred unitholders as we paid one-half of our preferred unit distributions in kind through the issuance of 15.6 million preferred units in 2021. Additionally, debt repayments decreased $6.8 million in 2021 as one series of Opco Senior Notes was fully repaid during the year ended December 31, 2020. These decreases in cash flow used were partially offset by $9.2 million used to settle the exercise of certain of our warrants in 2021 in addition to a $5.8 million increase in distributions to common unitholders and the general partner as we suspended our common unit distribution in the second quarter of 2020.
Capital Resources and Obligations
Debt, Net
We had the following debt outstanding as of December 31, 2021 and 2020:
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| December 31, |
(In thousands) | 2021 | | 2020 |
Current portion of long-term debt, net | $ | 39,102 | | | $ | 39,055 | |
Long-term debt, net | 394,443 | | | 432,444 | |
Total debt, net | $ | 433,545 | | | $ | 471,499 | |
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 11. Debt, Net" in this Annual Report on Form 10-K.
Debt Obligations
The following table reflects our long-term, non-cancelable debt obligations as of December 31, 2021:
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| | Payments Due by Period |
Debt Obligations (In thousands) | | Total | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter |
NRP: | | | | | | | | | | | | | | |
Debt principal payments (1) | | $ | 300,000 | | | $ | — | | | $ | — | | | $ | — | | | $ | 300,000 | | | $ | — | | | $ | — | |
Debt interest payments (1) | | 95,813 | | | 27,375 | | | 27,375 | | | 27,375 | | | 13,688 | | | — | | | — | |
Opco: | | | | | | | | | | | | | | |
Debt principal payments (including current maturities) (2) | | 138,484 | | | 39,396 | | | 39,396 | | | 31,028 | | | 14,332 | | | 14,332 | | | — | |
Debt interest payments (3) | | 16,925 | | | 7,131 | | | 4,895 | | | 2,724 | | | 1,450 | | | 725 | | | — | |
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Total | | $ | 551,222 | | | $ | 73,902 | | | $ | 71,666 | | | $ | 61,127 | | | $ | 329,470 | | | $ | 15,057 | | | $ | — | |
(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, 2021 we did not have any borrowings outstanding under the Opco Credit Facility and had $100.0 million in available borrowing capacity.
Inflation
Inflation in the United States has been relatively low in previous years, and despite rising costs beginning in 2021, inflation did not have a material impact on operations for the years ended December 31, 2021, 2020 and 2019.
Environmental Regulation
Related Party Transactions
Summary of Critical Accounting Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, 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
Mineral Rights Segment Revenues
Royalty-based 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. 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.
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 for these leases is recognized over time based on production as 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 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. We also have overriding royalty revenue interests in certain of our coal mineral rights. Revenue from these interests is recognized over time based on when the coal is sold.
Forest CO2 sequestration revenues. Revenues related to the sale of our carbon offset credits that is recognized at a point in time upon execution of the transaction.
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 are 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 affects 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 royalty and other mineral rights 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 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 Sisecam 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 Sisecam 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 Sisecam Wyoming is recognized in equity in unconsolidated investment on our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings of Sisecam Wyoming on the Consolidated Statements of Comprehensive Income (Loss). We decrease our investment for our proportional share of distributions received from Sisecam 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 economic tonnage as estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of our economic tonnage 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 economic tonnage, including many factors beyond our control. Estimates of economically recoverable tonnage 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, including intangible 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 tons 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
We do not believe that any other recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our financial statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We did not audit the financial statements of Sisecam Wyoming LLC (Sisecam Wyoming), a limited liability company in which the Partnership has a 49% interest. In the consolidated financial statements, the Partnership’s investment in Sisecam Wyoming is stated at $276 million and $263 million as of December 31, 2021 and 2020, respectively, and the Partnership’s equity in the net income of Sisecam Wyoming is stated at $22 million in 2021, $11 million in 2020 and $47 million in 2019. 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 Sisecam 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, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 15, 2022 expressed an unqualified opinion thereon.
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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates.
Impairment Assessment of Mineral Rights
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Description of the Matter | At December 31, 2021, the Partnership’s mineral rights, net totaled a combined $438 million. As described in Note 2 to the consolidated financial statements, the Partnership evaluates its mineral rights for possible impairment whenever events or changes in circumstances indicate that the carrying amounts of the asset may not be recoverable (“triggering events”). Management evaluates various qualitative factors in determining whether or not events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Potential events or circumstances include but are not limited to reduction in economically recoverable reserves or production ceasing on a property for an extended period, and other relevant information received from the operators, which may include operational or legal information that indicates production from mineral interests will not likely occur or may be significantly reduced in the future.
Auditing the Partnership’s impairment triggers assessment involved our subjective judgment because, in determining whether a triggering event occurred, significant uncertainty exists with judgments management utilizes regarding the likelihood of future production and the likelihood of potential contract renewals or modifications, which rely on reserve or other relevant information reported by the operators. |
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Partnership’s impairment assessment process. We tested controls over the Partnership’s process for identifying and evaluating potential triggers of impairment and related significant judgments.
To test the Partnership’s impairment assessment, our audit procedures included, among others, making inquiries of management (including personnel in operations) to understand changes in business, and evaluating the significant judgments and operating data used in the Partnership’s assessment. Specifically, we corroborated reserve information to reserve studies when available. Additionally, we inspected the cancellation or significant modification of royalty-based lease contracts. We searched for and evaluated other publicly available information, such as legislative or regulatory changes and bankruptcy filings, that corroborates or contradicts management’s assessment. |
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2002.
Houston, Texas
March 15, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Members of
Sisecam Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Sisecam Wyoming LLC (the "Company") as of December 31, 2021 and 2020, 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, 2021, and the related notes that are 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Agreements and Transactions with Affiliates – Refer to Notes 1, 2, 8, 12, and 13 to the financial statements
Critical Audit Matter Description
The Company is a subsidiary and investee within two different global group structures and agreements directly between the Company and affiliates, or indirectly between affiliates that the Company does not control, can have a significant impact on recorded amounts or disclosures in the Company's financial statements, including any commitments and contingencies between the Company and affiliates or, potentially, third parties. Performing audit procedures to evaluate the Company’s identification of upstream affiliate relationships, transactions, and commitments and contingencies originating outside of the Ciner Enterprises, Inc. group and the impact of such matters on the financial statements represents a critical audit matter because of the increased auditor judgment necessary to perform audit procedures related to these matters and evaluate the results of those procedures.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Company’s identification of upstream affiliate relationships, transactions, and commitments and contingencies outside of the Ciner Enterprises, Inc. group and the impact of such matters on the financial statements included the following, among others:
•We tested the effectiveness of controls over the Company’s affiliate process, including controls over the identification of the Company’s affiliate relationships, transactions, and commitments and contingencies originating outside of the Ciner Enterprises, Inc. group.
•We read publicly available financial filings and news sources related to the Company and its affiliates outside of the Ciner Enterprises, Inc. group and listened to the parent company (Sisecam Resources LP) quarterly investor relations calls for information related to potential new affiliates and transactions between the Company and affiliates.
•We inspected director and executive officer questionnaires from the Sisecam Resources LP's directors and officers to identify any affiliate matters.
•We searched the general ledger for potential transactions with affiliates.
•We read significant new or amended agreements and contracts of the Company to identify new affiliate relationships, transactions, or commitments and contingencies, and evaluated management’s analyses regarding the accounting and disclosure of such arrangements.
•We inquired of executive officers, key members of management, and the Board of Managers regarding affiliate relationships, transactions and commitments and contingencies.
•We confirmed with the Company's ultimate parent companies that the affiliate relationships, transactions, and commitments and contingencies identified and disclosed by the Company were complete.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 15, 2022
We have served as the Company’s auditor since 2008.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | |
| December 31, |
(In thousands, except unit data) | 2021 | | 2020 |
ASSETS | | | |
Current assets | | | |
Cash and cash equivalents | $ | 135,520 | | | $ | 99,790 | |
| | | |
Accounts receivable, net | 24,538 | | | 12,322 | |
Other current assets, net | 2,723 | | | 5,080 | |
| | | |
Total current assets | $ | 162,781 | | | $ | 117,192 | |
Land | 24,008 | | | 24,008 | |
| | | |
Mineral rights, net | 437,697 | | | 460,373 | |
Intangible assets, net | 16,130 | | | 17,459 | |
Equity in unconsolidated investment | 276,004 | | | 262,514 | |
Long-term contract receivable, net | 31,371 | | | 33,264 | |
| | | |
Other long-term assets, net | 5,832 | | | 7,067 | |
Total assets | $ | 953,823 | | | $ | 921,877 | |
LIABILITIES AND CAPITAL | | | |
Current liabilities | | | |
Accounts payable | $ | 1,956 | | | $ | 1,385 | |
Accrued liabilities | 10,297 | | | 7,733 | |
Accrued interest | 1,213 | | | 1,714 | |
Current portion of deferred revenue | 11,817 | | | 11,485 | |
Current portion of long-term debt, net | 39,102 | | | 39,055 | |
| | | |
Total current liabilities | $ | 64,385 | | | $ | 61,372 | |
Deferred revenue | 50,045 | | | 50,069 | |
Long-term debt, net | 394,443 | | | 432,444 | |
Other non-current liabilities | 5,018 | | | 5,131 | |
Total liabilities | $ | 513,891 | | | $ | 549,016 | |
Commitments and contingencies (see Note 15) | | | |
Class A Convertible Preferred Units (269,321 and 253,750 units issued and outstanding at December 31, 2021 and 2020, respectively, at $1,000 par value per unit; liquidation preference of $1,850 per unit at December 31, 2021 and $1,700 per unit per unit at December 31, 2020) | $ | 183,908 | | | $ | 168,337 | |
Partners’ capital | | | |
Common unitholders’ interest (12,351,306 and 12,261,199 units issued and outstanding at December 31, 2021 and 2020, respectively) | $ | 203,062 | | | $ | 136,927 | |
General partner’s interest | 1,787 | | | 459 | |
Warrant holders’ interest | 47,964 | | | 66,816 | |
Accumulated other comprehensive income | 3,211 | | | 322 | |
| | | |
| | | |
Total partners' capital | $ | 256,024 | | | $ | 204,524 | |
Total liabilities and partners' capital | $ | 953,823 | | | $ | 921,877 | |
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
(In thousands, except per unit data) | 2021 | | 2020 | | 2019 |
Revenues and other income | | | | | |
Royalty and other mineral rights | $ | 185,196 | | | $ | 120,166 | | | $ | 191,069 | |
Transportation and processing services | 9,052 | | | 8,845 | | | 19,279 | |
Equity in earnings of Sisecam Wyoming | 21,871 | | | 10,728 | | | 47,089 | |
| | | | | |
Gain on asset sales and disposals | 245 | | | 581 | | | 6,498 | |
Total revenues and other income | $ | 216,364 | | | $ | 140,320 | | | $ | 263,935 | |
| | | | | |
Operating expenses | | | | | |
Operating and maintenance expenses | $ | 27,049 | | | $ | 24,795 | | | $ | 32,738 | |
Depreciation, depletion and amortization | 19,075 | | | 9,198 | | | 14,932 | |
General and administrative expenses | 17,360 | | | 14,293 | | | 16,730 | |
Asset impairments | 5,102 | | | 135,885 | | | 148,214 | |
Total operating expenses | $ | 68,586 | | | $ | 184,171 | | | $ | 212,614 | |
| | | | | |
Income (loss) from operations | $ | 147,778 | | | $ | (43,851) | | | $ | 51,321 | |
| | | | | |
Other expenses, net | | | | | |
Interest expense, net | $ | (38,876) | | | $ | (40,968) | | | $ | (47,453) | |
| | | | | |
Loss on extinguishment of debt | — | | | — | | | (29,282) | |
| | | | | |
Total other expenses, net | $ | (38,876) | | | $ | (40,968) | | | $ | (76,735) | |
| | | | | |
Net income (loss) from continuing operations | $ | 108,902 | | | $ | (84,819) | | | $ | (25,414) | |
Income from discontinued operations | — | | | — | | | 956 | |
Net income (loss) | $ | 108,902 | | | $ | (84,819) | | | $ | (24,458) | |
| | | | | |
| | | | | |
Less: income attributable to preferred unitholders | (31,609) | | | (30,225) | | | (30,000) | |
Net income (loss) attributable to common unitholders and the general partner | $ | 77,293 | | | $ | (115,044) | | | $ | (54,458) | |
| | | | | |
Net income (loss) attributable to common unitholders | $ | 75,747 | | | $ | (112,743) | | | $ | (53,369) | |
Net income (loss) attributable to the general partner | 1,546 | | | (2,301) | | | (1,089) | |
| | | | | |
Income (loss) from continuing operations per common unit (see Note 6) | | | | |
Basic | $ | 6.14 | | | $ | (9.20) | | | $ | (4.43) | |
Diluted | 4.81 | | | (9.20) | | | (4.43) | |
| | | | | |
Net income (loss) per common unit (see Note 6) | | | | | |
Basic | $ | 6.14 | | | $ | (9.20) | | | $ | (4.35) | |
Diluted | 4.81 | | | (9.20) | | | (4.35) | |
| | | | | |
Net income (loss) | $ | 108,902 | | | $ | (84,819) | | | $ | (24,458) | |
Comprehensive income from unconsolidated investment and other | 2,889 | | | 2,916 | | | 868 | |
Comprehensive income (loss) | $ | 111,791 | | | $ | (81,903) | | | $ | (23,590) | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Unitholders | | General Partner | | Warrant Holders | | Accumulated Other Comprehensive Income (Loss) | | Partners' Capital Excluding Non-Controlling Interest | | Non-Controlling Interest | | Total Capital |
|
(In thousands) | Units | | Amounts | |
Balance at December 31, 2018 | 12,249 | | | $ | 355,113 | | | $ | 5,014 | | | $ | 66,816 | | | $ | (3,462) | | | $ | 423,481 | | | $ | (2,935) | | | $ | 420,546 | |
| | | | | | | | | | | | | | | |
Net loss (1) | — | | | (23,969) | | | (489) | | | — | | | — | | | (24,458) | | | — | | | (24,458) | |
Distributions to common unitholders and the general partner | — | | | (32,487) | | | (663) | | | — | | | — | | | (33,150) | | | — | | | (33,150) | |
Distributions to preferred unitholders | — | | | (29,400) | | | (600) | | | — | | | — | | | (30,000) | | | — | | | (30,000) | |
Issuance of unit-based awards | 12 | | | 486 | | | — | | | — | | | — | | | 486 | | | — | | | 486 | |
Unit-based awards amortization and vesting | — | | | 1,804 | | | — | | | — | | | — | | | 1,804 | | | — | | | 1,804 | |
Comprehensive income (loss) from unconsolidated investment and other | — | | | (76) | | | 8 | | | — | | | 868 | | | 800 | | | — | | | 800 | |
Balance at December 31, 2019 | 12,261 | | | $ | 271,471 | | | $ | 3,270 | | | $ | 66,816 | | | $ | (2,594) | | | $ | 338,963 | | | $ | (2,935) | | | $ | 336,028 | |
Cumulative effect of adoption of accounting standard | — | | | (3,833) | | | (78) | | | — | | | — | | | (3,911) | | | — | | | (3,911) | |
Net loss (2) | — | | | (83,123) | | | (1,696) | | | — | | | — | | | (84,819) | | | — | | | (84,819) | |
Distributions to common unitholders and the general partner | — | | | (16,552) | | | (338) | | | — | | | — | | | (16,890) | | | — | | | (16,890) | |
Distributions to preferred unitholders | — | | | (29,511) | | | (602) | | | — | | | — | | | (30,113) | | | — | | | (30,113) | |
Acquisition of non-controlling interest in BRP | — | | | (4,747) | | | (97) | | | — | | | — | | | (4,844) | | | 2,935 | | | (1,909) | |
| | | | | | | | | | | | | | | |
Unit-based awards amortization and vesting | — | | | 3,222 | | | — | | | — | | | — | | | 3,222 | | | — | | | 3,222 | |
Comprehensive income from unconsolidated investment and other | — | | | — | | | — | | | — | | | 2,916 | | | 2,916 | | | — | | | 2,916 | |
Balance at December 31, 2020 | 12,261 | | | $ | 136,927 | | | $ | 459 | | | $ | 66,816 | | | $ | 322 | | | $ | 204,524 | | | $ | — | | | $ | 204,524 | |
| | | | | | | | | | | | | | | |
Net income (3) | — | | | 106,724 | | | 2,178 | | | — | | | — | | | 108,902 | | | — | | | 108,902 | |
Distributions to common unitholders and the general partner | — | | | (22,192) | | | (453) | | | — | | | — | | | (22,645) | | | — | | | (22,645) | |
Distributions to preferred unitholders | — | | | (30,519) | | | (623) | | | — | | | — | | | (31,142) | | | — | | | (31,142) | |
| | | | | | | | | | | | | | | |
Issuance of unit-based awards | 90 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Unit-based awards amortization and vesting | — | | | 2,647 | | | — | | | — | | | — | | | 2,647 | | | — | | | 2,647 | |
Capital contribution | — | | | — | | | 32 | | | — | | | — | | | 32 | | | — | | | 32 | |
Warrant settlement | — | | | 9,475 | | | 194 | | | (18,852) | | | — | | | (9,183) | | | — | | | (9,183) | |
| | | | | | | | | | | | | | | |
Comprehensive income from unconsolidated investment and other | — | | | — | | | — | | | — | | | 2,889 | | | 2,889 | | | — | | | 2,889 | |
Balance at December 31, 2021 | 12,351 | | | $ | 203,062 | | | $ | 1,787 | | | $ | 47,964 | | | $ | 3,211 | | | $ | 256,024 | | | $ | — | | | $ | 256,024 | |
(1)Net loss includes $30.0 million of income 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. (2) Net loss includes $30.2 million of income attributable to preferred unitholders that accumulated during the period, of which $29.6 million is allocated to the common unitholders and $0.6 million is allocated to the general partner. (3) Net income includes $31.6 million of income attributable to preferred unitholders that accumulated during the period, of which $31.0 million is allocated to the common unitholders and $0.6 million is allocated to the general partner.
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
(In thousands) | 2021 | | 2020 | | 2019 |
Cash flows from operating activities | | | | | |
Net income (loss) | $ | 108,902 | | | $ | (84,819) | | | $ | (24,458) | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities of continuing operations: | | | | | |
Depreciation, depletion and amortization | 19,075 | | | 9,198 | | | 14,932 | |
Distributions from unconsolidated investment | 11,270 | | | 14,210 | | | 31,850 | |
Equity earnings from unconsolidated investment | (21,871) | | | (10,728) | | | (47,089) | |
Gain on asset sales and disposals | (245) | | | (581) | | | (6,498) | |
| | | | | |
Loss on extinguishment of debt | — | | | — | | | 29,282 | |
Income from discontinued operations | — | | | — | | | (956) | |
Asset impairments | 5,102 | | | 135,885 | | | 148,214 | |
Bad debt expense | 2,572 | | | 4,001 | | | 7,462 | |
Unit-based compensation expense | 4,039 | | | 3,570 | | | 2,361 | |
Amortization of debt issuance costs and other | 2,265 | | | 1,323 | | | 3,687 | |
Change in operating assets and liabilities: | | | | | |
Accounts receivable | (14,415) | | | 12,853 | | | (6,035) | |
Accounts payable | 570 | | | 207 | | | (1,234) | |
Accrued liabilities | 3,020 | | | (2,205) | | | (3,656) | |
Accrued interest | (501) | | | (602) | | | (12,029) | |
Deferred revenue | 307 | | | 9,733 | | | (732) | |
Other items, net | 1,714 | | | (4,477) | | | 2,218 | |
Net cash provided by operating activities of continuing operations | $ | 121,804 | | | $ | 87,568 | | | $ | 137,319 | |
Net cash provided by (used in) operating activities of discontinued operations | — | | | 1,706 | | | (8) | |
Net cash provided by operating activities | $ | 121,804 | | | $ | 89,274 | | | $ | 137,311 | |
| | | | | |
Cash flows from investing activities | | | | | |
| | | | | |
Proceeds from asset sales and disposals | $ | 249 | | | $ | 623 | | | $ | 6,500 | |
Return of long-term contract receivable | 2,163 | | | 2,122 | | | 1,743 | |
Acquisition of non-controlling interest in BRP | — | | | (1,000) | | | — | |
Acquisition of mineral rights | — | | | — | | | (22) | |
Net cash provided by investing activities of continuing operations | $ | 2,412 | | | $ | 1,745 | | | $ | 8,221 | |
Net cash used in investing activities of discontinued operations | — | | | (65) | | | (629) | |
Net cash provided by investing activities | $ | 2,412 | | | $ | 1,680 | | | $ | 7,592 | |
| | | | | |
Cash flows from financing activities | | | | | |
| | | | | |
Debt borrowings | $ | — | | | $ | — | | | $ | 300,000 | |
Debt repayments | (39,396) | | | (46,176) | | | (463,082) | |
| | | | | |
Distributions to common unitholders and the general partner | (22,645) | | | (16,890) | | | (33,150) | |
Distributions to preferred unitholders | (15,571) | | | (26,363) | | | (30,000) | |
Warrant settlement | (9,183) | | | — | | | — | |
Acquisition of non-controlling interest in BRP | (1,000) | | | — | | | — | |
Contributions from (to) discontinued operations | — | | | 1,641 | | | (637) | |
Other items | (691) | | | — | | | (26,436) | |
Net cash used in financing activities of continuing operations | $ | (88,486) | | | $ | (87,788) | | | $ | (253,305) | |
Net cash provided by (used in) financing activities of discontinued operations | — | | | (1,641) | | | 637 | |
Net cash used in financing activities | $ | (88,486) | | | $ | (89,429) | | | $ | (252,668) | |
| | | | | |
Net increase (decrease) in cash and cash equivalents | $ | 35,730 | | | $ | 1,525 | | | $ | (107,765) | |
| | | | | |
Cash and cash equivalents of continuing operations at beginning of period | 99,790 | | | 98,265 | | | 206,030 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Cash and cash equivalents at end of period | $ | 135,520 | | | $ | 99,790 | | | $ | 98,265 | |
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
(In thousands) | 2021 | | 2020 | | 2019 |
| | | | | |
Supplemental cash flow information: | | | | | |
Cash paid for interest | $ | 37,378 | | | $ | 39,830 | | | $ | 58,597 | |
| | | | | |
Non-cash investing and financing activities: | | | | | |
Plant, equipment, mineral rights and other funded with accounts payable or accrued liabilities | $ | — | | | $ | 970 | | | $ | — | |
Preferred unit distributions paid-in-kind | 15,571 | | | 3,750 | | | — | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning, 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 Sisecam Wyoming LLC ("Sisecam Wyoming"), formerly known as Ciner Wyoming, a trona ore mining and soda ash production business. The Partnership is organized into two operating segments further described in Note 7. 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 Blackstone 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. The Partnership has an equity investment in Sisecam 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 in the Notes to Consolidated Financial Statements 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 mineral rights 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 12. Fair Value Measurements for further details.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
There are three levels of inputs that may be used to measure fair value:
•Level 1—Quoted prices in active markets for identical assets or liabilities.
•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 and Cash Equivalents
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents
Allowance for Doubtful Accounts
The Partnership records an allowance for doubtful accounts for its accounts receivable and notes receivable comprised of estimated credit risk and non-credit risk (e.g., legal disputes) losses. Receivables are written off when collection efforts are exhausted and future recovery is doubtful. The Partnership includes an allowance for current expected credit losses ("CECL") on its financial assets based on the loss-rate method. NRP assesses the likelihood of collection of its receivables utilizing historical loss rates, current market conditions that include the estimated impact of the global COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers and properties. See Note 18. Credit Losses for more information. The total allowance related to accounts receivables included in accounts receivables, net on the Partnership's Consolidated Balance Sheets was $3.2 million and $1.7 million at December 31, 2021 and 2020, respectively. The total allowance related to short-term notes receivables included in other current assets, net on the Partnership's Consolidated Balance Sheets was $0.1 million and $0.6 million at December 31, 2021 and 2020, respectively. The total allowance related to the Partnership's long-term financing receivable included in long-term contract receivable, net on the Consolidated Balance Sheets was $1.1 million and $1.6 million at December 31, 2021 and 2020, respectively. The Partnership recorded bad debt expense of $2.6 million, $4.0 million and $7.5 million included in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) for the year ended December 31, 2021, 2020 and 2019, 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 economic 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 economic 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, including intangible 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 tons or production ceasing on a property for an extended period. This analysis is based on historic,
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
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, 2021 were $7.7 million of accrued employee costs and $2.6 million of other accrued liabilities, which includes property taxes. These amounts were $3.7 million and $4.0 million of accrued employee costs and other accrued liabilities, respectively, at December 31, 2020. Other accrued liabilities at December 31, 2020 primarily included property taxes.
Revenue Recognition
Mineral Rights 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.
The Partnership has defined its coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell its coal or aggregates over the lease term. NRP then evaluated the likelihood that consideration it 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 for these leases is recognized over time based on production as 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 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.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 certain coal mineral rights. Revenue from these interests is recognized over time based on when the coal is sold.
Forest CO2 sequestration revenues. Revenues related to the sale of NRP's carbon offset credits that are recognized at a point in time upon execution of the transaction.
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 are 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 royalty and other mineral rights 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.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Equity in Earnings of Sisecam 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 Sisecam 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 Sisecam 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 Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings of Sisecam Wyoming on the Consolidated Statements of Comprehensive Income (Loss). The Partnership decreases its investment for its proportional share of distributions received from Sisecam 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.
Property Taxes
The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in operating and maintenance expenses and in royalty and other mineral rights revenues, respectively, on the Consolidated Statements of Comprehensive Income (Loss).
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 16. 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 long-term 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.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
3. Revenues from Contracts with Customers
The following table represents the Partnership's Mineral Rights segment revenues by major source:
| | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
(In thousands) | | 2021 | | 2020 | | 2019 |
Coal royalty revenues | | $ | 104,089 | | | $ | 51,868 | | | $ | 109,612 | |
Production lease minimum revenues | | 14,269 | | | 21,749 | | | 24,068 | |
Minimum lease straight-line revenues | | 20,564 | | | 16,796 | | | 14,910 | |
Forest CO2 sequestration revenues | | 13,790 | | | — | | | — | |
Property tax revenues | | 6,028 | | | 5,786 | | | 6,287 | |
Wheelage revenues | | 10,065 | | | 7,025 | | | 5,880 | |
Coal overriding royalty revenues | | 4,367 | | | 4,977 | | | 13,496 | |
Lease amendment revenues | | 4,696 | | | 3,450 | | | 7,991 | |
Aggregates royalty revenues | | 1,889 | | | 1,717 | | | 4,265 | |
Oil and gas royalty revenues | | 4,506 | | | 5,816 | | | 3,031 | |
Other revenues | | 933 | | | 982 | | | 1,529 | |
Royalty and other mineral rights revenues | | $ | 185,196 | | | $ | 120,166 | | | $ | 191,069 | |
Transportation and processing services revenues (1) | | 9,052 | | | 8,845 | | | 19,279 | |
Total Mineral Rights segment revenues | | $ | 194,248 | | | $ | 129,011 | | | $ | 210,348 | |
(1)Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $5.4 million, $5.0 million and $9.6 million for the year ended December 31, 2021, 2020 and 2019, respectively. The remaining transportation and processing services revenues of $3.6 million, $3.8 million and $9.7 million for the year ended December 31, 2021, 2020 and 2019, respectively, related to other NRP-owned infrastructure leased to and operated by third-party operators accounted for under other guidance. See Note 17. Financing Transaction for more information. The following table details the Partnership's Mineral Rights segment receivables and liabilities resulting from contracts with customers:
| | | | | | | | | | | | | | |
| | December 31, |
(In thousands) | | 2021 | | 2020 |
Receivables | | | | |
Accounts receivable, net | | $ | 22,277 | | | $ | 10,193 | |
Other current assets, net (1) | | 769 | | | 3,307 | |
Other long-term assets, net (2) | | 250 | | | 525 | |
| | | | |
Contract liabilities | | | | |
Current portion of deferred revenue | | $ | 11,817 | | | $ | 11,485 | |
Deferred revenue | | 50,045 | | | 50,069 | |
(1)Other current assets, net includes short-term notes receivables from contracts with customers.
(2)Other long-term assets, net includes long-term lease amendment fee receivables from contracts with customers.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows the activity related to the Partnership's Mineral Rights segment deferred revenue:
| | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
(In thousands) | | 2021 | | 2020 | | 2019 |
| | | | | | |
| | | | | | |
Balance at beginning of period (current and non-current) | | $ | 61,554 | | | $ | 51,821 | | | $ | 52,553 | |
Increase due to minimums and lease amendment fees | | 19,842 | | | 41,557 | | | 47,038 | |
Recognition of previously deferred revenue | | (19,534) | | | (31,824) | | | (47,770) | |
Balance at end of period (current and non-current) | | $ | 61,862 | | | $ | 61,554 | | | $ | 51,821 | |
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 as of December 31, 2021 (in thousands):
| | | | | | | | | | | | | | |
Lease Term (1) | | Weighted Average Remaining Years | | Annual Minimum Payments |
0 - 5 years | | 2.6 | | $ | 18,341 | |
5 - 10 years | | 4.1 | | 6,823 | |
10+ years | | 13.5 | | 28,069 | |
Total | | 8.6 | | $ | 53,233 | |
(1)Lease term does not include renewal periods.
4. 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.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
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.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Initial Measurement
The net transaction price 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.
Subsequent Measurement
Subsequent adjustment of the preferred units will not occur until NRP has determined that the conversion or redemption of all or a portion of the preferred units is probable of occurring. Once conversion or redemption becomes probable of occurring, the carrying amount of the preferred units will be accreted to their redemption value over the period from the date the feature is probable of occurring to the date the preferred units can first be converted or redeemed.
Activity related to the preferred units is as follows:
| | | | | | | | | | | | | | |
(In thousands, except unit data) | | Units Outstanding | | Financial Position |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Balance at December 31, 2018 and 2019 | | 250,000 | | | $ | 164,587 | |
Distribution paid-in-kind | | 3,750 | | | 3,750 | |
Balance at December 31, 2020 | | 253,750 | | | $ | 168,337 | |
Distributions paid-in-kind | | 15,571 | | | 15,571 | |
Balance at December 31, 2021 | | 269,321 | | | $ | 183,908 | |
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. On November 10, 2021 (the "exercise date"), Blackstone exercised all of its 997,500 warrants with a strike price of $22.81 and NRP settled the warrants in cash on a net basis. NRP delivered the net cash settlement amount of $9.2 million. The 15-day VWAP ending on the business day prior to the exercise date was $32.02.
Activity related to the warrants is as follows:
| | | | | | | | | | | | | | |
(In thousands, except warrant data) | | Warrants Outstanding | | Financial Position |
Balance at December 31, 2018, 2019 and 2020 | | 4,000,000 | | | $ | 66,816 | |
Warrant settlement | | (997,500) | | | (18,852) | |
Balance at December 31, 2021 | | 3,002,500 | | | $ | 47,964 | |
Certain embedded features within the preferred unit and warrant purchase agreement are accounted for at fair value and are remeasured each quarter. See Note 12. Fair Value Measurements for further information regarding valuation of these embedded derivatives.
5. Common and Preferred Unit Distributions
The Partnership makes 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.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 $31.6 million, $30.2 million and $30.0 million during the year ended December 31, 2021, 2020 and 2019, respectively as a result of accumulated preferred unit distributions earned during the period.
The following table shows the distributions declared and paid to common and preferred unitholders during the year
ended December 31, 2021, 2020 and 2019, respectively:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Distributions | | Paid-in-kind Distributions |
| | Common Units | | Preferred Units |
Date Paid | | Period Covered by Distribution | | Distribution per Unit | | Total Distribution (1) (In thousands) | | Distribution per Unit | | Total Distribution (In thousands) | | Total Distribution (In units) |
2021 | | | | | | | | | | | | |
February 2021 | | October 1 - December 31, 2020 | | $ | 0.45 | | | $ | 5,630 | | | $ | 15.00 | | | $ | 3,806 | | | 3,806 | |
May 2021 | | January 1 - March 31, 2021 | | 0.45 | | | 5,672 | | | 15.00 | | | 3,864 | | | 3,864 | |
August 2021 | | April 1 - June 30, 2021 | | 0.45 | | | 5,671 | | | 15.00 | | | 3,921 | | | 3,921 | |
November 2021 | | July 1 - September 30, 2021 | | 0.45 | | | 5,672 | | | 15.00 | | | 3,980 | | | 3,980 | |
| | | | | | | | | | | | |
2020 | | | | | | | | | | | | |
February 2020 | | October 1 - December 31, 2019 | | $ | 0.45 | | | $ | 5,630 | | | $ | 30.00 | | | $ | 7,500 | | | — | |
May 2020 | | January 1 - March 31, 2020 | | — | | | — | | | 15.00 | | | 3,750 | | | 3,750 | |
June 2020 (2) | | January 1 - March 31, 2020 | | — | | | — | | | 15.45 | | | 3,863 | | | — | |
August 2020 | | April 1 - June 30, 2020 | | 0.45 | | | 5,630 | | | 30.00 | | | 7,500 | | | — | |
November 2020 | | July 1 - September 30, 2020 | | 0.45 | | | 5,630 | | | 15.00 | | | 3,750 | | | 3,750 | |
| | | | | | | | | | | | |
2019 | | | | | | | | | | | | |
February 2019 | | October 1 - December 31, 2018 | | $ | 0.45 | | | $ | 5,625 | | | $ | 30.00 | | | $ | 7,500 | | | — | |
May 2019 | | January 1 - March 31, 2019 | | 0.45 | | | 5,630 | | | 30.00 | | | 7,500 | | | — | |
May 2019 (3) | | Special Distribution | | 0.85 | | | 10,635 | | | — | | | — | | | — | |
August 2019 | | April 1 - June 30, 2019 | | 0.45 | | | 5,630 | | | 30.00 | | | 7,500 | | | — | |
November 2019 | | July 1 - September 30, 2019 | | 0.45 | | | 5,630 | | | 30.00 | | | 7,500 | | | — | |
(1)Total common unit distribution includes the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest.
(2)Redemption of preferred units paid in kind plus accrued interest.
(3)Special distribution was made to cover the common unitholders' tax liability resulting from the sale of NRP's construction aggregates business in December 2018.
6. 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 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
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
for purposes of the if-converted calculation. The calculation of diluted net income per common unit for the year ended December 31, 2021 includes the assumed conversion of the preferred units. The calculation of diluted net loss per common unit for the years ended December 31, 2020 and 2019 does not include the assumed conversion of the preferred units because the impact would have been anti-dilutive.
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. The calculation of diluted net income per common unit for the year ended December 31, 2021 includes the net settlement of warrants to purchase 0.75 million common units with a strike price of $22.81 but does 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. The calculation of diluted net loss per common unit for the years ended December 31, 2020 and 2019 does not include the net settlement of warrants to purchase 1.75 million common units with a strike price of $22.81 or 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.
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:
| | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
(In thousands, except per unit data) | | 2021 | | 2020 | | 2019 |
Allocation of net income (loss) | | | | | | |
Net income (loss) from continuing operations | | $ | 108,902 | | | $ | (84,819) | | | $ | (25,414) | |
| | | | | | |
Less: income attributable to preferred unitholders | | (31,609) | | | (30,225) | | | (30,000) | |
Net income (loss) from continuing operations attributable to common unitholders and the general partner | | $ | 77,293 | | | $ | (115,044) | | | $ | (55,414) | |
Add (less): net loss (income) from continuing operations attributable to the general partner | | (1,546) | | | 2,301 | | | 1,108 | |
Net income (loss) from continuing operations attributable to common unitholders | | $ | 75,747 | | | $ | (112,743) | | | $ | (54,306) | |
| | | | | | |
Net income from discontinued operations | | $ | — | | | $ | — | | | $ | 956 | |
Less: net income from discontinued operations attributable to the general partner | | — | | | — | | | (19) | |
Net income from discontinued operations attributable to common unitholders | | $ | — | | | $ | — | | | $ | 937 | |
| | | | | | |
Net income (loss) | | $ | 108,902 | | | $ | (84,819) | | | $ | (24,458) | |
| | | | | | |
Less: income attributable to preferred unitholders | | (31,609) | | | (30,225) | | | (30,000) | |
Net income (loss) attributable to common unitholders and the general partner | | $ | 77,293 | | | $ | (115,044) | | | $ | (54,458) | |
Add (less): net loss (income) attributable to the general partner | | (1,546) | | | 2,301 | | | 1,089 | |
Net income (loss) attributable to common unitholders | | $ | 75,747 | | | $ | (112,743) | | | $ | (53,369) | |
| | | | | | |
Basic income (loss) per common unit | | | | | | |
Weighted average common units—basic | | 12,337 | | | 12,261 | | | 12,260 | |
Basic net income (loss) from continuing operations per common unit | | $ | 6.14 | | | $ | (9.20) | | | $ | (4.43) | |
Basic net income from discontinued operations per common unit | | $ | — | | | $ | — | | | $ | 0.08 | |
Basic net income (loss) per common unit | | $ | 6.14 | | | $ | (9.20) | | | $ | (4.35) | |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
| | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
(In thousands, except per unit data) | | 2021 | | 2020 | | 2019 |
Diluted income (loss) per common unit | | | | | | |
Weighted average common units—basic | | 12,337 | | | 12,261 | | | 12,260 | |
Plus: dilutive effect of preferred units | | 9,604 | | | — | | | — | |
Plus: dilutive effect of warrants | | 74 | | | — | | | — | |
Plus: dilutive effect of unvested unit-based awards | | 178 | | | — | | | — | |
Weighted average common units—diluted | | 22,193 | | | 12,261 | | | 12,260 | |
| | | | | | |
Net income (loss) from continuing operations | | $ | 108,902 | | | $ | (84,819) | | | $ | (25,414) | |
| | | | | | |
Less: income attributable to preferred unitholders | | — | | | (30,225) | | | (30,000) | |
Diluted net income (loss) from continuing operations attributable to common unitholders and the general partner | | $ | 108,902 | | | $ | (115,044) | | | $ | (55,414) | |
Add (less): net loss (income) from continuing operations attributable to the general partner | | (2,178) | | | 2,301 | | | 1,108 | |
Diluted net income (loss) from continuing operations attributable to common unitholders | | $ | 106,724 | | | $ | (112,743) | | | $ | (54,306) | |
| | | | | | |
Diluted net income from discontinued operations attributable to common unitholders | | $ | — | | | $ | — | | | $ | 937 | |
| | | | | | |
Net income (loss) | | $ | 108,902 | | | $ | (84,819) | | | $ | (24,458) | |
| | | | | | |
Less: income attributable to preferred unitholders | | — | | | (30,225) | | | (30,000) | |
Diluted net income (loss) attributable to common unitholders and the general partner | | $ | 108,902 | | | $ | (115,044) | | | $ | (54,458) | |
Add (less): diluted net loss (income) attributable to the general partner | | (2,178) | | | 2,301 | | | 1,089 | |
Diluted net income (loss) attributable to common unitholders | | $ | 106,724 | | | $ | (112,743) | | | $ | (53,369) | |
| | | | | | |
Diluted net income (loss) from continuing operations per common unit | | $ | 4.81 | | | $ | (9.20) | | | $ | (4.43) | |
Diluted net income from discontinued operations per common unit | | $ | — | | | $ | — | | | $ | 0.08 | |
Diluted net income (loss) per common unit | | $ | 4.81 | | | $ | (9.20) | | | $ | (4.35) | |
7. 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:
Mineral Rights (formerly named Coal Royalty and Other segment)—consists of mineral interests and other subsurface rights across the United States. NRP's ownership provides critical inputs for the manufacturing of steel, electricity and basic building materials, as well as opportunities for carbon sequestration and renewable energy. The Partnership is working to strategically redefine its business as a key player in the transitional energy economy in the years to come.
Soda Ash—consists of the Partnership's 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining operation and soda ash refinery in the Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into 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).
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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).
The following table summarizes certain financial information for each of the Partnership's business segments:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Segments | | | | |
(In thousands) | | Mineral Rights | | Soda Ash | | Corporate and Financing | | Total |
For the Year Ended December 31, 2021 | | | | | | | | |
Revenues | | $ | 194,248 | | | $ | 21,871 | | | $ | — | | | $ | 216,119 | |
| | | | | | | | |
Gain on asset sales and disposals | | 245 | | | — | | | — | | | 245 | |
Operating and maintenance expenses | | 26,880 | | | 169 | | | — | | | 27,049 | |
Depreciation, depletion and amortization | | 19,075 | | | — | | | — | | | 19,075 | |
General and administrative expenses | | — | | | — | | | 17,360 | | | 17,360 | |
Asset impairments | | 5,102 | | | — | | | — | | | 5,102 | |
Other expenses, net | | 24 | | | — | | | 38,852 | | | 38,876 | |
Net income (loss) from continuing operations | | 143,412 | | | 21,702 | | | (56,212) | | | 108,902 | |
| | | | | | | | |
As of December 31, 2021 | | | | | | | | |
Total assets | | $ | 675,579 | | | $ | 276,004 | | | $ | 2,240 | | | $ | 953,823 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
For the Year Ended December 31, 2020 | | | | | | | | |
Revenues | | $ | 129,011 | | | $ | 10,728 | | | $ | — | | | $ | 139,739 | |
| | | | | | | | |
Gain on asset sales and disposals | | 581 | | | — | | | — | | | 581 | |
Operating and maintenance expenses | | 24,610 | | | 185 | | | — | | | 24,795 | |
Depreciation, depletion and amortization | | 9,198 | | | — | | | — | | | 9,198 | |
General and administrative expenses | | — | | | — | | | 14,293 | | | 14,293 | |
Asset impairments | | 135,885 | | | — | | | — | | | 135,885 | |
Other expenses, net | | 79 | | | — | | | 40,889 | | | 40,968 | |
Net income (loss) from continuing operations | | (40,180) | | | 10,543 | | | (55,182) | | | (84,819) | |
| | | | | | | | |
| | | | | | | | |
As of December 31, 2020 | | | | | | | | |
Total assets | | $ | 656,505 | | | $ | 262,514 | | | $ | 2,858 | | | $ | 921,877 | |
| | | | | | | | |
| | | | | | | | |
For the Year Ended December 31, 2019 | | | | | | | | |
Revenues | | $ | 210,348 | | | $ | 47,089 | | | $ | — | | | $ | 257,437 | |
| | | | | | | | |
Gain on asset sales and disposals | | 6,498 | | | — | | | — | | | 6,498 | |
Operating and maintenance expenses | | 32,489 | | | 249 | | | — | | | 32,738 | |
Depreciation, depletion and amortization | | 14,932 | | | — | | | — | | | 14,932 | |
General and administrative expenses | | — | | | — | | | 16,730 | | | 16,730 | |
Asset impairments | | 148,214 | | | — | | | — | | | 148,214 | |
Other expenses, net | | — | | | — | | | 76,735 | | | 76,735 | |
Net income (loss) from continuing operations | | 21,211 | | | 46,840 | | | (93,465) | | | (25,414) | |
Income from discontinued operations | | — | | | — | | | — | | | 956 | |
| | | | | | | | |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
8. Equity Investment
The Partnership accounts for its 49% investment in Sisecam Wyoming using the equity method of accounting. Activity related to this investment is as follows:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
(In thousands) | 2021 | | 2020 | | 2019 |
Balance at beginning of period | $ | 262,514 | | | $ | 263,080 | | | $ | 247,051 | |
Income allocation to NRP’s equity interests (1) | 26,979 | | | 15,205 | | | 52,016 | |
Amortization of basis difference | (5,108) | | | (4,477) | | | (4,927) | |
Other comprehensive income | 2,889 | | | 2,916 | | | 790 | |
Distribution | (11,270) | | | (14,210) | | | (31,850) | |
Balance at end of period | $ | 276,004 | | | $ | 262,514 | | | $ | 263,080 | |
(1)Includes reclassifications of accumulated other comprehensive income (loss) to income allocation to NRP equity interest of $0.0 million, $1.7 million and $0.6 million for the year ended December 31, 2021, 2020 and 2019, respectively.
The difference between the amount at which the investment in Sisecam Wyoming is carried and the amount of underlying equity in Sisecam Wyoming's net assets was $126.3 million and $131.4 million as of December 31, 2021 and 2020, 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 27 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 Sisecam Wyoming as derived from their respective financial statements for the years ended December 31, 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
(In thousands) | 2021 | | 2020 | | 2019 |
Net sales | $ | 540,139 | | | $ | 392,231 | | | $ | 522,843 | |
Gross profit | 80,550 | | | 54,838 | | | 131,712 | |
Net income | 55,059 | | | 31,030 | | | 106,155 | |
The financial position of Sisecam Wyoming is summarized as follows:
| | | | | | | | | | | |
| December 31, |
(In thousands) | 2021 | | 2020 |
Current assets | $ | 206,315 | | | $ | 164,720 | |
Noncurrent assets | 297,210 | | | 294,008 | |
Current liabilities | 73,181 | | | 55,313 | |
Noncurrent liabilities | 124,749 | | | 135,776 | |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9. Mineral Rights, Net
The Partnership’s mineral rights consist of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
(In thousands) | Carrying Value | | Accumulated Depletion | | Net Book Value | | Carrying Value | | Accumulated Depletion | | Net Book Value |
Coal properties | $ | 670,650 | | | $ | (253,503) | | | $ | 417,147 | | | $ | 785,623 | | | $ | (346,773) | | | $ | 438,850 | |
Aggregates properties | 8,747 | | | (2,975) | | | 5,772 | | | 9,039 | | | (2,819) | | | 6,220 | |
Oil and gas royalty properties | 12,354 | | | (9,115) | | | 3,239 | | | 12,354 | | | (8,593) | | | 3,761 | |
Other | 13,151 | | | (1,612) | | | 11,539 | | | 13,154 | | | (1,612) | | | 11,542 | |
Total mineral rights, net | $ | 704,902 | | | $ | (267,205) | | | $ | 437,697 | | | $ | 820,170 | | | $ | (359,797) | | | $ | 460,373 | |
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 $17.6 million, $8.8 million and $12.1 million for the year ended December 31, 2021, 2020 and 2019, respectively.
Sales of Mineral Rights
During the year ended December 31, 2021 and 2020, the Partnership recorded a cumulative gain of $0.2 million and $0.6 million, respectively, included in gain on asset sales and disposals on the Consolidated Statements of Comprehensive Income (Loss) related to sales of certain mineral rights. During the year ended December 31, 2019, the Partnership recorded a cumulative 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.
Impairment of Mineral Rights
During the years ended December 31, 2021, 2020 and 2019, 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:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
(In thousands) | 2021 | | 2020 | | 2019 |
Coal properties (1) | $ | 5,015 | | | $ | 114,302 | | | $ | 125,806 | |
| | | | | |
Aggregates properties (2) | 87 | | | 21,583 | | | 103 | |
Total | $ | 5,102 | | | $ | 135,885 | | | $ | 125,909 | |
(1)The Partnership recorded $5.0 million of impairment expense during the year ended December 31, 2021 primarily related to a lease termination. The Partnership recorded $114.3 million of impairment expense to impair certain assets during the year ended December 31, 2020 primarily related to weakened coal markets that resulted in termination of certain coal leases and changes to lessee mine plans resulting in permanent moves off certain of our coal properties. 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%. 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
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
coal 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.
(2)The Partnership recorded $0.1 million of aggregates royalty property impairments during the year ended December 31, 2021. The Partnership recorded $21.6 million of aggregates royalty property impairments during the year ended December 31, 2020 primarily related to decreased oil and gas drilling activity which negatively impacted the outlook for NRP's frac sand properties. The Partnership recorded $0.1 million of aggregates royalty property impairments during the year ended December 31, 2019. 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 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.
While the Partnership's impairment evaluation as of December 31, 2021 incorporated an estimated impact of the global COVID-19 pandemic, there is significant uncertainty as to the severity and duration of this disruption. If the impact is worse than we currently estimate, an additional impairment charge may be recognized in future periods.
10. Intangible Assets, Net
The Partnership's intangible assets consist of above-market coal royalty and related transportation contracts with subsidiaries of Foresight Energy Resources LLC ("Foresight") 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:
| | | | | | | | | | | |
| December 31, |
(In thousands) | 2021 | | 2020 |
Intangible assets at cost | $ | 51,353 | | | $ | 53,878 | |
Less: accumulated amortization | (35,223) | | | (36,419) | |
Total intangible assets, net | $ | 16,130 | | | $ | 17,459 | |
Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of Comprehensive Income (Loss) was $1.3 million, $0.2 million and $2.5 million for the year ended December 31, 2021, 2020 and 2019, respectively.
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) | | Estimated Amortization Expense |
2022 | | $ | 1,127 | |
2023 | | 1,041 | |
2024 | | 1,238 | |
2025 | | 1,202 | |
2026 | | 1,202 | |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
11. Debt, Net
The Partnership's debt consists of the following:
| | | | | | | | | | | |
| December 31, |
(In thousands) | 2021 | | 2020 |
NRP LP debt: | | | |
9.125% senior notes, with semi-annual interest payments in June and December, due June 2025 issued at par ("2025 Senior Notes") | $ | 300,000 | | | $ | 300,000 | |
| | | |
Opco debt: | | | |
Revolving credit facility | $ | — | | | $ | — | |
Senior Notes | | | |
| | | |
| | | |
| | | |
5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 | $ | 4,730 | | | $ | 7,094 | |
4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 | 12,008 | | | 18,013 | |
5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 38,053 | | | 50,738 | |
8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 12,035 | | | 16,047 | |
5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 57,104 | | | 68,524 | |
5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 14,554 | | | 17,464 | |
Total Opco Senior Notes | $ | 138,484 | | | $ | 177,880 | |
Total debt at face value | $ | 438,484 | | | $ | 477,880 | |
| | | |
Net unamortized debt issuance costs | (4,939) | | | (6,381) | |
Total debt, net | $ | 433,545 | | | $ | 471,499 | |
Less: current portion of long-term debt | (39,102) | | | (39,055) | |
Total long-term debt, net | $ | 394,443 | | | $ | 432,444 | |
NRP LP Debt
2025 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. 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. 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, 2021 and 2020, NRP and NRP Finance were in compliance with the terms of the Indenture relating to their 2025 Senior Notes.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
2022 Senior Notes
In 2019, the Partnership redeemed its 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).
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 BRP LLC and NRP Trona LLC. As of December 31, 2021 and 2020, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.
Opco Credit Facility
In 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%.
During the years ended December 31, 2021 and 2020, the Partnership did not have any borrowings outstanding under the Opco Credit Facility and had $100.0 million in available borrowing capacity at both December 31, 2021 and 2020. 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.
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 $345.0 million and $364.5 million classified as mineral rights, net and other long-term assets, net on the Partnership’s Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than BRP LLC and NRP Trona LLC (which owns a 49% non-controlling equity interest in Sisecam Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than BRP LLC and NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, and (4) certain of Opco’s coal-related infrastructure assets.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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, 2021 and 2020, the Opco Senior Notes had cumulative principal balances of $138.5 million and $177.9 million, respectively. Opco made mandatory principal payments on the Opco Senior Notes of $39.4 million, $46.2 million and $117.4 million during the year ended December 31, 2021, 2020 and 2019, 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, 2021.
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 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:
| | | | | | | | | | | | | | | | | | | | | | | |
| NRP LP | | Opco | |
(In thousands) | Senior Notes | | Senior Notes | | Credit Facility | | Total |
2022 | $ | — | | | $ | 39,396 | | | $ | — | | | $ | 39,396 | |
2023 | — | | | 39,396 | | | — | | | 39,396 | |
2024 | — | | | 31,028 | | | — | | | 31,028 | |
2025 | 300,000 | | | 14,332 | | | — | | | 314,332 | |
2026 | — | | | 14,332 | | | — | | | 14,332 | |
Thereafter | — | | | — | | | — | | | — | |
| $ | 300,000 | | | $ | 138,484 | | | $ | — | | | $ | 438,484 | |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
12. Fair Value Measurements
Fair Value of Financial Assets and Liabilities
The Partnership’s financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. The Partnership uses available market data and valuation methodologies to estimate the fair value of its debt and contract receivable.
The following table shows the carrying value and estimated fair value of the Partnership's debt and contract receivable:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, |
| | | 2021 | | 2020 |
(In thousands) | Fair Value Hierarchy Level | | Carrying Value | | Estimated Fair Value | | Carrying Value | | Estimated Fair Value |
Debt: | | | | | | | | | |
NRP 2025 Senior Notes | 1 | | $ | 296,236 | | | $ | 300,000 | | | $ | 295,160 | | | $ | 274,500 | |
| | | | | | | | | |
Opco Senior Notes (1) | 3 | | 137,309 | | | 138,484 | | | 176,339 | | | 162,760 | |
Opco Credit Facility | 3 | | — | | | — | | | — | | | — | |
| | | | | | | | | |
Assets: | | | | | | | | | |
Contract receivable, net (current and long-term) (2) | 3 | | $ | 33,612 | | | $ | 26,010 | | | $ | 35,313 | | | $ | 27,025 | |
(1)The fair value of the Opco Senior Notes are estimated by management using quotations obtained for the NRP 2025 Senior Notes on the closing trading prices near period end, which were at 100% and 92% of par value at December 31, 2021 and 2020, respectively.
(2)The fair value of the Partnership's contract receivable is determined based on the present value of future cash flow projections related to the underlying asset at a discount rate of 15% at December 31, 2021 and 2020.
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, 2021 and 2020.
Fair Value of Non-Financial Assets
The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregates properties at fair value on a nonrecurring basis. Refer to Note 9. Mineral Rights, Net for additional disclosures related to the fair value associated with the impaired assets.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
13. 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, including Quintana Infrastructure Development ("QID"), 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, WPPLP and QID are included on the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
(In thousands) | 2021 | | 2020 | | 2019 |
Operating and maintenance expenses | $ | 6,543 | | | $ | 6,559 | | | $ | 6,656 | |
General and administrative expenses | 4,611 | | | 4,611 | | | 4,946 | |
The Partnership had accounts payable to QMC of $0.4 million on its Consolidated Balance Sheets as of December 31, 2021 and 2020 and $0.9 million and $0.3 million of accounts payable to WPPLP as of December 31, 2021 and 2020, respectively.
During the years ended December 31, 2021, 2020 and 2019, the Partnership recognized $3.3 million, $0.4 million and $4.0 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, 2021 and 2020, the Partnership had $0.0 million and $0.3 million, respectively, of other long-term assets, net on its Consolidated Balance Sheets related to a prepaid royalty for this agreement.
Corbin J. Robertson, Jr. owns 85% of the general partner of Great Northern Properties Limited Partnership ("GNP"), a privately held company primarily engaged in owning and managing mineral properties and surface leases. As of December 31, 2021 the Partnership had $0.1 million of accounts receivable from GNP included in accounts receivable, net on its Consolidated Balance Sheets related to amounts collected for surface leases that belong to NRP.
Industrial Minerals Group LLC
Prior to December 31, 2019, Corbin J. Robertson, III, a Director of GP Natural Resource Partners LLC, held a minority ownership interest in Industrial Minerals Group LLC (“Industrial Minerals”), which, through its subsidiaries, leases one of NRP’s coal royalty properties in Central Appalachia. Coal royalty related revenues from Industrial Minerals totaled $1.7 million for the year ended December 31, 2019.
Quinwood Coal Company Royalty
Quinwood Coal Partners LP (“Quinwood”), an entity controlled by Corbin J. Robertson, III, leases two coal properties from NRP in Central Appalachia. Coal related revenues from Quinwood totaled $0.0 million, $0.0 million and $0.2 million for the year ended December 31, 2021, 2020 and 2019, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
14. Major Customers
Revenues from customers that exceeded 10 percent of total revenues for any of the periods presented below are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
(In thousands) | | Revenues | | Percent | | Revenues | | Percent | | Revenues | | Percent |
Foresight (1) (2) | | $ | 37,366 | | | 17 | % | | $ | 35,704 | | | 26 | % | | $ | 58,923 | | | 23 | % |
Alpha Metallurgical Resources, Inc. (1) | | 49,440 | | | 23 | % | | 33,227 | | | 24 | % | | 40,743 | | | 16 | % |
(1)Revenues from Foresight and Alpha Metallurgical Resources, Inc. are included within the Partnership's Mineral Rights segment.
(2)In June 2020, the Partnership entered into lease amendments with Foresight pursuant to which Foresight agreed to pay NRP fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreements between the Partnership and Foresight for calendar years 2020 and 2021.
15. 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.
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, 2021. 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.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
16. 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 either vest 3 years following the grant date or vest ratably over the 3 year period following the grant date. Awards granted to non-employee directors vest over a 1 year period. 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 settlement date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.
The awards granted in 2021, 2020 and 2019 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 year ended December 31, 2021, 2020 and 2019 were $3.8 million, $3.5 million and $5.4 million, respectively. Total unit-based compensation expense associated with these awards was $4.0 million,$3.6 million and $2.4 million for the year ended December 31, 2021, 2020 and 2019, 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, 2021 is $3.3 million, which is to be recognized over a weighted average period of 1.7 years. The unamortized cost associated with unvested outstanding awards as of December 31, 2020 was $3.7 million.
A summary of the unit activity in the outstanding grants during 2021 is as follows:
| | | | | | | | | | | |
(In thousands) | Common Units | | Weighted Average Grant Date Fair value per Common Unit |
Outstanding grants at January 1, 2021 | 355 | | | $ | 26.20 | |
Granted | 219 | | | $ | 17.31 | |
Fully vested and issued | (129) | | | $ | 21.38 | |
Forfeitures | (34) | | | $ | 26.00 | |
Outstanding at December 31, 2021 | 411 | | | $ | 23.00 | |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
17. Financing Transaction
The Partnership owns rail loadout and associated infrastructure at the Sugar Camp mine in the Illinois Basin operated by a subsidiary of Foresight. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight 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 $5.0 million due to the Partnership in 2020 and 2021 is included in the fixed cash payments from Foresight resulting from contract modifications entered into during the second quarter of 2020 as discussed in Note 14. Major Customers. 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.
18. Credit Losses
The Partnership is exposed to credit losses through collection of its trade receivables resulting from contracts with customers and a long-term receivable resulting from a financing transaction with a customer. The Partnership records an allowance for current expected credit losses on these receivables based on the loss-rate method. NRP assessed the likelihood of collection of its receivables utilizing historical loss rates, current market conditions that included the estimated impact of the global COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers and properties. Examples of these facts or circumstances include, but are not limited to, contract disputes or renegotiations with the customer and evaluation of short and long-term economic viability of the contracted property. For its long-term contract receivable, management reverts to the historical loss experience immediately after the reasonable and supportable forecast period ends.
As of December 31, 2021 and 2020, NRP recorded the following current expected credit loss (“CECL”) related to its receivables and long-term contract receivable:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2021 | | 2020 |
(In thousands) | | Gross | | CECL Allowance | | Net | | Gross | | CECL Allowance | | Net |
Receivables | | $ | 28,869 | | | $ | (3,312) | | | $ | 25,557 | | | $ | 18,512 | | | $ | (2,358) | | | $ | 16,154 | |
Long-term contract receivable | | 32,497 | | | (1,126) | | | 31,371 | | | 34,818 | | | (1,554) | | | 33,264 | |
Total | | $ | 61,366 | | | $ | (4,438) | | | $ | 56,928 | | | $ | 53,330 | | | $ | (3,912) | | | $ | 49,418 | |
NRP recorded $0.5 million and $0.0 million in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) related to the change in the CECL allowance during the year ended December 31, 2021 and 2020, respectively.
NRP has procedures in place to monitor its ongoing credit exposure through timely review of counterparty balances against contract terms and due dates, account and financing receivable reconciliations, bankruptcy monitoring, lessee audits and dispute resolution. The Partnership may employ legal counsel or collection specialists to pursue recovery of defaulted receivables.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
19. Leases
As of December 31, 2021, 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, 2021 and 2020, 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 Sheets 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 long-term assets, net and other non-current liabilities, respectively, on its Consolidated Balance Sheets totaled $3.5 million at both December 31, 2021 and 2020. During the years ended December 31, 2021, 2020 and 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 Statements of Comprehensive Income (Loss).
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) | | December 31, 2021 |
2022 | | $ | 483 | |
2023 | | 483 | |
2024 | | 483 | |
2025 | | 483 | |
2026 | | 483 | |
After 2026 | | 10,631 | |
Total lease payments (1) | | $ | 13,046 | |
Less: present value adjustment (2) | | (9,562) | |
Total operating lease liability | | $ | 3,484 | |
(1)The remaining lease term of the Partnership's operating lease is 27 years.
(2)The present value of the operating lease liability on the Partnership's Consolidated Balance Sheets 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.