Item 7. Management’s Discussion and Analysis
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.
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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.
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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:
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
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.
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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 U nits 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 cred its 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 CO 2 sequestration hub on Alabama's Gulf Coast. The agreement provides Denbury with the exclusive rights to develop a subsurface CO 2 sequestration site on approximately 75,000 acres of underground pore space controlled by us in Baldwin County, near Mobile, Alabama, with estimated CO 2 storage potential of over 300 million metric tons.
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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 CO 2 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:
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:
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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:
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 %
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 %
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 %
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 %
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 CO 2 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 %
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 %
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 %
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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 CO 2 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:
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) %
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.
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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:
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)
Add: total distributions from unconsolidated investment — 11,270 — 11,270
Add: interest expense, net 24 — 38,852 38,876
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
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)
Add: total distributions from unconsolidated investment — 14,210 — 14,210
Add: interest expense, net 79 — 40,889 40,968
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.
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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:
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)
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:
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
Add: proceeds from asset sales and disposals 249 — — 249
Add: return of long-term contract receivable 2,163 — — 2,163
Distributable cash flow $ 162,257 $ 11,106 $ (49,147) $ 124,216
Less: proceeds from asset sales and disposals (249) — — (249)
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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Operating Segments
For the Year Ended (In thousands) Mineral Rights Soda Ash Corporate and Financing Total
December 31, 2020
Net cash provided by (used in) operating activities of continuing operations $ 124,737 $ 14,037 $ (51,206) $ 87,568
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
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)
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.
For discussion of our Results of Operations comparing 2020 to 2019, refer to our 2020 Annual Report on Form 10-K filed March 15, 2021 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
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.
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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.
For discussion of our Cash Flows comparing 2020 to 2019, refer to our 2020 Annual Report on Form 10-K filed March 15, 2021 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Capital Resources and Obligations
Debt, Net
We had the following debt outstanding as of December 31, 2021 and 2020:
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.
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Debt Obligations
The following table reflects our long-term, non-cancelable debt obligations as of December 31, 2021:
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 —
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
For additional information on environmental regulation that may have a material impact on our business, see " Items 1. and 2. Business and Properties—Regulation and Environmental Matters ."
Related Party Transactions
The information required by this Item is included under " Item 8. Financial Statements and Supplementary Data—Note 13. Related Party Transactions " and " Item 13. Certain Relationships and Related Transactions, and Director Independence " in this Annual Report on Form 10-K and is incorporated by reference herein.
Summary of Critical Accounting Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See " Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies " in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significant accounting policies. The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates.
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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 CO 2 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.
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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.
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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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As a smaller reporting company for the year ended December 31, 2021, we are not required to include this disclosure in our 2021 Form 10-K.
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