ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consists of the following subjects:
•
Executive Overview
•
Results of Operations
•
Liquidity and Capital Resources
•
Off-Balance Sheet Transactions
•
Inflation
•
Environmental Regulation
•
Related Party Transactions
•
Summary of Critical Accounting Estimates
•
Recent Accounting Standards
As used in this Item 7, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes due 2018 (the "2018 Notes") and the 10.50% senior notes due 2022 (the "2022 Notes").
Executive Overview
We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates and other natural resources. Our common units trade on the New York Stock Exchange under the symbol "NRP".
Our business is organized into three operating segments:
Coal Royalty and Other
—consists primarily of coal royalty and coal related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of states across the United States. Our oil and gas royalty assets are located in Louisiana.
Soda Ash
—consists of our 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business.
VantaCore
—consists of our construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore
operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
For the year ended December 31, 2016, our financial results included (in thousands):
|
|
|
|
|
Revenues and other income
|
$
|
400,059
|
|
Net income from continuing operations
|
$
|
95,214
|
|
Adjusted EBITDA (1)
|
$
|
255,471
|
|
|
|
Operating cash flow provided by continuing operations
|
$
|
100,643
|
|
Investing cash flow provided by continuing operations
|
$
|
59,943
|
|
Financing cash flow (used in) continuing operations
|
$
|
(161,419
|
)
|
Distributable Cash Flow ("DCF") (1)
|
$
|
271,415
|
|
|
|
(1)
|
See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.
|
2017 Recapitalization Transactions
We have been pursuing or considering a number of actions in order to mitigate the effects of adverse market developments and scheduled debt principal payments since April 2015 when we announced our long-term strategic plan to strengthen our balance sheet and enhance our liquidity. On March 2, 2017, we completed the following transactions that achieved these objectives and will ultimately reposition the partnership for long-term growth:
|
|
•
|
the issuance of $250 million of a new class of 12.0% preferred units representing limited partner interests in NRP, together with warrants to purchase common units, to certain entities controlled by funds affiliated with The Blackstone Group, L.P. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree");
|
|
|
•
|
the exchange of $241 million of our 9.125% Senior Notes due 2018 (the "2018 Notes") for $241 million of a new series of 10.500% Senior Notes due 2022 (the "2022 Notes"), and the sale of $105 million of additional 2022 Notes in exchange for cash proceeds; and
|
|
|
•
|
the extension of Opco’s revolving credit facility (the "Opco Credit Facility") to April 2020, with commitments thereunder reduced to $180 million.
|
We used a portion of the proceeds from these transactions to repay Opco’s revolving credit facility in full and pay all fees and expenses associated with the transactions described above. We will also use a portion of the proceeds to redeem the remaining 2018 Notes. On March 3, 2017, we delivered a notice of partial redemption for $90.0 million of our outstanding 2018 Notes at a
redemption price of 104.563%, plus accrued and unpaid interest to the redemption date. This partial redemption of the 2018 Notes is expected to occur on April 3, 2017. We will redeem all of the remaining 2018 Notes within 60 days after October 1, 2017 at the then-applicable price and pay all accrued and unpaid interest thereon.
For more information on these transactions, including the terms of the preferred units, warrants and 2022 Notes, see "—Liquidity and Capital Resources—2017 Recapitalization Transactions."
2016 Asset Sales
Prior to completion of these recapitalization transactions, we had been pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments and scheduled debt principal payments. As part of this plan, we sold assets during the year ended December 31, 2016, for total gross proceeds of $181.0 million that consisted of the following:
|
|
•
|
Oil and gas working interest in the Williston Basin for $116.1 million gross sales proceeds that marked our exit from the non-operated oil and gas working interest business.
|
|
|
•
|
Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for
$36.4 million
gross sales proceeds.
|
|
|
•
|
Aggregates reserves and related royalty rights at
three
aggregates operations located in Texas, Georgia and Tennessee for
$10.0 million
gross sales proceeds.
|
|
|
•
|
Mineral reserves in multiple sale transactions for cumulative
$17.3 million
of gross sales proceeds. These amounts primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas royalty interests. Additional asset sales during the year included sales of land and plant and equipment for $1.2 million of gross proceeds.
|
Current Liquidity
As of December 31,
2016
, we had a total of
$40.4 million
of cash and cash equivalents. During the year ended December 31,
2016
, we reduced our debt by approximately
$248.1 million
by repaying
$85.0 million
of the NRP Oil and Gas reserve based lending facility in full (the "RBL Facility"),
$82.9 million
of the Opco Private Placement Notes (as defined below),
$80.0 million
of the Opco Credit Facility and
$0.2 million
of Opco's utility local improvement obligation.
In March 2017, we increased our liquidity through the completion of the recapitalization transactions described above, including by repaying borrowings outstanding under the Opco Credit Facility in full. In addition to enhancing our liquidity, these recapitalization transactions reduced our 2018 debt maturities by $575 million through the extension of debt principal payments from 2018 to 2020 and 2022. Even with these meaningful improvements to our liquidity and balance sheet, we continue to have substantial debt outstanding and intend to continue to use cash from operations to deleverage our balance sheet over time. While we have a diversified portfolio of assets, we face challenges in coal and other commodity markets. Our going concern analysis included an analysis of these relevant conditions and events and our ability to meet our obligations and remain in compliance with our debt covenants within one year after the issuance date of these financial statements. We expect that we will meet all of our obligations, including scheduled principal and interest payments on our debt and required distributions on the preferred units, comply with all covenants contained in our debt agreements and that we will continue as a going concern.
Current Results/Market Outlook
Coal Royalty and Other Business Segment
For the year ended December 31,
2016
, our Coal Royalty and Other business segment financial results included the following (in thousands):
|
|
|
|
|
Revenues and other income
|
$
|
239,183
|
|
Net income from continuing operations
|
$
|
161,816
|
|
Adjusted EBITDA (1)
|
$
|
209,443
|
|
|
|
Operating cash flow provided by continuing operations
|
$
|
134,490
|
|
Investing cash flow provided by continuing operations
|
$
|
65,057
|
|
Financing cash flow provided by continuing operations
|
$
|
16
|
|
DCF (1)
|
$
|
199,547
|
|
|
|
(1)
|
See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.
|
In the fourth quarter of 2016, we began to realize the benefits of the dramatic increase in metallurgical coal prices as well as the improvement in the thermal coal markets. A number of our lessees were able to take advantage of the improved markets and lock in tonnage commitments for 2017 at substantially higher prices than they realized in 2016. While spot metallurgical prices have recently retreated from the highs reached in the fourth quarter, we believe that that global supply/demand dynamic will support long-term metallurgical coal prices well above the lows hit in the first half of 2016. We derived approximately
37%
of our coal royalty revenues and approximately
35%
of the related production from metallurgical coal during the year ended December 31,
2016
. The domestic thermal coal markets have also shown modest improvements, as production cuts over the last year have rationalized coal stockpiles. Although a mild winter has tempered demand for thermal coal, natural gas prices remain higher than 2016, causing thermal coal to be more competitive for electricity generation as compared to recent years. In addition, we expect the actions of the Trump Administration to ease the regulatory burdens on the coal industry, reducing the production costs and increasing the competitiveness of our lessees against natural gas. Despite these improvements, producers of Central Appalachian thermal coal continue to face challenges, as many still have large debt burdens and their production costs remain high relative to sales prices. We have successfully navigated the bankruptcies of several of our lessees and have had substantially all of our leases assumed or assigned and received substantially all past-due amounts in these bankruptcies.
Production from our Illinois Basin properties decreased by
27%
during the year ended December 31,
2016
as compared to the year ended December 31, 2015. Substantially all of the decrease is attributable to the idling of Foresight Energy's Deer Run mine (which we also refer to as our Hillsboro property) during 2016. In July 2015, we received a notice from Foresight Energy declaring a force majeure event at the Deer Run mine after elevated levels of carbon monoxide were detected. We believe Foresight's claim of force majeure has no merit and we are vigorously pursuing our claims against them through a lawsuit filed in November 2015. However, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us quarterly minimum deficiency payments with respect to the Deer Run mine until mining resumes. Under the lease for the Deer Run mine, Foresight Energy is required to make minimum deficiency payments to us of $7.5 million per quarter, or $30.0 million per year. Foresight Energy’s failure to make the deficiency payments with respect to the second, third and fourth quarters of 2015 and all four quarters of 2016 resulted in a cumulative negative cash impact to us of $46.0 million. Such amount will increase for each quarter during which mining operations continue to be idled. Foresight Energy is continuing efforts to reenter the mine, but we do not know when, or if, mining activities at the Deer Run mine will recommence.
Soda Ash Business Segment
For the year ended December 31,
2016
, our Soda Ash business segment financial results included the following (in thousands):
|
|
|
|
|
Revenues and other income
|
$
|
40,061
|
|
Net income from continuing operations
|
$
|
40,061
|
|
Adjusted EBITDA (1)
|
$
|
46,550
|
|
|
|
Operating cash flow provided by continuing operations
|
$
|
46,550
|
|
Financing cash flow used by continuing operations
|
$
|
(7,229
|
)
|
DCF (1)
|
$
|
46,550
|
|
|
|
(1)
|
See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.
|
Income from our trona mining and soda ash refinery investment was lower year-over-year for the year ended December 31,
2016
. This decrease is primarily related to lower international prices compared to the prior year, in addition to higher royalty and G&A costs. These decreases were partially offset by an increase in soda ash volumes sold compared to the prior year. Ciner Resources LP, our partner that controls and operates Ciner Wyoming, is a publicly traded master limited partnership that depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders.
VantaCore Business Segment
For the year ended December 31,
2016
, our VantaCore business segment financial results included the following (in thousands):
|
|
|
|
|
Revenues and other income
|
$
|
120,815
|
|
Net income from continuing operations
|
$
|
4,438
|
|
Adjusted EBITDA (1)
|
$
|
20,009
|
|
|
|
Operating cash flow provided by continuing operations
|
$
|
20,400
|
|
Investing cash flow used by continuing operations
|
$
|
(5,114
|
)
|
Financing cash flow used by continuing operations
|
$
|
(1,825
|
)
|
DCF (1)
|
$
|
16,243
|
|
|
|
(1)
|
See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.
|
VantaCore’s construction aggregates mining and production business is largely dependent on the strength of the local markets that it serves. VantaCore’s Laurel Aggregates operation in southwestern Pennsylvania serves producers and oilfield service companies operating in the Marcellus and Utica Shales and was impacted during the year ended December 31,
2016
by the slowing pace of exploration and development of natural gas in those areas due to low natural gas prices. Increased local construction activity partially offset these declines during the year ended December 31,
2016
, but we expect that Laurel’s business will continue to be impacted by decreased natural gas development activities. While VantaCore's production and revenues have declined in 2016 compared to 2015, its cost management efforts have enabled the business to maintain its profitability.
Discontinued Operations
In July 2016, NRP Oil and Gas closed on the sale of its non-operated oil and gas working interest assets in the Williston Basin for
$116.1 million
in gross sales proceeds. Our exit from our non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on our soda ash, coal royalty and construction aggregates business segments. As a result, we have classified the assets and liabilities, operating results and cash flows of our non-operated oil and gas working interest assets as discontinued operations in our consolidated financial statements for all periods presented.
Results of Operations
Year Ended December 31,
2016
Compared to Year Ended December 31,
2015
Revenues and Other Income
Revenues and other income
decreased
$39.5 million
, or
9%
, from
$439.6 million
in the year ended
December 31, 2015
to
$400.1 million
in the year ended
December 31, 2016
. The following table shows our diversified sources of natural resource revenues and other income by business segment for the year ended
December 31, 2016
and 2015 (in thousands except for percentages):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Total
|
2016
|
|
|
|
|
|
|
|
|
Revenues and other income
|
|
$
|
239,183
|
|
|
$
|
40,061
|
|
|
$
|
120,815
|
|
|
$
|
400,059
|
|
Percentage of total
|
|
60
|
%
|
|
10
|
%
|
|
30
|
%
|
|
|
2015
|
|
|
|
|
|
|
|
|
Revenues and other income
|
|
$
|
250,717
|
|
|
$
|
49,918
|
|
|
$
|
139,013
|
|
|
$
|
439,648
|
|
Percentage of total
|
|
57
|
%
|
|
11
|
%
|
|
32
|
%
|
|
|
The changes in revenue and other income is discussed for each of the our business segments below:
Coal Royalty and Other
Revenues and other income related to our Coal Royalty and Other segment
decreased
$11.5 million
, or
5%
, from
$250.7 million
in the year ended
December 31, 2015
to
$239.2 million
in the year ended
December 31, 2016
.
The table below presents coal production and coal royalty revenues (including affiliates) derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
Increase
(Decrease)
|
|
Percentage
Change
|
|
2016
|
|
2015
|
|
|
(In thousands, except percent and per ton data)
(Unaudited)
|
Coal production (tons)
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
Northern
|
2,312
|
|
|
9,562
|
|
|
(7,250
|
)
|
|
(76
|
)%
|
Central
|
13,222
|
|
|
16,862
|
|
|
(3,640
|
)
|
|
(22
|
)%
|
Southern
|
2,776
|
|
|
3,803
|
|
|
(1,027
|
)
|
|
(27
|
)%
|
Total Appalachia
|
18,310
|
|
|
30,227
|
|
|
(11,917
|
)
|
|
(39
|
)%
|
Illinois Basin
|
8,116
|
|
|
11,173
|
|
|
(3,057
|
)
|
|
(27
|
)%
|
Northern Powder River Basin
|
3,781
|
|
|
4,905
|
|
|
(1,124
|
)
|
|
(23
|
)%
|
Gulf Coast
|
0.4
|
|
|
740
|
|
|
(740
|
)
|
|
(100
|
)%
|
Total coal production
|
30,207
|
|
|
47,045
|
|
|
(16,838
|
)
|
|
(36
|
)%
|
|
|
|
|
|
|
|
|
Coal royalty revenue per ton
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
Northern
|
$
|
1.15
|
|
|
$
|
0.28
|
|
|
$
|
0.87
|
|
|
311
|
%
|
Central
|
3.64
|
|
|
3.85
|
|
|
(0.21
|
)
|
|
(5
|
)%
|
Southern
|
3.84
|
|
|
4.57
|
|
|
(0.73
|
)
|
|
(16
|
)%
|
Illinois Basin
|
3.66
|
|
|
3.94
|
|
|
(0.28
|
)
|
|
(7
|
)%
|
Northern Powder River Basin
|
2.81
|
|
|
2.54
|
|
|
0.27
|
|
|
11
|
%
|
Gulf Coast
|
3.28
|
|
|
3.47
|
|
|
(0.19
|
)
|
|
(5
|
)%
|
|
|
|
|
|
|
|
|
Coal royalty revenues
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
Northern
|
$
|
2,667
|
|
|
$
|
2,672
|
|
|
$
|
(5
|
)
|
|
—
|
%
|
Central
|
48,119
|
|
|
64,877
|
|
|
(16,758
|
)
|
|
(26
|
)%
|
Southern
|
10,660
|
|
|
17,390
|
|
|
(6,730
|
)
|
|
(39
|
)%
|
Total Appalachia
|
61,446
|
|
|
84,939
|
|
|
(23,493
|
)
|
|
(28
|
)%
|
Illinois Basin
|
29,680
|
|
|
44,063
|
|
|
(14,383
|
)
|
|
(33
|
)%
|
Northern Powder River Basin
|
10,637
|
|
|
12,443
|
|
|
(1,806
|
)
|
|
(15
|
)%
|
Gulf Coast
|
1
|
|
|
2,570
|
|
|
(2,569
|
)
|
|
(100
|
)%
|
Total coal royalty revenue
|
$
|
101,764
|
|
|
$
|
144,015
|
|
|
$
|
(42,251
|
)
|
|
(29
|
)%
|
|
|
|
|
|
|
|
|
Other revenues
|
|
|
|
|
|
|
|
Minimums recognized as revenue
|
$
|
64,591
|
|
|
$
|
15,489
|
|
|
$
|
49,102
|
|
|
317
|
%
|
Transportation and processing fees
|
19,336
|
|
|
22,033
|
|
|
(2,697
|
)
|
|
(12
|
)%
|
Property tax revenue
|
10,457
|
|
|
11,258
|
|
|
(801
|
)
|
|
(7
|
)%
|
Wheelage
|
2,374
|
|
|
3,166
|
|
|
(792
|
)
|
|
(25
|
)%
|
Coal override revenue
|
2,281
|
|
|
2,920
|
|
|
(639
|
)
|
|
(22
|
)%
|
Lease assignment fee
|
—
|
|
|
21,000
|
|
|
(21,000
|
)
|
|
(100
|
)%
|
Gain on reserve swap
|
—
|
|
|
9,290
|
|
|
(9,290
|
)
|
|
(100
|
)%
|
Hard mineral royalty revenues
|
3,163
|
|
|
8,090
|
|
|
(4,927
|
)
|
|
(61
|
)%
|
Oil and gas royalty revenues
|
3,537
|
|
|
4,364
|
|
|
(827
|
)
|
|
(19
|
)%
|
Other
|
2,612
|
|
|
2,156
|
|
|
456
|
|
|
21
|
%
|
Total other revenues
|
$
|
108,351
|
|
|
$
|
99,766
|
|
|
$
|
8,585
|
|
|
9
|
%
|
Coal royalty and other income
|
210,115
|
|
|
243,781
|
|
|
(33,666
|
)
|
|
(14
|
)%
|
Gain on coal royalty and other segment asset sales
|
29,068
|
|
|
6,936
|
|
|
22,132
|
|
|
319
|
%
|
Total coal royalty and other segment revenues and other income
|
$
|
239,183
|
|
|
$
|
250,717
|
|
|
$
|
(11,534
|
)
|
|
(5
|
)%
|
Total coal production
decreased
16.8 million
tons, or
36%
, from
47.0 million
tons in the year ended
December 31, 2015
to
30.2 million
tons in the year ended
December 31, 2016
. Total coal royalty revenues
decreased
$42.3 million
, or
29%
, from
$144.0 million
in the year ended
December 31, 2015
to
$101.8 million
in the year ended
December 31, 2016
. Total coal production and coal royalty revenue decreases were driven by downward pressure in the coal markets as described above, with Central Appalachian thermal coal producers in particular continuing to face challenges, as their production costs remain high relative to sales prices.
Total other revenues increased
$8.6 million
in 2016 compared to 2015 primarily as a result of the agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the recognition of
$40.5 million
of deferred revenue. This increase was partially offset by non-recurring revenue transactions in 2015 that included
$21.0 million
in lease assignment fees and
$9.3 million
gain on reserve swap. Other revenues were also decreased
$4.9 million
in 2016 primarily as a result of the sale of our aggregates royalty assets in the first quarter of 2016.
Gain on coal royalty and other segment asset sales increased
$22.1 million
primarily as a result of the following asset sales during the first quarter of 2016:
1)
Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for
$36.4 million
gross sales proceeds. The effective date of the sale was January 1, 2016, and we recorded an
$18.6 million
gain from this sale.
2)
Aggregate reserves and related royalty rights in the Coal Royalty and Other segment at
three
aggregates operations located in Texas, Georgia and Tennessee for
$10.0 million
gross sales proceeds. The effective date of the sale was February 1, 2016, and we recorded a
$1.5 million
gain from this sale.
Soda Ash
Revenues and other income related to our equity investment in Ciner Wyoming
decreased
$9.8 million
, or
20%
, from
$49.9 million
in
the year ended
December 31, 2015
to
$40.1 million
in
the year ended
December 31, 2016
. This
decrease
is primarily related to lower international prices compared to the prior year, in addition to higher royalty and G&A costs. These decreases were partially offset by an increase in soda ash volumes sold compared to the prior year.
VantaCore
Revenues and other income related to our VantaCore segment
decreased
$18.2 million
, or
13%
, from
$139.0 million
in
the year ended
December 31, 2015
to
$120.8 million
in
the year ended
December 31, 2016
. This
decrease
is primarily due to a decrease in construction aggregates and brokered stone revenue as well as lower delivery and fuel income year-over-year. Tonnage sold by the VantaCore segment
decreased
0.4 million
tons, or
5%
from
7.4 million
tons in
the year ended
December 31, 2015
to
7.0 million
tons in
the year ended
December 31, 2016
as a result of decreased construction aggregates demand in the oil and gas services sector that was partially offset by increased aggregates sales into the construction market.
Operating and Maintenance Expenses (including affiliates)
Operating and maintenance expenses (including affiliates)
decreased
$21.8 million
, or
14%
, from
$152.3 million
in
the year ended
December 31, 2015
to
$130.5 million
in
the year ended
December 31, 2016
. This
decrease
is primarily related to the following:
VantaCore
Operating and maintenance expenses (including affiliates) in our VantaCore segment
decreased
$16.2 million
, or
14%
from
$116.9 million
in
the year ended
December 31, 2015
to
$100.7 million
in
the year ended
December 31, 2016
. This
decrease
is primarily due to the decline in materials cost as a result of the decrease in construction aggregates and brokered stone volume year-over-year due to reduced demand in the oil and gas sector and a decrease in delivery and fuel costs due to the lower construction aggregates production and brokered stone purchases year-over-year partially and effective variable cost management.
Depreciation, Depletion and Amortization ("DD&A") Expense
DD&A expense
decreased
$14.6 million
, or
24%
, from
$60.9 million
in
the year ended
December 31, 2015
to
$46.3 million
in
the year ended
December 31, 2016
. This
decrease
is primarily related to the reduced cost basis of our coal and aggregates royalty mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in coal royalty production year-over-year.
General and Administrative (including affiliates) ("G&A") Expense
Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized treasury and accounting. These costs
increased
$8.3 million
, or
67%
, from
$12.3 million
in
the year ended
December 31, 2015
to
$20.6 million
in
the year ended
December 31, 2016
. This
increase
is primarily related to increased legal and consulting fees associated with the implementation of our long-term plan to strengthen our balance sheet, reduce debt and enhance our liquidity and increased LTIP expense as a result of our unit price increasing in 2016 compared to decreasing unot price in 2015 and the accelerated recognition of our LTIP awards granted in 2016
Asset Impairments
Asset impairments
decreased
$367.6 million
, or
96%
, from
$384.5 million
in
the year ended
December 31, 2015
to
$16.9 million
in
the year ended
December 31, 2016
. We recorded the following asset impairments during the years ended December 31, 2016 and 2015 (in thousands):
|
|
|
|
|
|
|
|
|
|
For the Year Ended
December 31,
|
Impaired Assets
|
2016
|
|
2015
|
Coal Royalty and Other
|
|
|
|
Mineral Rights
|
$
|
13,801
|
|
|
$
|
371,397
|
|
Plant and Equipment
|
2,060
|
|
|
6,930
|
|
Total Coal Royalty and Other Impairment
|
$
|
15,861
|
|
|
$
|
378,327
|
|
|
|
|
|
VantaCore
|
|
|
|
Plant and Equipment
|
$
|
1,065
|
|
|
$
|
692
|
|
Goodwill
|
—
|
|
|
5,526
|
|
Total VantaCore Impairment
|
$
|
1,065
|
|
|
$
|
6,218
|
|
|
|
|
|
Total impairment
|
$
|
16,926
|
|
|
$
|
384,545
|
|
Coal Royalty and Other
Asset impairments
decreased
$362.4 million
, or
96%
, from
$378.3 million
in
the year ended
December 31, 2015
to
$15.9 million
in
the year ended
December 31, 2016
. This
decrease
is primarily related to
$257.5 million
in coal property impairment,
$70.5 million
in oil and gas property impairment and
$43.4 million
in aggregate property impairment recorded during
the year ended
December 31, 2015
as compared to
$12.1 million
in coal property impairment and
$1.7 million
in aggregate property impairment recorded during
the year ended
December 31, 2016
. The impairments in 2015 primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry.
VantaCore
Asset impairments
decreased
$5.1 million
, or
82%
, from
$6.2 million
in
the year ended
December 31, 2015
to
$1.1 million
in
the year ended
December 31, 2016
. This
decrease
is primarily related to the
$5.5 million
write off of goodwill during the year ended December 31, 2015.
Income (Loss) from Discontinued Operations
Income from discontinued operations
increased
$313.2 million
, from a loss of
$311.5 million
in
the year ended
December 31, 2015
to income of
$1.7 million
in
the year ended
December 31, 2016
. The change in income (loss) from discontinued operations is primarily related to the
$297.0 million
asset impairments recorded in 2015, the sale of our non-operated oil and gas working interest assets that was completed in July 2016 with an effective date of April 1, 2016 and the
$8.3 million
gain on sale for
the year ended
December 31, 2016
.
Adjusted EBITDA (Non-GAAP Financial Measure)
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the years ended
December 31, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Segments
|
|
|
|
For the Year Ended
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Corporate and Financing
|
|
Total
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
$
|
161,816
|
|
|
$
|
40,061
|
|
|
$
|
4,438
|
|
|
$
|
(111,101
|
)
|
|
$
|
95,214
|
|
Less: equity earnings from unconsolidated investment
|
|
—
|
|
|
(40,061
|
)
|
|
—
|
|
|
—
|
|
|
(40,061
|
)
|
Add: distributions from unconsolidated investment
|
|
—
|
|
|
46,550
|
|
|
—
|
|
|
—
|
|
|
46,550
|
|
Add: interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
90,570
|
|
|
90,570
|
|
Add: depreciation, depletion and amortization
|
|
31,766
|
|
|
—
|
|
|
14,506
|
|
|
—
|
|
|
46,272
|
|
Add: asset impairment
|
|
15,861
|
|
|
—
|
|
|
1,065
|
|
|
—
|
|
|
16,926
|
|
Adjusted EBITDA
|
|
$
|
209,443
|
|
|
$
|
46,550
|
|
|
$
|
20,009
|
|
|
$
|
(20,531
|
)
|
|
$
|
255,471
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
$
|
(208,248
|
)
|
|
$
|
49,918
|
|
|
$
|
251
|
|
|
$
|
(102,092
|
)
|
|
$
|
(260,171
|
)
|
Less: equity earnings from unconsolidated investment
|
|
—
|
|
|
(49,918
|
)
|
|
—
|
|
|
—
|
|
|
(49,918
|
)
|
Less: gain on reserve swap
|
|
(9,290
|
)
|
|
—
|
|
|
|
|
|
|
(9,290
|
)
|
Add: distributions from unconsolidated investment
|
|
—
|
|
|
46,795
|
|
|
—
|
|
|
—
|
|
|
46,795
|
|
Add: interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
89,762
|
|
|
89,762
|
|
Add: depreciation, depletion and amortization
|
|
45,338
|
|
|
—
|
|
|
15,578
|
|
|
—
|
|
|
60,916
|
|
Add: asset impairment
|
|
378,327
|
|
|
—
|
|
|
6,218
|
|
|
—
|
|
|
384,545
|
|
Adjusted EBITDA
|
|
$
|
206,127
|
|
|
$
|
46,795
|
|
|
$
|
22,047
|
|
|
$
|
(12,330
|
)
|
|
$
|
262,639
|
|
Adjusted EBITDA
decreased
$7.1 million
, or
3%
, from
$262.6 million
in
the year ended
December 31, 2015
to
$255.5 million
in
the year ended
December 31, 2016
. The
decrease
is primarily a result of
$42.3 million
in reduced coal royalty revenue resulting from decreased coal production and coal royalty revenue per ton driven by the continued pressure on U.S. coal producers as described above,
$21.0 million
in non-recurring 2015 lease assignment fees,
$4.9 million
of reduced aggregates royalty revenue in 2016 due to decreased 2016 aggregates production and sales and
$8.3 million
of additional G&A expense in 2016 compared to 2015 as described above. These decreases were partially offset by a
$49.1 million
increase in minimums recognized as revenue primarily as a result of coal lease modifications or terminations that resulted in our lessee forfeiting their minimum royalty balances and
$22.2 million
of additional gains on asset sales as compared to the same period in 2015. "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA" for an explanation of Adjusted EBITDA.
Distributable Cash Flow
(Non-GAAP Financial Measure)
The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the years ended
December 31, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Segments
|
|
|
|
|
For the Year Ended
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Corporate and Financing
|
|
Total
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
134,490
|
|
|
$
|
46,550
|
|
|
$
|
20,400
|
|
|
$
|
(100,797
|
)
|
|
$
|
100,643
|
|
Net cash provided by (used in) investing activities of continuing operations
|
|
65,057
|
|
|
—
|
|
|
(5,114
|
)
|
|
—
|
|
|
59,943
|
|
Net cash provided by (used in) financing activities of continuing operations
|
|
16
|
|
|
(7,229
|
)
|
|
(1,825
|
)
|
|
(152,381
|
)
|
|
(161,419
|
)
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
204,934
|
|
|
$
|
43,029
|
|
|
$
|
23,605
|
|
|
$
|
(103,056
|
)
|
|
$
|
168,512
|
|
Net cash provided by (used in) investing activities of continuing operations
|
|
15,805
|
|
|
—
|
|
|
(8,820
|
)
|
|
—
|
|
|
6,985
|
|
Net cash provided by (used in) financing activities of continuing operations
|
|
(2,744
|
)
|
|
—
|
|
|
—
|
|
|
(180,520
|
)
|
|
(183,264
|
)
|
The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to DCF for the years ended
December 31, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Segments
|
|
|
|
For the Year Ended
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Corporate and Financing
|
|
Total
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
134,490
|
|
|
$
|
46,550
|
|
|
$
|
20,400
|
|
|
$
|
(100,797
|
)
|
|
$
|
100,643
|
|
Add: proceeds from sale of PP&E
|
|
1,084
|
|
|
—
|
|
|
266
|
|
|
—
|
|
|
1,350
|
|
Add: proceeds from sale of mineral rights
|
|
61,033
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61,033
|
|
Add: proceeds from sale of assets included in discontinued operations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
109,872
|
|
Add: return on long-term contract receivables—affiliate
|
|
2,968
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,968
|
|
Less: maintenance capital expenditures
|
|
(28
|
)
|
|
—
|
|
|
(4,423
|
)
|
|
—
|
|
|
(4,451
|
)
|
Distributable Cash Flow
|
|
$
|
199,547
|
|
|
$
|
46,550
|
|
|
$
|
16,243
|
|
|
$
|
(100,797
|
)
|
|
$
|
271,415
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
204,934
|
|
|
$
|
43,029
|
|
|
$
|
23,605
|
|
|
$
|
(103,056
|
)
|
|
$
|
168,512
|
|
Add: proceeds from sale of PP&E
|
|
10,100
|
|
|
—
|
|
|
924
|
|
|
—
|
|
|
11,024
|
|
Add: proceeds from sale of mineral rights
|
|
3,505
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,505
|
|
Add: return on long-term contract receivables—affiliate
|
|
2,463
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,463
|
|
Less: maintenance capital expenditures
|
|
(416
|
)
|
|
—
|
|
|
(5,727
|
)
|
|
—
|
|
|
(6,143
|
)
|
Less: distributions to non-controlling interest
|
|
(2,744
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,744
|
)
|
Distributable Cash Flow
|
|
$
|
217,842
|
|
|
$
|
43,029
|
|
|
$
|
18,802
|
|
|
$
|
(103,056
|
)
|
|
$
|
176,617
|
|
DCF
increased
$94.8 million
, or
54%
, from
$176.6 million
in
the year ended
December 31, 2015
to
$271.4 million
in
the year ended
December 31, 2016
. This
increase
is due primarily to the
$109.9 million
net cash proceeds from the sale of our discontinued operation in addition to
$61.0 million
in net cash proceeds from sales of mineral rights in 2016. These increases were partially offset by lower coal royalty production, lower coal royalty revenue per ton and less minimum payments received from our coal leases. These decreases are driven by the continued pressure on U.S. coal producers as described above. See "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Distributable Cash Flow" for an explanation of Distributable Cash Flow.
Results of Operations
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Revenues and Other Income
Revenues and other income
increased
$88.7 million
, or
25%
, from
$350.9 million
in the year ended December 31, 2014 to
$439.6 million
in the year ended
December 31, 2015
. The following table shows our diversified sources of natural resource revenues and other income by business segment for the years ended December 31, 2015 and 2014 (in thousands except for percentages):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Total
|
2015
|
|
|
|
|
|
|
|
|
Revenues
|
|
250,717
|
|
|
49,918
|
|
|
139,013
|
|
|
439,648
|
|
Percentage of total
|
|
57
|
%
|
|
11
|
%
|
|
32
|
%
|
|
|
2014
|
|
|
|
|
|
|
|
|
Revenues
|
|
267,451
|
|
|
41,416
|
|
|
42,051
|
|
|
350,918
|
|
Percentage of total
|
|
76
|
%
|
|
12
|
%
|
|
12
|
%
|
|
|
The changes in revenue and other income is discussed for each of the our business segments below:
Coal Royalty and Other
Revenues and other income related to our Coal Royalty and Other segment
decreased
$16.8 million
, or
6%
, from
$267.5 million
in 2014 to
$250.7 million
in 2015.
The table below presents coal royalty production and revenues derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended
December 31,
|
|
Increase
(Decrease)
|
|
Percentage
Change
|
|
2015
|
|
2014
|
|
|
(In thousands, except percent and per ton data)
(Unaudited)
|
Coal production (tons)
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
Northern
|
9,562
|
|
|
9,339
|
|
|
223
|
|
|
2
|
%
|
Central
|
16,862
|
|
|
20,092
|
|
|
(3,230
|
)
|
|
(16
|
)%
|
Southern
|
3,803
|
|
|
3,914
|
|
|
(111
|
)
|
|
(3
|
)%
|
Total Appalachia
|
30,227
|
|
|
33,345
|
|
|
(3,118
|
)
|
|
(9
|
)%
|
Illinois Basin
|
11,173
|
|
|
13,177
|
|
|
(2,004
|
)
|
|
(15
|
)%
|
Northern Powder River Basin
|
4,905
|
|
|
2,844
|
|
|
2,061
|
|
|
72
|
%
|
Gulf Coast
|
740
|
|
|
1,093
|
|
|
(353
|
)
|
|
(32
|
)%
|
Total coal production
|
47,045
|
|
|
50,459
|
|
|
(3,414
|
)
|
|
(7
|
)%
|
|
|
|
|
|
|
|
|
Coal royalty revenue per ton
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
Northern
|
$
|
0.28
|
|
|
$
|
0.92
|
|
|
$
|
(0.64
|
)
|
|
(70
|
)%
|
Central
|
3.85
|
|
|
4.46
|
|
|
(0.61
|
)
|
|
(14
|
)%
|
Southern
|
4.57
|
|
|
5.18
|
|
|
(0.61
|
)
|
|
(12
|
)%
|
Illinois Basin
|
3.94
|
|
|
4.10
|
|
|
(0.16
|
)
|
|
(4
|
)%
|
Northern Powder River Basin
|
2.54
|
|
|
2.74
|
|
|
(0.20
|
)
|
|
(7
|
)%
|
Gulf Coast
|
3.47
|
|
|
3.47
|
|
|
—
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
Coal royalty revenues
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
Northern
|
$
|
2,672
|
|
|
$
|
8,621
|
|
|
$
|
(5,949
|
)
|
|
(69
|
)%
|
Central
|
64,877
|
|
|
89,627
|
|
|
(24,750
|
)
|
|
(28
|
)%
|
Southern
|
17,390
|
|
|
20,292
|
|
|
(2,902
|
)
|
|
(14
|
)%
|
Total Appalachia
|
84,939
|
|
|
118,540
|
|
|
(33,601
|
)
|
|
(28
|
)%
|
Illinois Basin
|
44,063
|
|
|
54,049
|
|
|
(9,986
|
)
|
|
(18
|
)%
|
Northern Powder River Basin
|
12,443
|
|
|
7,804
|
|
|
4,639
|
|
|
59
|
%
|
Gulf Coast
|
2,570
|
|
|
3,793
|
|
|
(1,223
|
)
|
|
(32
|
)%
|
Total coal royalty revenue
|
$
|
144,015
|
|
|
$
|
184,186
|
|
|
$
|
(40,171
|
)
|
|
(22
|
)%
|
|
|
|
|
|
|
|
|
Other revenues
|
|
|
|
|
|
|
|
Coal override revenue
|
$
|
2,920
|
|
|
$
|
4,601
|
|
|
$
|
(1,681
|
)
|
|
(37
|
)%
|
Transportation and processing fees
|
22,033
|
|
|
22,048
|
|
|
(15
|
)
|
|
—
|
%
|
Minimums recognized as revenue
|
15,489
|
|
|
6,659
|
|
|
8,830
|
|
|
133
|
%
|
Lease assignment fee
|
21,000
|
|
|
—
|
|
|
21,000
|
|
|
100
|
%
|
Gain on reserve swap
|
9,290
|
|
|
5,690
|
|
|
3,600
|
|
|
63
|
%
|
Wheelage
|
3,166
|
|
|
3,442
|
|
|
(276
|
)
|
|
(8
|
)%
|
Hard mineral royalty revenues
|
8,090
|
|
|
12,073
|
|
|
(3,983
|
)
|
|
(33
|
)%
|
Oil and gas royalty revenues
|
4,364
|
|
|
10,732
|
|
|
(6,368
|
)
|
|
(59
|
)%
|
Property tax revenue
|
11,258
|
|
|
13,609
|
|
|
(2,351
|
)
|
|
(17
|
)%
|
Other
|
2,156
|
|
|
3,045
|
|
|
(889
|
)
|
|
(29
|
)%
|
Total other revenues
|
$
|
99,766
|
|
|
$
|
81,899
|
|
|
$
|
17,867
|
|
|
22
|
%
|
Coal royalty and other income
|
243,781
|
|
|
266,085
|
|
|
(22,304
|
)
|
|
(8
|
)%
|
Gain on coal royalty and other segment asset sales
|
6,936
|
|
|
1,366
|
|
|
5,570
|
|
|
408
|
%
|
Total coal royalty and other segment revenues and other income
|
$
|
250,717
|
|
|
$
|
267,451
|
|
|
$
|
(16,734
|
)
|
|
(6
|
)%
|
Total coal production decreased
3.4 million
tons, or
7%
, from 50.4 million tons in 2014 to
47.0 million
tons in 2015. Total coal royalty revenues decreased
$40.2 million
, or
22%
, from
$184.2 million
in 2014 to
$144.0 million
in 2015. During 2015, depressed coal prices negatively affected our coal related revenues. During the year ended December 31, 2015 as compared to 2014, total coal production and total coal royalty revenues were down in Appalachia, the Illinois Basin and the Gulf Coast, while we saw a significant increase in the Northern Powder River Basin. All Appalachian regions saw a decrease in coal royalty revenues during the year with coal royalty revenues in Northern Appalachia down
69%
despite a
2%
increase in production from that area. We saw a decrease in the average coal revenue per ton throughout all of our regions, with the exception of the Gulf Coast whose average coal revenue per ton remained flat, for the year ended December 31, 2015 when compared to the year ended December 31, 2014.
Other coal royalty and other income increased
$17.9 million
, or
22%
, from
$81.9 million
in 2014 to
$99.8 million
in 2015. This increase is primarily a result of two lease assignment fee payments received in 2015 totaling
$21.0 million
, an
$8.8 million
increase in minimums recognized as revenue and a
$3.6 million
increase in reserve swap gains year-over-year. These increases were partially offset by decreased oil and gas royalty revenue as a result of lower commodity prices year-over-year and decreases in hard mineral royalty revenues, property taxes and override revenue in 2015 when compared to 2014.
Soda Ash
Revenues and other income related to our Soda Ash segment increased $8.5 million, or 21%, from $41.4 million in 2014 to $49.9 million in 2015. This increase is primarily related to our allocated percentage of Ciner Wyoming's $15.0 million increase in income year-over-year. For the year ended December 31, 2015, we received $46.8 million in cash distributions from Ciner Wyoming and for the year ended December 31, 2014, we received $46.6 million in cash distributions.
VantaCore
Tonnage sold by the VantaCore segment increased 5.1 million tons from 2.3 million tons in 2014 to 7.4 million tons in 2015. Revenues and other income related to our VantaCore segment increased $96.9 million, or 231%, from $42.1 million in 2014 to $139.0 million in 2015. This increase is due to the fact that VantaCore was acquired in the fourth quarter of 2014.
Operating and Maintenance Expenses (including affiliates)
Operating and maintenance expenses (including affiliates) increased
$76.2 million
, or
100%
, from
$76.1 million
in 2014 to
$152.3 million
in 2015. This
increase
is primarily related to the following:
VantaCore
Operating and maintenance expenses in our VantaCore segment
increased
$78.2 million
from
$38.7 million
in 2014 to
$116.9 million
in 2015. This increase is due to the fact that 2014 results only include three months of VantaCore activity as compared to twelve months in 2015.
Depreciation, Depletion and Amortization ("DD&A") Expense
DD&A expense
decreased
$1.0 million
from
$61.9 million
in 2014 to
$60.9 million
in 2015. This
decrease
is primarily related to the following:
Coal Royalty and Other
DD&A expense for our Coal Royalty and Other segment
decreased
$13.3 million
, or
23%
, from
$58.6 million
in 2014 to
$45.3 million
in 2015. This decrease was primarily the result of the reduction in depletion expense on the assets that were impaired during the third and fourth quarters of 2015 and reduced production year-over-year.
VantaCore
DD&A expense for our VantaCore segment
increased
$12.3 million
from
$3.3 million
in 2014 to
$15.6 million
in 2015. This increase was due to the fact that 2014 results only include three months of activity as compared to a full year in 2015.
General and Administrative (including affiliates) ("G&A") Expense
Corporate and financing G&A expense includes corporate headquarters, financing and centralized treasury and accounting. These costs
increased
$1.8 million
, or
17%
, from
$10.5 million
in 2014 to
$12.3 million
in 2015. This increase was primarily due to an increase in salaries, bonus and benefits, consulting, rent and legal fees. This increase was partially offset by a decrease in LTIP expense as a result of the decline in unit price year-over-year.
Asset Impairment
Asset impairment expense increased
$358.3 million
from
$26.2 million
in 2014 to
$384.5 million
in 2015. We recorded the following asset impairments during the years ended December 31, 2015 and 2014 (in thousands):
|
|
|
|
|
|
|
|
|
|
For the Year Ended
December 31,
|
Impaired Assets
|
2015
|
|
2014
|
Coal Royalty and Other
|
|
|
|
Mineral Rights
|
$
|
371,397
|
|
|
$
|
19,806
|
|
Plant and Equipment
|
6,930
|
|
|
779
|
|
Intangible Assets
|
—
|
|
|
5,624
|
|
Total Coal Royalty and Other Impairment
|
$
|
378,327
|
|
|
$
|
26,209
|
|
|
|
|
|
VantaCore
|
|
|
|
Plant and Equipment
|
$
|
692
|
|
|
$
|
—
|
|
Goodwill
|
5,526
|
|
|
—
|
|
Total VantaCore Impairment
|
$
|
6,218
|
|
|
$
|
—
|
|
|
|
|
|
Total impairment
|
$
|
384,545
|
|
|
$
|
26,209
|
|
Coal Royalty and Other
Asset impairment expense related to our Coal Royalty and Other segment
increased
$352.1 million
from
$26.2 million
in 2014 to
$378.3 million
in 2015. This increase was primarily due to the significant impairment expense taken in the third quarter 2015. Coal property impairments primarily resulted from idled operations in Appalachia combined with the continued deterioration in the coal markets and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, low natural gas prices, and continued regulatory pressure on the electric power generation industry. Oil and gas royalty property impairments primarily results from declines in future expected realized commodity prices and reduced expected drilling activity on our acreage. Aggregate royalty property impairments primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. During the fourth quarter of 2015, we recognized an additional
$8.2 million
impairment expense on our coal properties as a result of continued market declines and
$4.7 million
impairment expense related to coal processing and transportation assets as well as obsolete equipment at our Logan office. During the second quarter of 2015 we recorded a
$2.3 million
impairment expense related to a coal preparation plant.
VantaCore
The
$6.2 million
impairment expense in 2015 was related to a
$5.5 million
write off of goodwill as well as a
$0.7 million
impairment related to obsolete plant and equipment.
Interest Expense
Interest expense
increased
$10.3 million
, or
13%
, from
$79.4 million
in 2014 to
$89.7 million
in 2015. This increase was primarily the result of additional debt incurred to complete acquisitions in the fourth quarter of 2014.
Income (Loss) from Discontinued Operations
Income from discontinued operations
decreased
$323.6 million
, from income of
$12.1 million
in 2014 to a loss of
$311.5 million
in 2015. The change in income (loss) from discontinued operations primarily related to asset impairments recorded in 2015 due to the declines in future expected realized commodity prices and reduced expected drilling activity and reduced oil and gas prices in 2015 compared to 2014.
Adjusted EBITDA (Non-GAAP Financial Measure)
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the years ended December 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Segments
|
|
|
|
For the Year Ended
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Corporate and Financing
|
|
Total
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
$
|
(208,248
|
)
|
|
$
|
49,918
|
|
|
$
|
251
|
|
|
$
|
(102,092
|
)
|
|
$
|
(260,171
|
)
|
Less: equity earnings from unconsolidated investment
|
|
—
|
|
|
(49,918
|
)
|
|
—
|
|
|
—
|
|
|
(49,918
|
)
|
Less: gain on reserve swap
|
|
(9,290
|
)
|
|
—
|
|
|
|
|
|
|
(9,290
|
)
|
Add: distributions from unconsolidated investment
|
|
—
|
|
|
46,795
|
|
|
—
|
|
|
—
|
|
|
46,795
|
|
Add: interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
89,762
|
|
|
89,762
|
|
Add: depreciation, depletion and amortization
|
|
45,338
|
|
|
—
|
|
|
15,578
|
|
|
—
|
|
|
60,916
|
|
Add: asset impairment
|
|
378,327
|
|
|
—
|
|
|
6,218
|
|
|
—
|
|
|
384,545
|
|
Adjusted EBITDA
|
|
$
|
206,127
|
|
|
$
|
46,795
|
|
|
$
|
22,047
|
|
|
$
|
(12,330
|
)
|
|
$
|
262,639
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
$
|
145,237
|
|
|
$
|
41,416
|
|
|
$
|
32
|
|
|
$
|
(89,972
|
)
|
|
$
|
96,713
|
|
Less: equity earnings from unconsolidated investment
|
|
—
|
|
|
(41,416
|
)
|
|
—
|
|
|
—
|
|
|
(41,416
|
)
|
Less: gain on reserve swap
|
|
(5,690
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,690
|
)
|
Add: distributions from unconsolidated investment
|
|
—
|
|
|
46,638
|
|
|
—
|
|
|
—
|
|
|
46,638
|
|
Add: interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
79,523
|
|
|
79,523
|
|
Add: depreciation, depletion and amortization
|
|
58,598
|
|
|
—
|
|
|
3,296
|
|
|
—
|
|
|
61,894
|
|
Add: asset impairment
|
|
26,209
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26,209
|
|
Adjusted EBITDA
|
|
$
|
224,354
|
|
|
$
|
46,638
|
|
|
$
|
3,328
|
|
|
$
|
(10,449
|
)
|
|
$
|
263,871
|
|
Adjusted EBITDA
decreased
$1.3 million
from
$263.9 million
in 2014 to
$262.6 million
in 2015. The
decrease
is mainly related to declines in our Coal Royalty and Other segment, partially offset by higher income from our VantaCore business that was acquired in October 2014. Adjusted EBITDA is a non-GAAP financial measure. See "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA" for an explanation of Adjusted EBITDA.
Distributable Cash Flow
(Non-GAAP Financial Measure)
The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the years ended December 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Segments
|
|
|
|
|
For the Year Ended
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Corporate and Financing
|
|
Total
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
204,934
|
|
|
$
|
43,029
|
|
|
$
|
23,605
|
|
|
$
|
(103,056
|
)
|
|
$
|
168,512
|
|
Net cash provided by (used in) investing activities of continuing operations
|
|
$
|
15,805
|
|
|
$
|
—
|
|
|
$
|
(8,820
|
)
|
|
$
|
—
|
|
|
$
|
6,985
|
|
Net cash provided by (used in) financing activities of continuing operations
|
|
$
|
(2,744
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(180,520
|
)
|
|
$
|
(183,264
|
)
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
238,564
|
|
|
$
|
42,516
|
|
|
$
|
2,746
|
|
|
$
|
(91,662
|
)
|
|
$
|
192,164
|
|
Net cash provided by (used in) investing activities of continuing operations
|
|
$
|
(2,067
|
)
|
|
$
|
3,633
|
|
|
$
|
(171,078
|
)
|
|
$
|
—
|
|
|
$
|
(169,512
|
)
|
Net cash provided by (used in) financing activities of continuing operations
|
|
$
|
(974
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(65,012
|
)
|
|
$
|
(65,986
|
)
|
The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to DCF for the years ended December 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Segments
|
|
|
|
For the Year Ended
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Corporate and Financing
|
|
Total
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
204,934
|
|
|
$
|
43,029
|
|
|
$
|
23,605
|
|
|
$
|
(103,056
|
)
|
|
$
|
168,512
|
|
Add: proceeds from sale of PP&E
|
|
10,100
|
|
|
—
|
|
|
924
|
|
|
—
|
|
|
11,024
|
|
Add: proceeds from sale of mineral rights
|
|
3,505
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,505
|
|
Add: return on long-term contract receivables—affiliate
|
|
2,463
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,463
|
|
Less: maintenance capital expenditures
|
|
(416
|
)
|
|
—
|
|
|
(5,727
|
)
|
|
—
|
|
|
(6,143
|
)
|
Less: distributions to non-controlling interest
|
|
(2,744
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,744
|
)
|
Distributable Cash Flow
|
|
$
|
217,842
|
|
|
$
|
43,029
|
|
|
$
|
18,802
|
|
|
$
|
(103,056
|
)
|
|
$
|
176,617
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities of continuing operations
|
|
$
|
238,564
|
|
|
$
|
42,516
|
|
|
$
|
2,746
|
|
|
$
|
(91,662
|
)
|
|
$
|
192,164
|
|
Add: return of unconsolidated equity investment
|
|
—
|
|
|
3,633
|
|
|
—
|
|
|
—
|
|
|
3,633
|
|
Add: proceeds from sale of PP&E
|
|
968
|
|
|
—
|
|
|
38
|
|
|
—
|
|
|
1,006
|
|
Add: proceeds from sale of mineral rights
|
|
412
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
412
|
|
Add: return on long-term contract receivables—affiliate
|
|
1,904
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,904
|
|
Less: maintenance capital expenditures
|
|
(316
|
)
|
|
—
|
|
|
(900
|
)
|
|
—
|
|
|
(1,216
|
)
|
Less: distributions to non-controlling interest
|
|
(974
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(974
|
)
|
Distributable Cash Flow
|
|
$
|
240,558
|
|
|
$
|
46,149
|
|
|
$
|
1,884
|
|
|
$
|
(91,662
|
)
|
|
$
|
196,929
|
|
Distributable Cash Flow for 2015
decreased
$20.3 million
, or
10%
, from
$196.9 million
in 2014 to
$176.6 million
in 2015. This
decrease
is due primarily to a reduction in cash provided by our coal operations, partially offset by our VantaCore business that was acquired in October 2014. Distributable Cash Flow is a non-GAAP financial measure. See "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Distributable Cash Flow" for an explanation of Distributable Cash Flow.
Liquidity and Capital Resources
2017 Restructuring Transactions
The following discussion describes the recapitalization transactions completed on March 2, 2017 and the terms of the preferred units, warrants to purchase common units and debt securities issued in connection therewith.
Issuance of Preferred Units and Warrants
We issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred Units") to Blackstone and GoldenTree (together the "Preferred Purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. We issued 250,000 Preferred Units to the Preferred Purchasers at a price of $1,000 per Preferred Unit (the "Per Unit Purchase Price"), less a 2.5% structuring and origination fee. The Preferred Units entitle the Preferred Purchasers to receive cumulative dividends at a rate of 12% per year, up to one half of which NRP may pay in additional Preferred Units (such additional Preferred Units, the "PIK Units"). We also issued two tranches of warrants (the "Warrants") to purchase common units to the Preferred Purchasers (Warrants to purchase 1.75 million common units with a strike price of $22.81 and Warrants to purchase 2.25 million common units with a strike price of $34.00). The Warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the Warrants, we may, at our option, elect to settle the Warrants in common units or cash, each on a net basis.
The Preferred Units have a perpetual term, unless converted or redeemed as described below. The Preferred Units (including any PIK Units) are convertible into common units at the election of the holders (1) after the fifth anniversary and prior to the eighth anniversary of the issue date at a 7.5% discount to the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to the notice of conversion if the 30-day VWAP immediately prior to such notice is greater than $51.00 (subject to a maximum of 33% of the Preferred Units per year) and (2) after the eighth anniversary of the issue date at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Instead of issuing common units pursuant to clause (1) of the preceding sentence, we have the option to redeem the Preferred Units proposed to be converted for cash at a price equal to the Per Unit Purchase Price, plus the value of any accrued and unpaid distributions. To the extent the holders of the Preferred Units have not elected to convert their Preferred Units by the twelfth anniversary of the issue date, we have the right to force conversion of the Preferred Units into common units at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. In addition, we have the ability to redeem at any time (subject to compliance with our debt agreements) all or any portion of the Preferred Units (including PIK Units) for cash at the agreed upon per unit amount, which is calculated as the Per Unit Purchase Price multiplied by (i) prior to the third anniversary of the closing date, 1.50, (ii) on or after the third anniversary of the closing date and prior to the fourth anniversary of the closing date, 1.70 and (iii) on or after the fourth anniversary of the closing date, 1.85.
The terms of the Preferred Units contain certain restrictions on our ability to pay distributions on our common units. To the extent that either (i) our consolidated Leverage Ratio (as defined in the Restated Partnership Agreement) is greater than 3.25x, or (ii) the ratio of our Distributable Cash Flow to cash distributions made or proposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), we may not increase the quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding Preferred Units. In addition, if at any time after January 1, 2022, any PIK Units are outstanding, we may not make distributions on our common units until we have redeemed all PIK Units for cash.
The holders of the Preferred Units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rights with respect to changes of the terms of the Preferred Units. In addition, Blackstone has certain approval rights over certain matters, including:
|
|
•
|
the incurrence of new indebtedness, subject to certain exceptions;
|
|
|
•
|
material changes to NRP’s business;
|
|
|
•
|
acquisitions and divestitures in excess of certain dollar thresholds;
|
|
|
•
|
amendments to material contracts resulting in a cash impact to NRP in excess of certain dollar thresholds;
|
|
|
•
|
settlement of any litigation or regulatory matter resulting in cash payments by NRP in excess of certain thresholds; and
|
|
|
•
|
amendments to related party contracts outside of the ordinary course of business.
|
GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the Minimum Preferred Unit Threshold (as defined below). The Preferred Purchaser Approval Rights are not transferrable without our consent. In addition, the Preferred Purchaser Approval Rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). To the extent any Preferred Units that have converted into common units are still held by the applicable Preferred Purchaser (or its affiliates), such common units will be deemed to represent a number of Preferred Units based on the weighted average number of common units issued in each conversion and will count towards the Minimum Preferred Unit Threshold.
The foregoing terms of the Preferred Units are reflected in our Fifth Amended and Restated Agreement of Limited Partnership, dated as of March 2, 2017, which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference. The terms of the Warrants are reflected in the Form of Warrant to Purchase Common Units filed as Exhibit 4.28 to this Annual Report on Form 10-K, which is incorporated herein by reference.
At the closing, pursuant to a Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights and appointed one director and one observer to the Board of Directors of GP Natural Resource Partners LLC. For more information on these rights, see "Certain Relationships and Related Transactions, and Director Independence—Board Representation and Observation Rights Agreement."
We also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with the Preferred Purchasers, pursuant to which we are required to file (i) a shelf registration statement to register the common units issuable upon exercise of the Warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the Preferred Units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of Preferred Units (the "Registration Deadlines"). In addition, the Preferred Unit and Warrant Registration Rights Agreement gives the Preferred Purchasers piggyback registration and demand underwritten offering rights under certain circumstances. If the shelf registration statements are not effective by the applicable Registration Deadline, we will be required to pay the Preferred Purchasers liquidated damages in the amounts and upon the term set forth in the Preferred Unit and Warrant Registration Rights Agreement.
Opco Credit Facility Amendment
We entered into the Second Amendment to Opco’s Third Amended and Restated Credit Agreement to extend the term thereof until April 2020, and reduced the commitments of the lenders to $180 million (from $210 million) effective at the closing of the recapitalization transactions. Pursuant the Second Amendment, commitments under the Opco Credit Facility will be reduced to $150 million at December 31, 2017 and further reduced to $100 million at December 31, 2018 through maturity in April 2020. The amendment does not change the pricing grid or financial covenants under the Opco Credit Facility; provided, however, that if we increase our quarterly distribution to our common unitholders above $0.45 per common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from 4.0x to 3.0x. Other terms of the Second Amendment include revisions to the mandatory prepayment provisions with respect to net cash proceeds received from certain asset sales, additional limitations on the ability of Opco and its subsidiaries to make certain investments. The Second Amendment is filed as Exhibit 10.14 to this Annual Report on Form 10-K and is incorporated herein by reference.
Issuance of 2022 Notes; Exchange and Redemption of 2018 Notes
NRP and NRP Finance issued $346 million aggregate principal amount of 10.500% Senior Notes due 2022 to several holders of its 2018 Notes. Of the $346 million of 2022 Notes issued, $241 million in aggregate principal amount were issued in exchange for $241 million in aggregate principal amount of 2018 Notes, and $105 million of the 2022 Notes were issued to the holders in exchange for cash. The 2022 Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 Indenture"), bear interest at 10.500% per year, are payable semi-annually on March 15 and September 15, beginning September 15, 2017, and mature on March 15, 2022.
We and NRP Finance have the option to redeem the 2022 Notes, in whole or in part, at any time on or after March 15, 2019, at the redemption prices (expressed as percentages of principal amount) of 105.25% for the 12-month period beginning March 15, 2019, 102.625% for the 12-month period beginning March 15, 2020, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the date of redemption. Furthermore, before March 15, 2019, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of certain public or private equity offerings at a redemption price of 110.500% of the principal amount of 2022 Notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Notes issued under the 2022 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the 2022 Indenture, the holders of the 2022 Notes may require us to purchase their 2022 Notes at a purchase price equal to 101% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any. The 2022 Notes purchased for cash were issued at a price of 98.75% (original issue discount of 1.25%), and each holder exchanging 2018 Notes received a fee of 5.813% of the aggregate principal amount of all 2018 Notes tendered for exchange by such holder, as well as all accrued and unpaid interest thereon.
The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing the 2018 Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under the debt incurrence covenant, our non-guarantor restricted subsidiaries will not be permitted to incur additional indebtedness unless their consolidated leverage ratio is less than 3.00x (measured on a pro forma basis and assuming that the greater of (i) $150.0 million of debt (or, if less, at our election, the amount of total lending commitments under any revolving credit facility) and (ii) the actual amount of debt outstanding is outstanding under any revolving credit facility); provided, however, that such non-guarantor restricted subsidiaries will be permitted to make up to $150 million in borrowings under a revolving credit facility (which amount will be reduced on a dollar-for-dollar basis to the extent we have made the election described in clause (i) above). Under the restricted payments covenant, we will not be able to increase the quarterly distribution on our common units or elect to pay more than 50% of the distributions required to be made on the Preferred Units in the form of cash, unless, in each case, our consolidated leverage ratio is less than 4.00x. The 2022 Indenture also contains restrictions on our ability to redeem the Preferred Units in cash.
The 2022 Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance, including the remaining outstanding 2018 Notes, and senior in right of payment to any of our subordinated debt. The 2022 Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of our subsidiaries guarantee the 2022 Notes.
The terms of the 2022 Notes are more fully described in the 2022 Indenture, which is filed as Exhibit 4.24 to this Annual Report on Form 10-K and incorporated herein by reference.
We entered into a registration rights agreement (the "Notes Registration Rights Agreement") with the holders of the 2022 Notes, pursuant to which we and NRP Finance agreed to file a registration statement with the Securities and Exchange Commission for the benefit of the holders of the 2022 Notes so that such holders can exchange the 2022 Notes for exchange securities that have substantially identical terms as the 2022 Notes. We and NRP Finance agreed to use commercially reasonable efforts to cause the exchange to be completed within 180 days after the closing and will be required to pay additional interest, as specified in the Notes Registration Rights Agreement, if we fail to comply with our obligations to register the 2022 Notes within the specified time periods.
We expect to redeem $90 million in aggregate principal amount of the 2018 Notes at a redemption price of 104.563%, and pay all accrued and unpaid interest thereon, in April 2017. In addition, we are required to redeem any and all remaining outstanding 2018 Notes (and pay all accrued and unpaid interest thereon) within 60 days after October 1, 2017.
The following table summarizes our long-term debt and convertible preferred unit obligations at December 31, 2016 and at December 31, 2016 after giving pro forma effect to the recapitalization transactions described above (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
As of December 31, 2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
2018 Notes
|
|
$
|
—
|
|
|
$
|
425.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
425.0
|
|
Opco Credit Facility
|
|
60.0
|
|
|
150.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
210.0
|
|
Opco Senior Notes and other
|
|
80.6
|
|
|
80.6
|
|
|
76.0
|
|
|
54.7
|
|
|
47.0
|
|
|
164.9
|
|
|
503.8
|
|
Total long-term debt obligations
|
|
$
|
140.6
|
|
|
$
|
655.6
|
|
|
$
|
76.0
|
|
|
$
|
54.7
|
|
|
$
|
47.0
|
|
|
$
|
164.9
|
|
|
$
|
1,138.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
After Recapitalization Transactions
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
2022 Notes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
346.0
|
|
|
$
|
346.0
|
|
2018 Notes
|
|
94.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
94.0
|
|
Opco Credit Facility
(1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Opco Senior Notes and other
|
|
80.6
|
|
|
80.6
|
|
|
76.0
|
|
|
54.7
|
|
|
47.0
|
|
|
164.9
|
|
|
503.8
|
|
Total long-term debt obligations
|
|
$
|
174.6
|
|
|
$
|
80.6
|
|
|
$
|
76.0
|
|
|
$
|
54.7
|
|
|
$
|
47.0
|
|
|
$
|
510.9
|
|
|
$
|
943.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred unit obligations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
250.0
|
|
|
$
|
250.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt and convertible preferred unit obligations
|
|
$
|
174.6
|
|
|
$
|
80.6
|
|
|
$
|
76.0
|
|
|
$
|
54.7
|
|
|
$
|
47.0
|
|
|
$
|
760.9
|
|
|
$
|
1,193.8
|
|
|
|
(1)
|
Assumes no additional borrowings under the Opco Credit Facility following closing.
|
Current Liquidity
Generally, we satisfy our working capital requirements with cash generated from operations. Our current liabilities exceeded our current assets by approximately
$83.8 million
as of December 31, 2016, primarily due to $80.6 million in total principal payments due in 2017 on the Opco Senior Notes and Opco utility local improvement obligation and
$60.0 million
of payments due in 2017 on the Opco Credit Facility. Excluding these principal payments, our current assets exceeded our current liabilities by approximately
$56.8 million
as of December 31, 2016. In March 2017, we increased our liquidity through the completion of the recapitalization transactions described above. In addition to enhancing our liquidity, these recapitalization transactions reduced our 2018 debt maturities by $575 million through the extension of debt principal payments from 2018 to 2020 and 2022.
Capital Expenditures
A portion of the capital expenditures associated with our VantaCore segment are maintenance capital expenditures, which are capital expenditures made to maintain the long-term production capacity of those businesses. Expansion capital expenditures are made to increase productive capacity. We deduct maintenance capital expenditures when calculating DCF. VantaCore’s maintenance and expansion capital expenditures for the year ended December 31, 2016 were $4.4 million and $1.0 million, respectively.
Cash Flows
Cash flow provided by operating activities decreased
$95.4 million
, from
$203.4 million
in the year ended December 31, 2015 to
$108.0 million
in the year ended December 31, 2016. Operating cash flow from continuing operations decreased
$70.4 million
in our Coal Royalty and Other segment year-over-year primarily as a result of the reduction in coal royalty revenue and reduction of coal royalty minimum cash payments received on certain leases. Cash flow provided by operating activities of discontinued operations decreased
$27.6 million
, from
$34.9 million
in the year ended December 31, 2015 to
$7.3 million
in the year ended December 31, 2016 primarily as a result of completing the sale of our non-operated oil and gas working interest assets in July 2016 that had an effective date of April 1, 2016.
Cash flow provided by operating activities decreased
$7.4 million
, from
$210.8 million
in the year ended December 31, 2014 to
$203.4 million
in the year ended December 31, 2015. Operating cash flow from continuing operations decreased
$33.7 million
in our Coal Royalty and Other segment year-over-year primarily as a result of the reduction in coal royalty revenue and reduction of coal royalty minimum cash payments received on certain leases. Corporate and Financing used an additional
$11.4 million
in operating activities of continuing operations primarily due to the increase in cash paid for interest year-over-year. These decreases were partially offset by a
$20.9 million
increase in cash provided by operating activities of continuing operations in our VantaCore segment primarily due to a full year of operations due to the fourth quarter of 2014 acquisition. Cash flow provided by operating activities of discontinued operations increased
$16.3 million
, from
$18.6 million
in the year ended December 31, 2014 to
$34.9 million
in the year ended December 31, 2015 primarily as a result of a full year of revenue on our fourth quarter 2014 Williston Basin non-operated working interest asset acquisition.
Cash flow provided by investing activities increased
$197.1 million
, from
$30.3 million
used in the year ended December 31, 2015 to
$166.8 million
provided in the year ended December 31, 2016. Investing cash flows from discontinued operations increased
$144.2 million
primarily as a result of the sale of our non-operated oil and gas working interest assets in July 2016 for
$109.9 million
in net cash proceeds in addition to a $37.8 million decrease in cash flow used as a result of lower oil and gas drilling activity and the non-operated working interest asset sale in July 2016. Investing cash flows from continuing operations increased
$52.9 million
primarily as a result of 2016 sales of oil and gas and aggregate royalty properties.
Cash flow used by investing activities decreased
$490.2 million
, from
$520.5 million
in the year ended December 31, 2014 to
$30.3 million
in the year ended December 31, 2015 primarily due to the 2014 VantaCore acquisition and various 2015 asset sales including an aggregate preparation plant, cell phone tower lease contracts and condemnation payments within our Coal Royalty and Other segment, partially offset by plant and equipment acquisitions within our VantaCore segment. Cash flow used by investing activities of discontinued operations decreased
$313.7 million
primarily due to our 2014 investing activities consisting of our Sanish Field acquisition as well as additional capital expenditures related to the participation in new wells, partially offset by 2015 well participation costs.
Cash flow used in financing activities increased
$114.7 million
, from
$171.5 million
in the year ended December 31, 2015 to
$286.2 million
in the year ended December 31, 2016. Cash used in financing activities of discontinued operations increased
$136.6 million
primarily as a result of using $85.0 million to repay the RBL Credit Facility and contributing the
$39.4 million
of discontinued asset sales proceeds that remained after repayment of the RBL Facility in full to continuing operations. This increase in cash flow used in financing activities was partially offset by a
$21.9 million
decrease in cash flow used in financing activities from continuing operations primarily a result of distributing
$49.3 million
less cash to partners and receiving the remaining net proceeds from discontinuing operations after repayment as described above.
Cash flow used in financing activities increased
$438.8 million
, from
$267.3 million
provided in the year ended December 31, 2014 to
$171.5 million
used in the year ended December 31, 2015 primarily due to $518.4 million in loan proceeds and $127.2 million in general partner contributions received during the year ended December 31, 2014. This change was partially offset by higher distributions to partners and loan repayments made during 2014. Cash flow provided by financing activities of discontinued operations decreased
$321.5 million
, from
$333.3 million
in the year ended December 31, 2014 to
$11.8 million
provided in the year ended December 31, 2015, primarily as a result of contributions from continuing operations to fund investing activities of the discontinued operation in 2014.
Capital Resources and Obligations
Indebtedness
As of December 31, 2016 and 2015, we had the following indebtedness (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
Current portion of long-term debt, net
|
$
|
138,903
|
|
|
$
|
80,745
|
|
Long-term debt and debt—affiliate, net
|
987,400
|
|
|
1,290,211
|
|
Total debt and debt—affiliate, net
|
$
|
1,126,303
|
|
|
$
|
1,370,956
|
|
We were and continue to be in compliance with the terms of the financial covenants contained in Opco's debt agreements. Adjusted EBITDA as defined in "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA" differs
from the EBITDDA definitions contained in our debt agreements. For additional information regarding our debt and the agreements governing our debt, including the covenants contained therein, see and "—2017 Recapitalization Transactions" above and "Item 8. Financial Statements and Supplementary Data—Note 11. Debt and Debt—Affiliate" in this Annual Report on Form 10-K.
Long-Term Contractual Obligations
The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2016 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
Contractual Obligations
|
|
Total
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
NRP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt principal payments (including current maturities) (1)
|
|
$
|
425.0
|
|
|
$
|
—
|
|
|
$
|
425.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Long-term debt interest payments (1)
|
|
77.6
|
|
|
38.8
|
|
|
38.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Opco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt principal payments (including current maturities) (2)
|
|
713.8
|
|
|
140.6
|
|
|
230.6
|
|
|
76.0
|
|
|
54.7
|
|
|
47.0
|
|
|
164.9
|
|
Long-term debt interest payments (3)
|
|
114.8
|
|
|
28.1
|
|
|
23.1
|
|
|
18.1
|
|
|
14.2
|
|
|
11.1
|
|
|
20.2
|
|
Rental leases (4)
|
|
5.2
|
|
|
2.2
|
|
|
1.6
|
|
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
|
1.1
|
|
Total
|
|
$
|
1,336.4
|
|
|
$
|
209.7
|
|
|
$
|
719.1
|
|
|
$
|
94.2
|
|
|
$
|
69.0
|
|
|
$
|
58.2
|
|
|
$
|
186.2
|
|
|
|
(1)
|
The amounts indicated in the table include principal and interest due on NRP’s 2018 Notes.
|
|
|
(2)
|
The amounts indicated in the table include principal due on Opco’s senior notes, credit facility and utility local improvement obligation.
|
|
|
(3)
|
The amounts indicated in the table include interest due on Opco’s senior notes and utility local improvement obligation.
|
|
|
(4)
|
The rental lease amounts primarily consist of office space and VantaCore equipment leases.
|
Shelf Registration Statement
In September 2015, we filed a registration statement on Form S-3 with the SEC that is available for registered offerings of common units.
Off-Balance Sheet Transactions
We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the years ended December 31, 2016, 2015 and 2014.
Environmental Regulation
For additional information on environmental regulation that may have a material impact on our business, see "Item 1. 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 and liabilities in the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income during the reporting period. See "Note 2. Summary of Significant Accounting Policies" to the audited consolidated financial statements under Item 8 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.
Revenues
Coal Royalty and Other Revenues.
Coal royalty and other revenues are recognized on the basis of tons of mineral sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons of material processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, we receive a fixed price per ton for all material transported on the beltlines.
Most of our coal and aggregates lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as a deferred revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments.
Oil and gas related revenues consist of revenues from royalties and overriding royalties. Oil and gas royalty revenues are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales.
Equity in Earnings from Ciner Wyoming.
We account for non-marketable equity investments using the equity method of accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for our investment in Ciner Wyoming using this method.
Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of the investee's net assets is hypothetically allocated first to identified tangible assets and liabilities, then to finite-lived intangibles or indefinite-lived intangibles and the remaining balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived intangibles, if any, and goodwill are not amortized. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income.
Our carrying value in an equity method investee company is reflected in the caption "Equity and other unconsolidated investments" in our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of the investee company is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity and other unconsolidated investment income." Our share of investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the proportionate share of the investee’s net assets, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets.
VantaCore Revenues.
Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to the estimated total costs for each contract. That method is used since we consider total cost to be the best available measure of progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses
are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred.
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 aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage as defined by the SEC’s Industry Guide 7 and estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of our proved reserves include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statistical analysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results.
Asset Impairment
We have developed procedures to periodically evaluate our long-lived assets for possible impairment. These procedures are performed throughout the year and are based on historic, current and future performance and are designed to be early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property.
We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.
Recent Accounting Standards
For a discussion of recent accounting pronouncements, see the applicable section of "Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies" to the audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Natural Resource Partners L.P.
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2016 and 2015, and the related consolidated statements of comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Ciner Wyoming LLC (Ciner Wyoming), a Limited Liability Company in which Natural Resource Partners L.P. owns a 49% interest. In the consolidated financial statements Natural Resource Partners L.P.’s investment in Ciner Wyoming is stated at $256 million and $262 million as of December 31, 2016 and 2015 respectively, and Natural Resource Partners L.P.’s equity in the net income of Ciner Wyoming is stated at $40 million, $50 million, and $41 million for each of the three years in the period ended December 31, 2016. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ciner Wyoming LLC, is based on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Natural Resource Partners L.P.'s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated
March 6, 2017
expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
March 6, 2017
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
We have audited the accompanying balance sheets of Ciner Wyoming LLC (the "Company") as of December 31, 2016 and 2015 and the related statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
March 6, 2017
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data)
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
40,371
|
|
|
$
|
41,204
|
|
Accounts receivable, net
|
43,202
|
|
|
43,633
|
|
Accounts receivable—affiliates, net
|
6,658
|
|
|
6,345
|
|
Inventory
|
6,893
|
|
|
7,835
|
|
Prepaid expenses and other
|
6,137
|
|
|
4,268
|
|
Current assets of discontinued operations (see Note 3)
|
991
|
|
|
17,844
|
|
Total current assets
|
104,252
|
|
|
121,129
|
|
Land
|
25,252
|
|
|
25,022
|
|
Plant and equipment, net
|
49,443
|
|
|
60,675
|
|
Mineral rights, net
|
908,192
|
|
|
984,522
|
|
Intangible assets, net
|
3,236
|
|
|
3,930
|
|
Intangible assets, net—affiliate
|
49,811
|
|
|
52,997
|
|
Equity in unconsolidated investment
|
255,901
|
|
|
261,942
|
|
Long-term contracts receivable—affiliate
|
43,785
|
|
|
47,359
|
|
Other assets
|
3,791
|
|
|
1,173
|
|
Other assets—affiliate
|
1,018
|
|
|
1,124
|
|
Non-current assets of discontinued operations (see Note 3)
|
—
|
|
|
110,162
|
|
Total assets
|
$
|
1,444,681
|
|
|
$
|
1,670,035
|
|
LIABILITIES AND CAPITAL
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable
|
$
|
6,234
|
|
|
$
|
5,022
|
|
Accounts payable—affiliates
|
940
|
|
|
801
|
|
Accrued liabilities
|
41,587
|
|
|
44,997
|
|
Accrued liabilities—affiliates
|
—
|
|
|
456
|
|
Current portion of long-term debt, net
|
138,903
|
|
|
80,745
|
|
Current liabilities of discontinued operations (see Note 3)
|
353
|
|
|
4,388
|
|
Total current liabilities
|
188,017
|
|
|
136,409
|
|
Deferred revenue
|
44,931
|
|
|
80,812
|
|
Deferred revenue
—
affiliates
|
71,632
|
|
|
82,853
|
|
Long-term debt, net
|
987,400
|
|
|
1,186,681
|
|
Long-term debt, net
—
affiliate
|
—
|
|
|
19,930
|
|
Other non-current liabilities
|
4,565
|
|
|
5,171
|
|
Non-current liabilities of discontinued operations (see Note 3)
|
—
|
|
|
85,237
|
|
Commitments and contingencies (see Note 14)
|
|
|
|
Partners’ capital:
|
|
|
|
Common unitholders’ interest (12,232,006 units outstanding)
|
152,309
|
|
|
79,094
|
|
General partner’s interest
|
887
|
|
|
(606
|
)
|
Accumulated other comprehensive loss
|
(1,666
|
)
|
|
(2,152
|
)
|
Total partners’ capital
|
151,530
|
|
|
76,336
|
|
Non-controlling interest
|
(3,394
|
)
|
|
(3,394
|
)
|
Total capital
|
148,136
|
|
|
72,942
|
|
Total liabilities and capital
|
$
|
1,444,681
|
|
|
$
|
1,670,035
|
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Revenues and other income:
|
|
|
|
|
|
Coal royalty and other
|
$
|
144,520
|
|
|
$
|
154,066
|
|
|
$
|
181,526
|
|
Coal royalty and other—affiliates
|
65,595
|
|
|
89,715
|
|
|
84,559
|
|
VantaCore
|
120,802
|
|
|
139,049
|
|
|
42,031
|
|
Equity in earnings of Ciner Wyoming
|
40,061
|
|
|
49,918
|
|
|
41,416
|
|
Gain on asset sales, net
|
29,081
|
|
|
6,900
|
|
|
1,386
|
|
Total revenues and other income
|
400,059
|
|
|
439,648
|
|
|
350,918
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
Operating and maintenance expenses
|
119,621
|
|
|
136,943
|
|
|
65,933
|
|
Operating and maintenance expenses—affiliates, net
|
10,925
|
|
|
15,323
|
|
|
10,197
|
|
Depreciation, depletion and amortization
|
43,087
|
|
|
57,295
|
|
|
58,586
|
|
Amortization expense—affiliate
|
3,185
|
|
|
3,621
|
|
|
3,308
|
|
General and administrative
|
16,979
|
|
|
7,036
|
|
|
7,287
|
|
General and administrative—affiliates
|
3,591
|
|
|
5,312
|
|
|
3,258
|
|
Asset impairments
|
16,926
|
|
|
384,545
|
|
|
26,209
|
|
Total operating expenses
|
214,314
|
|
|
610,075
|
|
|
174,778
|
|
|
|
|
|
|
|
Income (loss) from operations
|
185,745
|
|
|
(170,427
|
)
|
|
176,140
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
|
|
|
Interest expense
|
(90,047
|
)
|
|
(87,911
|
)
|
|
(79,144
|
)
|
Interest expense—affiliate
|
(523
|
)
|
|
(1,851
|
)
|
|
(379
|
)
|
Interest income
|
39
|
|
|
18
|
|
|
96
|
|
Other expense, net
|
(90,531
|
)
|
|
(89,744
|
)
|
|
(79,427
|
)
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
95,214
|
|
|
(260,171
|
)
|
|
96,713
|
|
Income (loss) from discontinued operations (see Note 3)
|
1,678
|
|
|
(311,549
|
)
|
|
12,117
|
|
Net income (loss)
|
$
|
96,892
|
|
|
$
|
(571,720
|
)
|
|
$
|
108,830
|
|
|
|
|
|
|
|
Net income (loss) attributable to limited partners:
|
|
|
|
|
|
Continuing operations
|
$
|
93,585
|
|
|
$
|
(254,173
|
)
|
|
$
|
94,779
|
|
Discontinued operations
|
1,644
|
|
|
(305,319
|
)
|
|
11,874
|
|
Total
|
$
|
95,229
|
|
|
$
|
(559,492
|
)
|
|
$
|
106,653
|
|
|
|
|
|
|
|
Net income (loss) attributable to the general partner:
|
|
|
|
|
|
Continuing operations
|
$
|
1,629
|
|
|
$
|
(5,998
|
)
|
|
$
|
1,934
|
|
Discontinued operations
|
34
|
|
|
(6,230
|
)
|
|
243
|
|
Total
|
$
|
1,663
|
|
|
$
|
(12,228
|
)
|
|
$
|
2,177
|
|
|
|
|
|
|
|
Basic and diluted net income (loss) per common unit:
|
|
|
|
|
|
Continuing operations
|
$
|
7.65
|
|
|
$
|
(20.78
|
)
|
|
$
|
8.37
|
|
Discontinued operations
|
0.13
|
|
|
(24.97
|
)
|
|
1.05
|
|
Total
|
$
|
7.78
|
|
|
$
|
(45.75
|
)
|
|
$
|
9.42
|
|
|
|
|
|
|
|
Average number of common units outstanding
|
12,232
|
|
|
12,232
|
|
|
11,326
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
96,892
|
|
|
$
|
(571,720
|
)
|
|
$
|
108,830
|
|
Add: comprehensive income (loss) from unconsolidated investment and other
|
486
|
|
|
(1,693
|
)
|
|
(81
|
)
|
Comprehensive income (loss)
|
$
|
97,378
|
|
|
$
|
(573,413
|
)
|
|
$
|
108,749
|
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Unitholders
|
|
General Partner
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Partners' Capital Excluding Non-Controlling Interest
|
|
Non-Controlling Interest
|
|
Total Capital
|
|
|
Units
|
|
Amounts
|
|
Balance at December 31, 2013
|
10,983
|
|
|
$
|
606,774
|
|
|
$
|
10,069
|
|
|
$
|
(378
|
)
|
|
$
|
616,465
|
|
|
$
|
324
|
|
|
$
|
616,789
|
|
Net income
|
—
|
|
|
106,653
|
|
|
2,177
|
|
|
—
|
|
|
108,830
|
|
|
—
|
|
|
108,830
|
|
Issuance of common units
|
1,006
|
|
|
127,202
|
|
|
—
|
|
|
—
|
|
|
127,202
|
|
|
—
|
|
|
127,202
|
|
Issuance of common units for acquisitions
|
243
|
|
|
31,604
|
|
|
—
|
|
|
—
|
|
|
31,604
|
|
|
—
|
|
|
31,604
|
|
Capital contribution
|
—
|
|
|
—
|
|
|
3,240
|
|
|
—
|
|
|
3,240
|
|
|
—
|
|
|
3,240
|
|
Cost associated with equity transactions
|
—
|
|
|
(4,413
|
)
|
|
—
|
|
|
—
|
|
|
(4,413
|
)
|
|
—
|
|
|
(4,413
|
)
|
Distributions to unitholders
|
—
|
|
|
(158,801
|
)
|
|
(3,241
|
)
|
|
—
|
|
|
(162,042
|
)
|
|
—
|
|
|
(162,042
|
)
|
Distributions to non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(974
|
)
|
|
(974
|
)
|
Comprehensive loss from unconsolidated investment and other
|
—
|
|
|
—
|
|
|
—
|
|
|
(81
|
)
|
|
(81
|
)
|
|
—
|
|
|
(81
|
)
|
Balance at December 31, 2014
|
12,232
|
|
|
$
|
709,019
|
|
|
$
|
12,245
|
|
|
$
|
(459
|
)
|
|
$
|
720,805
|
|
|
$
|
(650
|
)
|
|
$
|
720,155
|
|
Net loss
|
—
|
|
|
(559,492
|
)
|
|
(12,228
|
)
|
|
—
|
|
|
(571,720
|
)
|
|
—
|
|
|
(571,720
|
)
|
Cost associated with equity transactions
|
—
|
|
|
(109
|
)
|
|
—
|
|
|
—
|
|
|
(109
|
)
|
|
—
|
|
|
(109
|
)
|
Distributions to unitholders
|
—
|
|
|
(70,324
|
)
|
|
(1,434
|
)
|
|
—
|
|
|
(71,758
|
)
|
|
—
|
|
|
(71,758
|
)
|
Distributions to non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,744
|
)
|
|
(2,744
|
)
|
Non-cash contributions
|
—
|
|
|
—
|
|
|
811
|
|
|
—
|
|
|
811
|
|
|
—
|
|
|
811
|
|
Comprehensive loss from unconsolidated investment and other
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,693
|
)
|
|
(1,693
|
)
|
|
—
|
|
|
(1,693
|
)
|
Balance at December 31, 2015
|
12,232
|
|
|
$
|
79,094
|
|
|
$
|
(606
|
)
|
|
$
|
(2,152
|
)
|
|
$
|
76,336
|
|
|
$
|
(3,394
|
)
|
|
$
|
72,942
|
|
Net income
|
—
|
|
|
95,229
|
|
|
1,663
|
|
|
—
|
|
|
96,892
|
|
|
—
|
|
|
96,892
|
|
Distributions to unitholders
|
—
|
|
|
(22,014
|
)
|
|
(451
|
)
|
|
—
|
|
|
(22,465
|
)
|
|
—
|
|
|
(22,465
|
)
|
Non-cash contributions
|
—
|
|
|
—
|
|
|
281
|
|
|
—
|
|
|
281
|
|
|
—
|
|
|
281
|
|
Comprehensive income from unconsolidated investment and other
|
—
|
|
|
—
|
|
|
—
|
|
|
486
|
|
|
486
|
|
|
—
|
|
|
486
|
|
Balance at December 30, 2016
|
12,232
|
|
|
$
|
152,309
|
|
|
$
|
887
|
|
|
$
|
(1,666
|
)
|
|
$
|
151,530
|
|
|
$
|
(3,394
|
)
|
|
$
|
148,136
|
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Cash flows from operating activities:
|
|
|
|
|
|
Net income (loss)
|
$
|
96,892
|
|
|
$
|
(571,720
|
)
|
|
$
|
108,830
|
|
Adjustments to reconcile net income to net cash provided by operating activities of continuing operations:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
43,087
|
|
|
57,295
|
|
|
58,586
|
|
Amortization expense—affiliates
|
3,185
|
|
|
3,621
|
|
|
3,308
|
|
Distributions from equity earnings from unconsolidated investment
|
46,550
|
|
|
46,795
|
|
|
43,005
|
|
Equity earnings from unconsolidated investment
|
(40,061
|
)
|
|
(49,918
|
)
|
|
(41,416
|
)
|
Gain on asset sales, net
|
(29,081
|
)
|
|
(6,900
|
)
|
|
(1,386
|
)
|
(Income) loss from discontinued operations
|
(1,678
|
)
|
|
311,549
|
|
|
(12,117
|
)
|
Asset impairments
|
16,926
|
|
|
384,545
|
|
|
26,209
|
|
Gain on reserve swap
|
—
|
|
|
(9,290
|
)
|
|
(5,690
|
)
|
Other, net
|
8,284
|
|
|
(7,109
|
)
|
|
(5,279
|
)
|
Other, net—affiliates
|
993
|
|
|
(912
|
)
|
|
(180
|
)
|
Change in operating assets and liabilities:
|
|
|
|
|
|
Accounts receivable
|
431
|
|
|
7,705
|
|
|
4,483
|
|
Accounts receivable—affiliates
|
(313
|
)
|
|
3,149
|
|
|
(1,828
|
)
|
Accounts payable
|
707
|
|
|
(3,625
|
)
|
|
(8,928
|
)
|
Accounts payable—affiliates
|
139
|
|
|
(32
|
)
|
|
457
|
|
Accrued liabilities
|
4,618
|
|
|
1,420
|
|
|
6,002
|
|
Accrued liabilities—affiliates
|
(456
|
)
|
|
—
|
|
|
456
|
|
Deferred revenue
|
(35,881
|
)
|
|
7,605
|
|
|
2,056
|
|
Deferred revenue—affiliates
|
(11,222
|
)
|
|
(4,200
|
)
|
|
15,618
|
|
Other items, net
|
(2,477
|
)
|
|
(1,466
|
)
|
|
(22
|
)
|
Other items, net—affiliates
|
—
|
|
|
—
|
|
|
—
|
|
Net cash provided by operating activities of continuing operations
|
100,643
|
|
|
168,512
|
|
|
192,164
|
|
Net cash provided by operating activities of discontinued operations
|
7,318
|
|
|
34,912
|
|
|
18,591
|
|
Net cash provided by operating activities
|
107,961
|
|
|
203,424
|
|
|
210,755
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Proceeds from sale of oil and gas royalty properties
|
42,844
|
|
|
—
|
|
|
—
|
|
Proceeds from sale of coal and aggregate royalty properties
|
18,189
|
|
|
3,505
|
|
|
412
|
|
Return of long-term contract receivables—affiliate
|
2,968
|
|
|
2,463
|
|
|
1,904
|
|
Proceeds from sale of plant and equipment and other
|
1,350
|
|
|
11,024
|
|
|
1,006
|
|
Acquisition of plant and equipment and other
|
(5,408
|
)
|
|
(9,607
|
)
|
|
(2,454
|
)
|
Acquisition of mineral rights
|
—
|
|
|
(400
|
)
|
|
(5,035
|
)
|
Acquisition of aggregates business
|
—
|
|
|
—
|
|
|
(168,978
|
)
|
Return of equity from unconsolidated investment
|
—
|
|
|
—
|
|
|
3,633
|
|
Net cash provided by (used in) investing activities of continuing operations
|
59,943
|
|
|
6,985
|
|
|
(169,512
|
)
|
Net cash provided by (used in) investing activities of discontinued operations
|
106,872
|
|
|
(37,256
|
)
|
|
(350,991
|
)
|
Net cash provided by (used in) investing activities
|
166,815
|
|
|
(30,271
|
)
|
|
(520,503
|
)
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
Proceeds from loans
|
20,000
|
|
|
100,000
|
|
|
498,471
|
|
Proceeds from loan—affiliate
|
—
|
|
|
—
|
|
|
19,904
|
|
Proceeds from issuance of common units
|
—
|
|
|
—
|
|
|
127,202
|
|
Capital contribution by general partner
|
—
|
|
|
—
|
|
|
3,240
|
|
Repayments of loans
|
(183,141
|
)
|
|
(165,983
|
)
|
|
(318,983
|
)
|
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to unitholders
|
(22,465
|
)
|
|
(71,758
|
)
|
|
(162,042
|
)
|
Distributions to non-controlling interest
|
—
|
|
|
(2,744
|
)
|
|
(974
|
)
|
Contributions from (to) discontinued operations
|
39,421
|
|
|
(36,725
|
)
|
|
(226,000
|
)
|
Debt issue costs and other
|
(15,234
|
)
|
|
(6,054
|
)
|
|
(6,804
|
)
|
Net cash used in financing activities of continuing operations
|
(161,419
|
)
|
|
(183,264
|
)
|
|
(65,986
|
)
|
Net cash provided by (used in) financing activities of discontinued operations
|
(124,759
|
)
|
|
11,808
|
|
|
333,297
|
|
Net cash provided by (used in) financing activities
|
(286,178
|
)
|
|
(171,456
|
)
|
|
267,311
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
(11,402
|
)
|
|
1,697
|
|
|
(42,437
|
)
|
|
|
|
|
|
|
Cash and cash equivalents of continuing operations at beginning of period
|
41,204
|
|
|
48,971
|
|
|
92,305
|
|
Cash and cash equivalents of discontinued operations at beginning of period
|
10,569
|
|
|
1,105
|
|
|
208
|
|
Cash and cash equivalents at beginning of period
|
51,773
|
|
|
50,076
|
|
|
92,513
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
40,371
|
|
|
51,773
|
|
|
50,076
|
|
Less: cash and cash equivalents of discontinued operations at end of period
|
—
|
|
|
10,569
|
|
|
1,105
|
|
Cash and cash equivalents of continuing operations at end of period
|
$
|
40,371
|
|
|
$
|
41,204
|
|
|
$
|
48,971
|
|
|
|
|
|
|
|
Supplemental cash flow information:
|
|
|
|
|
|
Cash paid during the period for interest
|
$
|
84,380
|
|
|
$
|
85,738
|
|
|
$
|
75,833
|
|
Non-cash investing activities:
|
|
|
|
|
|
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities
|
$
|
—
|
|
|
$
|
4,304
|
|
|
$
|
—
|
|
Units issued for acquisition of aggregates business
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
31,604
|
|
The accompanying notes are an integral part of these consolidated financial statements.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning, operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates and other natural resources and is organized into three operating segments further described in
Note 4. 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, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson is entitled to nominate all ten of the directors to the board of directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, LLC, an affiliate of Christopher Cline.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with International Paper Company controlled by the Partnership. The Partnership has an equity investment 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 which is accounted for using the equity method. Intercompany transactions and balances have been eliminated.
Management’s Going Concern Analysis
While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics have been impacted by challenges in coal and other commodity markets. The following going concern analysis includes discussion of the relevant conditions and events and an evaluation of NRP's ability to meet its obligations and remain in compliance with its debt covenants within one year after the issuance date of these financial statements.
In order to mitigate the effect of these adverse market developments on the Partnership's ability to remain in compliance with the covenants under its debt agreements and meet scheduled debt principal payments, the Partnership pursued or considered a number of actions. On a cumulative basis since January 1, 2015, the Partnership reduced debt by
$339.1 million
and completed asset sales for
$199 million
in gross sales proceeds. In addition, the Partnership completed the following series of recapitalization transactions on March 2, 2017 (see
Note 19. Subsequent Events
for further detail):
|
|
•
|
the issuance of
$250 million
of a new class of
12.0%
preferred units representing limited partner interests in NRP, together with warrants to purchase common units, to certain entities controlled by funds affiliated with The Blackstone Group, L.P. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree");
|
|
|
•
|
the exchange of
$241 million
of our
9.125%
Senior Notes due 2018 (the "2018 Notes") for
$241 million
of a new series of
10.500%
Senior Notes due 2022 (the "2022 Notes"), and the sale of
$105 million
of additional 2022 Notes in exchange for cash proceeds; and
|
|
|
•
|
the extension of Opco’s revolving credit facility (the "Opco Credit Facility") to April 2020, with commitments thereunder reduced to
$180 million
.
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
These recapitalization transactions increased the Partnership's liquidity and reduced the Partnership's 2018 debt maturities by
$575 million
through the extension of debt principal payments from 2018 to 2020 and 2022. While the Partnership continues to face challenges in coal and other commodity markets, it expects that it will meet all of its obligations, including scheduled principal and interest payments on its debt and required distributions on the convertible preferred units, that it will remain in compliance with its debt covenants and that it will continue as a going concern.
Recasting of Certain Prior Period Information
As described in
Note 3. Discontinued Operations
, the Partnership has classified the assets and liabilities, operating results and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated financial statements for all periods presented. As described in
Note 4. Segment Information
, the Partnership has reclassified oil and gas royalty activities in prior period amounts to conform to the way it internally manages and monitors segment performance that had no impact on the Partnership's consolidated financial position, net income (loss) or cash flows.
On January 1, 2016, the Partnership adopted a new accounting standard using a retrospective approach that required the presentation of the Partnership's debt issuance costs as a direct deduction from the related debt liability, rather than recorded as an asset. The adoption resulted in a reclassification that reduced other current assets and short-term debt by
$0.2 million
and reduced other assets and long-term debt (including affiliate) by
$13.8 million
on the Partnership’s Consolidated Balance Sheet at December 31, 2015.
Reverse Unit Split
On January 26, 2016, the board of directors of our general partner approved a 1-for-10 reverse split on our common units, effective following market close on February 17, 2016. Pursuant to the authorization provided, the Partnership completed the 1-for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange on February 18, 2016. As a result of the reverse unit split, every
10
outstanding common units were combined into one common unit. The reverse unit split reduced the number of common units outstanding from
122.3 million
units to approximately
12.2 million
units. All units and per unit data included in the December 31, 2015 consolidated financial statements were retroactively restated to reflect the reverse unit split.
Use of Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income during the reporting period. Actual results could differ from those estimates.
Business Combinations
For purchase acquisitions accounted for as business combinations, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques.
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."
There are three levels of inputs that may be used to measure fair value:
|
|
•
|
Level 1—Quoted prices in active markets for identical assets or liabilities.
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
|
•
|
Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
|
|
|
•
|
Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments 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.
Accounts Receivable
Accounts receivable from the Partnership’s lessees and customers do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying Consolidated Balance Sheets. The Partnership evaluates the collectability of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its accounts receivable and when it becomes aware of a specific lessee’s or customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s or customer’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. The reserve is recognized as a reduction in the accounts receivable and an increase in operating and maintenance expenses or operating and maintenance expenses—affiliates. Accounts are charged off when collection efforts are complete and future recovery is doubtful. The allowance for doubtful accounts included in the Partnership's net accounts receivable balance (including affiliates) was
$4.6 million
and
$5.3 million
at
December 31, 2016
and
December 31, 2015
, respectively. A significant amount of the Partnership's allowance for doubtful accounts relates to allowances for doubtful coal-related receivables.
Inventory
Inventories are stated at the lower of cost or market. The cost of aggregates and asphalt components such as stone, sand, and recycled and liquid asphalt is determined by the first-in, first-out (FIFO) method. Cost includes all direct materials, direct labor and related production overheads based on normal operating capacity. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Partnership’s aggregates operations.
Plant and Equipment
Plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the asset acquired and consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at cost and are depreciated on a straight-line basis over their useful lives generally as follows:
|
|
|
|
Years
|
Buildings and improvements
|
20 to 40
|
Machinery and equipment
|
5 to 12
|
Leasehold improvements
|
Life of Lease
|
The Partnership begins capitalizing mine development costs at its aggregates operations at a point when reserves are determined to be proven or probable, economically mineable and when demand supports investment in the market. Capitalization of these costs ceases when production commences. Mine development costs are amortized based on production over the estimated life of mineral reserves and amortization is included as a component of depreciation expense.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.
Intangible Assets
The Partnership’s intangible assets consist primarily of contracts that at acquisition were more favorable for the Partnership than prevailing market rates, known as above-market contracts. The estimated fair values of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis except that a minimum amortization is calculated on a straight-line basis for temporarily idled assets.
Asset Impairment
The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These procedures are performed throughout the year and are based on historic, current and future performance and are designed to be early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. The Partnership believes its estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property.
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 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.
Revenue Recognition
Coal Royalty and Other Revenues.
Coal royalty and other revenues are recognized on the basis of tons of mineral sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons of material processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, the Partnership receives a fixed price per ton for all material transported on the beltlines.
Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as deferred revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments.
Oil and gas related revenues consist of revenues from royalties and overriding royalties. Oil and gas royalty revenues are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Also, included within oil and gas royalties are lease bonus payments, which are generally paid upon the execution of a lease.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Equity in Earnings from Ciner Wyoming.
The Partnership accounts for non-marketable equity investments using the equity method of accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if the Partnership has an ownership interest representing between
20%
and
50%
of the voting stock of the investee. The Partnership accounts for its investment in Ciner Wyoming using this method.
Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets is hypothetically allocated first to identified tangible assets and liabilities, then to finite-lived intangibles or indefinite-lived intangibles and the balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived intangibles, if any, and goodwill are not amortized. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income.
Our carrying value in Ciner Wyoming is reflected in the caption "Equity in unconsolidated investments" in our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity in earnings of Ciner Wyoming." Our share of investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the proportionate share of the investee’s net assets, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets.
VantaCore Revenues.
Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to the estimated total costs for each contract. That method is used since the Partnership considers total cost to be the best available measure of progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred.
Property Taxes
The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in Coal Royalty and Other revenues and in Operating and maintenance expenses, respectively, in the Consolidated Statements of Comprehensive Income.
Transportation Revenue and Expense
The Company records transportation revenue and pays transportation costs to a Foresight affiliate to operate equipment on behalf of the Company. The revenue and expenses related to these transactions are recorded as Coal Royalty and Other—affiliates revenues and Operating and maintenance expenses—affiliates in the Consolidated Statements of Comprehensive Income. Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as VantaCore revenues and Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income. Shipping and handling revenue included in VantaCore revenues was
$36.0 million
,
$42.6 million
and
$14.0 million
for the years ended December 31, 2016, 2015 and 2014, respectively. Shipping and handling costs included in Operating and maintenance expenses was
$35.9 million
,
$42.1 million
and
$13.9 million
for the years ended December 31, 2016, 2015, and 2014, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Unit-Based Compensation
The Partnership has awarded unit-based compensation in the form of phantom units that are more fully described in Note 16. Unit-Based Compensation. A summary of our accounting policy for unit-based awards follows.
The Partnership accounts for awards relating to its unit-based Long-Term Incentive Plan using the fair value method, which requires the Partnership to estimate the fair value of the grant, and charge or credit the estimated fair value to expense over the requisite service period of the grant based on fluctuations in the Partnership’s common unit price. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability and the fair value is recalculated at each reporting date over the service or vesting period of the grant.
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These costs are amortized over the term of the debt. Deferred financing costs for existing debt agreements are included as a a direct deduction from the related debt liability on the Partnership's Consolidated Balance Sheets. Deferred financing costs that the Partnership has incurred related to its restructuring efforts are included in Other Assets on the Partnership's Consolidated Balance Sheets until the related debt agreement has been executed.
Income Taxes
The Partnership is not subject to federal or material state income taxes, as the partners are taxed individually on their allocable share of taxable income. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.
Lessee Audits and Inspections
The Partnership periodically audits lessee information by examining certain records and internal reports of its lessees. The Partnership’s regional managers also perform periodic mine inspections to verify that the information that has been reported to the Partnership is accurate. The audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to the Partnership and the actual results from each property. Audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the revenue was initially recorded. Typically there are no material adjustments from this process.
Recently Issued Accounting Standards
The Financial Accounting Standards Board ("FASB") issued guidance that requires an entity's management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The Partnership adopted this guidance on December 31, 2016. For additional information, see Management’s Going Concern Analysis located in this footnote above.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The FASB issued authoritative guidance on revenue recognition. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance will also require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. The Partnership is required to adopt this guidance in the first quarter of 2018 using one of two retrospective application methods. The Partnership has performed revenue scoping procedures to identify the contracts for all of its revenue streams and utilized the practical expedient of grouping contracts or performance obligations with similar characteristics as prescribed by the new standard. The Partnership is currently evaluating these contracts and while the effect of adoption is unknown, it is not currently aware of any material changes that would result from adoption of this new revenue recognition guidance and expects to complete its assessment of how it will be affected in the second quarter of 2016. The Partnership anticipates utilizing the full retrospective adoption method for financial statement comparability and electing the practical expedient of not restating contracts that begin and are completed within the same annual reporting period.
The FASB issued authoritative guidance which intended to simplify the measurement of inventory. This guidance requires an entity to measure inventory at the lower of cost or net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This guidance is effective for annual and interim periods beginning after December 15, 2016. The Partnership does not expect for the adoption of this guidance to have a material impact on its consolidated financial statements.
The FASB issued authoritative lease guidance that requires lessees to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The guidance also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The guidance is effective for annual and interim periods ending after December 31, 2018. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.
The FASB issued authoritative guidance that replaces the incurred loss impairment methodology in the current standard with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The guidance is effective for annual and interim periods ending after December 31, 2019. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.
The FASB issued authoritative guidance to clarify how certain cash receipts and cash payments are presented and classified in the statement of cash flows in order to reduce current and potential future diversity in practice. The guidance is effective for annual and interim periods ending after December 31, 2017. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.
3. Discontinued Operations
In June 2016, NRP Oil and Gas signed a definitive agreement to sell its non-operated oil and gas working interest assets assets for
$116.1 million
in gross sales proceeds, and the Partnership determined it met the criteria required for held for sale classification. In July 2016, NRP Oil and Gas closed this transaction, which had an effective date of April 1, 2016.
The Partnership's exit from its non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on its construction aggregates, soda ash and coal royalty and other business segments. As a result, the Partnership classified the operating results, cash flows and assets and liabilities of its non-operated oil and gas working interest assets as discontinued operations in its consolidated statements of comprehensive income and consolidated statements of cash flows for all periods presented. The Partnership transitioned the remaining investments in royalty interests in oil and natural gas properties into the Coal Royalty and Other operating segment during the third quarter of 2016.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table (in thousands) presents summarized financial results of the Partnership's discontinued operations in the Consolidated Statements of Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Revenues and other income:
|
|
|
|
|
|
Oil and gas
|
$
|
16,486
|
|
|
$
|
48,750
|
|
|
$
|
48,834
|
|
Gain on asset sales
|
8,274
|
|
|
451
|
|
|
—
|
|
Total revenues and other income
|
24,760
|
|
|
49,201
|
|
|
48,834
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
Operating and maintenance expenses (including affiliates)
|
11,503
|
|
|
19,724
|
|
|
18,073
|
|
Depreciation, depletion and amortization
|
7,527
|
|
|
39,912
|
|
|
17,982
|
|
Asset impairments
|
564
|
|
|
297,049
|
|
|
—
|
|
Total operating expenses
|
19,594
|
|
|
356,685
|
|
|
36,055
|
|
|
|
|
|
|
|
Interest expense
|
(3,488
|
)
|
|
(4,065
|
)
|
|
(662
|
)
|
Income (loss) from discontinued operations
|
$
|
1,678
|
|
|
$
|
(311,549
|
)
|
|
$
|
12,117
|
|
The following table (in thousands) presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations in the Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
10,569
|
|
Accounts receivable, net (including affiliates) (1)
|
991
|
|
|
7,053
|
|
Other
|
—
|
|
|
222
|
|
Total current assets
|
991
|
|
|
17,844
|
|
Mineral rights, net
|
—
|
|
|
109,505
|
|
Other non-current assets
|
—
|
|
|
657
|
|
Total assets of discontinued operations
|
$
|
991
|
|
|
$
|
128,006
|
|
|
|
|
|
LIABILITIES
|
|
|
|
Current liabilities:
|
|
|
|
Other (including affiliates) (1)
|
$
|
353
|
|
|
$
|
4,388
|
|
Total current liabilities
|
353
|
|
|
4,388
|
|
Long-term debt, net (2)
|
—
|
|
|
83,600
|
|
Other non-current liabilities
|
—
|
|
|
1,637
|
|
Total liabilities of discontinued operations
|
$
|
353
|
|
|
$
|
89,625
|
|
|
|
(2)
|
The Partnership identified the RBL Facility as specifically attributed to its non-operated oil and gas working interest assets and included the interest from this debt in discontinued operations. See
Note 11. Debt and Debt—Affiliate
for additional information on the Partnership's debt related to discontinued operations.
|
The following table (in thousands) presents supplemental cash flow information of the Partnership's discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Cash paid for interest
|
$
|
1,906
|
|
|
$
|
2,755
|
|
|
$
|
322
|
|
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities
|
—
|
|
|
1,645
|
|
|
11,879
|
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Capital expenditures related to the Partnership's discontinued operations were
$1.4 million
,
$30.6 million
and
$359.9 million
during the years months ended December 31, 2016, 2015 and 2014, respectively.
4. Segment Information
The Partnership's segments are strategic business units that offer products and services to different customer segments in different geographies within the U.S. and that are managed accordingly. NRP has the following
three
operating segments:
Coal Royalty and Other
—consists primarily of coal royalty and coal related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. The Partnership's coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. The Partnership's aggregates and industrial minerals are located in a number of states across the United States. The Partnership's oil and gas royalty assets are located in Louisiana.
Soda Ash
—consists of the Partnership's
49%
non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, the Partnership's operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. The Partnership receives regular quarterly distributions from this business.
VantaCore
—consists of the Partnership's construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore
operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
Direct segment costs and certain costs incurred at a corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments. These allocated costs include costs of: taxes, legal, information technology and shared facilities services and are included in Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. Intersegment sales are at prices that approximate market.
Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other corporate-level activity not specifically allocated to a segment.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Segments
|
|
|
|
For the Year Ended
|
|
Coal Royalty and Other
|
|
Soda Ash
|
|
VantaCore
|
|
Corporate and Financing
|
|
Total
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
Revenues (including affiliates)
|
|
$
|
210,115
|
|
|
$
|
40,061
|
|
|
$
|
120,802
|
|
|
$
|
—
|
|
|
$
|
370,978
|
|
Intersegment revenues (expenses)
|
|
150
|
|
|
—
|
|
|
(150
|
)
|
|
—
|
|
|
—
|
|
Gain on asset sales
|
|
29,068
|
|
|
—
|
|
|
13
|
|
|
—
|
|
|
29,081
|
|
Operating and maintenance expenses
(including affiliates)
|
|
29,890
|
|
|
—
|
|
|
100,656
|
|
|
—
|
|
|
130,546
|
|
General and administrative (including affiliates)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,570
|
|
|
20,570
|
|
Depreciation, depletion and amortization
(including affiliates)
|
|
31,766
|
|
|
—
|
|
|
14,506
|
|
|
—
|
|
|
46,272
|
|
Asset impairment
|
|
15,861
|
|
|
—
|
|
|
1,065
|
|
|
—
|
|
|
16,926
|
|
Other expense, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
90,531
|
|
|
90,531
|
|
Net income (loss) from continuing operations
|
|
161,816
|
|
|
40,061
|
|
|
4,438
|
|
|
(111,101
|
)
|
|
95,214
|
|
Net income from discontinued operations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,678
|
|
Capital expenditures
|
|
5
|
|
|
—
|
|
|
5,380
|
|
|
—
|
|
|
5,385
|
|
Total assets of continuing operations at December 31, 2016
|
|
990,172
|
|
|
255,901
|
|
|
190,615
|
|
|
7,002
|
|
|
1,443,690
|
|
Total assets of discontinued operations at December 31, 2016
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
991
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Revenues (including affiliates)
|
|
$
|
243,781
|
|
|
$
|
49,918
|
|
|
$
|
139,049
|
|
|
$
|
—
|
|
|
$
|
432,748
|
|
Intersegment revenues (expenses)
|
|
21
|
|
|
—
|
|
|
(21
|
)
|
|
—
|
|
|
—
|
|
Gain (loss) on asset sales
|
|
6,936
|
|
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
6,900
|
|
Operating and maintenance expenses
(including affiliates)
|
|
35,321
|
|
|
—
|
|
|
116,945
|
|
|
—
|
|
|
152,266
|
|
General and administrative (including affiliates)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,348
|
|
|
12,348
|
|
Depreciation, depletion and amortization
(including affiliates)
|
|
45,338
|
|
|
—
|
|
|
15,578
|
|
|
—
|
|
|
60,916
|
|
Asset impairment
|
|
378,327
|
|
|
—
|
|
|
6,218
|
|
|
—
|
|
|
384,545
|
|
Other expense, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
89,744
|
|
|
89,744
|
|
Net income (loss) from continuing operations
|
|
(208,248
|
)
|
|
49,918
|
|
|
251
|
|
|
(102,092
|
)
|
|
(260,171
|
)
|
Net loss from discontinued operations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(311,549
|
)
|
Capital expenditures
|
|
428
|
|
|
—
|
|
|
14,039
|
|
|
—
|
|
|
14,467
|
|
Total assets of continuing operations at December 31, 2015
|
|
1,078,778
|
|
|
261,942
|
|
|
200,348
|
|
|
961
|
|
|
1,542,029
|
|
Total assets of discontinued operations at December 31, 2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
128,006
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
Revenues (including affiliates)
|
|
$
|
266,085
|
|
|
$
|
41,416
|
|
|
$
|
42,031
|
|
|
$
|
—
|
|
|
$
|
349,532
|
|
Gain on asset sales
|
|
1,366
|
|
|
—
|
|
|
20
|
|
|
—
|
|
|
1,386
|
|
Operating and maintenance expenses
(including affiliates)
|
|
37,407
|
|
|
—
|
|
|
38,723
|
|
|
—
|
|
|
76,130
|
|
General and administrative (including affiliates)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,545
|
|
|
10,545
|
|
Depreciation, depletion and amortization
(including affiliates)
|
|
58,598
|
|
|
—
|
|
|
3,296
|
|
|
—
|
|
|
61,894
|
|
Asset impairment
|
|
26,209
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26,209
|
|
Other expense, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
79,427
|
|
|
79,427
|
|
Net income (loss) from continuing operations
|
|
145,237
|
|
|
41,416
|
|
|
32
|
|
|
(89,972
|
)
|
|
96,713
|
|
Net income from discontinued operations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,117
|
|
Capital expenditures
|
|
5,351
|
|
|
—
|
|
|
171,116
|
|
|
—
|
|
|
176,467
|
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
5. Acquisitions and Divestitures
Acquisitions
On October 1, 2014, the Partnership completed its acquisition of VantaCore for total consideration of
$200.6 million
in cash and common units. The Partnership funded this acquisition through the borrowing of
$169.0 million
under its Opco’s revolving credit facility and the issuance of
0.2 million
common units to certain of the sellers. Revenue and operating income from VanataCore included in the Consolidated Statements of Comprehensive Income were
$42.1 million
and
$0.1 million
, respectively, for the year ended December 31, 2014.
On November 12, 2014, the Partnership completed its acquisition of non-operated oil and gas working interests in the Sanish Field of the Williston Basin from an affiliate of Kaiser-Francis Oil Company for
$339.1 million
. These non-operated working interest assets were sold during 2016 as discussed in
Note 3. Discontinued Operations
. The Partnership funded this acquisition using the net proceeds from the issuance of additional
$125 million
principal amount of its
9.125%
Senior Notes due 2018, borrowing
$117.0 million
under an NRP Oil and Gas revolving credit facility and proceeds of
$100.4 million
from a public common unit offering. Revenue and operating income from these acquired oil and gas assets included in the Consolidated Statements of Comprehensive Income were
$12.8 million
and
$3.7 million
, respectively, for the year ended December 31, 2014.
These acquisitions were accounted for under the acquisition method of accounting for businesses. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The results of operations of all acquisitions have been included in the consolidated financial statements since the acquisition dates. The following unaudited pro forma financial information (in thousands) presents a summary of the Partnership’s consolidated revenues, net income and net income per common unit for the twelve months ended December 31, 2014 assuming the VantaCore and Sanish Field acquisitions had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired:
|
|
|
|
|
|
For the Year ended
December 31, 2014
|
Total revenues and other income
|
$
|
533,517
|
|
Net income
|
$
|
122,319
|
|
Basic and diluted net income per common unit
|
$
|
9.90
|
|
Divestitures
As discussed in
Note 2. Summary of Significant Accounting Policies
, the Partnership has been and is currently pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments which could otherwise cause the Partnership to breach financial covenants under its debt agreements, and mitigate the effects of scheduled debt principal payments that will strain the Partnership's liquidity. As part of this plan, the Partnership completed the sale of the following assets during the year ended December 31, 2016:
2)
Oil and gas royalty and overriding royalty interests in the Coal Royalty and Other segment in several producing properties located in the Appalachian Basin for
$36.4 million
gross sales proceeds. The effective date of the sale was January 1, 2016, and the Partnership recorded an
$18.6 million
gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
3)
Aggregate reserves and related royalty rights in the Coal Royalty and Other segment at
three
aggregates operations located in Texas, Georgia and Tennessee for
$10.0 million
gross sales proceeds. The effective date of the sale was February 1, 2016, and the Partnership recorded a
$1.5 million
gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
4)
In addition to the asset sales described above, during the year ended
December 31, 2016
, the Partnership sold mineral reserves within its Coal Royalty and Other segment in multiple sale transactions for cumulative
$17.3 million
of gross sales proceeds and recorded
$8.6 million
of cumulative gain from these sale transactions that are included in Gain on asset sales, net
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
on its Consolidated Statement of Comprehensive Income. These amounts primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas royalty interests.
Additional asset sales during the year included sales of land and plant and equipment within the Coal Royalty and Other segment for
$1.2 million
of gross proceeds and a
$0.3 million
of cumulative gain from these transactions that are included in Gain on asset sales, net on the Consolidated Statement of Comprehensive Income.
During the year ended December 31, 2015, the Partnership sold mineral reserves in multiple transactions for cumulative
$3.5 million
of gross sales proceeds and recorded a
$3.3 million
gain on asset sales included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income. The Partnership sold intangible assets for
$4.4 million
in gross proceeds and recorded a gain of
$3.1 million
included in Gain on asset sales, net in the Consolidated Statement of Comprehensive Income. The Partnership also sold plant and equipment
$6.7 million
of gross proceeds and recorded a gain of
$0.6 million
included in Gain on asset sales, net on the Consolidated Statement of Comprehensive Income.
During the year ended December 31, 2014, the Partnership sold land and mineral reserves for
$1.4 million
in gross sales proceeds and recorded a cumulative gain of
$1.4 million
on these asset sales included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
6. Equity Investment
The Partnership accounts for its
49%
investment in Ciner Wyoming using the equity method of accounting. Ciner Wyoming distributed
$46.6 million
,
$46.8 million
and
$46.6 million
to the Partnership in the year ended
December 31, 2016
,
2015
and
2014
, respectively.
The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was
$150.0 million
and
$154.8 million
as of
December 31, 2016
and
2015
, respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of
28 years
. The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method.
The Partnership's equity in the earnings of Ciner Wyoming is summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Income allocation to NRP’s equity interests
(1)
|
$
|
44,882
|
|
|
$
|
54,709
|
|
|
$
|
47,354
|
|
Amortization of basis difference
|
(4,821
|
)
|
|
(4,791
|
)
|
|
(5,938
|
)
|
Equity in earnings of unconsolidated investment
|
$
|
40,061
|
|
|
$
|
49,918
|
|
|
$
|
41,416
|
|
|
|
(1)
|
Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of
$0.9 million
,
$0.7 million
and
$0.5 million
for the year ended December 31, 2016, 2015 and 2014, respectively.
|
The results of Ciner Wyoming’s operations are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Sales
|
$
|
475,187
|
|
|
$
|
486,393
|
|
|
$
|
465,032
|
|
Gross profit
|
114,232
|
|
|
131,493
|
|
|
118,439
|
|
Net Income
|
91,596
|
|
|
111,650
|
|
|
96,640
|
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The financial position of Ciner Wyoming is summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
Current assets
|
$
|
134,616
|
|
|
$
|
144,695
|
|
Noncurrent assets
|
235,427
|
|
|
233,845
|
|
Current liabilities
|
55,396
|
|
|
43,018
|
|
Noncurrent liabilities
|
98,425
|
|
|
116,808
|
|
The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming required the Partnership to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement were met by Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014, 2015 and 2016, the Partnership paid contingent consideration of
$0.5 million
,
$3.8 million
and
$7.2 million
, respectively, in contingent consideration to Anadarko for performance criteria met by Ciner Wyoming in 2013, 2014 and 2015, respectively. The Partnership has no further contingent consideration payments due to Anadarko under the purchase agreement.
7. Inventory
The components of inventories at
December 31, 2016
and
2015
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
Aggregates
|
$
|
6,037
|
|
|
$
|
7,056
|
|
Supplies and parts
|
856
|
|
|
779
|
|
Total inventory
|
$
|
6,893
|
|
|
$
|
7,835
|
|
8. Plant and Equipment
The Partnership’s plant and equipment consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
Plant and equipment at cost
|
$
|
79,171
|
|
|
$
|
92,049
|
|
Construction in process
|
557
|
|
|
646
|
|
Less accumulated depreciation
|
(30,285
|
)
|
|
(32,020
|
)
|
Total plant and equipment, net
|
$
|
49,443
|
|
|
$
|
60,675
|
|
Depreciation expense related to the Partnership's plant and equipment totaled
$12.4 million
,
$15.9 million
and
$7.6 million
for the year ended
December 31, 2016
,
2015
and
2014
, respectively.
Impairment expense related to the Partnership's plant and equipment totaled
$3.1 million
,
$7.7 million
, and
$0.8 million
and are included in Asset impairments in the Consolidated Statements of Comprehensive Income for the year ending December 31, 2016, 2015 and December 31, 2014, respectively. During 2016, the Partnership recorded a
$2.0 million
impairment expense in its Coal Royalty and Other segment primarily related to a coal preparation plant and a
$1.1 million
impairment expense in its VantaCore segment primarily related to equipment write-downs. During the second quarter of 2015 the Partnership recorded a
$2.3 million
impairment expense related to a coal preparation plant and during the fourth quarter of 2015 the Partnership recorded a
$4.7 million
impairment expense related to coal processing and transportation assets and obsolete equipment. During 2015, the Partnership also recorded a
$0.7 million
impairment expense related to obsolete plant and equipment at VantaCore.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9. Mineral Rights
The Partnership’s mineral rights consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2016
|
|
Carrying Value
|
|
Accumulated Depletion
|
|
Net Book Value
|
Coal properties
|
$
|
1,170,904
|
|
|
$
|
(420,032
|
)
|
|
$
|
750,872
|
|
Aggregates properties
|
176,774
|
|
|
(39,056
|
)
|
|
137,718
|
|
Oil and gas royalty properties
|
12,395
|
|
|
(6,289
|
)
|
|
6,106
|
|
Other
|
14,946
|
|
|
(1,450
|
)
|
|
13,496
|
|
Total
|
$
|
1,375,019
|
|
|
$
|
(466,827
|
)
|
|
$
|
908,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2015
|
|
Carrying Value
|
|
Accumulated Depletion
|
|
Net Book Value
|
Coal properties
|
$
|
1,169,718
|
|
|
$
|
(398,235
|
)
|
|
$
|
771,483
|
|
Aggregates properties
|
206,309
|
|
|
(35,752
|
)
|
|
170,557
|
|
Oil and gas royalty properties
|
38,885
|
|
|
(9,994
|
)
|
|
28,891
|
|
Other
|
14,947
|
|
|
(1,356
|
)
|
|
13,591
|
|
Total
|
$
|
1,429,859
|
|
|
$
|
(445,337
|
)
|
|
$
|
984,522
|
|
Depletion expense related to the Partnership’s mineral rights totaled
$29.8 million
,
$40.4 million
and
$50.6 million
for the year ended
December 31, 2016
,
2015
and
2014
, respectively.
Impairment of Mineral Rights
The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These procedures are performed throughout the year and consider both quantitative and qualitative information based on historic, current and future performance and are designed to identify impairment indicators. If an impairment indicator is identified, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is primarily determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. The Partnership believes its estimates of cash flows and discount rates are consistent with those of principal market participants. The inputs used by management for fair value measurements include significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement for these types of assets. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require that a separate impairment evaluation be completed on a significant property.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the years ended
December 31, 2016
,
2015
and
2014
, 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 as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
Impaired Asset Description
|
2016
|
|
2015
|
|
2014
|
Coal properties (1)
|
$
|
12,088
|
|
|
$
|
257,468
|
|
|
$
|
16,793
|
|
Oil and gas properties (2)
|
36
|
|
|
70,527
|
|
|
—
|
|
Aggregates royalty properties (3)
|
1,677
|
|
|
43,402
|
|
|
3,013
|
|
Total
|
$
|
13,801
|
|
|
$
|
371,397
|
|
|
$
|
19,806
|
|
|
|
(1)
|
The Partnership recorded
$12.1 million
of coal property impairments during the year ended
December 31, 2016
, primarily as a result of lease surrender and termination. The Partnership recorded
$3.8 million
of coal property impairment during the three months ended September 30, 2016 and the fair value of the impaired asset recorded at fair value was
$4.0 million
at September 30, 2016. The Partnership recorded
$8.2 million
of coal property impairment during the three months ended December 31, 2016 and the fair value of the impaired asset recorded at fair value was
$0.0 million
at December 31, 2016.
|
Total coal property impairment expense for the year ended December 31, 2015 was
$257.5 million
. The Partnership recorded
$1.5 million
of coal property impairment during the three months ended June 30, 2015 and the fair value measurement of these impaired assets recorded at fair value was
$0.0 million
at June 30, 2015. The Partnership recorded
$247.8 million
of coal property impairment during the three months ended September 30, 2015 and the fair value of these impaired assets recorded at fair value was
$28.4 million
at September 30, 2015. The Partnership recorded the remaining
$8.2 million
of coal property impairment during the three months ended December 31, 2015 and the fair value of these impaired assets recorded at fair value was
$0.4 million
at December 31, 2015. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows.
Total coal property impairment expense for the year ended December 31, 2014 was
$16.8 million
. This expense was recorded during the fourth quarter of 2014 when management concluded certain unleased properties were impaired due primarily to the ongoing regulatory environment and continued depressed coal markets with little indications of improvement in the near term. The fair values for those unleased properties were determined for the associated reserves using Level 2 market approaches based upon recent comparable sales and Level 3 expected cash flows.
|
|
(2)
|
The Partnership recorded
$36 thousand
of oil and gas royalty asset impairment during the year ended
December 31, 2016
. Total oil and gas royalty asset impairment expense for the year ended December 31, 2015 was
$70.5 million
. The Partnership recorded this impairment during the three months ended September 30, 2015. The fair value measurement of these impaired assets recorded at fair value were
$13.0 million
at September 30, 2015. This impairment primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on its acreage. NRP compared net capitalized costs of its oil and gas royalty properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials.
|
|
|
(3)
|
The Partnership recorded
$1.7 million
of aggregates royalty property impairments during the year ended
December 31, 2016
. Total aggregates property impairment expense for the year ended December 31, 2015 was
$43.4 million
.This impairment was recorded during the three months ended September 30, 2015. The fair value measurement of these impaired assets recorded at fair value was
$13.1 million
at September 30, 2015. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. Total aggregates property impairment expense for the year ended December 31, 2014 was
$3.0 million
.
10. Goodwill and Intangible Assets (Including Affiliate)
The Partnership's intangible assets—affiliate relate to above market coal transportation contracts with subsidiaries of Foresight Energy LP ("Foresight Energy") in which the Partnership receives throughput fees for the handling and transportation of coal as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
Intangible assets—affiliate
|
$
|
81,109
|
|
|
$
|
81,109
|
|
Less accumulated amortization—affiliate
|
(31,298
|
)
|
|
(28,112
|
)
|
Total intangible assets, net—affiliate
|
$
|
49,811
|
|
|
$
|
52,997
|
|
Amortization expense related to the Partnership's intangible assets—affiliate totaled
$3.2 million
,
$3.6 million
and
$3.3 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
The Partnership's intangible assets consist of permits, aggregate-related trade names and other agreements as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
Intangible assets
|
$
|
5,227
|
|
|
$
|
5,076
|
|
Less accumulated amortization
|
(1,991
|
)
|
|
(1,146
|
)
|
Total intangible assets, net
|
$
|
3,236
|
|
|
$
|
3,930
|
|
Amortization expense related to the Partnership's intangible assets totaled
$0.8 million
,
$1.0 million
and
$0.3 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
During the second quarter of 2014, the Partnership and a lessee amended an aggregates lease in its Coal Royalty and Other segment, which led the Partnership to conclude an impairment triggering event had occurred. Fair value of the lease agreement was determined using Level 3 expected cash flows. The resulting impairment expense of
$5.6 million
is included in Asset impairments on the Consolidated Statements of Comprehensive Income.
The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods.
|
|
|
|
|
|
For the Year Ended December 31,
|
|
Estimated Amortization Expense
|
|
|
(in thousands)
|
2017
|
|
$
|
3,559
|
|
2018
|
|
3,289
|
|
2019
|
|
3,275
|
|
2020
|
|
3,280
|
|
2021
|
|
3,280
|
|
The weighted average remaining amortization period for contract intangibles and other intangibles was
28 years
and
16 years
, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the fourth quarter of 2014,
$52.0 million
of goodwill was added relating to the VantaCore acquisition. This amount represented the preliminary residual value. During 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for VantaCore’s property, plant and equipment, right to mine assets and asset retirement obligations that existed as of the acquisition date. These adjustments decreased goodwill by
$46.5 million
and resulted in an acquisition date goodwill of
$5.5 million
.
During the fourth quarter of 2015, the Partnership evaluated goodwill for impairment and compared the estimated fair value of the VantaCore reporting unit to its carrying amount. The carrying amount exceeded fair value and the Partnership recorded a
$5.5 million
goodwill impairment expense include in Asset impairments on the Partnership's Consolidated Statements of Comprehensive Income. The lower fair value was primarily a result of the deterioration in certain regional markets in which VantaCore operates causing a decline in future performance levels compared to levels estimated during the purchase price allocation process. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. These estimates were based on current conditions and historical experience applied to develop projections of future operating performance.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
11. Debt and Debt—Affiliate
As of
December 31, 2016
and
2015
, Debt and debt—affiliate consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
NRP LP debt
(1)
:
|
|
|
|
9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5%
(2)
|
$
|
425,000
|
|
|
$
|
425,000
|
|
Opco debt
(1)
:
|
|
|
|
Revolving credit facility, due June 2018
(2)
|
210,000
|
|
|
290,000
|
|
Senior notes
|
|
|
|
4.91% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018
|
9,187
|
|
|
13,850
|
|
8.38% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019
|
64,029
|
|
|
85,714
|
|
5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020
|
30,633
|
|
|
38,462
|
|
5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023
|
18,825
|
|
|
21,600
|
|
4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023
|
52,204
|
|
|
60,000
|
|
5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024
|
119,524
|
|
|
135,000
|
|
8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024
|
36,272
|
|
|
40,909
|
|
5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026
|
134,035
|
|
|
148,077
|
|
5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026
|
38,262
|
|
|
42,308
|
|
5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021
|
961
|
|
|
1,153
|
|
NRP Oil and Gas debt:
|
|
|
|
Revolving credit facility
|
—
|
|
|
85,000
|
|
Total debt at face value
|
$
|
1,138,932
|
|
|
$
|
1,387,073
|
|
Net unamortized debt discount
|
(1,322
|
)
|
|
(2,077
|
)
|
Net unamortized debt issuance costs
(1)
|
(11,307
|
)
|
|
(14,040
|
)
|
Total debt, net
|
$
|
1,126,303
|
|
|
$
|
1,370,956
|
|
Less: current portion of long-term debt
|
138,903
|
|
|
80,745
|
|
Less: debt classified as non-current liabilities of discontinued operations
|
—
|
|
|
83,600
|
|
Total long-term debt
|
$
|
987,400
|
|
|
$
|
1,206,611
|
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NRP LP Debt
NRP 2018 Senior Notes
In September 2013, the Partnership, together with NRP Finance Corporation ("NRP Finance"), a wholly owned subsidiary of the Partnership, as co-issuer, issued
$300.0 million
of
9.125%
Senior Notes at an offering price of
99.007%
of par (the "NRP 2018 Senior Notes"). Net proceeds after expenses from the issuance of NRP 2018 Senior Notes were approximately
$289.0 million
. The NRP 2018 Senior Notes call for semi-annual interest payments on April 1 and October 1 of each year, and will mature on October 1, 2018. None of the Partnership's subsidiaries guarantee the NRP 2018 Senior Notes.
In October 2014, the Partnership, together with NRP Finance as co-issuer, issued an additional
$125.0 million
of the NRP 2018 Senior Notes at an offering price of
99.5%
of par. The additional issuance constituted the same series of securities as the existing NRP 2018 Senior Notes. Net proceeds of
$122.6 million
from the additional issuance of the NRP 2018 Senior Notes were used to fund a portion of the purchase price of NRP’s acquisition of non-operated working interests in oil and gas assets located in the Williston Basin in North Dakota.
The Partnership and NRP Finance have the option to redeem the NRP 2018 Senior Notes, in whole or in part, at any time on or after April 1, 2016, at fixed redemption prices specified in the indenture governing the NRP 2018 Senior Notes (the "2018 Indenture"). The 2018 Indenture contains covenants that, among other things, limit the ability of the Partnership and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the 2018 Indenture, the Partnership and certain of its subsidiaries generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as defined in the indenture) is at least
2.0
to
1.0
for the four preceding full fiscal quarters. The ability of the Partnership and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of the Partnership and certain of its subsidiaries that is senior to the Partnership's unsecured indebtedness exceeds certain thresholds.
Opco Debt
All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of
December 31, 2016
and 2015, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.
Opco Credit Facility
In June 2016, Opco entered into the first amendment (the "First Amendment") to its Amended and Restated Credit Agreement (the "Opco Credit Facility") that is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of the assets of Opco and its subsidiaries, as further described below. Under the First Amendment:
|
|
•
|
The maturity date of the Opco Credit Facility was extended from October 1, 2017 to June 30, 2018;
|
|
|
•
|
The maximum leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Opco Credit Facility) has been amended to remain at
4.0
x for the remaining term of the Opco Credit Facility;
|
|
|
•
|
The asset sale covenant was amended to allow asset sales of up to
$300.0 million
from and after the effective date of the First Amendment; provided, however, that
75%
of the net cash proceeds of any such asset sales must be used to repay the Opco Credit Facility (without any corresponding commitment reduction) and/or NRP Opco’s Senior Notes described below.
|
On the effective date of the First Amendment, the total commitment under the Opco Credit Facility was reduced from
$300.0 million
to
$260.0 million
. In addition, Opco and the lenders agreed to further reduce commitments under the Opco Credit Facility to (a)
$210.0 million
on December 31, 2016, (b)
$180.0 million
on June 30, 2017 and (c)
$150.0 million
on December 31, 2017. Opco will have the right to delay any of these commitment reductions by up to
90 days
each upon the agreement of the lenders holding
66.7%
of the then-existing commitments. To the extent any such commitment reduction is extended under the terms of the A&R Revolving Credit Facility, Opco's ability to make distributions to the Partnership will be limited to amounts necessary for the Partnership to pay taxes and other general partnership expenses and make interest payments on its
9.125%
Senior Notes due 2018.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In addition to the 4.0x leverage ratio described above, the Opco Credit Facility requires Opco to maintain a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than
3.5
to 1.0. As of
December 31, 2016
, Opco's leverage ratio was
2.80
x, and fixed charge coverage ratio was
4.99
x.
Effective on the date of the First Amendment, 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%
.
|
The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for the years ended
December 31, 2016
and 2015 were
4.46%
and
2.91%
, respectively.
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 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. The Opco Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes (as described below).
The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of
$673.0 million
and
$709.9 million
classified as Land, Plant and equipment and Mineral rights on the Partnership’s Consolidated Balance Sheet as of
December 31, 2016
and 2015, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a
49%
non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of VantaCore’s construction aggregates mining operations, and (5) certain of Opco’s coal-related infrastructure assets.
Opco Senior Notes
Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of
December 31, 2016
and 2015, the Opco Senior Notes had cumulative principal balances of
$503.0 million
and
$585.9 million
, respectively. Opco made principal payments of
$82.9 million
on the Opco Senior Notes during the year ended
December 31, 2016
and
$80.8 million
for the years ended December 31, 2015 and 2014.
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.
|
The
8.38%
and
8.92%
Opco Senior Notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Note Purchase Agreements) exceeds
3.75
to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of
2.00%
per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above
3.75
to 1.00. Opco has not exceeded the
3.75
to 1.00 ratio at the end of any fiscal quarter through
December 31, 2016
. As of
December 31, 2016
, Opco's leverage ratio was
2.80
x, and fixed charge coverage ratio was
4.99
x.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepayment offers on the Opco Senior Notes as follows:
|
|
•
|
Until the earlier of the time that (1) Opco has sold
$300 million
of assets and (2) June 30, 2020, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using
25%
of the net cash proceeds from certain asset sales; and
|
|
|
•
|
After the earlier to occur of the dates above, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid.
|
The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes.
NRP Oil and Gas Debt Classified as Liabilities of Discontinued Operations
RBL Facility
In August 2013, NRP Oil and Gas entered into the RBL Facility, a senior secured, reserve-based revolving credit facility, in order to fund capital expenditure requirements related to the development of the oil and gas assets in which it owned non-operated working interests. The RBL Facility was secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas was the sole obligor under the RBL Facility, and neither the Partnership nor any of its other subsidiaries was a guarantor of the RBL Facility.
At December 31, 2015, there was
$85.0 million
respectively, outstanding under the RBL Facility. As described in
Note 3. Discontinued Operations
, the Partnership included this debt and its related interest expense in discontinued operations. In July 2016, NRP Oil and Gas LLC closed the sale of its non-operated oil and gas working interest assets and used a portion of the proceeds to repay the RBL Facility in full.
Consolidated Principal Payments
The consolidated principal payments due are set forth below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRP LP
|
|
|
|
Opco
|
|
|
Senior Notes
|
|
|
|
Senior Notes
(2)
|
|
Credit Facility
|
|
Total
|
2017
|
$
|
—
|
|
|
|
|
$
|
80,638
|
|
|
$
|
60,000
|
|
|
$
|
140,638
|
|
2018
|
425,000
|
|
|
(1)
|
|
80,638
|
|
|
150,000
|
|
|
655,638
|
|
2019
|
—
|
|
|
|
|
76,045
|
|
|
—
|
|
|
76,045
|
|
2020
|
—
|
|
|
|
|
54,704
|
|
|
—
|
|
|
54,704
|
|
2021
|
—
|
|
|
|
|
47,043
|
|
|
—
|
|
|
47,043
|
|
Thereafter
|
—
|
|
|
|
|
164,864
|
|
|
—
|
|
|
164,864
|
|
|
$
|
425,000
|
|
|
|
|
$
|
503,932
|
|
|
$
|
210,000
|
|
|
$
|
1,138,932
|
|
|
|
(1)
|
The
9.125%
senior notes due 2018 were issued at a discount and were carried at
$423.7 million
as of December 31, 2016.
|
|
|
(2)
|
Incudes
$1.0 million
utility local improvement obligation.
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
12. Fair Value Measurements
The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. The following table (in thousands) shows the carrying amount and estimated fair value of the Partnership's other financial instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
|
Carrying
Value
|
|
Estimated
Fair Value
|
|
Carrying
Value
|
|
Estimated
Fair Value
|
Debt and debt—affiliate:
|
|
|
|
|
|
|
|
NRP 2018 Senior Notes (1)
|
$
|
420,097
|
|
|
$
|
412,250
|
|
|
$
|
417,296
|
|
|
$
|
277,313
|
|
Opco Senior Notes and utility local improvement obligation (2)
|
500,174
|
|
|
488,814
|
|
|
584,890
|
|
|
383,065
|
|
Opco Revolving Credit Facility (3)
|
$
|
206,032
|
|
|
$
|
210,000
|
|
|
$
|
285,170
|
|
|
$
|
290,000
|
|
NRP Oil and Gas RBL Facility (3)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
83,600
|
|
|
$
|
85,000
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Contracts receivable—affiliate, current and long-term(2)
|
46,742
|
|
|
32,554
|
|
|
50,366
|
|
|
34,498
|
|
|
|
(1)
|
The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period end.
|
|
|
(2)
|
The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing trading prices near period end.
|
|
|
(3)
|
The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.
|
13. Related Party Transactions
Reimbursements to Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, provide their services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. In addition, the Partnership receives non-cash equity contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners' Capital and were
$0.3 million
and
$0.8 million
during the years ended
December 31, 2016
and
2015
, respectively. These QMC and WPPLP employee management service costs and non-cash equity compensation expenses are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income. NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain rent, legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by or on behalf of the Partnership’s general partner and its affiliates and are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income.
The Partnership had Accounts payable—affiliates to QMC of
$0.4 million
and
$1.1 million
, including less than
$0.1 million
and
$0.6 million
related to discontinued operations at
December 31, 2016
and
2015
, respectively, for services provided by QMC to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of
$0.6 million
and
$0.3 million
at
December 31, 2016
and
2015
, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Direct general and administrative expenses charged to the Partnership by WPPLP and QMC are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
December 31,
|
|
2016
|
|
2015
|
|
2014
|
Operating and maintenance expenses—affiliates, net
|
9,891
|
|
|
10,063
|
|
|
9,166
|
|
General and administrative—affiliates
|
3,591
|
|
|
5,312
|
|
|
3,258
|
|
Included in income (loss) from discontinued operations are
$1.3 million
,
$0.7 million
and
$0.6 million
of operating and maintenance expenses charged by QMC for the year ended December 30, 2016, 2015 and 2014, respectively.
Cline Affiliates
Various companies affiliated with Chris Cline, including Foresight Energy LP, lease coal reserves from the Partnership, and the Partnership also leases coal transportation assets to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a
31%
interest (unaudited) in the NRP's general partner, as well as approximately
0.5
million of NRP's common units (unaudited) at December 31, 2016.
Coal related revenues from Foresight Energy totaled
$63.4 million
,
$86.6 million
and
$81.5 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively. As of
December 31, 2016
and
2015
, the Partnership had Accounts receivable—affiliates from Foresight Energy of
$6.5 million
and
$6.4 million
, respectively. As of
December 31, 2016
and 2015, the Partnership had received
$71.6 million
and
$82.6 million
, respectively in minimum royalty payments to date that have been recorded as Deferred revenue—affiliates since they have not been recouped by Foresight Energy.
NRP owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy's Sugar Camp mine. The lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at
December 31, 2016
were
$76.4 million
with unearned income of
$31.8 million
, and the net amount receivable was
$44.6 million
, of which
$2.2 million
is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets. Minimum lease payments are
$5.0 million
per year for the next five years and represent a
$1.25 million
per quarter in deficiency payment. Total projected remaining payments under the lease at
December 31, 2015
were
$81.2 million
with unearned income of
$35.4 million
and the net amount receivable was
$45.9 million
, of which
$2.0 million
is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates on the accompanying Consolidated Balance Sheets.
NRP holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of
December 31, 2016
was
$2.7 million
, of which
$1.4 million
is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of
December 31, 2015
was
$4.9 million
, of which
$1.5 million
is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.
NRP owns rail load out transportation assets and subcontracts out the operating responsibilities to an affiliate of Foresight Energy at Foresight's Williamson mine. During the years ended December 31, 2016, 2015 and 2014, the Partnership recorded operating and maintenance expenses—affiliates of
$1.3 million
,
$1.4 million
and
$1.6 million
, respectively, to operate these assets.
During the years ended
December 31, 2016
,
2015
and
2014
, the Partnership recognized a gain of
$0.0 million
,
$9.3 million
and
$5.7 million
, respectively on a reserve swap at Foresight Energy's Williamson mine. The gain is included in Coal royalty and other—affiliates revenues on the Consolidated Statements of Comprehensive Income. The Level 3 fair value of the reserves was estimated using a discounted cash flow model. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Long-Term Debt—Affiliate
Donald R. Holcomb, one of the Partnership’s former directors, was a manager of Cline Trust Company, LLC (the "Cline Trust Company"). As of December 31, 2015, Cline Trust Company owned approximately
0.5 million
of the Partnership’s common units and
$20.0 million
in principal amount of the Partnership’s
9.125%
Senior Notes due 2018. As of December 31, 2015, the members of the Cline Trust Company were four trusts for the benefit of the children of Chris Cline, each of which owns an approximately equal membership interest in the Cline Trust Company. As of December 31, 2015, Mr. Holcomb also served as trustee of each of the four trusts. The balance on this portion of the Partnership’s
9.125%
Senior Notes due 2018 was
$19.9 million
as of December 31,
2015
and was included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet. In April 2016, Mr. Holcomb resigned from the Partnership's board of directors and as a result the
$19.9 million
debt balance held by Cline Trust Company was subsequently reclassified as Long-term debt, net on the Partnership's accompanying Consolidated Balance Sheet.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in the Partnership's conflicts policy.
At
December 31, 2016
, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp ("Corsa")., a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Coal related revenues from Corsa totaled
$2.2 million
,
$3.1 million
and
$3.0 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
As of
December 31, 2016
and 2015 the Partnership had recorded
$0.0 million
and
$0.3 million
, respectively in minimum royalty payments to date as Deferred revenue—affiliates since they have not been recouped by Corsa. The Partnership also had Accounts receivable—affiliates totaling
$0.2 million
and
$0.2 million
from Corsa at
December 31, 2016
and 2015, respectively.
WPPLP Production Royalty and Overriding Royalty
For the year ended
December 31, 2016
, the Partnership recorded
$0.7 million
in operating and maintenance expenses—affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007. These charges were
$0.4 million
and
zero
for the years ended December 31,
2015
and
2014
, respectively. The Partnership had Other assets—affiliate from WPPLP of
$1.0 million
and
$1.1 million
at
December 31, 2016
and December 31,
2015
, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.
14. 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 claims will not have a material effect on the Partnership’s financial position, liquidity or operations.
Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property had been closed, the property had been reclaimed, and the state reclamation bond had been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations. A subsidiary of the Partnership has been named as a defendant in one of these lawsuits. The Partnership currently cannot reasonably estimate a range of potential loss, if any, related to this matter.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Foresight Energy Disputes
In November 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled. In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. We believe the force majeure claim by Hillsboro has no merit and we are vigorously pursuing recovery against them. However, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency payments of
$7.5 million
per quarter, or
$30.0 million
per year. Foresight Energy's failure to make the deficiency payment with respect to 2015 and 2016 resulted in a cumulative
$46.0 million
negative cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected.
In April 2016, we filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its recoupable balance and failure to make payments in accordance with these lease agreements has resulted in a cumulative
$6.2 million
negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount has been recorded.
Environmental Compliance
The operations the Partnership’s lessees conduct on its properties, as well as the aggregates/industrial minerals and oil and gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. See "Item 1. Business—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 to have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31, 2016. The Partnership is not associated with any material environmental contamination that may require remediation costs. However, the Partnership’s lessees do 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 working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities, including environmental liabilities, arising from uninsured and underinsured events during the period it was an owner. The Partnership is also responsible for losses and liabilities, including environmental liabilities that may arise from uninsured and underinsured events at its VantaCore operations.
15. Major Customers
Revenues from customers that exceeded ten percent of total revenues and other income for any of the periods presented below are as follows (in thousands except for percentages):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
Revenues
|
|
Percent
|
|
Revenues
|
|
Percent
|
|
Revenues
|
|
Percent
|
Foresight Energy
|
|
$
|
63,355
|
|
|
15.8
|
%
|
|
$
|
86,614
|
|
|
19.7
|
%
|
|
$
|
81,546
|
|
|
23.2
|
%
|
Alpha Natural Resources
|
|
$
|
18,184
|
|
|
4.5
|
%
|
|
$
|
34,364
|
|
|
7.8
|
%
|
|
$
|
48,783
|
|
|
13.9
|
%
|
All of the revenue related to the customers above is included in revenues of the Coal Royalty and Other segment.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership had a significant concentration of revenues with Foresight Energy and Alpha Natural Resources. The exposure is currently spread out over a number of different mining operations and leases. During the year ended December 31, 2015, total revenues and other income from Alpha Natural Resources included a
$6.0 million
non-recurring lease assignment fee.
16. Unit-Based Compensation
GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the "Long-Term Incentive Plan") for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.
Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a unit of the Parent common units upon each vesting. The Partnership records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted quarterly for any changes in the Partnership’s unit price. Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the
20
trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.
In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.
A summary of activity in the outstanding grants during 2016 is as follows (in thousands):
|
|
|
|
|
Phantom Units
|
Outstanding grants at January 1, 2016
|
126
|
|
Grants during the period
|
—
|
|
Grants vested and paid during the period
|
(28
|
)
|
Forfeitures during the period
|
(12
|
)
|
Outstanding grants at December 31, 2016
|
86
|
|
Grants typically vest at the end of a
four
-year period and are paid in cash upon vesting. The Partnership recorded a credit to general and administrative expenses related to its Long-Term Incentive Plan of
$3.4 million
for the year ended December 31, 2015, due to the decline in the market price of the Partnership's common units during 2015. For the years ended December 31, 2016 and 2014 the Partnership recorded G&A expenses of
$1.4 million
and
$1.0 million
, respectively.
In connection with the Long-Term Incentive Plans, payments are typically made during the first quarter of the year. Payments of
$1.5 million
,
$4.4 million
and
$6.5 million
were made during the years ended December 31, 2016, 2015, and 2014, respectively. The grant date fair value was
$0.0 million
,
$4.2 million
and
$6.6 million
for awards in 2016, 2015 and 2014, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at December 31, 2016 and December 31, 2015, was
$0.8 million
and
$0.7 million
, respectively.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
17. Cash Distributions
The following table shows the distributions paid by the Partnership during the year ended December 31, 2016, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Distributions (In thousands)
|
Date Paid
|
|
Period Covered by Distribution
|
|
Distribution per Common Unit
|
|
Common Units
|
|
GP Interest
|
|
Total
|
2016
|
|
|
|
|
|
|
|
|
|
|
February 12, 2016
|
|
October 1 - December 31, 2015
|
|
$
|
0.45
|
|
|
$
|
5,503
|
|
|
$
|
113
|
|
|
$
|
5,616
|
|
May 13, 2016
|
|
January 1 - March 31, 2016
|
|
0.45
|
|
|
5,503
|
|
|
113
|
|
|
5,616
|
|
August 12, 2016
|
|
April 1 - June 30, 2016
|
|
0.45
|
|
|
5,505
|
|
|
112
|
|
|
5,617
|
|
November 14, 2016
|
|
July 1 - September 30, 2016
|
|
0.45
|
|
|
5,503
|
|
|
113
|
|
|
5,616
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
February 13, 2015
|
|
October 1 - December 31, 2014
|
|
$
|
3.50
|
|
|
$
|
42,804
|
|
|
$
|
874
|
|
|
$
|
43,678
|
|
May 14, 2015
|
|
January 1 - March 31, 2015
|
|
0.90
|
|
|
11,007
|
|
|
225
|
|
|
11,232
|
|
August 14, 2015
|
|
April 1 - June 30, 2015
|
|
0.90
|
|
|
11,009
|
|
|
223
|
|
|
11,232
|
|
November 13, 2015
|
|
July 1 - September 30, 2015
|
|
0.45
|
|
|
5,504
|
|
|
112
|
|
|
5,616
|
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
January 31, 2014
|
|
October 1 - December 31, 2013
|
|
$
|
3.50
|
|
|
$
|
38,433
|
|
|
$
|
785
|
|
|
$
|
39,218
|
|
May 14, 2014
|
|
January 1 - March 31, 2014
|
|
3.50
|
|
|
38,634
|
|
|
787
|
|
|
39,421
|
|
August 14, 2014
|
|
April 1 - June 30, 2014
|
|
3.50
|
|
|
38,938
|
|
|
795
|
|
|
39,733
|
|
November 14, 2014
|
|
July 1 - September 30, 2014
|
|
3.50
|
|
|
42,796
|
|
|
874
|
|
|
43,670
|
|
18. Deferred Revenue and Deferred Revenue—Affiliate
Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as a deferred revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments. The Partnership’s deferred revenue (including affiliate) consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
Deferred revenue
|
$
|
44,931
|
|
|
$
|
80,812
|
|
Deferred revenue—affiliate
|
71,632
|
|
|
82,853
|
|
Total deferred revenue (including affiliate)
|
$
|
116,563
|
|
|
$
|
163,665
|
|
The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums as Coal royalty and other revenue (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Coal royalty and other
|
$
|
49,284
|
|
|
$
|
3,451
|
|
|
$
|
6,659
|
|
Coal royalty and other—affiliates
|
15,307
|
|
|
12,038
|
|
|
—
|
|
Total coal royalty and other (including affiliates)
|
$
|
64,591
|
|
|
$
|
15,489
|
|
|
$
|
6,659
|
|
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances
During the year ended December 31, 2016, the Partnership entered into agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the Partnership recognizing
$40.5 million
of deferred revenue as follows:
•
An agreement that terminated a central Appalachia coal royalty lease and resulted in the lessee forfeiting the right to recoup
$26.2 million
of minimum royalties previously paid to the Partnership. The Partnership agreed to transfer its coal mineral rights that were subject to this former lease to the lessee. This terminated lease had no current or planned production and the mineral rights transferred had zero net book value on the Partnership's consolidated Balance Sheets as of March 31, 2016. As a result of this transaction, in April 2016 the Partnership recognized
$26.2 million
of revenue.
•
Lease modifications, terminations and forfeitures of existing coal royalty and other leases resulted in lessee forfeiture of rights to recoup previously paid minimum royalties and the reduction in lessee recoupment time. As a result of these modifications, in the first and second quarters of 2016 the Partnership recognized
$10.7 million
of revenue.
•
The Partnership recognized
$3.6 million
of revenue from various other coal and aggregates lease modifications, terminations and forfeitures during the year ended December 31, 2016.
During the years ended December 31, 2015 and 2014, there was less than
$0.1 million
and
$1.4 million
of revenue recognized from coal and aggregate lease modifications, terminations or forfeitures, respectively.
19. Subsequent Events
The following represents material events that have occurred subsequent to December 31, 2016 through the time of the Partnership’s filing of its Annual Report on Form 10-K with the SEC:
Distribution Declared
On February 14, 2017, the Partnership paid a distribution of
$0.45
per unit to unitholders of record on February 7, 2017.
Recapitalization Transactions
On March 2, 2017, the Partnership completed the following recapitalization transactions:
Issuance of Preferred Units and Warrants
NRP issued
$250 million
of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred Units") to Blackstone and GoldenTree (together the "Preferred Purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued
250,000
Preferred Units to the Preferred Purchasers at a price of
$1,000
per Preferred Unit (the "Per Unit Purchase Price"), less a
2.5%
structuring and origination fee. The Preferred Units entitle the Preferred Purchasers to receive cumulative dividends at a rate of
12%
per year, up to one half of which NRP may pay in additional Preferred Units (such additional Preferred Units, the "PIK Units"). NRP also issued two tranches of warrants (the "Warrants") to purchase common units to the Preferred Purchasers (Warrants to purchase
1.75 million
common units with a strike price of
$22.81
and Warrants to purchase
2.25 million
common units with a strike price of
$34.00
). The Warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the Warrants, NRP may, at its option, elect to settle the Warrants in common units or cash, each on a net basis.
The Preferred Units have a perpetual term, unless converted or redeemed as described below. The Preferred Units (including any PIK Units) are convertible into common units at the election of the holders (1) after the fifth anniversary and prior to the eighth anniversary of the issue date at a
7.5%
discount to the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to the notice of conversion if the 30-day VWAP immediately prior to such notice is greater than
$51.00
(subject to a maximum of
33%
of the Preferred Units per year) and (2) after the eighth anniversary of the issue date at a
10%
discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Instead of issuing common units pursuant to clause (1) of the preceding sentence, NRP has the option to redeem the Preferred Units proposed to be converted for cash at a price equal to the Per Unit Purchase Price, plus the value of any accrued and unpaid distributions. To the extent the holders of the Preferred Units have not elected to convert their Preferred Units by the twelfth anniversary of the issue date, NRP has the right to force conversion of the Preferred Units into common units at a
10%
discount to the VWAP for the 30
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
trading days immediately prior to the notice of conversion. In addition, NRP has the ability to redeem at any time (subject to compliance with our debt agreements) all or any portion of the Preferred Units (including PIK Units) for cash at the agreed upon per unit amount, which is calculated as the Per Unit Purchase Price multiplied by (i) prior to the third anniversary of the closing date,
1.50
, (ii) on or after the third anniversary of the closing date and prior to the fourth anniversary of the closing date,
1.70
and (iii) on or after the fourth anniversary of the closing date,
1.85
.
The terms of the Preferred Units contain certain restrictions on our ability to pay distributions on our common units. To the extent that either (i) our consolidated Leverage Ratio (as defined in the Restated Partnership Agreement) is greater than
3.25
x, or (ii) the ratio of our Distributable Cash Flow to cash distributions made or proposed to be made is less than
1.2
x (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, including:
|
|
•
|
the incurrence of new indebtedness, subject to certain exceptions;
|
|
|
•
|
material changes to NRP’s business;
|
|
|
•
|
acquisitions and divestitures in excess of certain dollar thresholds;
|
|
|
•
|
amendments to material contracts resulting in a cash impact to NRP in excess of certain dollar thresholds;
|
|
|
•
|
settlement of any litigation or regulatory matter resulting in cash payments by NRP in excess of certain thresholds; and
|
|
|
•
|
amendments to related party contracts outside of the ordinary course of business.
|
GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the Minimum Preferred Unit Threshold (as defined below). The Preferred Purchaser Approval Rights are not transferrable without NRP's consent. In addition, the Preferred Purchaser Approval Rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least
20%
of the total number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). To the extent any Preferred Units that have converted into common units are still held by the applicable Preferred Purchaser (or its affiliates), such common units will be deemed to represent a number of Preferred Units based on the weighted average number of common units issued in each conversion and will count towards the Minimum Preferred Unit Threshold.
The foregoing terms of the Preferred Units are reflected in our Fifth Amended and Restated Agreement of Limited Partnership, dated as of March 2, 2017, which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference. The terms of the Warrants are reflected in the Form of Warrant to Purchase Common Units filed as Exhibit 4.28 to this Annual Report on Form 10-K, which is incorporated herein by reference.
At the closing, pursuant to a Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights and appointed one director and one observer to the Board of Directors of GP Natural Resource Partners LLC. For more information on these rights, see "Certain Relationships and Related Transactions, and Director Independence—Board Representation and Observation Rights Agreement."
NRP also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with the Preferred Purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the Warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the Preferred Units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of Preferred Units (the "Registration Deadlines"). In addition, the Preferred Unit and Warrant Registration Rights Agreement gives the Preferred Purchasers piggyback registration and demand underwritten offering rights under certain circumstances. If the shelf registration statements are not effective by the
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
applicable Registration Deadline, NRP will be required to pay the Preferred Purchasers liquidated damages in the amounts and upon the term set forth in the Preferred Unit and Warrant Registration Rights Agreement.
Opco Credit Facility Amendment
NRP entered into the Second Amendment to Opco’s Third Amended and Restated Credit Agreement to extend the term thereof until April 2020, and reduced the commitments of the lenders to
$180 million
(from
$210 million
) effective at the closing of the recapitalization transactions. Pursuant the Second Amendment, commitments under the Opco Credit Facility will be reduced to
$150 million
at December 31, 2017 and further reduced to
$100 million
at December 31, 2018 through maturity in April 2020. The amendment does not change the pricing grid or financial covenants under the Opco Credit Facility; provided, however, that if NRP increases its quarterly distribution to its common unitholders above
$0.45
per common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from
4.0
x to
3.0
x. Other terms of the Second Amendment include revisions to the mandatory prepayment provisions with respect to net cash proceeds received from certain asset sales and additional limitations on the ability of Opco and its subsidiaries to make certain investments. The Second Amendment is filed as Exhibit 10.14 to this Annual Report on Form 10-K and is incorporated herein by reference.
Issuance of 2022 Notes; Exchange and Redemption of 2018 Notes
NRP and NRP Finance issued
$346 million
aggregate principal amount of
10.500%
Senior Notes due 2022 to several holders of its 2018 Notes. Of the
$346 million
of 2022 Notes issued,
$241 million
in aggregate principal amount were issued in exchange for
$241 million
in aggregate principal amount of 2018 Notes, and
$105 million
of the 2022 Notes were issued to the holders in exchange for cash. The 2022 Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 Indenture"), bear interest at
10.500%
per year, are payable semi-annually on March 15 and September 15, beginning September 15, 2017, and mature on March 15, 2022.
NRP and NRP Finance have the option to redeem the 2022 Notes, in whole or in part, at any time on or after March 15, 2019, at the redemption prices (expressed as percentages of principal amount) of
105.25%
for the 12-month period beginning March 15, 2019,
102.625%
for the 12-month period beginning March 15, 2020, and thereafter at
100.000%
, together, in each case, with any accrued and unpaid interest to the date of redemption. Furthermore, before March 15, 2019, NRP may on any one or more occasions redeem up to
35%
of the aggregate principal amount of the 2022 Notes with the net proceeds of certain public or private equity offerings at a redemption price of
110.500%
of the principal amount of 2022 Notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least
65%
of the aggregate principal amount of the 2022 Notes issued under the 2022 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the 2022 Indenture, the holders of the 2022 Notes may require us to purchase their 2022 Notes at a purchase price equal to
101%
of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any. The 2022 Notes purchased for cash were issued at a price of
98.75%
(original issue discount of
1.25%
), and each holder exchanging 2018 Notes received a fee of
5.813%
of the aggregate principal amount of all 2018 Notes tendered for exchange by such holder, as well as all accrued and unpaid interest thereon.
The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing the 2018 Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under the debt incurrence covenant, NRP's non-guarantor restricted subsidiaries will not be permitted to incur additional indebtedness unless their consolidated leverage ratio is less than
3.00
x (measured on a pro forma basis and assuming that the greater of (i)
$150.0 million
of debt (or, if less, at NRP's election, the amount of total lending commitments under any revolving credit facility) and (ii) the actual amount of debt outstanding is outstanding under any revolving credit facility); provided, however, that such non-guarantor restricted subsidiaries will be permitted to make up to
$150 million
in borrowings under a revolving credit facility (which amount will be reduced on a dollar-for-dollar basis to the extent we have made the election described in clause (i) above). Under the restricted payments covenant, NRP will not be able to increase the quarterly distribution on its common units or elect to pay more than
50%
of the distributions required to be made on the Preferred Units in the form of cash, unless, in each case, our consolidated leverage ratio is less than
4.00
x. The 2022 Indenture also contains restrictions on NRP's ability to redeem the Preferred Units.
The 2022 Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance, including the remaining outstanding 2018 Notes, and senior in right of payment to any of NRP's subordinated debt. The 2022 Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiaries guarantee the 2022 Notes.
The terms of the 2022 Notes are more fully described in the 2022 Indenture, which is filed as Exhibit 4.24 to this Annual Report on Form 10-K and incorporated herein by reference.
NRP entered into a registration rights agreement (the "Notes Registration Rights Agreement") with the holders of the 2022 Notes, pursuant to which we and NRP Finance agreed to file a registration statement with the Securities and Exchange Commission for the benefit of the holders of the 2022 Notes so that such holders can exchange the 2022 Notes for exchange securities that have substantially identical terms as the 2022 Notes. NRP and NRP Finance agreed to use commercially reasonable efforts to cause the exchange to be completed within 180 days after the closing and will be required to pay additional interest, as specified in the Notes Registration Rights Agreement, if NRP fails to comply with its obligations to register the 2022 Notes within the specified time periods.
NRP expects to redeem
$90 million
in aggregate principal amount of the 2018 Notes at a redemption price of 104.563%, and pay all accrued and unpaid interest thereon, in April 2017. In addition, NRP is required to redeem any and all remaining outstanding 2018 Notes (and pay accrued and unpaid interest thereon) within 60 days after October 1, 2017.
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
As discussed in
Note 3. Discontinued Operations
, the Partnership sold its non-operated oil and gas working interest assets in July 2016 and exited this business. The Partnership prepared the following oil and gas information in accordance with the authoritative guidance for oil and gas extractive activities for the years ended December 31, 2015 and 2014.
Capitalized Costs for the year ended December 31, 2015 (in thousands):
|
|
|
|
|
Proven properties
|
$
|
199,404
|
|
Unproven properties
|
—
|
|
Total property, plant, and equipment
|
199,404
|
|
Accumulated depreciation, depletion, and amortization
|
(60,542
|
)
|
Net capitalized costs
|
$
|
138,862
|
|
Costs incurred for property acquisitions, exploration, and development (in thousands):
|
|
|
|
|
|
|
|
|
|
For the Years Ended
December 31,
|
|
2015
|
|
2014
|
Property acquisitions
|
|
|
|
Proven properties
|
$
|
—
|
|
|
$
|
298,627
|
|
Unproven properties
|
—
|
|
|
40,800
|
|
Development
|
29,080
|
|
|
5,340
|
|
Total
|
$
|
29,080
|
|
|
$
|
344,767
|
|
Results of Operations for Producing Activities (in thousands):
|
|
|
|
|
|
|
|
|
|
For the Years Ended
December 31,
|
|
2015
|
|
2014
|
Production revenue
|
$
|
49,201
|
|
|
$
|
48,834
|
|
Royalty and overriding royalty revenue (1)
|
4,364
|
|
|
10,732
|
|
Total oil and gas related revenue
|
53,565
|
|
|
59,566
|
|
Operating costs and expense:
|
|
|
|
Depreciation, depletion and amortization
|
40,772
|
|
|
23,936
|
|
Property, franchise and other taxes
|
5,210
|
|
|
5,529
|
|
Production costs
|
12,871
|
|
|
12,544
|
|
Impairment of oil and gas properties
|
367,576
|
|
|
—
|
|
Total operating costs and expense
|
426,429
|
|
|
42,009
|
|
Total income from operations
|
$
|
(372,864
|
)
|
|
$
|
17,557
|
|
|
|
(1)
|
Includes
$0.4 million
and
$1.9 million
for the years ended December 31, 2015 and 2014, respectively of nonproduction revenues including lease bonus payments
|
Estimated Proved Reserves
Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term "reasonable certainty" implies a high degree of confidence that the quantities of crude oil, natural gas liquids and/or natural gas actually recovered will equal or exceed the estimate. The Partnership estimated proved reserves as of December 31, 2015 and 2014 were prepared by a third party independent reserve engineer. To achieve reasonable certainty, the third party engineer employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
used in the estimation of the Partnership’s proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole and production data and well test data. The third party engineer prepared its report covering properties representing
100%
of the Partnership’s estimated proved reserves as of December 31 2015 and 2014. Prices were calculated using the unweighted average of the first-day-of-the-month pricing for the twelve months ended December 31, 2015 and 2014. These prices were then adjusted for transportation and other costs. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reserve engineers often arrive at different estimates for the same properties.
The following table shows our estimated domestic proved reserves and reserve additions and revisions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil
(MBbl)
|
|
NGLs
(MBbl)
|
|
Natural
Gas
(MMcf)(2)
|
|
Total
Proved
Reserves
(MBoe)(3)
|
December 31, 2014
|
|
9,983
|
|
|
1,229
|
|
|
14,370
|
|
|
13,607
|
|
Revisions of previous estimates
|
|
(1,451
|
)
|
|
89
|
|
|
701
|
|
|
(1,244
|
)
|
Extensions, discoveries and other additions
|
|
776
|
|
|
60
|
|
|
541
|
|
|
926
|
|
Sales of properties
|
|
(98
|
)
|
|
—
|
|
|
(62
|
)
|
|
(108
|
)
|
Production
|
|
(1,136
|
)
|
|
(156
|
)
|
|
(2,226
|
)
|
|
(1,663
|
)
|
December 31, 2015 (1)
|
|
8,074
|
|
|
1,222
|
|
|
13,324
|
|
|
11,518
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of December 31, 2015
|
|
7,862
|
|
|
1,196
|
|
|
13,157
|
|
|
11,251
|
|
Proved undeveloped reserves as of December 31, 2015
|
|
212
|
|
|
26
|
|
|
167
|
|
|
267
|
|
|
|
(1)
|
Includes reserves attributable to the Partnership's
51%
member interest in BRP LLC.
|
|
|
(2)
|
Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency.
|
|
|
(3)
|
Includes
10,063
MBoe of estimated proved reserves attributable to the Partnership’s non-operated working interests in oil and natural gas properties in the Williston Basin, approximately
3%
of which were proved undeveloped reserves.
|
The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows for the year ended December 31, 2015 (in thousands):
|
|
|
|
|
Future cash inflows
|
$
|
364,352
|
|
Less related future:
|
|
Production costs
|
(164,649
|
)
|
Development and abandonment costs
|
(7,826
|
)
|
Future net cash flows before 10% discount
|
191,877
|
|
Discount to present value at a 10% annual rate
|
(75,524
|
)
|
Total standardized measure of discounted net cash flows
|
$
|
116,353
|
|
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
The table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during the year ended December 31, 2015 (in thousands):
|
|
|
|
|
Beginning of the period
|
$
|
305,197
|
|
Revisions to previous estimates:
|
|
Changes in prices and costs
|
(188,946
|
)
|
Changes in quantities
|
(11,750
|
)
|
Changes in future development costs
|
(12,202
|
)
|
Previously estimated development costs incurred during the period
|
29,080
|
|
Additions to proved reserves from extensions, discoveries and improved recovery, less related costs
|
11,928
|
|
Purchases and sales of reserves in place, net
|
(3,851
|
)
|
Accretion of discount
|
31,795
|
|
Sales of oil and gas, net of production costs
|
(35,112
|
)
|
Production timing and other
|
(9,786
|
)
|
Net increase (decrease)
|
(188,844
|
)
|
End of period
|
$
|
116,353
|
|
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following table summarizes quarterly financial data for 2016 and 2015 (in thousands, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
(1)
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
2016
|
2016
|
|
|
|
|
|
|
|
|
|
Revenues (including affiliates)
|
$
|
73,902
|
|
|
$
|
119,317
|
|
|
$
|
91,448
|
|
|
$
|
86,311
|
|
|
$
|
370,978
|
|
Gains on asset sales
(2)
|
21,925
|
|
|
(1,071
|
)
|
|
6,426
|
|
|
1,801
|
|
|
29,081
|
|
Depreciation, depletion and amortization
(including affiliates)
|
10,502
|
|
|
11,176
|
|
|
12,831
|
|
|
11,763
|
|
|
46,272
|
|
Asset impairment
|
1,893
|
|
|
91
|
|
|
5,697
|
|
|
9,245
|
|
|
16,926
|
|
Income from operations
|
48,991
|
|
|
70,741
|
|
|
38,907
|
|
|
27,106
|
|
|
185,745
|
|
Net income from continuing operations
|
26,351
|
|
|
48,633
|
|
|
16,419
|
|
|
3,811
|
|
|
95,214
|
|
Net income (loss) from discontinued operations
|
(2,924
|
)
|
|
(2,187
|
)
|
|
7,112
|
|
|
(323
|
)
|
|
1,678
|
|
Net income from continuing operations per limited partner unit
|
$
|
2.11
|
|
|
$
|
3.90
|
|
|
$
|
1.32
|
|
|
$
|
0.31
|
|
|
$
|
7.65
|
|
Net income (loss) from discontinued operations per limited partner unit
|
$
|
(0.23
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
0.57
|
|
|
$
|
(0.03
|
)
|
|
$
|
0.13
|
|
Weighted average number of common units outstanding
|
12,232
|
|
|
12,232
|
|
|
12,232
|
|
|
12,232
|
|
|
12,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
(1)
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
(3)
|
|
Total
2015
|
2015
|
|
|
|
|
|
|
|
|
|
Revenues (including affiliates)
|
$
|
94,447
|
|
|
$
|
120,228
|
|
|
$
|
112,199
|
|
|
$
|
105,874
|
|
|
$
|
432,748
|
|
Gains on asset sales
|
1,615
|
|
|
3,455
|
|
|
1,833
|
|
|
(3
|
)
|
|
6,900
|
|
Depreciation, depletion and amortization
(including affiliates)
|
11,514
|
|
|
19,077
|
|
|
16,437
|
|
|
13,888
|
|
|
60,916
|
|
Asset impairment
(4)
|
—
|
|
|
3,803
|
|
|
361,703
|
|
|
19,039
|
|
|
384,545
|
|
Income (loss) from operations
|
46,499
|
|
|
58,324
|
|
|
(307,831
|
)
|
|
32,581
|
|
|
(170,427
|
)
|
Net income (loss) from continuing operations
|
24,379
|
|
|
36,389
|
|
|
(330,736
|
)
|
|
9,797
|
|
|
(260,171
|
)
|
Net income (loss) from discontinued operations
|
(6,890
|
)
|
|
(3,811
|
)
|
|
(269,265
|
)
|
|
(31,583
|
)
|
|
(311,549
|
)
|
Net income (loss) from continuing operations per limited partner unit
|
$
|
1.95
|
|
|
$
|
2.82
|
|
|
$
|
(26.34
|
)
|
|
$
|
0.78
|
|
|
$
|
(20.78
|
)
|
Net income (loss) from discontinued operations per limited partner unit
|
$
|
(0.55
|
)
|
|
$
|
(0.31
|
)
|
|
$
|
(21.57
|
)
|
|
$
|
(2.53
|
)
|
|
$
|
(24.97
|
)
|
Weighted average number of common units outstanding
|
12,232
|
|
|
12,232
|
|
|
12,232
|
|
|
12,232
|
|
|
12,232
|
|
|
|
(1)
|
As a result of the sale of its non-operated oil and gas working interest business effective April 1, 2016, the Partnership classified the operating results and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated statements of comprehensive income subsequent to the filing of the First Quarter 2016 Form 10-Q. See below for a reconciliation to the amounts reported in the First Quarter 2016 Form 10-Q.
|
|
|
(2)
|
During the first quarter of 2016 the Partnership sold oil and gas royalty and aggregates royalty assets for a cumulative gain of
$21.9 million
. During the third quarter of 2016 the Partnership sold assets in multiple sale transactions for a net gain of
$6.4 million
primarily related to eminent domain transactions with governmental agencies.
|
|
|
(3)
|
As a result of the sale of its non-operated oil and gas working interest business effective April 1, 2016, the Partnership classified the operating results and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated statements of comprehensive income subsequent to the filing of the 2015 Form 10-K where this quarter's results were previously reported. See below for a reconciliation to the amounts reported in the 2015 Form 10-K.
|
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following table reconciles previously reported quarterly information to the quarterly financial data disclosed above (in thousands, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As Previously Reported
|
|
Reclassified to Discontinued Operations
|
|
Revised
|
First Quarter 2016
|
|
|
|
|
|
|
Revenues
|
|
$
|
80,826
|
|
|
$
|
(6,924
|
)
|
|
$
|
73,902
|
|
Gains on asset sales
|
|
21,925
|
|
|
—
|
|
|
21,925
|
|
Depreciation, depletion and amortization
|
|
14,743
|
|
|
(4,241
|
)
|
|
10,502
|
|
Asset impairment
|
|
2,030
|
|
|
(137
|
)
|
|
1,893
|
|
Income from operations
|
|
47,156
|
|
|
1,835
|
|
|
48,991
|
|
Net income from continuing operations
|
|
23,427
|
|
|
2,924
|
|
|
26,351
|
|
Net income (loss) from discontinued operations
|
|
—
|
|
|
(2,924
|
)
|
|
(2,924
|
)
|
Net income from continuing operations per limited partner unit
|
|
$
|
1.88
|
|
|
$
|
0.23
|
|
|
$
|
2.11
|
|
Net income (loss) from discontinued operations per limited partner unit
|
|
$
|
—
|
|
|
$
|
(0.23
|
)
|
|
$
|
(0.23
|
)
|
Weighted average number of common units outstanding
|
|
12,232
|
|
|
|
|
12,232
|
|
|
|
|
|
|
|
|
First Quarter 2015
|
|
|
|
|
|
|
Revenues
|
|
$
|
107,611
|
|
|
$
|
(13,164
|
)
|
|
$
|
94,447
|
|
Gains on asset sales
|
|
2,066
|
|
|
(451
|
)
|
|
1,615
|
|
Depreciation, depletion and amortization
|
|
25,392
|
|
|
(13,878
|
)
|
|
11,514
|
|
Asset impairment
|
|
—
|
|
|
—
|
|
|
—
|
|
Income from operations
|
|
40,417
|
|
|
6,082
|
|
|
46,499
|
|
Net income from continuing operations
|
|
17,489
|
|
|
6,890
|
|
|
24,379
|
|
Net income (loss) from discontinued operations
|
|
—
|
|
|
(6,890
|
)
|
|
(6,890
|
)
|
Net income from continuing operations per limited partner unit
|
|
$
|
1.40
|
|
|
$
|
0.55
|
|
|
$
|
1.95
|
|
Net income (loss) from discontinued operations per limited partner unit
|
|
$
|
—
|
|
|
$
|
(0.55
|
)
|
|
$
|
(0.55
|
)
|
Weighted average number of common units outstanding
|
|
12,232
|
|
|
|
|
12,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As Reported
|
|
Presentation Reclassification
|
|
Reclassified to Discontinued Operations
|
|
As Revised
|
Fourth Quarter 2015
|
|
|
|
|
|
|
|
Revenues
|
$
|
116,063
|
|
|
$
|
3
|
|
|
$
|
(10,192
|
)
|
|
$
|
105,874
|
|
Gains on asset sales
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
Depreciation, depletion and amortization
|
18,152
|
|
|
—
|
|
|
(4,264
|
)
|
|
13,888
|
|
Asset impairment
|
50,953
|
|
|
—
|
|
|
(31,914
|
)
|
|
19,039
|
|
Income from operations
|
2,042
|
|
|
—
|
|
|
30,539
|
|
|
32,581
|
|
Net income from continuing operations
|
(21,786
|
)
|
|
—
|
|
|
31,583
|
|
|
9,797
|
|
Net income (loss) from discontinued operations
|
—
|
|
|
—
|
|
|
(31,583
|
)
|
|
(31,583
|
)
|
Net income from continuing operations per limited partner unit
|
$
|
(1.75
|
)
|
|
$
|
—
|
|
|
$
|
2.53
|
|
|
$
|
0.78
|
|
Net income (loss) from discontinued operations per limited partner unit
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2.53
|
)
|
|
$
|
(2.53
|
)
|
Weighted average number of common units outstanding
|
12,232
|
|
|
|
|
|
|
12,232
|
|