Item
1. Financial Statements (Unaudited)
RHINO
RESOURCE PARTNERS LP
UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(in
thousands)
|
|
September
30, 2017
|
|
|
December
31, 2016
|
|
ASSETS
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
27
|
|
|
$
|
47
|
|
Accounts
receivable, net of allowance for doubtful accounts ($-0- as of
September
30, 2017 and December 31, 2016)
|
|
|
18,467
|
|
|
|
13,893
|
|
Inventories
|
|
|
11,334
|
|
|
|
8,050
|
|
Advance
royalties, current portion
|
|
|
653
|
|
|
|
898
|
|
Investment
in available for sale securities
|
|
|
9,590
|
|
|
|
3,532
|
|
Prepaid
expenses and other
|
|
|
4,676
|
|
|
|
5,133
|
|
Total
current assets
|
|
|
44,747
|
|
|
|
31,553
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
At
cost, including coal properties, mine development and construction costs
|
|
|
459,469
|
|
|
|
449,181
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
(280,027
|
)
|
|
|
(266,874
|
)
|
Net
property, plant and equipment
|
|
|
179,442
|
|
|
|
182,307
|
|
Advance
royalties, net of current portion
|
|
|
7,847
|
|
|
|
7,652
|
|
Investment
in unconsolidated affiliates
|
|
|
130
|
|
|
|
5,121
|
|
Intangible
purchase option
|
|
|
21,750
|
|
|
|
21,750
|
|
Note
receivable-related party
|
|
|
-
|
|
|
|
2,040
|
|
Other
non-current assets
|
|
|
27,667
|
|
|
|
27,018
|
|
TOTAL
|
|
$
|
281,583
|
|
|
$
|
277,441
|
|
LIABILITIES
AND EQUITY
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
11,954
|
|
|
$
|
10,420
|
|
Accrued
expenses and other
|
|
|
11,749
|
|
|
|
10,063
|
|
Accrued
preferred distributions
|
|
|
4,118
|
|
|
|
-
|
|
Current
portion of long-term debt
|
|
|
9,940
|
|
|
|
10,040
|
|
Current
portion of asset retirement obligations
|
|
|
917
|
|
|
|
917
|
|
Total
current liabilities
|
|
|
38,678
|
|
|
|
31,440
|
|
NON-CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Asset
retirement obligations, net of current portion
|
|
|
23,749
|
|
|
|
22,361
|
|
Other
non-current liabilities
|
|
|
45,908
|
|
|
|
45,371
|
|
Total
non-current liabilities
|
|
|
69,657
|
|
|
|
67,732
|
|
Total
liabilities
|
|
|
108,335
|
|
|
|
99,172
|
|
COMMITMENTS
AND CONTINGENCIES (NOTE 12)
|
|
|
|
|
|
|
|
|
PARTNERS’
CAPITAL:
|
|
|
|
|
|
|
|
|
Limited
partners
|
|
|
150,787
|
|
|
|
154,696
|
|
Subscription
receivable from limited partners
|
|
|
-
|
|
|
|
(2,000
|
)
|
General
partner
|
|
|
8,942
|
|
|
|
8,959
|
|
Preferred
partners
|
|
|
19,118
|
|
|
|
15,000
|
|
Preferred
partner distribution earned
|
|
|
(4,118
|
)
|
|
|
-
|
|
Investment
in Royal common stock (NOTE 11)
|
|
|
(4,126
|
)
|
|
|
-
|
|
Accumulated
other comprehensive income
|
|
|
2,645
|
|
|
|
1,614
|
|
Total
partners’ capital
|
|
|
173,248
|
|
|
|
178,269
|
|
TOTAL
|
|
$
|
281,583
|
|
|
$
|
277,441
|
|
See
notes to unaudited condensed consolidated financial statements.
RHINO
RESOURCE PARTNERS LP
UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE
INCOME
(in
thousands, except per unit data)
|
|
Three
Months
|
|
|
Nine
Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal
sales
|
|
$
|
56,460
|
|
|
$
|
40,992
|
|
|
$
|
162,951
|
|
|
$
|
116,777
|
|
Freight
and handling revenues
|
|
|
220
|
|
|
|
424
|
|
|
|
537
|
|
|
|
1,634
|
|
Other
revenues
|
|
|
1,666
|
|
|
|
1,999
|
|
|
|
4,944
|
|
|
|
5,947
|
|
Total
revenues
|
|
|
58,346
|
|
|
|
43,415
|
|
|
|
168,432
|
|
|
|
124,358
|
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
|
46,455
|
|
|
|
35,249
|
|
|
|
138,066
|
|
|
|
98,105
|
|
Freight
and handling costs
|
|
|
1,518
|
|
|
|
385
|
|
|
|
2,515
|
|
|
|
1,451
|
|
Depreciation,
depletion and amortization
|
|
|
5,188
|
|
|
|
6,489
|
|
|
|
16,495
|
|
|
|
18,341
|
|
Selling,
general and administrative (exclusive of depreciation, depletion and amortization shown separately above)
|
|
|
2,671
|
|
|
|
4,305
|
|
|
|
8,454
|
|
|
|
12,248
|
|
Gain
on sale/disposal of assets—net
|
|
|
(83
|
)
|
|
|
(125
|
)
|
|
|
(40
|
)
|
|
|
(420
|
)
|
Total
costs and expenses
|
|
|
55,749
|
|
|
|
46,303
|
|
|
|
165,490
|
|
|
|
129,725
|
|
INCOME/(LOSS)
FROM OPERATIONS
|
|
|
2,597
|
|
|
|
(2,888
|
)
|
|
|
2,942
|
|
|
|
(5,367
|
)
|
INTEREST
AND OTHER (EXPENSE)/INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(1,011
|
)
|
|
|
(1,904
|
)
|
|
|
(3,131
|
)
|
|
|
(5,195
|
)
|
Interest
income and other
|
|
|
86
|
|
|
|
(54
|
)
|
|
|
86
|
|
|
|
11
|
|
Gain
on extinguishment of debt
|
|
|
-
|
|
|
|
1,663
|
|
|
|
-
|
|
|
|
1,663
|
|
Equity
in net (loss)/income of unconsolidated affiliates
|
|
|
-
|
|
|
|
(27
|
)
|
|
|
36
|
|
|
|
(132
|
)
|
Total
interest and other (expense)
|
|
|
(925
|
)
|
|
|
(322
|
)
|
|
|
(3,009
|
)
|
|
|
(3,653
|
)
|
NET
INCOME/(LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS
|
|
|
1,672
|
|
|
|
(3,210
|
)
|
|
|
(67
|
)
|
|
|
(9,020
|
)
|
INCOME
TAXES
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
NET
INCOME/(LOSS) FROM CONTINUING OPERATIONS
|
|
|
1,672
|
|
|
|
(3,210
|
)
|
|
|
(67
|
)
|
|
|
(9,020
|
)
|
DISCONTINUED
OPERATIONS (NOTE 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from discontinued operations
|
|
|
-
|
|
|
|
(575
|
)
|
|
|
-
|
|
|
|
(117,940
|
)
|
NET
INCOME/(LOSS)
|
|
|
1,672
|
|
|
|
(3,785
|
)
|
|
|
(67
|
)
|
|
|
(126,960
|
)
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
market value adjustment for available-for-sale investment
|
|
|
(990
|
)
|
|
|
-
|
|
|
|
1,030
|
|
|
|
-
|
|
COMPREHENSIVE
INCOME/(LOSS)
|
|
$
|
682
|
|
|
$
|
(3,785
|
)
|
|
$
|
963
|
|
|
$
|
(126,960
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
partner’s interest in net income/(loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income/(loss) from continuing operations
|
|
$
|
1
|
|
|
$
|
(21
|
)
|
|
$
|
(18
|
)
|
|
$
|
(87
|
)
|
Net
(loss) from discontinued operations
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
-
|
|
|
|
(750
|
)
|
General
partner’s interest in net income/(loss)
|
|
$
|
1
|
|
|
$
|
(25
|
)
|
|
$
|
(18
|
)
|
|
$
|
(837
|
)
|
Common
unitholders’ interest in net income/(loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income/(loss) from continuing operations
|
|
$
|
25
|
|
|
$
|
(2,758
|
)
|
|
$
|
(3,803
|
)
|
|
$
|
(7,144
|
)
|
Net
(loss) from discontinued operations
|
|
|
-
|
|
|
|
(494
|
)
|
|
|
-
|
|
|
|
(93,734
|
)
|
Common
unitholders’ interest in net income/(loss)
|
|
$
|
25
|
|
|
$
|
(3,252
|
)
|
|
$
|
(3,803
|
)
|
|
$
|
(100,878
|
)
|
Subordinated
unitholders’ interest in net income/(loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income/(loss) from continuing operations
|
|
$
|
2
|
|
|
$
|
(431
|
)
|
|
$
|
(364
|
)
|
|
$
|
(1,788
|
)
|
Net
(loss) from discontinued operations
|
|
|
-
|
|
|
|
(77
|
)
|
|
|
-
|
|
|
|
(23,456
|
)
|
Subordinated
unitholders’ interest in net income/(loss)
|
|
$
|
2
|
|
|
$
|
(508
|
)
|
|
$
|
(364
|
)
|
|
$
|
(25,244
|
)
|
Preferred
unitholders’ interest in net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income from continuing operations
|
|
$
|
1,644
|
|
|
|
n/a
|
|
|
$
|
4,118
|
|
|
|
n/a
|
|
Net
income from discontinued operations
|
|
|
-
|
|
|
|
n/a
|
|
|
|
-
|
|
|
|
n/a
|
|
Preferred
unitholders’ interest in net income
|
|
$
|
1,644
|
|
|
|
n/a
|
|
|
$
|
4,118
|
|
|
$
|
-
|
|
Net
(loss)/income per limited partner unit, basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
$
|
-
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(1.45
|
)
|
Net
(loss) per unit from discontinued operations
|
|
|
-
|
|
|
|
(0.06
|
)
|
|
|
-
|
|
|
|
(18.98
|
)
|
Net
(loss) per common unit, basic
|
|
$
|
-
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(20.43
|
)
|
Subordinated
units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
$
|
-
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(1.45
|
)
|
Net
(loss) per unit from discontinued operations
|
|
|
-
|
|
|
|
(0.06
|
)
|
|
|
-
|
|
|
|
(18.98
|
)
|
Net
(loss) per subordinated unit, basic
|
|
$
|
-
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(20.43
|
)
|
Preferred
units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per unit from continuing operations
|
|
$
|
1.10
|
|
|
|
n/a
|
|
|
$
|
2.75
|
|
|
|
n/a
|
|
Net
income per unit from discontinued operations
|
|
|
-
|
|
|
|
n/a
|
|
|
|
-
|
|
|
|
n/a
|
|
Net
income per preferred unit, basic
|
|
$
|
1.10
|
|
|
|
n/a
|
|
|
$
|
2.75
|
|
|
|
n/a
|
|
Net
(loss)/income per limited partner unit, diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
$
|
-
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(1.45
|
)
|
Net
(loss) per unit from discontinued operations
|
|
|
-
|
|
|
|
(0.06
|
)
|
|
|
-
|
|
|
|
(18.98
|
)
|
Net
(loss) per common unit, diluted
|
|
$
|
-
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(20.43
|
)
|
Subordinated
units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
$
|
-
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(1.45
|
)
|
Net
(loss) per unit from discontinued operations
|
|
|
-
|
|
|
|
(0.06
|
)
|
|
|
-
|
|
|
|
(18.98
|
)
|
Net
(loss) per subordinated unit, diluted
|
|
$
|
-
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(20.43
|
)
|
Preferred
units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per unit from continuing operations
|
|
$
|
1.10
|
|
|
|
n/a
|
|
|
$
|
2.75
|
|
|
|
n/a
|
|
Net
income per unit from discontinued operations
|
|
|
-
|
|
|
|
n/a
|
|
|
|
-
|
|
|
|
n/a
|
|
Net
income per preferred unit, diluted
|
|
$
|
1.10
|
|
|
|
n/a
|
|
|
$
|
2.75
|
|
|
|
n/a
|
|
Distributions
paid per limited partner unit (1)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Weighted
average number of limited partner units outstanding, basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
12,994
|
|
|
|
7,906
|
|
|
|
12,942
|
|
|
|
4,937
|
|
Subordinated
units
|
|
|
1,236
|
|
|
|
1,236
|
|
|
|
1,236
|
|
|
|
1,236
|
|
Preferred
units
|
|
|
1,500
|
|
|
|
n/a
|
|
|
|
1,500
|
|
|
|
n/a
|
|
Weighted
average number of limited partner units outstanding, diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
12,994
|
|
|
|
7,906
|
|
|
|
12,942
|
|
|
|
4,937
|
|
Subordinated
units
|
|
|
1,236
|
|
|
|
1,236
|
|
|
|
1,236
|
|
|
|
1,236
|
|
Preferred
units
|
|
|
1,500
|
|
|
|
n/a
|
|
|
|
1,500
|
|
|
|
n/a
|
|
(1)
No distributions were paid for the nine months ended September 30, 2017 and 2016.
See
notes to unaudited condensed consolidated financial statements.
RHINO
RESOURCE PARTNERS LP
UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in
thousands)
|
|
Nine
Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(67
|
)
|
|
$
|
(126,960
|
)
|
Adjustments
to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
16,495
|
|
|
|
18,753
|
|
Accretion
on asset retirement obligations
|
|
|
1,422
|
|
|
|
1,141
|
|
Amortization
of deferred revenue
|
|
|
-
|
|
|
|
(1,337
|
)
|
Amortization
of advance royalties
|
|
|
876
|
|
|
|
773
|
|
Amortization
of debt issuance costs
|
|
|
1,068
|
|
|
|
1,976
|
|
Amortization
of actuarial gain
|
|
|
-
|
|
|
|
(4,796
|
)
|
Loss
on impairment of asset
|
|
|
-
|
|
|
|
2,000
|
|
Equity
in net loss/(income) of unconsolidated affiliates
|
|
|
(36
|
)
|
|
|
132
|
|
Loss
on retirement of advance royalties
|
|
|
136
|
|
|
|
144
|
|
Loss
on disposal of business
|
|
|
-
|
|
|
|
119,160
|
|
(Gain)
on sale/disposal of assets—net
|
|
|
(40
|
)
|
|
|
(420
|
)
|
Equity-based
compensation
|
|
|
260
|
|
|
|
528
|
|
Changes
in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(4,820
|
)
|
|
|
(54
|
)
|
Inventories
|
|
|
(3,285
|
)
|
|
|
(237
|
)
|
Advance
royalties
|
|
|
(962
|
)
|
|
|
(1,782
|
)
|
Prepaid
expenses and other assets
|
|
|
(1,923
|
)
|
|
|
21
|
|
Accounts
payable
|
|
|
1,239
|
|
|
|
(78
|
)
|
Accrued
expenses and other liabilities
|
|
|
2,888
|
|
|
|
(3,649
|
)
|
Asset
retirement obligations
|
|
|
(34
|
)
|
|
|
(161
|
)
|
Postretirement
benefits
|
|
|
-
|
|
|
|
(45
|
)
|
Net
cash provided by operating activities
|
|
|
13,217
|
|
|
|
5,109
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Additions
to property, plant, and equipment
|
|
|
(14,306
|
)
|
|
|
(5,892
|
)
|
Proceeds
from sales of property, plant, and equipment
|
|
|
506
|
|
|
|
348
|
|
Proceeds
from business disposal
|
|
|
890
|
|
|
|
10,650
|
|
Net
cash (used in)/provided by investing activities
|
|
|
(12,910
|
)
|
|
|
5,106
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Borrowings
on line of credit
|
|
|
98,350
|
|
|
|
80,450
|
|
Repayments
on line of credit
|
|
|
(98,450
|
)
|
|
|
(91,300
|
)
|
Restricted
cash from Royal contribution
|
|
|
-
|
|
|
|
(2,000
|
)
|
Repayments
on long-term debt
|
|
|
-
|
|
|
|
(1,210
|
)
|
Gain
on debt extinguishment
|
|
|
-
|
|
|
|
(1,663
|
)
|
Distributions
to unitholders
|
|
|
-
|
|
|
|
(24
|
)
|
Payments
on debt issuance costs
|
|
|
(227
|
)
|
|
|
(1,510
|
)
|
Limited
partner contributions
|
|
|
-
|
|
|
|
7,000
|
|
Net
cash used in financing activities
|
|
|
(327
|
)
|
|
|
(10,257
|
)
|
NET
DECREASE IN CASH AND CASH EQUIVALENTS
|
|
|
(20
|
)
|
|
|
(42
|
)
|
CASH
AND CASH EQUIVALENTS—Beginning of period
|
|
|
47
|
|
|
|
78
|
|
CASH
AND CASH EQUIVALENTS—End of period
|
|
$
|
27
|
|
|
$
|
36
|
|
See
notes to unaudited condensed consolidated financial statements.
RHINO
RESOURCE PARTNERS LP
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
AS
OF SEPTEMBER 30, 2017 AND DECEMBER 31, 2016 AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
1.
BASIS OF PRESENTATION AND ORGANIZATION
Basis
of Presentation and Principles of Consolidation
— The accompanying unaudited interim financial statements include
the accounts of Rhino Resource Partners LP and its subsidiaries (the “Partnership”). Intercompany transactions and
balances have been eliminated in consolidation.
Unaudited
Interim Financial Information
—The accompanying unaudited interim financial statements have been prepared in accordance
with generally accepted accounting principles for interim financial information. The condensed consolidated statement of financial
position as of September 30, 2017, condensed consolidated statements of operations and comprehensive income for the three and
nine months ended September 30, 2017 and 2016 and the condensed consolidated statements of cash flows for the nine months ended
September 30, 2017 and 2016 include all adjustments that the Partnership considers necessary for a fair presentation of the financial
position, operating results and cash flows for the periods presented. The condensed consolidated statement of financial position
as of December 31, 2016 was derived from audited financial statements, but does not include all disclosures required by accounting
principles generally accepted in the United States of America (“U.S.”). The Partnership filed its Annual Report on
Form 10-K for the year ended December 31, 2016 with the Securities and Exchange Commission (“SEC”), which included
all information and notes necessary for such presentation. The results of operations for the interim periods are not necessarily
indicative of the results to be expected for the year or any future period. These unaudited interim financial statements should
be read in conjunction with the audited financial statements included in the Partnership’s Annual Report on Form 10-K for
the year ended December 31, 2016 filed with the SEC.
Reclassifications.
Certain prior year amounts have been reclassified to discontinued operations on the unaudited condensed consolidated statements
of operations and comprehensive income related to the disposal of the Elk Horn coal leasing business during 2016. See Note 3 for
further information on the Elk Horn disposal.
Debt
Classification
— The Partnership evaluated its amended and restated senior secured credit facility at September 30,
2017 to determine whether this debt liability should be classified as a long-term or current liability on the Partnership’s
unaudited condensed consolidated statements of financial position. On May 13, 2016, the Partnership entered into a fifth amendment
(the “Fifth Amendment”) of its amended and restated agreement that initially extended the term of the senior secured
credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December
31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. As of December 31,
2016, the Partnership had met the requirements to extend the maturity date of the credit facility to December 31, 2017. Since
the credit facility has an expiration date of December 2017, the Partnership determined that its credit facility debt liability
at September 30, 2017 and December 31, 2016 of $9.9 million and $10.0 million, respectively, should be classified as a current
liability on its consolidated statements of financial position. The classification of the credit facility balance as a current
liability raises substantial doubt of the Partnership’s ability to continue as a going concern for the next twelve months.
The Partnership is considering alternative financing options that could result in a new long-term credit facility. Since the credit
facility has an expiration date of December 31, 2017, the Partnership will have to secure alternative financing to replace its
credit facility by the expiration date of December 31, 2017 in order to continue its normal business operations and meet its obligations
as they come due. The financial statements do not include any adjustments relating to the recoverability and classification of
assets carrying amounts or the amount of and classification of liabilities that may result should the Partnership be unable to
continue as a going concern.
Organization
—Rhino
Resource Partners LP is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Operating
Company”). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground
mines in Kentucky, Ohio, West Virginia, and Utah. The majority of sales are made to electric utilities and other coal-related
organizations in the United States.
Reverse
Unit Split
On
April 18, 2016, the Partnership completed a 1-for-10 reverse split on its common units and subordinated units. Pursuant to the
reverse split, common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated
unitholders received one subordinated unit for every 10 subordinated units owned on April 18, 2016. All common and subordinated
units, net income (loss) per unit and distribution per unit references included herein have been adjusted as if the change took
place before the date of the earliest transaction reported. Any fractional units resulting from the reverse unit split were rounded
to the nearest whole unit.
Royal
Energy Resources, Inc. Acquisition
On
January 21, 2016, a definitive agreement (“Definitive Agreement”) was completed between Royal Energy Resources, Inc.
(“Royal”) and Wexford Capital LP (“Wexford Capital”) whereby Royal acquired 676,911 issued and outstanding
common units of the Partnership from Wexford Capital for $3.5 million. The Definitive Agreement also included the committed acquisition
by Royal within sixty days from the date of the Definitive Agreement of all of the issued and outstanding membership interests
of Rhino GP LLC, the general partner of the Partnership (the “General Partner”), as well as 945,525 issued and outstanding
subordinated units of the Partnership from Wexford Capital for $1.0 million.
On
March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of the General Partner
as well as the 945,525 issued and outstanding subordinated units from Wexford Capital. Royal obtained control of, and a majority
limited partner interest, in the Partnership with the completion of this transaction.
On
March 21, 2016, the Partnership and Royal entered into a securities purchase agreement (the “Securities Purchase Agreement”)
pursuant to which the Partnership issued 6,000,000 common units in the Partnership to Royal in a private placement at $1.50 per
common unit for an aggregate purchase price of $9.0 million. Royal paid the Partnership $2.0 million in cash and delivered a promissory
note payable to the Partnership (“Rhino Promissory Note”) in the amount of $7.0 million. The promissory note was payable
in three installments: (i) $3.0 million on July 31, 2016; (ii) $2.0 million on or before September 30, 2016 and (iii) $2.0 million
on or before December 31, 2016. In the event the disinterested members of the board of directors of the General Partner determined
that the Partnership did not need the capital that would be provided by either or both installments set forth in (ii) and (iii)
above, in each case, the Partnership had the option to rescind Royal’s purchase of 1,333,333 common units and the applicable
installment would not be payable (each, a “Rescission Right”). If the Partnership failed to exercise a Rescission
Right, in each case, the Partnership had the option to repurchase 1,333,333 common units at $3.00 per common unit from Royal (each,
a “Repurchase Option”). The Repurchase Options terminate on December 31, 2017. On May 13, 2016 and September 30, 2016,
Royal paid the Partnership $3.0 million and $2.0 million, respectively, for the promissory note installments that were due July
31, 2016 and September 30, 2016, respectively. The payments were made in relation to the Fifth Amendment of the amended and restated
credit agreement completed on May 13, 2016. On December 30, 2016, the Partnership modified the Securities Purchase Agreement with
Royal for the final $2.0 million payment due on or before December 31, 2016 to extend the due date to December 31, 2018. Please
read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”
Option
Agreement-Armstrong Energy
On
December 30, 2016, the Partnership entered into an option agreement (the “Option Agreement”) with Royal, Rhino Resources
Partners Holdings, LLC (“Rhino Holdings”), an entity wholly owned by certain investment partnerships managed by Yorktown
Partners LLC (“Yorktown”), and the General Partner. Upon execution of the Option Agreement, the Partnership received
an option (the “Call Option”) from Rhino Holdings to acquire substantially all of the outstanding common stock of
Armstrong Energy, Inc. (“Armstrong Energy”) that is currently owned by investment partnerships managed by Yorktown,
representing approximately 97% of the outstanding common stock of Armstrong Energy. The Option Agreement stipulates that the Partnership
can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings
granting the Partnership the Call Option, the Partnership issued 5.0 million common units, representing limited partner interests
in the Partnership (the “Call Option Premium Units”) to Rhino Holdings upon the execution of the Option Agreement.
The Option Agreement stipulates the Partnership can exercise the Call Option and purchase the common stock of Armstrong Energy
in exchange for a number of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units,
will result in Rhino Holdings owning 51% of the fully diluted common units of the Partnership. The purchase of Armstrong Energy
through the exercise of the Call Option would also require Royal to transfer a 51% ownership interest in the General Partner to
Rhino Holdings. The Partnership’s ability to exercise the Call Option is conditioned upon (i) sixty (60) days having passed
since the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the amendment of
the Partnership’s revolving credit facility to permit the acquisition of Armstrong Energy.
The
Option Agreement also contains an option (the “Put Option”) granted by the Partnership to Rhino Holdings whereby Rhino
Holdings has the right, but not the obligation, to cause the Partnership to purchase substantially all of the outstanding common
stock of Armstrong Energy from Rhino Holdings under the same terms and conditions discussed above for the Call Option. The exercise
of the Put Option is dependent upon (i) the entry by Armstrong Energy into an agreement with its bondholders to restructure its
bonds and (ii) the termination and repayment of any outstanding balance under the Partnership’s revolving credit facility.
The
Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising
from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the Seventh Amendment
(defined below) and the GP Amendment (defined below). Upon the request by Rhino Holdings, the Partnership will also enter into
a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration
statements on Form S-1, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding
common units.
Pursuant
to the Option Agreement, the Second Amended and Restated Limited Liability Company Agreement of our general partner was amended
(“GP Amendment”). Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of the
General Partner as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director.
Rhino Holdings has the right to appoint two members to the board of directors of the General Partner for as long as it continues
to own 20% of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent
to any delegation of authority to any committee of the board of the General Partner. Upon the exercise of the Call Option or the
Put Option, the Second Amended and Restated Limited Liability Company Agreement of the General Partner, as amended, will be further
amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors and that the remaining
director will be the chief executive officer of the General Partner unless agreed otherwise.
On
October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy
Court. Per the Chapter 11 petitions, Armstrong Energy will file a detailed restructuring plan as part of the Chapter 11 proceedings.
The Partnership is evaluating the Armstrong Energy Chapter 11 filing and any effect it may have on the Option Agreement. See Note
6 for further information on the Partnership’s assessment of the Call Option.
Series
A Preferred Unit Purchase Agreement
On
December 30, 2016, the Partnership entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Agreement”)
with Weston Energy LLC (“Weston”), an entity wholly owned by certain investment partnerships managed by Yorktown,
and Royal. Under the Preferred Unit Agreement, Weston and Royal purchased 1,300,000 and 200,000, respectively, of Series A preferred
units representing limited partner interests in the Partnership at a price of $10.00 per Series A preferred unit. The Series A
preferred units have the preferences, rights and obligations set forth in the Amended and Restated Partnership Agreement. Weston
and Royal paid cash of $11.0 million and $2.0 million, respectively, to the Partnership and Weston assigned to the Partnership
a $2.0 million note receivable from Royal originally dated September 30, 2016 (the “Weston Promissory Note”). Please
read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”
The
Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for
as long as the Series A preferred units are outstanding, the Partnership will cause CAM Mining, LLC (“CAM Mining”),
which comprises the Partnership’s Central Appalachia segment, to conduct its business in the ordinary course consistent
with past practice and use reasonable best efforts to maintain and preserve intact its current organization, business and franchise
and to preserve the rights, franchises, goodwill and relationships of its employees, customers, lenders, suppliers, regulators
and others having business relationships with CAM Mining.
The
Preferred Unit Agreement stipulates that upon the request of the holder of the majority of the Partnership’s common units
following their conversion from Series A preferred units, as outlined in the Amended and Restated Partnership Agreement (defined
below), the Partnership will enter into a registration rights agreement with such holder. Such majority holder has the right to
demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights.
Letter
Agreement Regarding Rhino Promissory Note and Weston Promissory Note
On
December 30, 2016, the Partnership and Royal entered into a letter agreement whereby they extended the maturity dates of the Weston
Promissory Note and the final installment payment of the Rhino Promissory Note to December 31, 2018. The letter agreement further
provides that the aggregate $4.0 million balance of the Weston Promissory Note and Rhino Promissory Note may be converted at Royal’s
option into a number of shares of Royal’s common stock equal to the outstanding balance multiplied by seventy-five percent
(75%) of the volume-weighted average closing price of Royal’s common stock for the 90 days preceding the date of conversion
(“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50. On September 1, 2017,
Royal elected to convert the Rhino Promissory Note and the Weston Promissory Note to shares of Royal common stock. Royal issued
914,797 shares of its common stock to Rhino at a conversion price of $4.51 as calculated per the method stipulated above. See
Note 11 for further discussion.
Fourth
Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP
On
December 30, 2016, the general partner entered into the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership
(“Amended and Restated Partnership Agreement”) to create, authorize and issue the Series A preferred units.
The
Series A preferred units are a new class of equity security that rank senior to all classes or series of equity securities of
the Partnership with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units shall
be entitled to receive annual distributions equal to the greater of (i) 50% of the CAM Mining free cash flow (as defined below)
and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. “CAM Mining free cash
flow” is defined in the Amended and Restated Partnership Agreement as (i) the total revenue of the Partnership’s Central
Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for the
Partnership’s Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number
of coal tons sold by the Partnership from its Central Appalachia business segment. If the Partnership fails to pay any or all
of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and the Partnership
will not be permitted to pay any distributions on its Partnership interests that rank junior to the Series A preferred units,
including its common units. The Series A preferred units will be liquidated in accordance with their capital accounts and upon
liquidation will be entitled to distributions of property and cash in accordance with the balances of their capital accounts prior
to such distributions to equity securities that rank junior to the Series A preferred units.
The
Series A preferred units will vote on an as-converted basis with the common units, and the Partnership will be restricted from
taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance
of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale
or transfer of CAM Mining or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights
or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation
of a spin off; (v) the incurrence, assumption or guaranty of indebtedness for borrowed money in excess of $50.0 million except
indebtedness relating to entities or assets that are acquired by the Partnership or its affiliates that is in existence at the
time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational
reporting principles of the Partnership’s Central Appalachia business segment, subject to certain exceptions.
The
Partnership will have the option to convert the outstanding Series A preferred units at any time on or after the time at which
the amount of aggregate distributions paid in respect of each Series A preferred unit exceeds $10.00 per unit. Each Series A preferred
unit will convert into a number of common units equal to the quotient (the “Series A Conversion Ratio”) of (i) the
sum of $10.00 and any unpaid distributions in respect of such Series A Preferred Unit divided by (ii) 75% of the volume-weighted
average closing price of the common units for the preceding 90 trading days (the “VWAP”); provided however, that the
VWAP will be capped at a minimum of $2.00 and a maximum of $10.00. On December 31, 2021, all outstanding Series A preferred units
will convert into common units at the then applicable Series A Conversion Ratio.
Delisting
of Common Units from NYSE
On
December 17, 2015, the New York Stock Exchange (“NYSE”) notified the Partnership that the NYSE had determined to commence
proceedings to delist its common units from the NYSE as a result of the Partnership’s failure to comply with the continued
listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization
over a consecutive 30 trading-day period of at least $15 million for our common units. The NYSE also suspended the trading of
the Partnership’s common units at the close of trading on December 17, 2015.
On
January 4, 2016, the Partnership filed an appeal with the NYSE to review the suspension and delisting determination of the Partnership’s
common units. The NYSE held a hearing regarding our appeal on April 20, 2016 and affirmed its prior decision to delist the Partnership’s
common units.
On
April 27, 2016, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist the Partnership’s
common units and terminate the registration of its common units under Section 12(b) of the Securities Exchange Act of 1934. The
delisting became effective on May 9, 2016. The Partnership’s common units trade on the OTCQB Marketplace under the ticker
symbol “RHNO.”
The
Partnership is exploring the possibility of listing its common units on the NASDAQ Stock Market (“NASDAQ”), pending
its capability to meet the NASDAQ initial listing standards.
2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL
Investments
in Unconsolidated Affiliates.
Investments in other entities are accounted for using the consolidation, equity method or
cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence over the operating
and financial policies of the investee and whether the Partnership is determined to be the primary beneficiary of a variable interest
entity. Equity investments are recorded at original cost and adjusted periodically to recognize the Partnership’s proportionate
share of the investees’ net income or losses after the date of investment. Any losses from the Partnership’s equity
method investments are absorbed by the Partnership based upon its proportionate ownership percentage. If losses are incurred that
exceed the Partnership’s investment in the equity method entity, then the Partnership must continue to record its proportionate
share of losses in excess of its investment. Investments are written down only when there is clear evidence that a decline in
value that is other than temporary has occurred.
In
December 2012, the Partnership made an initial investment in a new joint venture, Muskie Proppant LLC (“Muskie”),
with affiliates of Wexford Capital. In November 2014, the Partnership contributed its investment interest in Muskie to Mammoth
Energy Partners LP (“Mammoth”) in return for a limited partner interest in Mammoth. In October 2016, the Partnership
contributed its limited partner interests in Mammoth to Mammoth Energy Services, Inc. (NASDAQ: TUSK) (“Mammoth Inc.”)
in exchange for 234,300 shares of common stock of Mammoth, Inc.
In
September 2014, the Partnership made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC (“Sturgeon”),
with affiliates of Wexford Capital and Gulfport Energy Corporation (NASDAQ: GPOR) (“Gulfport”). The Partnership accounted
for the investment in this joint venture and results of operations under the equity method based upon its ownership percentage.
The Partnership recorded its proportionate share of the operating income for this investment for the three and nine months ended
September 30, 2017 of approximately $0 and $36,000, respectively. The Partnership recorded its proportionate share of the operating
(loss) for Sturgeon for the three and nine months ended September 30, 2016 of approximately ($26,000) and ($0.1) million, respectively.
In June 2017, the Partnership contributed its limited partner interests in Sturgeon to Mammoth Inc. in exchange for 336,447 shares
of common stock of Mammoth Inc. As of September 30, 2017, the Partnership owned 568,794 shares of Mammoth Inc.
As
of September 30, 2017 and December 31, 2016, the Partnership recorded a fair market value adjustment of $1.0 million and $1.6
million, respectively, for its available-for-sale investment in Mammoth Inc. based on the market value of the shares at September
30, 2017 and December 31, 2016, respectively, which was recorded in Other Comprehensive Income. As of September 30, 2017 and December
31, 2016, the Partnership has recorded its investment in Mammoth Inc. as a short-term asset, which the Partnership has classified
as available-for-sale. The Partnership has included its investment in Mammoth Inc. and its prior investment in Muskie and Sturgeon
in its Other category for segment reporting purposes.
Recently
Issued Accounting Standards.
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting
Standards Update (“ASU”) 2014-09,
Revenue from Contracts with Customers
. ASU 2014-09 clarifies the principles
for recognizing revenue and establishes a common revenue standard for U.S. financial reporting purposes. The guidance in ASU 2014-09
affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for
the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts
or lease contracts). ASU 2014-09 supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”)
605,
Revenue Recognition
, and most industry-specific accounting guidance. Additionally, ASU 2014-09 supersedes some guidance
included in ASC 605-35,
Revenue Recognition—Construction-Type and Production-Type Contracts
. In addition, the existing
requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer
(for example, assets within the scope of ASC 360,
Property, Plant, and Equipment
, and intangible assets within the scope
of ASC 350,
Intangibles—Goodwill and Other
) are amended to be consistent with the guidance on recognition and measurement
(including the constraint on revenue) in ASU 2014-09. In July 2015, the FASB approved to defer the effective date of ASU 2014-09
by one year. Accordingly, ASU 2014-09 will be effective for public entities for annual reporting periods beginning after December
15, 2017 and interim periods therein. The Partnership is evaluating the requirements of this new accounting guidance and currently
believes the new guidance will not have a material impact on its financial results when adopted, but will require additional disclosures
in its financial statements.
In
February 2016, the FASB issued ASU 2016-02,
Leases (Topic 842)
. ASU 2016-02 requires that lessees recognize all leases
(other than leases with a term of twelve months or less) on the balance sheet as lease liabilities, based upon the present value
of the lease payments, with corresponding right of use assets. ASU 2016-02 also makes targeted changes to other aspects of current
guidance, including identifying a lease and lease classification criteria as well as the lessor accounting model, including guidance
on separating components of a contract and consideration in the contract. The amendments in ASU 2016-02 will be effective for
the Partnership on January 1, 2019 and will require modified retrospective application as of the beginning of the earliest period
presented in the financial statements. Early application is permitted. The Partnership is currently evaluating this guidance and
currently believes this new guidance will not have a material impact on its financial results when adopted, but will require additional
assets and liabilities to be recognized for certain agreements where the Partnership has the rights to use assets.
In
August 2016, the FASB issued ASU 2016-15,
Statement of Cash Flows (Topic 230)
:
Classification of Certain Cash Receipts
and Cash Payments
. ASU 2016-15 provides guidance on eight cash flow issues, including debt prepayment or debt extinguishment
costs. ASU 2016-15 requires that cash payments related to debt prepayments or debt extinguishments, excluding accrued interest,
be classified as a financing activity rather than an operating activity even when the effects enter into the determination of
net income. The amendments in ASU 2016-15 will be effective on January 1, 2018 and must be applied retrospectively. Early application
is permitted. The Partnership is currently evaluating this guidance.
In
January 2017, the FASB issued ASU 2017-01,
Business Combinations (Topic 805)
. ASU 2017—01 clarifies the definition
of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted
for as acquisitions (or disposals) of assets or businesses. ASU is effective for fiscal years beginning after December 15, 2017,
including interim periods within those fiscal years. The Partnership is currently evaluating this guidance.
3.
DISCONTINUED OPERATIONS
Elk
Horn Coal Leasing
In
August 2016, the Partnership entered into an agreement to sell its Elk Horn coal leasing company (“Elk Horn”) to a
third party for total cash consideration of $12.0 million. The Partnership received $10.5 million in cash consideration upon the
closing of the Elk Horn transaction and the remaining $1.5 million of consideration was paid in ten equal monthly installments
of $150,000 on the 20th of each calendar month beginning on September 20, 2016. The Partnership recorded a loss of $119.9 million
from the Elk Horn disposal during the year ended December 31, 2016. The previous operating results of Elk Horn have been reclassified
and reported on the (Gain)/loss from discontinued operations line on the Partnership’s unaudited condensed consolidated
statements of operations and comprehensive income for the three and nine months ended September 30, 2016.
Major
components of net (loss)/income from discontinued operations for the three and nine months
ended September 30, 2017 and 2016 are summarized as follows:
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Major
line items constituting loss from discontinued operations for the Elk Horn disposal:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
revenues
|
|
$
|
-
|
|
|
$
|
442
|
|
|
$
|
-
|
|
|
$
|
2,668
|
|
Total
revenues
|
|
|
-
|
|
|
|
442
|
|
|
|
-
|
|
|
|
2,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
|
-
|
|
|
|
345
|
|
|
|
-
|
|
|
|
799
|
|
Depreciation,
depletion and amortization
|
|
|
-
|
|
|
|
87
|
|
|
|
-
|
|
|
|
413
|
|
Selling,
general and administrative (exclusive of depreciation, depletion and amortization shown separately above)
|
|
|
-
|
|
|
|
78
|
|
|
|
-
|
|
|
|
174
|
|
(Gain)
on sale/disposal of assets, net
|
|
|
-
|
|
|
|
504
|
|
|
|
-
|
|
|
|
504
|
|
Loss
on disposal of business
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
118,705
|
|
Interest
expense and other
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
13
|
|
Total
costs and expenses
|
|
|
-
|
|
|
|
1,017
|
|
|
|
-
|
|
|
|
120,608
|
|
Loss
from discontinued operations before income taxes for the Elk Horn disposal
|
|
|
-
|
|
|
|
(575
|
)
|
|
|
-
|
|
|
|
(117,940
|
)
|
Income
taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net
loss from discontinued operations
|
|
$
|
-
|
|
|
$
|
(575
|
)
|
|
$
|
-
|
|
|
$
|
(117,940
|
)
|
The
depreciation, depletion and amortization amounts for Elk Horn for each period presented are listed in the previous table. The
Partnership did not fund any capital expenditures for Elk Horn for any periods presented. The amortization of Elk Horn’s
deferred revenue, which was zero and $1.3 million for the nine months ended September 30, 2017 and 2016, respectively, is the
only material non-cash operating item for all periods presented. Elk Horn did not have any material non-cash investing items for
the nine months ended September 30, 2016.
4.
PREPAID EXPENSES AND OTHER CURRENT ASSETS
Prepaid
expenses and other current assets as of September 30, 2017 and December 31, 2016 consisted of the following:
|
|
September
30, 2017
|
|
|
December
31, 2016
|
|
|
|
(in
thousands)
|
|
Other
prepaid expenses
|
|
$
|
1,729
|
|
|
$
|
707
|
|
Debt
issuance costs—net
|
|
|
398
|
|
|
|
1,239
|
|
Prepaid
insurance
|
|
|
1,922
|
|
|
|
1,432
|
|
Prepaid
leases
|
|
|
123
|
|
|
|
77
|
|
Supply
inventory
|
|
|
504
|
|
|
|
614
|
|
Deposits
|
|
|
-
|
|
|
|
164
|
|
Note
receivable-current portion
|
|
|
-
|
|
|
|
900
|
|
Total
Prepaid expenses and other
|
|
$
|
4,676
|
|
|
$
|
5,133
|
|
Debt
issuance costs were included in Prepaid expenses and other current assets as of September 30, 2017 and December 31, 2016 since
the Partnership classified its credit facility balance as a current liability. See Note 8 for further information on the amendments
to the amended and restated senior secured credit facility.
As
of December 31, 2016, the note receivable balance of $0.9 million related to the $1.5 million of consideration paid in ten equal
monthly installments of $150,000 for the Elk Horn sale discussed earlier. The note receivable was paid in full as of June 30,
2017.
5.
PROPERTY, PLANT AND EQUIPMENT
Property,
plant and equipment, including coal properties and mine development and construction costs, as of September 30, 2017 and December
31, 2016 are summarized by major classification as follows:
|
|
Useful
Lives
|
|
September
30, 2017
|
|
|
December
31, 2016
|
|
|
|
|
|
|
(in
thousands)
|
|
Land
|
|
|
|
$
|
15,770
|
|
|
$
|
16,377
|
|
Mining
and other equipment and related facilities
|
|
2
- 20 Years
|
|
|
314,804
|
|
|
|
305,626
|
|
Mine
development costs
|
|
1
- 15 Years
|
|
|
57,797
|
|
|
|
57,392
|
|
Coal
properties
|
|
1
- 15 Years
|
|
|
67,989
|
|
|
|
67,989
|
|
Construction
work in process
|
|
|
|
|
3,109
|
|
|
|
1,797
|
|
Total
|
|
|
|
|
459,469
|
|
|
|
449,181
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
|
|
(280,027
|
)
|
|
|
(266,874
|
)
|
Net
|
|
|
|
$
|
179,442
|
|
|
$
|
182,307
|
|
Depreciation
expense for mining and other equipment and related facilities, depletion expense for coal properties and oil and natural gas properties,
amortization expense for mine development costs, amortization expense for intangible assets and amortization expense for asset
retirement costs for the three and nine months ended September 30, 2017 and 2016 were as follows:
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
Depreciation
expense-mining and other equipment and related facilities
|
|
$
|
3,995
|
|
|
$
|
5,597
|
|
|
$
|
12,816
|
|
|
$
|
15,908
|
|
Depletion
expense for coal properties and oil and natural gas properties
|
|
|
450
|
|
|
|
404
|
|
|
|
1,221
|
|
|
|
1,224
|
|
Amortization
expense for mine development costs
|
|
|
721
|
|
|
|
511
|
|
|
|
2,265
|
|
|
|
1,294
|
|
Amortization
expense for intangible assets
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Amortization
expense for asset retirement costs
|
|
|
22
|
|
|
|
(23
|
)
|
|
|
193
|
|
|
|
(85
|
)
|
Total
depreciation, depletion and amortization
|
|
$
|
5,188
|
|
|
$
|
6,489
|
|
|
$
|
16,495
|
|
|
$
|
18,341
|
|
Taylorville
Land Sale
On
December 30, 2015, the Partnership completed the sale of its land surface rights for the Taylorville property in central Illinois
for approximately $7.2 million in net proceeds. The sale agreement allows the Partnership to retain the mining permit and control
of the proven and probable coal reserves at the Taylorville property as the Partnership has the option to repurchase the rights
to the land within seven years from the date of the sale agreement. In accordance with ASC 360-20-40-38,
Real Estate Sales
- Derecognition
, since the Partnership has the option to repurchase the rights to the land, the transaction has been accounted
for as a financing arrangement rather than a sale. The Taylorville property is recorded in the unaudited condensed consolidated
statements of financial position within the net property, plant and equipment caption and the related liability is recorded in
the unaudited condensed consolidated statements of financial position within the other noncurrent liability caption.
6.
INTANGIBLE AND OTHER NON-CURRENT ASSETS
Other
non-current assets as of September 30, 2017 and December 31, 2016 consisted of the following:
|
|
September
30, 2017
|
|
|
December
31, 2016
|
|
|
|
(in
thousands)
|
|
Deposits
and other
|
|
$
|
343
|
|
|
$
|
218
|
|
Due
(to)/from Rhino GP
|
|
|
(27
|
)
|
|
|
(573
|
)
|
Non-current
receivable
|
|
|
27,157
|
|
|
|
27,157
|
|
Deferred
expenses
|
|
|
194
|
|
|
|
216
|
|
Total
|
|
$
|
27,667
|
|
|
$
|
27,018
|
|
Non-current
receivable
. The non-current receivable balance of $27.2 million as of September 30, 2017 and December 31, 2016 consisted
of the amount due from the Partnership’s workers’ compensation insurance providers for potential claims against the
Partnership that are the primary responsibility of the Partnership, which are covered under the Partnership’s insurance
policies. The $27.2 million is also included in the Partnership’s accrued workers’ compensation benefits liability
balance, which is included in the other non-current liabilities section of the Partnership’s unaudited condensed consolidated
statements of financial position. The Partnership presents this amount on a gross asset and liability basis since a right of setoff
does not exist per the accounting guidance in ASC Topic 210,
Balance Sheet
. This presentation has no impact on the Partnership’s
results of operations or cash flows.
Note
receivable-related party
. In connection with the Series A preferred units issued in December 2016, Weston assigned to
the Partnership the Weston Promissory Note and related accrued interest from Royal originally dated September 30, 2016. See Note
1 and Note 11 for further information on the Series A preferred units and the Weston Promissory Note.
Call
Option-Armstrong Energy
. As discussed in Note 1, the Partnership and Rhino Holdings executed an Option Agreement in December
2016 where the Partnership received a Call Option from Rhino Holdings to acquire substantially all of the outstanding common stock
of Armstrong Energy. In exchange for Rhino Holdings granting the Partnership the Call Option, the Partnership issued 5.0 million
common units to Rhino Holdings upon the execution of the Option Agreement. The Partnership valued the Call Option at $21.8 million
based upon the closing price of the Partnership’s publicly traded common units on the date the Option Agreement was executed.
The Partnership has determined the value of the common units issued at December 30, 2016 of $21.8 million constituted an amount
that would be applied to the potential acquisition of Armstrong Energy, as discussed in Note 1.
As
discussed in Note 1, on October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s
United States Bankruptcy Court. The Partnership is evaluating the Chapter 11 petitions filed by Armstrong Energy and the Partnership
will further evaluate the detailed restructuring plan when it is submitted by Armstrong Energy to determine what, if any, effect
the ultimate outcome of the Chapter 11 proceedings will have on the Call Option. Because of the uncertain facts and circumstances
surrounding the current state of the Armstrong Energy Chapter 11 proceedings, which includes the possibility that the Partnership
will still exercise the Call Option as outlined in Note 1, the Partnership concluded that the value of the Call Option was not
impaired as of September 30, 2017. However, management expects that further information, including the progression of Armstrong’s
restructuring plan and bankruptcy proceedings, will become available in the next quarter; such information may have a material
effect on the carrying value of Option Agreement.
7.
ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES
Accrued
expenses and other current liabilities as of September 30, 2017 and December 31, 2016 consisted of the following:
|
|
September
30, 2017
|
|
|
December
31, 2016
|
|
|
|
(in
thousands)
|
|
Payroll,
bonus and vacation expense
|
|
$
|
1,786
|
|
|
$
|
1,496
|
|
Non
income taxes
|
|
|
3,393
|
|
|
|
2,252
|
|
Royalty
expenses
|
|
|
2,077
|
|
|
|
1,617
|
|
Accrued
interest
|
|
|
601
|
|
|
|
601
|
|
Health
claims
|
|
|
803
|
|
|
|
630
|
|
Workers’
compensation & pneumoconiosis
|
|
|
2,450
|
|
|
|
2,450
|
|
Accrued
insured litigation claims
|
|
|
26
|
|
|
|
277
|
|
Other
|
|
|
613
|
|
|
|
740
|
|
Total
|
|
$
|
11,749
|
|
|
$
|
10,063
|
|
The
$26,000 and $277,000 accrued for insured litigation claims as of September 30, 2017 and December 31, 2016, respectively, consists
of probable and estimable litigation claims that are the primary obligation of the Partnership. The amount accrued for litigation
claims is also due from the Partnership’s insurance providers and is included in Accounts receivable, net of allowance for
doubtful accounts on the Partnership’s unaudited condensed consolidated statements of financial position. The Partnership
presents this amount on a gross asset and liability basis, as a right of setoff does not exist per the accounting guidance in
ASC Topic 210,
Balance Sheet
. This presentation has no impact on the Partnership’s results of operations or cash
flows.
8.
DEBT
Debt
as of September 30, 2017 and December 31, 2016 consisted of the following:
|
|
September
30, 2017
|
|
|
December
31, 2016
|
|
|
|
(in
thousands)
|
|
Senior
secured credit facility with PNC Bank, N.A.
|
|
$
|
9,940
|
|
|
$
|
10,040
|
|
Other
notes payable
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
|
9,940
|
|
|
|
10,040
|
|
Less
current portion
|
|
|
(9,940
|
)
|
|
|
(10,040
|
)
|
Long-term
debt
|
|
$
|
-
|
|
|
$
|
-
|
|
Senior
Secured Credit Facility with PNC Bank, N.A.
— On July 29, 2011, the Partnership executed the amended and restated
credit agreement. The maximum availability under the amended and restated credit facility was $300.0 million, with a one-time
option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million was available
for letters of credit. In April 2015, the amended and restated credit agreement was amended and the borrowing commitment under
the facility was reduced to $100.0 million and the amount available for letters of credit was reduced to $50.0 million. As described
below, in March 2016 and May 2016, the borrowing commitment under the facility was further reduced to $80.0 million and $75.0
million, respectively, and the amount available for letters of credit was reduced to $30.0 million. In addition, as described
below, the borrowing commitment under the facility was further reduced by amendments in July 2016 and December 2016 to $44.3 million
as of September 30, 2017. The amount available for letters of credit was unchanged from these amendments.
On
March 17, 2016, the Partnership entered into a fourth amendment (the “Fourth Amendment”) of the amended and restated
credit agreement. The Fourth Amendment amended the definition of change of control in the amended and restated credit agreement
to permit Royal to purchase the membership interests of the General Partner. The Fourth Amendment also eliminated the option to
borrow funds utilizing the LIBOR rate plus an applicable margin and establishes the borrowing rate for all borrowings under the
facility to be based upon the current PRIME rate plus an applicable margin of 3.50%.
On
May 13, 2016, the Partnership entered into the Fifth Amendment, which extended the term to July 31, 2017.
In
July 2016, the Partnership entered into a sixth amendment (the “Sixth Amendment”) of its amended and restated senior
secured credit agreement that permitted the sale of Elk Horn that was discussed earlier. The Sixth Amendment further reduced the
maximum commitment amount allowed under the credit facility by $375,000 each quarterly period beginning September 30, 2016 through
September 30, 2017 for the additional $1.5 million that was received from the Elk Horn sale.
In
December 2016, the Partnership entered into a seventh amendment of its amended and restated credit agreement (the “Seventh
Amendment”). The Seventh Amendment allows for the Series A preferred units as outlined in the Amended and Restated Partnership
Agreement. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provided for additional
revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further
reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset
sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. The Seventh Amendment
alters the maximum leverage ratio to 4.0 to 1.0 effective December 31, 2016 through May 31, 2017 and 3.5 to 1.0 from June 30,
2017 through December 31, 2017. The maximum leverage ratio shall be reduced by 0.50 to 1.0 for every $10.0 million of net cash
proceeds, in the aggregate, received after the Seventh Amendment date from (i) the issuance of any equity by the Partnership and/or
(ii) the disposition of any assets in excess of $2.0 million in the aggregate, provided, however, that in no event will the maximum
leverage ratio be reduced below 3.0 to 1.0.
The
Seventh Amendment alters the minimum consolidated EBITDA figure, as calculated on a rolling twelve months basis, to $12.5 million
from December 31, 2016 through May 31, 2017 and $15.0 million from June 30, 2017 through December 31, 2017. The Seventh Amendment
alters the maximum capital expenditures allowed, as calculated on a rolling twelve months basis, to $20.0 million through the
expiration of the credit facility. A condition precedent to the effectiveness of the Seventh Amendment is the receipt of the $13.0
million of cash proceeds received by the Partnership from the issuance of the Series A preferred units pursuant to the Preferred
Unit Agreement, which was used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment,
the receipt of $13.0 million cash proceeds fulfilled the required Royal equity contribution, which was a requirement of prior
amendments to the credit agreement.
On
March 23, 2017, the Partnership entered into an eighth amendment (the “Eighth Amendment”) of its amended and restated
credit agreement that allows the annual auditor’s report for the years ended December 31, 2016 and 2015 to contain a qualification
with respect to the short-term classification of the Partnership’s credit facility balance without creating a default under
the credit agreement.
On
June 9, 2017, the Partnership entered into a ninth amendment (the “Ninth Amendment”) of its amended and restated credit
agreement that permitted outstanding letters of credit to be replaced with different counterparties without affecting the revolving
credit commitments under the credit agreement. The Ninth Amendment also permits certain lease and sale leaseback transactions
under the credit agreement that do not affect the revolving credit commitments under the credit agreement for asset dispositions
and also do not factor in the calculation of the maximum capital expenditures allowed under the credit agreement.
At
September 30, 2017, the Operating Company had borrowed $9.9 million at a variable interest rate of prime plus 3.50% (7.75% at
September 30, 2017). In addition, the Operating Company had outstanding letters of credit of $26.1 million at a fixed interest
rate of 5.00% at September 30, 2017. Based upon a maximum borrowing capacity of 3.50 times a trailing twelve-month EBITDA calculation
(as defined in the credit agreement), the Operating Company had not used $8.2 million of the borrowing availability at September
30, 2017. As of September 30, 2017 and December 31, 2016, the Partnership was in compliance with respect to all covenants contained
in its credit agreement.
9.
ASSET RETIREMENT OBLIGATIONS
The
changes in asset retirement obligations for the nine months ended September 30, 2017 and the year ended December 31, 2016 are
as follows:
|
|
Nine
months ended
|
|
|
Year
ended
|
|
|
|
September
30, 2017
|
|
|
December
31, 2016
|
|
|
|
(in
thousands)
|
|
Balance
at beginning of period (including current portion)
|
|
$
|
23,278
|
|
|
$
|
23,077
|
|
Accretion
expense
|
|
|
1,422
|
|
|
|
1,486
|
|
Adjustments
to the liability from annual recosting and other
|
|
|
-
|
|
|
|
(1,085
|
)
|
Liabilities
settled
|
|
|
(34
|
)
|
|
|
(200
|
)
|
Balance at
end of period
|
|
|
24,666
|
|
|
|
23,278
|
|
Less
current portion of asset retirement obligation
|
|
|
(917
|
)
|
|
|
(917
|
)
|
Long-term
portion of asset retirement obligation
|
|
$
|
23,749
|
|
|
$
|
22,361
|
|
10.
EMPLOYEE BENEFITS
In
conjunction with the acquisition of the coal operations of American Electric Power on April 16, 2004, the Operating Company acquired
a postretirement benefit plan that provided healthcare to eligible employees at its Hopedale operations. The Partnership has no
other postretirement plans.
On
December 10, 2015, the Partnership notified the employees at its Hopedale operations that healthcare benefits from the postretirement
benefit plan would cease on January 31, 2016. The negative plan amendment that arose on December 10, 2015 resulted in an approximate
$6.5 million prior service cost benefit. The Partnership amortized the prior service cost benefit over the remaining term of the
benefits provided through January 31, 2016. For the nine months ended September 30, 2016, the Partnership recognized a benefit
of approximately $3.9 million from the plan amendment in the Cost of operations line of the unaudited condensed consolidated statements
of operations and comprehensive income.
401(k)
Plans
—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees.
Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum
contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the
Operating Company’s discretion. The expense under these plans for the three and nine months ended September 30, 2017 and
2016 is included in Cost of operations and Selling, general and administrative expense in the Partnership’s unaudited condensed
consolidated statements of operations and comprehensive income and was as follows:
|
|
Three
months ended September 30,
|
|
|
Nine
months ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
|
|
(in
thousands)
|
|
401(k)
plan expense
|
|
$
|
387
|
|
|
$
|
406
|
|
|
$
|
1,107
|
|
|
$
|
1,113
|
|
11.
EQUITY-BASED COMPENSATION/PARTNERS’ CAPITAL
Equity-Based
Compensation
— In October 2010, the General Partner established the Rhino Long-Term Incentive Plan (the “Plan”
or “LTIP”). The Plan is intended to promote the interests of the Partnership by providing to employees, consultants
and directors of the General Partner, the Partnership or affiliates of either, incentive compensation awards to encourage superior
performance. The LTIP provides for grants of restricted units, unit options, unit appreciation rights, phantom units, unit awards,
and other unit-based awards.
As
discussed in Note 1, on March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests
of Rhino GP LLC as well as 945,525 issued and outstanding subordinated units from Wexford Capital. Royal obtained control of,
and a majority limited partner interest, in the Partnership with the completion of this transaction, which constituted a change
in control of the Partnership. The language in the Partnership’s phantom unit and restricted unit grant agreements states
that all outstanding, unvested units would become immediately vested upon a change in control. For the nine months ended September
30, 2016, the Partnership recognized approximately $10,000 of expense from the vesting of these units as a result of the change
in control.
Partners’
Capital
— On September 1, 2017, Royal elected to convert the Weston Promissory Note of $2.1 million (including accrued
interest) and the Rhino Promissory Note of $2.0 million to shares of Royal common stock. Royal issued 914,797 shares of its common
stock to the Partnership at a conversion price of $4.51 per share. The price per share was calculated per the method specified
in the letter agreement discussed above. Per the guidance in ASC 505, the Partnership recorded the $4.1 million conversion of
the Weston Promissory Note and Rhino Promissory Note as Investment in Royal common stock in the Partners’ Capital section
of the Partnership’s unaudited condensed consolidated statements of financial position since Royal does not have significant
economic activity apart from its investment in the Partnership.
12.
COMMITMENTS AND CONTINGENCIES
Coal
Sales Contracts and Contingencies
—As of September 30, 2017, the Partnership had commitments under sales contracts
to deliver annually scheduled base quantities of coal as follows:
Year
|
|
Tons
(in thousands)
|
|
|
Number
of customers
|
|
2017-Q4
|
|
|
1,329
|
|
|
|
14
|
|
2018
|
|
|
1,825
|
|
|
|
6
|
|
2019
|
|
|
700
|
|
|
|
2
|
|
Some
of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of
factors and indices.
Purchase
Commitments
— The Partnership has a commitment to purchase approximately 1.0 million gallons of diesel fuel at fixed
prices from January 2017 through December 2017 for approximately $2.0 million.
Purchased
Coal Expenses
—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts.
In addition, the Partnership incurs expense from time to time related to coal purchased on the over-the-counter market (“OTC”).
The Partnership had no expense for purchase coal from coal purchase contracts or expense from OTC purchases for the three and
nine months ended September 30, 2017 and 2016.
Leases
—The
Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal
reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the three and
nine months ended September 30, 2017 and 2016 are included in Cost of operations in the Partnership’s unaudited condensed
consolidated statements of operations and comprehensive income and was as follows:
|
|
Three
months ended September 30,
|
|
|
Nine
months ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
|
|
(in
thousands)
|
|
Lease
expense
|
|
$
|
726
|
|
|
$
|
1,438
|
|
|
$
|
3,217
|
|
|
$
|
3,517
|
|
Royalty
expense
|
|
$
|
3,636
|
|
|
$
|
2,409
|
|
|
$
|
10,963
|
|
|
$
|
7,350
|
|
Joint
Ventures
—The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the
first quarter of 2012. The Partnership did not make any capital contributions to the Timber Wolf joint venture during the nine
months ended September 30, 2017 or 2016.
Prior
to the Partnership’s contribution of Sturgeon to Mammoth, Inc. in June 2017, the Partnership may have contributed additional
capital to the Sturgeon joint venture that was formed in the third quarter of 2014. The Partnership made an initial capital contribution
of $5.0 million during the third quarter ended September 30, 2014 based upon its proportionate ownership interest. The Partnership
did not make any capital contributions to the Sturgeon joint venture during the nine months ended September 30, 2017 or 2016.
See Note 2 for discussion on the contribution of Sturgeon to Mammoth, Inc.
Series
A preferred unit distributions-
For the nine months ended September 30, 2017
,
the Partnership accrued $4.1
million for distributions due to holders of Series A preferred units. See Note 1.
13.
EARNINGS PER UNIT (“EPU”)
On
April 18, 2016, the Partnership completed a 1-for-10 reverse split on its common units and subordinated units. The following tables
present a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended September
30, 2017 and 2016, which include the retrospective application of the 1-for-10 reverse unit split:
Diluted
EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted
EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. Since the
Partnership incurred total net losses for the nine months ended September 30, 2017 and the three and nine months ended September
30, 2016, all potential dilutive units were excluded from the diluted EPU calculation for these periods. There were no dilutive
potential units for the three months ended September 30, 2017.
Three
months ended September 30, 2017
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
Preferred
Unitholders
|
|
|
|
(in
thousands, except per unit data)
|
|
Numerator:
|
|
|
|
Interest
in net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income from continuing operations
|
|
$
|
1
|
|
|
$
|
25
|
|
|
$
|
2
|
|
|
$
|
1,644
|
|
Net
income from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
interest in net income
|
|
$
|
1
|
|
|
$
|
25
|
|
|
$
|
2
|
|
|
$
|
1,644
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
12,994
|
|
|
|
1,236
|
|
|
|
1,500
|
|
Weighted
average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
12,994
|
|
|
|
1,236
|
|
|
|
1,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1.10
|
|
Net
income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net
income per common unit, basic
|
|
|
n/a
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1.10
|
|
Net
income per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
1.10
|
|
Net
income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net
income per common unit, diluted
|
|
|
n/a
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
1.10
|
|
Three
months ended September 30, 2016
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
Preferred
Unitholders
|
|
|
(in
thousands, except per unit data)
|
|
|
|
Numerator:
|
|
|
|
|
|
Interest
in net (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) from continuing operations
|
|
$
|
(21
|
)
|
|
$
|
(2,758
|
)
|
|
$
|
(431
|
)
|
|
n/a
|
Net
(loss) from discontinued operations
|
|
|
(4
|
)
|
|
|
(494
|
)
|
|
|
(77
|
)
|
|
n/a
|
Total
interest in net (loss)
|
|
$
|
(25
|
)
|
|
$
|
(3,252
|
)
|
|
$
|
(508
|
)
|
|
n/a
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
7,906
|
|
|
|
1,236
|
|
|
n/a
|
Weighted
average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
7,906
|
|
|
|
1,236
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.35
|
)
|
|
n/a
|
Net
(loss) per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(0.06
|
)
|
|
|
(0.06
|
)
|
|
n/a
|
Net
(loss) per common unit, basic
|
|
|
n/a
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.41
|
)
|
|
n/a
|
Net
(loss) per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.35
|
)
|
|
n/a
|
Net
(loss) per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(0.06
|
)
|
|
|
(0.06
|
)
|
|
n/a
|
Net
(loss) per common unit, diluted
|
|
|
n/a
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.41
|
)
|
|
n/a
|
Nine
months ended September 30, 2017
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
Preferred
Unitholders
|
|
|
(in
thousands, except per unit data)
|
|
Numerator:
|
|
|
|
Interest
in net (loss)/income:
|
|
|
|
|
|
|
|
|
Net
(loss)/income from continuing operations
|
|
$
|
(18
|
)
|
|
$
|
(3,803
|
)
|
|
$
|
(364
|
)
|
|
$4,118
|
Net
(loss)/income from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
-
|
Total
interest in net (loss)/income
|
|
$
|
(18
|
)
|
|
$
|
(3,803
|
)
|
|
$
|
(364
|
)
|
|
$4,118
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
12,942
|
|
|
|
1,236
|
|
|
1,500
|
Weighted
average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
12,942
|
|
|
|
1,236
|
|
|
1,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss)/income per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss)/income per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(0.29
|
)
|
|
$
|
(0.29
|
)
|
|
$2.75
|
Net
(loss)/income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
|
-
|
Net
(loss)/income per common unit, basic
|
|
|
n/a
|
|
|
$
|
(0.29
|
)
|
|
$
|
(0.29
|
)
|
|
$2.75
|
Net
(loss)/income per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss)/income per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(0.29
|
)
|
|
$
|
(0.29
|
)
|
|
2.75
|
Net
(loss)/income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
|
-
|
Net
(loss)/income per common unit, diluted
|
|
|
n/a
|
|
|
$
|
(0.29
|
)
|
|
$
|
(0.29
|
)
|
|
2.75
|
Nine
months ended September 30, 2016
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
Preferred
Unitholders
|
|
|
(in
thousands, except per unit data)
|
|
|
|
Numerator:
|
|
|
|
|
|
Interest
in net (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) from continuing operations
|
|
$
|
(87
|
)
|
|
$
|
(7,144
|
)
|
|
$
|
(1,788
|
)
|
|
n/a
|
Net
(loss) from discontinued operations
|
|
|
(750
|
)
|
|
|
(93,734
|
)
|
|
|
(23,456
|
)
|
|
n/a
|
Total
interest in net (loss)
|
|
$
|
(837
|
)
|
|
$
|
(100,878
|
)
|
|
$
|
(25,244
|
)
|
|
n/a
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
4,937
|
|
|
|
1,236
|
|
|
n/a
|
Weighted
average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
4,937
|
|
|
|
1,236
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(1.45
|
)
|
|
$
|
(1.45
|
)
|
|
n/a
|
Net
(loss) per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(18.98
|
)
|
|
|
(18.98
|
)
|
|
n/a
|
Net
(loss) per common unit, basic
|
|
|
n/a
|
|
|
$
|
(20.43
|
)
|
|
$
|
(20.43
|
)
|
|
n/a
|
Net
(loss) per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(1.45
|
)
|
|
$
|
(1.45
|
)
|
|
n/a
|
Net
(loss) per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(18.98
|
)
|
|
|
(18.98
|
)
|
|
n/a
|
Net
(loss) per common unit, diluted
|
|
|
n/a
|
|
|
$
|
(20.43
|
)
|
|
$
|
(20.43
|
)
|
|
n/a
|
14.
MAJOR CUSTOMERS
The
Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues:
|
|
September
30
|
|
|
December
31
|
|
|
Nine
months
|
|
|
Nine
months
|
|
|
|
2017
|
|
|
2016
|
|
|
ended
|
|
|
ended
|
|
|
|
Receivable
|
|
|
Receivable
|
|
|
September
30
|
|
|
September
30
|
|
|
|
Balance
|
|
|
Balance
|
|
|
2017
Sales
|
|
|
2016
Sales
|
|
|
|
(in
thousands)
|
|
LG&E
and KU (PPL)
|
|
$
|
1,749
|
|
|
$
|
1,496
|
|
|
$
|
30,971
|
|
|
$
|
31,333
|
|
Big
Rivers Electric Corporation
|
|
|
1,133
|
|
|
|
-
|
|
|
|
18,387
|
|
|
|
14,045
|
|
Integrity
Coal Sales
|
|
|
2,125
|
|
|
|
1,975
|
|
|
|
18,152
|
|
|
|
2,532
|
|
Dominion
Energy
|
|
|
1,826
|
|
|
|
-
|
|
|
|
17,148
|
|
|
|
4,673
|
|
15.
FAIR VALUE OF
FINANCIAL INSTRUMENTS
The
Partnership determines the fair value of assets and liabilities based on the exchange price that would be received for an asset
or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an
orderly transaction between market participants. The fair values are based on assumptions that market participants would use when
pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs
to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable.
Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Partnership’s
assumptions of what market participants would use.
The
fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:
Level
One - Quoted prices for identical instruments in active markets.
Level
Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that
use significant observable inputs.
Level
Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity.
In
those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy,
the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the
fair value hierarchy.
The
book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their
respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership’s
amended and restated senior secured credit facility was based upon a Level 2 measurement utilizing a market approach, which incorporated
market-based interest rate information with credit risks similar to the Partnership. The fair value of the Partnership’s
amended and restated senior secured credit facility approximates the carrying value at September 30, 2017.
As
of September 30, 2017 and December 31, 2016, the Partnership had a recurring fair value measurement relating to its investment
in Mammoth, Inc. As discussed in Note 2, in October 2016, the Partnership contributed its limited partner interests in Mammoth
to Mammoth, Inc. in exchange for 234,300 shares of common stock of Mammoth, Inc. The common stock of Mammoth, Inc. began trading
on the NASDAQ Global Select Market in October 2016 under the ticker symbol TUSK and the Partnership sold 1,953 shares during the
initial public offering of Mammoth, Inc. and received proceeds of approximately $27,000. In June 2017, the Partnership contributed
its limited partner interests in Sturgeon to Mammoth Inc. in exchange for 336,447 shares of common stock of Mammoth, Inc. As of
September 30, 2017, the Partnership owned 568,794 shares of Mammoth, Inc. The Partnership’s shares of Mammoth, Inc. are
classified as an available-for-sale investment on the Partnership’s unaudited condensed consolidated statements of financial
position. Based on the availability of a quoted price, the recurring fair value measurement of the Mammoth, Inc. shares is a Level
1 measurement.
16.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
The
unaudited condensed consolidated statements of cash flows for the nine months ended September 30, 2017 and 2016 excludes approximately
$1.3 million and $0.2 million, respectively, of property additions, which are recorded in accounts payable.
17.
SEGMENT INFORMATION
The
Partnership produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah. The Partnership
sells primarily to electric utilities in the United States. For the three and nine months ended September 30, 2017, the Partnership
had four reportable segments: Central Appalachia (comprised of both surface and underground mines located in Eastern Kentucky
and Southern West Virginia), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Rhino Western
(comprised of an underground mine in Utah) and Illinois Basin (comprised of an underground mine in western Kentucky).
The
Partnership’s Other category is comprised of the Partnership’s ancillary businesses and its remaining oil and natural
gas activities. The Partnership has not provided disclosure of total expenditures by segment for long-lived assets, as the Partnership
does not maintain discrete financial information concerning segment expenditures for long lived-assets, and accordingly such information
is not provided to the Partnership’s chief operating decision maker. The information provided in the following tables represents
the primary measures used to assess segment performance by the Partnership’s chief operating decision maker. For the 2017
reporting period, the Partnership changed its methodology for allocating interest expense to its reportable segments where interest
expense is no longer allocated to the reportable segments and is reported in the Other category. All prior periods have been recast
to reflect this allocation methodology change.
Reportable
segment results of operations for the three months ended September 30, 2017 are as follows (Note: “DD&A” refers
to depreciation, depletion and amortization):
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
Total
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(in thousands)
|
|
Total revenues
|
|
$
|
27,891
|
|
|
$
|
6,398
|
|
|
$
|
9,080
|
|
|
$
|
14,965
|
|
|
$
|
12
|
|
|
$
|
58,346
|
|
DD&A
|
|
|
1,890
|
|
|
|
379
|
|
|
|
1,080
|
|
|
|
1,755
|
|
|
|
84
|
|
|
|
5,188
|
|
Interest expense
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,011
|
|
|
|
1,011
|
|
Net income (loss) from continuing operations
|
|
$
|
3,785
|
|
|
$
|
(910
|
)
|
|
$
|
1,416
|
|
|
$
|
107
|
|
|
$
|
(2,726
|
)
|
|
$
|
1,672
|
|
Reportable
segment results of operations for the three months ended September 30, 2016 are as follows:
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
Total
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(in thousands)
|
|
Total revenues
|
|
$
|
10,432
|
|
|
$
|
10,974
|
|
|
$
|
7,219
|
|
|
$
|
14,576
|
|
|
$
|
214
|
|
|
$
|
43,415
|
|
DD&A
|
|
|
1,642
|
|
|
|
777
|
|
|
|
1,292
|
|
|
|
2,638
|
|
|
|
140
|
|
|
|
6,489
|
|
Interest expense
|
|
|
205
|
|
|
|
38
|
|
|
|
41
|
|
|
|
78
|
|
|
|
1,596
|
|
|
|
1,958
|
|
Net (loss)/income from continuing operations
|
|
$
|
(233
|
)
|
|
$
|
3,633
|
|
|
$
|
567
|
|
|
$
|
(1,559
|
)
|
|
$
|
(5,618
|
)
|
|
$
|
(3,210
|
)
|
Reportable
segment results of operations for the nine months ended September 30, 2017 as are follows:
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
Total
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(in thousands)
|
|
Total revenues
|
|
$
|
76,880
|
|
|
$
|
17,014
|
|
|
$
|
25,141
|
|
|
$
|
49,377
|
|
|
$
|
20
|
|
|
$
|
168,432
|
|
DD&A
|
|
|
5,812
|
|
|
|
1,294
|
|
|
|
3,396
|
|
|
|
5,708
|
|
|
|
285
|
|
|
|
16,495
|
|
Interest expense
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,131
|
|
|
|
3,131
|
|
Net income (loss) from continuing operations
|
|
$
|
9,416
|
|
|
$
|
(3,267
|
)
|
|
$
|
1,570
|
|
|
$
|
1,736
|
|
|
$
|
(9,522
|
)
|
|
$
|
(67
|
)
|
Reportable
segment results of operations for the nine months ended September 30, 2016 as are follows:
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
Total
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(in thousands)
|
|
Total revenues
|
|
$
|
21,673
|
|
|
$
|
31,707
|
|
|
$
|
25,140
|
|
|
$
|
45,456
|
|
|
$
|
382
|
|
|
$
|
124,358
|
|
DD&A
|
|
|
4,951
|
|
|
|
2,541
|
|
|
|
4,107
|
|
|
|
6,319
|
|
|
|
423
|
|
|
|
18,341
|
|
Interest expense
|
|
|
596
|
|
|
|
204
|
|
|
|
118
|
|
|
|
230
|
|
|
|
4,047
|
|
|
|
5,195
|
|
Net (loss)/income from continuing operations
|
|
$
|
(5,513
|
)
|
|
$
|
10,623
|
|
|
$
|
1,027
|
|
|
$
|
(1,012
|
)
|
|
$
|
(14,145
|
)
|
|
$
|
(9,020
|
)
|
18.
ACCUMULATED DISTRIBUTION ARREARAGES
Beginning
with the quarter ended June 30, 2015 and continuing through the quarter ended September 30, 2017, we have suspended the cash distribution
on our common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, we announced cash
distributions per common unit at levels lower than the minimum quarterly distribution. We have not paid any distribution on our
subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were
the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow. The current amount
of accumulated arrearages as of September 30, 2017 related to the common unit distribution was approximately $380.5 million.
19.
SUBSEQUENT EVENTS
On
October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy
Court. The Partnership is evaluating the Chapter 11 petitions filed by Armstrong Energy and the Partnership will further evaluate
the detailed restructuring plan when it is submitted by Armstrong Energy to determine what, if any, effect the ultimate outcome
of the Chapter 11 proceedings will have on the Partnership’s financial statements.
On
November 7, 2017, the Partnership closed an agreement with a third party to transfer 100% of the memberships interests and related
assets and liabilities in the Partnership’s Sands Hill Mining entity to the third party in exchange for a future override
royalty for any mineral sold, excluding coal, from Sands Hill Mining after the closing date. The Partnership expects to recognize
a gain from the sale of Sands Hill since the third party will assume the reclamation obligations associated with this operation.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless
the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or
similar terms refer to Rhino Resource Partners LP and its subsidiaries. References to our “general partner” refer
to Rhino GP LLC, the general partner of Rhino Resource Partners LP. The following discussion of the historical financial condition
and results of operations should be read in conjunction with the historical audited consolidated financial statements and accompanying
notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 and the section “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” included in such Annual Report on Form 10-K.
In
addition, this discussion includes forward looking statements that are subject to risks and uncertainties that may result in actual
results differing from statements we make. Please read the section “Cautionary Note Regarding Forward Looking Statements”.
In addition, factors that could cause actual results to differ include those risks and uncertainties discussed in Part I, Item
1A. “Risk Factors” also included in our Annual Report on Form 10-K for the year ended December 31, 2016.
In
August 2016, we sold our Elk Horn coal leasing company (“Elk Horn”) to a third party for total cash consideration
of $12.0 million. Our unaudited condensed consolidated statements of operations and comprehensive income have been retrospectively
adjusted to reclassify our Elk Horn operations to discontinued operations for the three and nine months ended September 30, 2016.
Overview
We
are a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities,
including energy infrastructure investments. We produce, process and sell high quality coal of various steam and metallurgical
grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers
for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material
in the steel manufacturing process. In addition, we have expanded our business to include infrastructure support services, as
well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the
Utica Shale region. We have also invested in joint ventures that provide sand for fracking operations to drillers in the Utica
Shale region and other oil and natural gas basins in the United States.
We
have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin
and the Western Bituminous region. As of December 31, 2016, we controlled an estimated 256.9 million tons of proven and probable
coal reserves, consisting of an estimated 203.5 million tons of steam coal and an estimated 53.4 million tons of metallurgical
coal. In addition, as of December 31, 2016, we controlled an estimated 196.5 million tons of non-reserve coal deposits.
We
operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate may
vary from time to time depending on a number of factors, including the demand for and price of coal, depletion of economically
recoverable reserves and availability of experienced labor.
Our
principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our
diverse asset base in order to resume, and, over time, increase our quarterly cash distributions. In addition, we intend to continue
to expand and potentially diversify our operations through strategic acquisitions, including the acquisition of long-term, cash
generating natural resource assets. We believe that such assets will allow us to grow our cash available for distribution and
enhance stability of our cash flow.
For
the three and nine months ended September 30, 2017, we generated revenues of approximately $58.3 million and $168.4 million, respectively,
and we generated net income of $1.7 million for the three months ended September 30, 2017 and net loss of $0.1 million for the
nine months ended September 30, 2017. For the three months ended September 30, 2017, we produced and sold approximately 1.1 million
tons of coal, of which approximately 35% were sold pursuant to long-term supply contracts as we executed more spot sales in the
quarter ended September 30, 2017. For the nine months ended September 30, 2017, we produced and sold approximately 3.1 million
tons of coal, of which approximately 65% were sold pursuant to long-term supply contracts.
Current
Liquidity and Outlook
Since
our credit facility has an expiration date of December 31, 2017, we determined that our credit facility debt liability at September
30, 2017 and December 31, 2016 of $9.9 million and $10.0 million, respectively, should be classified as a current liability on
our unaudited condensed consolidated statements of financial position. The classification of our credit facility balance as a
current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months.
We
are evaluating and negotiating alternative credit facilities. We currently anticipate repaying the debt outstanding under our
credit facility with the proceeds from one of these alternative facilities in the fourth quarter of 2017. If it becomes apparent
this refinancing will not occur prior to December 31, 2017, we may seek a short-term extension of the Partnership’s existing
credit facility. There can be no assurance that we will be able to refinance our credit facility or that the lenders will be willing
to grant an extension to provide us with additional time to refinance. If we are unable to secure a replacement facility, we will
lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business,
including repaying amounts due under our credit facility upon expiration, which could cause us to further curtail our operations
and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional
assets, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune
time. If we are not able to fund our liquidity requirements, we may not be able to continue as a going concern.
For more information about our liquidity and our credit facility, please read “—Liquidity and Capital Resources.”
Further,
even if we are able to refinance our credit facility, the replacement credit facility may include a significantly higher interest
rate, significant amortization payments, or liens on a substantial portion of our assets, all of which could adversely impact
our future plans and operations.
Since
the current maturity date of our credit facility is December 31, 2017, we are unable to demonstrate that we have sufficient liquidity
to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going
concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our
ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31,
2016. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship
with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise
additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of
operations, financial condition and prospects could be materially adversely affected.
As
of September 30, 2017, our available liquidity was $8.3 million, including cash on hand of $0.1 million and $8.2 million available
under our amended and restated credit agreement. On May 13, 2016, we entered into a fifth amendment (the “Fifth Amendment”)
of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017.
Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit
commitments were reduced to $55 million or less as of December 31, 2016. The Fifth Amendment also immediately reduced the revolving
credit commitments under the credit facility to a maximum of $75 million and maintains the amount available for letters of credit
at $30 million. As of December 31, 2016, we met the requirements to extend the maturity date of the credit facility to December
31, 2017. In December 2016, we entered into a seventh amendment (the “Seventh Amendment”) of our amended and restated
credit agreement. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provided for
additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment
further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from
any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. For more
information about our amended and restated credit agreement, please read “—Recent Developments—Amended and Restated
Credit Agreement Amendments” below.
We
continue to take measures, including the suspension of cash distributions on our common and subordinated units and cost and productivity
improvements, to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures
and meet our financial commitments and debt service obligations.
Recent
Developments
Sands
Hill Disposition
On
November 7, 2017, we closed an agreement with a third party to transfer 100% of the memberships interests and related assets and
liabilities in our Sands Hill Mining entity to the third party in exchange for a future override royalty for any mineral sold,
excluding coal, from Sands Hill Mining after the closing date. We expect to recognize a gain from the sale of Sands Hill since
the third party will assume the reclamation obligations associated with this operation.
Option
Agreement
On
December 30, 2016, we entered into the Option Agreement with Royal Energy Resources, Inc. (“Royal”), Rhino Resources
Partners Holdings, LLC (“Rhino Holdings”), and our general partner. Royal is a publicly traded company listed on the
OTC market (OTCQB: ROYE) and is focused on the acquisition of coal, natural gas and renewable energy assets that are profitable
at current distressed prices. Rhino Holdings is an entity wholly owned by certain investment partnerships managed by Yorktown
Partners LLC (“Yorktown”), and our general partner. Upon execution of the Option Agreement, we received a Call Option
from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy that is owned by investment
partnerships managed by Yorktown, representing approximately 97% of the outstanding common stock of Armstrong Energy. Armstrong
Energy is a coal producing company with approximately 567 million tons of proven and probable reserves and five mines located
in the Illinois Basin in western Kentucky as of December 31, 2016. The Option Agreement stipulates that we can exercise the Call
Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting us the Call
Option, we issued 5.0 million Call Option Premium Units to Rhino Holdings upon the execution of the Option Agreement. The Option
Agreement stipulates we can exercise the Call Option and purchase the common stock of Armstrong Energy in exchange for a number
of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings
owning 51% of the fully diluted common units of us. The purchase of Armstrong Energy through the exercise of the Call Option would
also require Royal to transfer a 51% ownership interest in our general partner to Rhino Holdings. Our ability to exercise the
Call Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its
bondholders to restructure its bonds and (ii) the amendment of our revolving credit facility to permit the acquisition of Armstrong
Energy.
The
Option Agreement also contains a Put Option granted by us to Rhino Holdings whereby Rhino Holdings has the right, but not the
obligation, to cause us to purchase substantially all of the outstanding common stock of Armstrong Energy from Rhino Holdings
under the same terms and conditions discussed above for the Call Option. The exercise of the Put Option is dependent upon (i)
the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the termination and repayment
of any outstanding balance under our revolving credit facility.
The
Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising
from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the Seventh Amendment
and the GP Amendment (defined below). Upon the request by Rhino Holdings, we will also enter into a registration rights agreement
that provides Rhino Holdings with the right to demand two shelf registration statements and registration statements on Form S-1,
as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding common units.
Pursuant
to the Option Agreement, the Second Amended and Restated Limited Liability Company Agreement of our general partner was amended
(“GP Amendment”). Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of our
General Partner as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director.
Rhino Holdings has the right to appoint two members to the board of directors of our General Partner for as long as it continues
to own 20% of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent
to any delegation of authority to any committee of the board of our General Partner. Upon the exercise of the Call Option or the
Put Option, the Second Amended and Restated Limited Liability Company Agreement of our General Partner, as amended, will be further
amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors and that the remaining
director will be the chief executive officer of our General Partner unless agreed otherwise.
The
Option Agreement superseded and terminated the equity exchange agreement entered into on September 30, 2016 by and among Royal,
Rhino Holdings and our general partner.
On
October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy
Court. Per the Chapter 11 petitions, Armstrong Energy will file a detailed restructuring plan as part of the Chapter 11 proceedings.
Based on the uncertain facts and circumstances surrounding the current state of the Armstrong Energy Chapter 11 proceedings, which
includes the possibility that we will still exercise the Call Option as outlined in Note 1, we concluded that the value of the
Call Option was not impaired as of September 30, 2017.
Series
A Preferred Unit Purchase Agreement
On
December 30, 2016, we entered into a Series A Preferred Unit Purchase Agreement (“Preferred Unit Agreement”) with
Weston Energy LLC (“Weston”), an entity wholly owned by certain investment partnerships managed by Yorktown, and Royal.
Under the Preferred Unit Agreement, Weston and Royal agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred
units representing limited partner interests in us at a price of $10.00 per Series A preferred unit. The Series A preferred units
have the preferences, rights and obligations set forth in our Fourth Amended and Restated Agreement of Limited Partnership, which
is described below. In exchange for the Series A preferred units, Weston and Royal paid cash of $11.0 million and $2.0 million,
respectively, to us and Weston assigned to us a $2.0 million note receivable from Royal originally dated September 30, 2016. (“Weston
Promissory Note”) Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”
The
Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for
as long as the Series A preferred units are outstanding, we will cause CAM Mining, one of our subsidiaries, to conduct its business
in the ordinary course consistent with past practice and use reasonable best efforts to maintain and preserve intact its current
organization, business and franchise and to preserve the rights, franchises, goodwill and relationships of its employees, customers,
lenders, suppliers, regulators and others having business relationships with CAM Mining.
The
Preferred Unit Agreement stipulates that upon the request of the holder of the majority of our common units following their conversion
from Series A preferred units, as outlined in our partnership agreement, we will enter into a registration rights agreement with
such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form
S-1, as well as piggyback registration rights.
On
January 27, 2017, Royal sold 100,000 of its Series A preferred units to Weston and its other 100,000 Series A preferred units
to another third party.
Letter
Agreement Regarding Rhino Promissory Note and Weston Promissory Note
On
December 30, 2016, we entered into a letter agreement with Royal whereby the maturity dates of the Weston Promissory Note and
the final installment payment of the Rhino Promissory Note were extended to December 31, 2018. The letter agreement further provides
that the aggregate $4.0 million balance of the Weston Promissory Note and Rhino Promissory Note may be converted at Royal’s
option into a number of shares of Royal’s common stock equal to the outstanding balance multiplied by seventy-five percent
(75%) of the volume-weighted average closing price of Royal’s common stock for the 90 days preceding the date of conversion
(“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50. On September 1, 2017,
Royal elected to convert the Weston Promissory Note of $2.1 million (including accrued interest) and the Rhino Promissory Note
of $2.0 million to shares of Royal common stock. Royal issued 914,797 shares of its common stock to us at a conversion price of
$4.51 per share. The price per share was calculated per the method specified above. We recorded the $4.1 million conversion of
the Weston Promissory Note and Rhino Promissory Note as Investment in Royal common stock in the Partners’ Capital section
of the Partnerships’ unaudited condensed consolidated statements of financial position.
Fourth
Amended and Restated Partnership Agreement of Limited Partnership
On
December 30, 2016, our General Partner entered into the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership
(“Amended and Restated Partnership Agreement”) to create, authorize and issue the Series A preferred units.
The
Series A preferred units are a new class of equity security that rank senior to all classes or series of our equity securities
with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units shall be entitled
to receive annual distributions equal to the greater of (i) 50% of the CAM Mining free cash flow (as defined below) and (ii) an
amount equal to the number of outstanding Series A preferred units multiplied by $0.80. “CAM Mining free cash flow”
is defined in our partnership agreement as (i) the total revenue of our Central Appalachia business segment, minus (ii) the cost
of operations (exclusive of depreciation, depletion and amortization) for our Central Appalachia business segment, minus (iii)
an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by us from our Central Appalachia
business segment. If we fail to pay any or all of the distributions in respect of the Series A preferred units, such deficiency
will accrue until paid in full and we will not be permitted to pay any distributions on our partnership interests that rank junior
to the Series A preferred units, including our common units. The Series A preferred units will be liquidated in accordance with
their capital accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances
of their capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.
The
Series A preferred units vote on an as-converted basis with the common units, and we will be restricted from taking certain actions
without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series
A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining
or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of
common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the
incurrence, assumption or guaranty of indebtedness for borrowed money in excess of $50.0 million except indebtedness relating
to entities or assets that are acquired by us or our affiliates that is in existence at the time of such acquisition or (vi) the
modification of CAM Mining’s accounting principles or the financial or operational reporting principles of our Central Appalachia
business segment, subject to certain exceptions.
We
will have the option to convert the outstanding Series A preferred units at any time on or after the time at which the amount
of aggregate distributions paid in respect of each Series A preferred unit exceeds $10.00 per unit. Each Series A preferred unit
will convert into a number of common units equal to the quotient (the “Series A Conversion Ratio”) of (i) the sum
of $10.00 and any unpaid distributions in respect of such Series A Preferred Unit divided by (ii) 75% of the volume-weighted average
closing price of the common units for the preceding 90 trading days (the “VWAP”); provided however, that the VWAP
will be capped at a minimum of $2.00 and a maximum of $10.00. On December 31, 2021, all outstanding Series A preferred units will
convert into common units at the then applicable Series A Conversion Ratio.
Amended
and Restated Credit Agreement Amendments
In
December 2016, we entered into a Seventh Amendment, which allows for the Series A preferred units as outlined in the Fourth Amended
and Restated Agreement of Limited Partnership, which is further discussed in “—Fourth Amended and Restated Partnership
Agreement”. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provides for
additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment
further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from
any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. The Seventh
Amendment alters the maximum leverage ratio to 4.0 to 1.0 effective December 31, 2016 through May 31, 2017 and 3.5 to 1.0 from
June 30, 2017 through December 31, 2017. The maximum leverage ratio shall be reduced by 0.50 to 1.0 for every $10.0 million of
net cash proceeds, in the aggregate, received after the Seventh Amendment date from (i) the issuance of any equity by us and/or
(ii) the disposition of any assets in excess of $2.0 million in the aggregate, provided, however, that in no event will the maximum
leverage ratio be reduced below 3.0 to 1.0.
The
Seventh Amendment alters the minimum consolidated EBITDA figure, as calculated on a rolling twelve months basis, to $12.5 million
from December 31, 2016 through May 31, 2017 and $15.0 million from June 30, 2017 through December 31, 2017. The Seventh Amendment
alters the maximum capital expenditures allowed, as calculated on a rolling twelve months basis, to $20.0 million through the
expiration of the credit facility. A condition precedent to the effectiveness of the Seventh Amendment was the receipt of the
$13.0 million of cash proceeds received by us from the issuance of the Series A preferred units pursuant to the Preferred Unit
Agreement, which we used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt
of $13.0 million cash proceeds fulfills the required Royal equity contributions as outlined in the previous amendments to our
credit agreement.
On
March 23, 2017, we entered into an eighth amendment (the “Eighth Amendment”) of our amended and restated credit agreement
that allows the annual auditor’s report for the years ending December 31, 2016 and 2015 to contain a qualification with
respect to the short-term classification of our credit facility balance without creating a default under our credit agreement.
On
June 9, 2017, we entered into a ninth amendment (the “Ninth Amendment”) of our amended and restated credit agreement
that permitted outstanding letters of credit to be replaced with different counterparties without affecting the revolving credit
commitments under the credit agreement. The Ninth Amendment also permits certain lease and sale leaseback transactions under the
credit agreement that do not affect the revolving credit commitments under the credit agreement for asset dispositions and also
do not factor in the calculation of the maximum capital expenditures allowed under the credit agreement.
As
of September 30, 2017 and December 31, 2016, we were in compliance with respect to all covenants contained in our credit agreement.
Reverse
Unit Split
On
April 18, 2016, we completed a 1-for-10 reverse split on our common units and subordinated units. Pursuant to the reverse split,
common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated unitholders received
one subordinated unit for every 10 subordinated units owned on April 18, 2016. All common and subordinated unit, net income (loss)
per unit and distribution per unit references included herein have been adjusted as if the change took place before the date of
the earliest transaction reported. Any fractional units resulting from the reverse unit split were rounded to the nearest whole
unit.
Distribution
Suspension
Beginning
with the quarter ended June 30, 2015 and continuing through the quarter ended September 30, 2017, we have suspended the cash distribution
on our common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, we announced cash
distributions per common unit at levels lower than the minimum quarterly distribution. We have not paid any distribution on our
subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were
the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow.
Pursuant
to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum
level of $4.45 per unit. Since our distributions for the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015
were below the minimum level and we altogether suspended the distribution beginning with the quarter ended June 30, 2015, we have
accumulated arrearages at September 30, 2017 related to the common unit distribution of approximately $380.5 million.
Factors
That Impact Our Business
Our
results of operations in the near term could be impacted by a number of factors, including (1) our ability to fund our ongoing
operations and necessary capital expenditures, (2) the availability of transportation for coal shipments, (3) poor mining conditions
resulting from geological conditions or the effects of prior mining, (4) equipment problems at mining locations, (5) adverse weather
conditions and natural disasters or (6) the availability and costs of key supplies and commodities such as steel, diesel fuel
and explosives.
On
a long-term basis, our results of operations could be impacted by, among other factors, (1) our ability to fund our ongoing operations
and necessary capital expenditures, (2) changes in governmental regulation, (3) the availability and prices of competing electricity-generation
fuels, (4) the world-wide demand for steel, which utilizes metallurgical coal and can affect the demand and prices of metallurgical
coal that we produce, (5) our ability to secure or acquire high-quality coal reserves and (6) our ability to find buyers for coal
under favorable supply contracts.
We
have historically sold a majority of our coal through long-term supply contracts and anticipate that we will continue to do so.
As of September 30, 2017, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:
Year
|
|
Tons (in thousands)
|
|
|
Number of customers
|
|
2017-Q4
|
|
|
1,329
|
|
|
|
14
|
|
2018
|
|
|
1,825
|
|
|
|
6
|
|
2019
|
|
|
700
|
|
|
|
2
|
|
Some
of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of
factors and indices.
Results
of Operations
Segment
Information
As
of September 30, 2017, we have four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois
Basin. Additionally, we have an Other category that includes our ancillary businesses and our remaining oil and natural gas activities.
Our Central Appalachia segment consists of two mining complexes: Tug River and Rob Fork, which, as of September 30, 2017, together
included one underground mine, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and
southern West Virginia. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex,
and the Leesville field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation
plant and loadout facility as of September 30, 2017. Our Sands Hill mining complex, located in southern Ohio, included one surface
mine, a preparation plant and a river terminal as of September 30, 2017. Our Rhino Western segment includes one underground mine
in the Western Bituminous region at our Castle Valley mining complex in Utah. Our Illinois Basin segment includes one underground
mine, preparation plant and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our
Taylorville field reserves located in central Illinois. Our Other category is comprised of our ancillary businesses and our remaining
oil and natural gas activities.
Evaluating
Our Results of Operations
Our
management uses a variety of financial measurements to analyze our performance, including (1) Adjusted EBITDA, (2) coal revenues
per ton and (3) cost of operations per ton.
Adjusted
EBITDA.
The discussion of our results of operations below includes references to, and analysis of, our segments’
Adjusted EBITDA results. Adjusted EBITDA, a Non-GAAP financial measure, represents net income before deducting interest expense,
income taxes and depreciation, depletion and amortization, while also excluding certain non-cash and/or non-recurring items. Adjusted
EBITDA is used by management primarily as a measure of our segments’ operating performance. Adjusted EBITDA should not be
considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of
financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate Adjusted EBITDA identically,
our calculation may not be comparable to similarly titled measures of other companies. Please read “—Reconciliations
of Adjusted EBITDA” for reconciliations of Adjusted EBITDA to net income by segment for each of the periods indicated.
Coal
Revenues Per Ton
.
Coal revenues per ton represents coal revenues divided by tons of coal sold. Coal revenues per
ton is a key indicator of our effectiveness in obtaining favorable prices for our product.
Cost
of Operations Per Ton
.
Cost of operations per ton sold represents the cost of operations (exclusive of depreciation,
depletion and amortization) divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency
of operations.
Summary
The
following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational
data for the three and nine months ended September 30, 2017 and 2016:
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
|
|
(in millions)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
58.3
|
|
|
$
|
43.4
|
|
|
$
|
168.4
|
|
|
$
|
124.4
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
|
46.5
|
|
|
|
35.2
|
|
|
|
138.1
|
|
|
|
98.1
|
|
Freight and handling costs
|
|
|
1.5
|
|
|
|
0.4
|
|
|
|
2.5
|
|
|
|
1.5
|
|
Depreciation, depletion and amortization
|
|
|
5.2
|
|
|
|
6.5
|
|
|
|
16.5
|
|
|
|
18.3
|
|
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)
|
|
|
2.6
|
|
|
|
4.3
|
|
|
|
8.5
|
|
|
|
12.3
|
|
(Gain)on sale/disposal of assets-net
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
(0.4
|
)
|
Income/(loss) from operations
|
|
|
2.6
|
|
|
|
(2.9
|
)
|
|
|
2.9
|
|
|
|
(5.4
|
)
|
Interest and other (expense)/income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(1.0
|
)
|
|
|
(2.0
|
)
|
|
|
(3.1
|
)
|
|
|
(5.2
|
)
|
Gain on extinguishment of debt
|
|
|
-
|
|
|
|
1.7
|
|
|
|
-
|
|
|
|
1.7
|
|
Interest income
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Equity in net (loss)of unconsolidated affiliates
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(0.1
|
)
|
Total interest and other (expense)
|
|
|
(0.9
|
)
|
|
|
(0.3
|
)
|
|
|
(3.0
|
)
|
|
|
(3.6
|
)
|
Net income/(loss) from continuing operations
|
|
|
1.7
|
|
|
|
(3.2
|
)
|
|
|
(0.1
|
)
|
|
|
(9.0
|
)
|
Net (loss) from discontinued operations
|
|
|
-
|
|
|
|
(0.6
|
)
|
|
|
-
|
|
|
|
(117.9
|
)
|
Net income/(loss)
|
|
$
|
1.7
|
|
|
$
|
(3.8
|
)
|
|
$
|
(0.1
|
)
|
|
$
|
(126.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA from continuing operations
|
|
$
|
7.9
|
|
|
$
|
5.5
|
|
|
$
|
19.6
|
|
|
$
|
14.9
|
|
Adjusted EBITDA from discontinued operations
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
1.8
|
|
Total Adjusted EBITDA
|
|
$
|
7.9
|
|
|
$
|
5.6
|
|
|
$
|
19.6
|
|
|
$
|
16.7
|
|
Three
Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
Summary.
For the three months ended September 30, 2017, our total revenues increased to $58.3 million from $43.4 million for the
three months ended September 30, 2016, which is a 34.4% increase. We sold approximately 1.1 million tons of coal for the three
months ended September 30, 2017, which is a 28.8% increase compared to the tons of coal sold for the three months ended September
30, 2016. The increase in revenue and tons sold was primarily the result of increased production in Central Appalachia due to
recent increases in coal prices and demand for met and steam coal produced in this region. We anticipate the recent increase in
price and demand will continue to benefit our financial results for the remainder of 2017.
Net
income from continuing operations was $1.7 million for the three months ended September 30, 2017 compared to net loss from continuing
operations of $3.2 million for the three months ended September 30, 2016. Our net income from continuing operations improved during
the three months ended September 30, 2017 compared to 2016 primarily due to increased coal revenues from improved demand for met
and steam coal in our Central Appalachia segment discussed above. For the three months ended September 30, 2016, our total net
loss from continuing operations was impacted by an impairment charge of $2.0 million related to the note receivable from the sale
of our Deane mining complex.
Adjusted
EBITDA from continuing operations increased to $7.9 million for the three months ended September 30, 2017 from $5.5 million for
the three months ended September 30, 2016. Adjusted EBITDA from continuing operations increased period to period due to an increase
in net income during the three months ended September 30, 2017 compared to a net loss generated for the three months ended September
30, 2016.
Including
the net loss from discontinued operations of $0.6 million, our total net loss and Adjusted EBITDA for the three months ended September
30, 2016 were $3.8 million and $5.6 million, respectively. We did not incur a gain or loss from discontinued operations for the
three months ended September 30, 2017.
Tons
Sold.
The following table presents tons of coal sold by reportable segment for the three months ended September 30, 2017
and 2016:
|
|
Three months
|
|
|
Three months
|
|
|
Increase/
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
Tons
|
|
|
% *
|
|
|
|
(in thousands, except %)
|
|
Central Appalachia
|
|
|
381.6
|
|
|
|
179.7
|
|
|
|
201.9
|
|
|
|
112.4
|
%
|
Northern Appalachia
|
|
|
114.5
|
|
|
|
149.1
|
|
|
|
(34.6
|
)
|
|
|
(23.3
|
%)
|
Rhino Western
|
|
|
241.9
|
|
|
|
185.1
|
|
|
|
56.8
|
|
|
|
30.7
|
%
|
Illinois Basin
|
|
|
315.8
|
|
|
|
304.5
|
|
|
|
11.3
|
|
|
|
3.7
|
%
|
Total *
|
|
|
1,053.8
|
|
|
|
818.4
|
|
|
|
235.4
|
|
|
|
28.8
|
%
|
*
|
Calculated
percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts presented
in this table.
|
We
sold approximately 1.1 million tons of coal for the three months ended September 30, 2017, which was a 28.8% increase compared
to the three months ended September 30, 2016. The increase in tons sold period over period was primarily due to higher sales from
our Central Appalachia segment due to the increased demand for met and steam coal from this region. Tons of coal sold in our Central
Appalachia segment increased by approximately 112.4% to approximately 0.4 million tons for the three months ended September 30,
2017 compared to the three months ended September 30, 2016, primarily due to an increase in demand for met and steam coal tons
from this region. For our Northern Appalachia segment, tons of coal sold decreased by approximately 23.3% for the three months
ended September 30, 2017 compared to the three months ended September 30, 2016, as we experienced a decrease in tons sold from
our Sands Hill and Hopedale operations due to weak demand for coal from this region. Coal sales from our Rhino Western segment
increased by approximately 30.7% for the three months ended September 30, 2017 compared to the same period in 2016 due to increased
customer demand. For our Illinois Basin segment, tons of coal sold increased by approximately 3.7% for the three months ended
September 30, 2017 compared to the three months ended September 30, 2016 as we increased production and sales period over period
from our Pennyrile mine in western Kentucky to meet our contracted sales commitments.
Revenues.
The following table presents revenues and coal revenues per ton by reportable segment for the three months ended September
30, 2017 and 2016:
|
|
Three months
|
|
|
Three months
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
ended
|
|
|
Increase/(Decrease)
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
$
|
|
|
%*
|
|
|
|
(in millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
27.9
|
|
|
$
|
10.4
|
|
|
$
|
17.5
|
|
|
|
167.8
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
27.9
|
|
|
$
|
10.4
|
|
|
$
|
17.5
|
|
|
|
167.8
|
%
|
Coal revenues per ton*
|
|
$
|
73.02
|
|
|
$
|
57.91
|
|
|
$
|
15.11
|
|
|
|
26.1
|
%
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
4.6
|
|
|
$
|
8.8
|
|
|
$
|
(4.2
|
)
|
|
|
(48.0
|
%)
|
Freight and handling revenues
|
|
|
0.2
|
|
|
|
0.4
|
|
|
|
(0.2
|
)
|
|
|
(48.1
|
%)
|
Other revenues
|
|
|
1.6
|
|
|
|
1.8
|
|
|
|
(0.2
|
)
|
|
|
(9.3
|
%)
|
Total revenues
|
|
$
|
6.4
|
|
|
$
|
11.0
|
|
|
$
|
(4.6
|
)
|
|
|
(41.7
|
%)
|
Coal revenues per ton*
|
|
$
|
39.81
|
|
|
$
|
58.75
|
|
|
$
|
(18.94
|
)
|
|
|
(32.2
|
%)
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
9.1
|
|
|
$
|
7.2
|
|
|
$
|
1.9
|
|
|
|
25.8
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
9.1
|
|
|
$
|
7.2
|
|
|
$
|
1.9
|
|
|
|
25.8
|
%
|
Coal revenues per ton*
|
|
$
|
37.53
|
|
|
$
|
39.00
|
|
|
$
|
(1.47
|
)
|
|
|
(3.8
|
%)
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
14.9
|
|
|
$
|
14.6
|
|
|
$
|
0.3
|
|
|
|
2.4
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
14.9
|
|
|
$
|
14.6
|
|
|
$
|
0.3
|
|
|
|
2.4
|
%
|
Coal revenues per ton*
|
|
$
|
47.37
|
|
|
$
|
47.97
|
|
|
$
|
(0.60
|
)
|
|
|
(1.2
|
%)
|
Other**
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Freight and handling revenues
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
0.2
|
|
|
|
(0.2
|
)
|
|
|
(94.7
|
%)
|
Total revenues
|
|
$
|
-
|
|
|
$
|
0.2
|
|
|
$
|
(0.2
|
)
|
|
|
(94.7
|
%)
|
Coal revenues per ton*
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
56.5
|
|
|
$
|
41.0
|
|
|
$
|
15.5
|
|
|
|
37.7
|
%
|
Freight and handling revenues
|
|
|
0.2
|
|
|
|
0.4
|
|
|
|
(0.2
|
)
|
|
|
(48.1
|
%)
|
Other revenues
|
|
|
1.6
|
|
|
|
2.0
|
|
|
|
(0.4
|
)
|
|
|
(16.6
|
%)
|
Total revenues
|
|
$
|
58.3
|
|
|
$
|
43.4
|
|
|
$
|
14.9
|
|
|
|
34.4
|
%
|
Coal revenues per ton*
|
|
$
|
53.58
|
|
|
$
|
50.09
|
|
|
$
|
3.49
|
|
|
|
7.0
|
%
|
*
|
Percentages
and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
|
|
|
**
|
The
Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses also
do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the
Other category.
|
Our
coal revenues for the three months ended September 30, 2017 increased by approximately $15.5 million, or 37.7%, to approximately
$56.5 million from approximately $41.0 million for the three months ended September 30, 2016. The increase in coal revenues was
primarily due to an increase in met and steam coal tons sold in Central Appalachia as we saw increased demand for met and steam
coal from this region during the period. Coal revenues per ton was $53.58 for the three months ended September 30, 2017, an increase
of $3.49, or 7.0%, from $50.09 per ton for the three months ended September 30, 2016. This increase in coal revenues per ton was
primarily the result of a higher mix of higher priced met coal tons sold in Central Appalachia compared to the prior period.
For
our Central Appalachia segment, coal revenues increased by approximately $17.5 million, or 167.8%, to approximately $27.9 million
for the three months ended September 30, 2017 from approximately $10.4 million for the three months ended September 30, 2016.
This increase was primarily due to the increase in coal prices and demand for met and steam coal tons sold from this region. Coal
revenues per ton for our Central Appalachia segment increased by $15.11, or 26.1%, to $73.02 per ton for the three months ended
September 30, 2017 as compared to $57.91 for the three months ended September 30, 2016, which was primarily due to a higher mix
of higher priced met coal tons sold in Central Appalachia compared to the prior period.
For
our Northern Appalachia segment, coal revenues were approximately $4.6 million for the three months ended September 30, 2017,
a decrease of approximately $4.2 million, or 48.0%, from approximately $8.8 million for the three months ended September 30, 2016.
This decrease was primarily due to a decrease in tons sold from our Sands Hill and Hopedale operations in Northern Appalachia
due to weak demand for coal from the Northern Appalachia region during the three months ended September 30, 2017. Coal revenues
per ton decreased by $18.94 or 32.2% per ton for the three months ended September 30, 2017 as compared to $58.75 for the three
months ended September 30, 2016, which was primarily due to lower prices for tons sold from our Hopedale complex compared to the
prior year due to weak demand for coal from this region.
For
our Rhino Western segment, coal revenues increased by approximately $1.9 million, or 25.8%, to approximately $9.1 million for
the three months ended September 30, 2017 from approximately $7.2 million for the three months ended September 30, 2016 primarily
due to an increase in tons sold from the Castle Valley mine due to increased customer demand. Coal revenues per ton for our Rhino
Western segment decreased by $1.47 or 3.8% to $37.53 per ton for the three months ended September 30, 2017 as compared to $39.00
per ton for the three months ended September 30, 2016 due to lower contracted sales prices.
For
our Illinois Basin segment, coal revenues of approximately $14.9 million for the three months ended September 30, 2017 increased
by approximately $0.3 million, or 2.4%, compared to $14.6 million for the three months ended September 30, 2016. The increase
was due to increased sales from our Pennyrile mine in western Kentucky to fulfill our customer contracts. Coal revenues per ton
for our Illinois Basin segment were $47.37 for the three months ended September 30, 2017, a decrease of $0.60, or 1.2%, from $47.97
for the three months ended September 30, 2016. The decrease in coal revenues per ton was due to lower contracted prices for tons
sold.
Other
revenues for our Other category were relatively flat for the three months ended September 30, 2017 as compared to the three months
ended September 30, 2016.
Central
Appalachia Overview of Results by Product.
Additional information for the Central Appalachia segment detailing the types
of coal produced and sold, premium high-vol met coal and steam coal, is presented below. Note that our Northern Appalachia, Rhino
Western and Illinois Basin segments currently produce and sell only steam coal.
(In thousands, except per ton data and %)
|
|
Three months ended September 30, 2017
|
|
|
Three months ended September 30, 2016
|
|
|
Increase
(Decrease) %*
|
|
Met coal tons sold
|
|
|
196.8
|
|
|
|
88.4
|
|
|
|
122.5
|
%
|
Steam coal tons sold
|
|
|
184.8
|
|
|
|
91.3
|
|
|
|
102.5
|
%
|
Total tons sold
|
|
|
381.6
|
|
|
|
179.7
|
|
|
|
112.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenue
|
|
$
|
18,285
|
|
|
$
|
5,654
|
|
|
|
223.4
|
%
|
Steam coal revenue
|
|
$
|
9,580
|
|
|
$
|
4,753
|
|
|
|
101.6
|
%
|
Total coal revenue
|
|
$
|
27,865
|
|
|
$
|
10,407
|
|
|
|
167.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenues per ton
|
|
$
|
92.93
|
|
|
$
|
63.95
|
|
|
|
45.3
|
%
|
Steam coal revenues per ton
|
|
$
|
51.82
|
|
|
$
|
52.07
|
|
|
|
(0.5
|
%)
|
Total coal revenues per ton
|
|
$
|
73.02
|
|
|
$
|
57.91
|
|
|
|
26.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal tons produced
|
|
|
151.9
|
|
|
|
108.0
|
|
|
|
40.1
|
%
|
Steam coal tons produced
|
|
|
253.8
|
|
|
|
104.0
|
|
|
|
144.9
|
%
|
Total tons produced
|
|
|
405.7
|
|
|
|
212.0
|
|
|
|
91.6
|
%
|
*
Percentage amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
Costs
and Expenses.
The following table presents costs and expenses (including the cost of purchased coal) and cost of operations
per ton by reportable segment for the three months ended September 30, 2017 and 2016:
|
|
Three months
|
|
|
Three months
|
|
|
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
Increase/(Decrease)
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
$
|
|
|
%*
|
|
|
|
(in millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
20.9
|
|
|
$
|
8.9
|
|
|
$
|
12.0
|
|
|
|
135.8
|
%
|
Freight and handling costs
|
|
|
1.2
|
|
|
|
-
|
|
|
|
1.2
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
1.9
|
|
|
|
1.6
|
|
|
|
0.3
|
|
|
|
15.1
|
%
|
Selling, general and administrative
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Cost of operations per ton*
|
|
$
|
54.73
|
|
|
$
|
49.29
|
|
|
$
|
5.44
|
|
|
|
11.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
6.6
|
|
|
$
|
7.8
|
|
|
$
|
(1.2
|
)
|
|
|
(14.7
|
%)
|
Freight and handling costs
|
|
|
0.3
|
|
|
|
0.4
|
|
|
|
(0.1
|
)
|
|
|
(27.0
|
%)
|
Depreciation, depletion and amortization
|
|
|
0.4
|
|
|
|
0.8
|
|
|
|
(0.4
|
)
|
|
|
(51.3
|
%)
|
Selling, general and administrative
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Cost of operations per ton*
|
|
$
|
57.95
|
|
|
$
|
52.13
|
|
|
$
|
5.82
|
|
|
|
11.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
6.6
|
|
|
$
|
5.3
|
|
|
$
|
1.3
|
|
|
|
24.6
|
%
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
1.1
|
|
|
|
1.3
|
|
|
|
(0.2
|
)
|
|
|
(16.4
|
%)
|
Selling, general and administrative
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Cost of operations per ton*
|
|
$
|
27.48
|
|
|
$
|
28.82
|
|
|
$
|
(1.34
|
)
|
|
|
(4.7
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
13.1
|
|
|
$
|
13.4
|
|
|
$
|
(0.3
|
)
|
|
|
(2.4
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
1.8
|
|
|
|
2.6
|
|
|
|
(0.8
|
)
|
|
|
(33.5
|
%)
|
Selling, general and administrative
|
|
|
-
|
|
|
|
0.1
|
|
|
|
(0.1
|
)
|
|
|
(6.5
|
%)
|
Cost of operations per ton*
|
|
$
|
41.40
|
|
|
$
|
43.99
|
|
|
$
|
(2.59
|
)
|
|
|
(5.9
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
(0.7
|
)
|
|
$
|
(0.2
|
)
|
|
$
|
(0.5
|
)
|
|
|
603.8
|
%
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
-
|
|
|
|
0.2
|
|
|
|
(0.2
|
)
|
|
|
(39.4
|
%)
|
Selling, general and administrative
|
|
|
2.6
|
|
|
|
4.2
|
|
|
|
(1.6
|
)
|
|
|
(39.9
|
%)
|
Cost of operations per ton**
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
46.5
|
|
|
$
|
35.2
|
|
|
$
|
11.3
|
|
|
|
31.8
|
%
|
Freight and handling costs
|
|
|
1.5
|
|
|
|
0.4
|
|
|
|
1.1
|
|
|
|
294.4
|
%
|
Depreciation, depletion and amortization
|
|
|
5.2
|
|
|
|
6.5
|
|
|
|
(1.3
|
)
|
|
|
(20.1
|
%)
|
Selling, general and administrative
|
|
|
2.6
|
|
|
|
4.3
|
|
|
|
(1.7
|
)
|
|
|
(38.0
|
%)
|
Cost of operations per ton*
|
|
$
|
44.08
|
|
|
$
|
43.07
|
|
|
$
|
1.01
|
|
|
|
2.4
|
%
|
*
Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
**
Cost of operations presented for our Other category includes costs incurred by our ancillary businesses and our oil and natural
gas investments. The activities performed by these ancillary businesses do not directly relate to coal production. As a result,
per ton measurements are not presented for this category.
Cost
of Operations.
Total cost of operations increased by $11.3 million or 31.8% to $46.5 million for the three months ended
September 30, 2017 as compared to $35.2 million for the three months ended September 30, 2016. Our cost of operations per ton
was $44.08 for the three months ended September 30, 2017, an increase of $1.01, or 2.4%, from the three months ended September
30, 2016. The increase in cost of operations was primarily due to the $12.0 million increase in cost of production at our Central
Appalachia operations as demand for met and steam coal increased in this region. Cost of operations per ton increased due to higher
maintenance costs and costs for outside services.
Our
cost of operations for the Central Appalachia segment increased by $12.0 million, or 135.8%, to $20.9 million for the three months
ended September 30, 2017 from $8.9 million for the three months ended September 30, 2016. Our cost of operations per ton of $54.73
for the three months ended September 30, 2017 was an increase of 11.0% compared to $49.29 per ton for the three months ended September
30, 2016. Total cost of operations increased period over period as we increased production in this region during the three months
ended September 30, 2017 due to increased demand for met and steam coal.
In
our Northern Appalachia segment, our cost of operations decreased by $1.2 million, or 14.7%, to $6.6 million for the three months
ended September 30, 2017 from $7.8 million for the three months ended September 30, 2016. Our cost of operations per ton was $57.95
for the three months ended September 30, 2017, an increase of $5.82, or 11.2%, compared to $52.13 for the three months ended September
30, 2016. The decrease in total cost of operations in Northern Appalachia was due to a decrease in sales in this region in response
to weak market demand. The increase in the cost of operations on a per ton basis was primarily due to fixed operating costs being
allocated to fewer tons of coal sold during the current period.
Our
cost of operations for the Rhino Western segment increased by $1.3 million, or 24.6%, to $6.6 million for the three months ended
September 30, 2017 from $5.3 million for the three months ended September 30, 2016. Total cost of operations increased for the
three months ended September 30, 2017 compared to the same period in 2016 due to increased tons produced and sold from our Castle
Valley operation. Our cost of operations per ton was $27.48 for the three months ended September 30, 2017, a decrease of $1.34,
or 4.7%, compared to $28.82 for the three months ended September 30, 2016. Cost of operations per ton decreased for the three
months ended September 30, 2017 compared to the same period in 2016 due to an increase in tons sold from our Castle Valley mine
in the current period.
Cost
of operations in our Illinois Basin segment was $13.1 million while cost of operations per ton was $41.40 for the three months
ended September 30, 2017, both of which related to our Pennyrile mining complex in western Kentucky. For the three months ended
September 30, 2016, cost of operations in our Illinois Basin segment was $13.4 million and cost of operations per ton was $43.99.
The decrease in cost of operations per ton was primarily the result of an increase in tons sold during the current period.
Freight
and Handling.
Total freight and handling cost increased to $1.5 million for the three months ended September 30, 2017
as compared to $0.4 million for the three months ended September 30, 2016. The increase in freight and handling costs was primarily
the result of rail transportation costs in our Central Appalachia operations as we executed more export coal sales in the current
period that require us to pay for railroad transportation to the port of export.
Depreciation,
Depletion and Amortization.
Total DD&A expense for the three months ended September 30, 2017 was $5.2 million as compared
to $6.5 million for the three months ended September 30, 2016.
For
the three months ended September 30, 2017, our depreciation cost decreased to $4.0 million compared to $5.6 million for the three
months ended September 30, 2016. This decrease is primarily the result of assets becoming fully depreciated.
For
the three months ended September 30, 2017 and 2016, our depletion cost remained flat at $0.4 million.
For
the three months ended September 30, 2017, our amortization cost was $0.8 million compared to $0.5 million for the three months
ended September 30, 2016. The increase period over period was due to an increase in amortization of mine development cost, which
was the result of increased mining operations in Central Appalachia compared to the prior period.
Selling,
General and Administrative.
SG&A expense for the three months ended September 30, 2017 decreased to $2.6 million as
compared to $4.3 million for the three months ended September 30, 2016. This decrease was primarily attributable to the $2.0 million
impairment charge related to the note receivable from the sale of our Deane mining complex during the three months ended September
30, 2016.
Interest
Expense
.
Interest expense for the three months ended September 30, 2017 decreased to $1.0 million as compared to
$2.0 million for the three months ended September 30, 2016. This decrease was primarily due to lower outstanding balances on our
senior secured credit facility and reduced debt issuance costs during the three months ended September 30, 2017.
Net
Income (Loss) from Continuing Operations.
The following table presents net income (loss) from continuing operations by
reportable segment for the three months ended September 30, 2017 and 2016:
|
|
Three months ended
|
|
|
Three months ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
Central Appalachia
|
|
$
|
3.8
|
|
|
$
|
(0.2
|
)
|
|
$
|
4.0
|
|
Northern Appalachia
|
|
|
(0.9
|
)
|
|
|
3.6
|
|
|
|
(4.5
|
)
|
Rhino Western
|
|
|
1.4
|
|
|
|
0.6
|
|
|
|
0.8
|
|
Illinois Basin
|
|
|
0.1
|
|
|
|
(1.6
|
)
|
|
|
1.7
|
|
Other
|
|
|
(2.7
|
)
|
|
|
(5.6
|
)
|
|
|
2.9
|
|
Total
|
|
$
|
1.7
|
|
|
$
|
(3.2
|
)
|
|
$
|
4.9
|
|
For
the three months ended September 30, 2017, net income from continuing operations was approximately $1.7 million compared to net
loss from continuing operations of approximately $3.2 million for the three months ended September 30, 2016. For the three months
ended September 30, 2017, our net income from continuing operations was positively impacted by increased production and sales
from our Central Appalachia operations compared to the prior period. For the three months ended September 30, 2016, our net loss
from continuing operations was impacted by an impairment charge of $2.0 million related to the note receivable from our Deane
mining complex sale and positively impacted by a gain of $1.7 million for extinguishment of debt, which resulted when we settled
a $2.8 million note payable to a third party for $1.1 million
For
our Central Appalachia segment, net income from continuing operations was approximately $3.8 million for the three months ended
September 30, 2017, an increase of $4.0 million in net income from continuing operations as compared to the three months ended
September 30, 2016. The increase in net income from continuing operations was primarily due to increased sales from the Central
Appalachia mining operations in the third quarter of 2017 due to increased demand for both met and steam coal from this region.
Net
loss from continuing operations in our Northern Appalachia segment was $0.9 million for the three months ended September 30, 2017
compared to net income from continuing operations of $3.6 million for the three months ended September 30, 2016. Net income for
the three months ended September 30, 2016 was positively impacted by a gain of $1.7 million for extinguishment of debt, which
resulted when we settled a $2.8 million note payable to a third party for $1.1 million.
Net
income from continuing operations in our Rhino Western segment was $1.4 million for the three months ended September 30, 2017,
compared to $0.6 million for the three months ended September 30, 2016. This increase in net income from continuing operations
was primarily the result of more tons sold at our Castle Valley operation due to increased customer demand.
For
our Illinois Basin segment, we generated net income from continuing operations of $0.1 million for the three months ended September
30, 2017, which was an improvement of $1.7 million compared to the three months ended September 30, 2016. This increase in net
income was primarily the result of decreased costs as we continue to optimize production at our Pennyrile mining complex.
For
the Other category, we had a net loss from continuing operations of $2.7 million for the three months ended September 30, 2017
as compared to net loss from continuing operations of $5.6 million for the three months ended September 30, 2016. For the three
months ended September 30, 2016, our net loss from continuing operations was impacted by an impairment charge of $2.0 million
related to the note receivable from the sale of our Deane mining complex.
Adjusted
EBITDA from Continuing Operations.
The following table presents Adjusted EBITDA from continuing operations by reportable
segment for the three months ended September 30, 2017 and 2016:
|
|
Three months ended
|
|
|
Three months ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
Central Appalachia
|
|
$
|
5.7
|
|
|
$
|
1.6
|
|
|
$
|
4.1
|
|
Northern Appalachia
|
|
|
(0.5
|
)
|
|
|
2.7
|
|
|
|
(3.2
|
)
|
Rhino Western
|
|
|
2.5
|
|
|
|
2.0
|
|
|
|
0.5
|
|
Illinois Basin
|
|
|
1.9
|
|
|
|
1.1
|
|
|
|
0.8
|
|
Other
|
|
|
(1.7
|
)
|
|
|
(1.9
|
)
|
|
|
0.2
|
|
Total
|
|
$
|
7.9
|
|
|
$
|
5.5
|
|
|
$
|
2.4
|
|
Adjusted
EBITDA from continuing operations for the three months ended September 30, 2017 increased by $2.4 million to $7.9 million from
$5.5 million for the three months ended September 30, 2016. Adjusted EBITDA from continuing operations increased period over period
primarily due to the increase in net income at our Central Appalachia segment, which was the result of an increase in met and
steam coal tons sold due to increased demand in coal produced from this region. Adjusted EBITDA for the three months ended September
30, 2016 was $5.6 million once the results from discontinued operations were included. We did not incur a gain or loss from discontinued
operations for the three months ended September 30, 2017. Please read “—Reconciliations of Adjusted EBITDA”
for reconciliations of Adjusted EBITDA from continuing operations to net income/(loss) from continuing operations on a segment
basis.
Nine
Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Summary.
For the nine months ended September 30, 2017, our total revenues increased to $168.4 million from $124.4 million for the
nine months ended September 30, 2016, which is a 35.4% increase. We sold approximately 3.1 million tons of coal for the nine months
ended September 30, 2017, which is a 27.8% increase compared to the tons of coal sold for the nine months ended September 30,
2016. The increase in revenue and tons sold was primarily the result of increased sales in Central Appalachia due to increases
in coal prices and demand for met and steam coal produced in this region.
We
generated net loss from continuing operations of approximately $0.1 million for the nine months ended September 30, 2017 compared
to a net loss from continuing operations of approximately $9.0 million for the nine months ended September 30, 2016. Our net loss
from continuing operations improved during the nine months ended September 30, 2017 compared to 2016 primarily due to higher coal
revenues from the increased demand for met and steam coal in our Central Appalachia segment.
Adjusted
EBITDA from continuing operations increased to $19.6 million for the nine months ended September 30, 2017 from $14.9 million for
the nine months ended September 30, 2016. Adjusted EBITDA from continuing operations increased primarily due to the decrease in
net loss during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 resulting from the
increase in production and sales at our Central Appalachia operation. Adjusted EBITDA for the nine months ended September 30,
2016 was positively impacted by the $3.9 million prior service cost benefit resulting from the cancellation of the postretirement
benefit plan at our Hopedale operation.
Including
the net loss from discontinued operations of approximately $117.9 million, our total net loss for the nine months ended September
30, 2016 was $126.9 million. Adjusted EBITDA for the nine months ended September 30, 2016 was $16.7 million once the impact of
discontinued operations was included. We did not incur a gain or loss from discontinued operations for the nine months ended September
30, 2017.
Tons
Sold.
The following table presents tons of coal sold by reportable segment for the nine months ended September 30, 2017
and 2016:
|
|
Nine months
|
|
|
Nine months
|
|
|
Increase/
|
|
|
|
|
|
|
Ended
|
|
|
ended
|
|
|
(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
Tons
|
|
|
% *
|
|
|
|
(in thousands, except %)
|
|
Central Appalachia
|
|
|
1,090.7
|
|
|
|
367.9
|
|
|
|
722.8
|
|
|
|
196.4
|
%
|
Northern Appalachia
|
|
|
308.4
|
|
|
|
432.8
|
|
|
|
(124.4
|
)
|
|
|
(28.8
|
%)
|
Rhino Western
|
|
|
661.7
|
|
|
|
652.1
|
|
|
|
9.6
|
|
|
|
1.5
|
%
|
Illinois Basin
|
|
|
1,013.6
|
|
|
|
953.7
|
|
|
|
59.9
|
|
|
|
6.3
|
%
|
Total *
|
|
|
3,074.4
|
|
|
|
2,406.5
|
|
|
|
667.9
|
|
|
|
27.8
|
%
|
*
Calculated percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts
presented in this table.
We
sold approximately 3.1 million tons of coal for the nine months ended September 30, 2017, which was a 27.8% increase compared
to the nine months ended September 30, 2016. The increase in tons sold year-to-year was primarily due to higher sales from our
Central Appalachia segment due to an increase in demand for met and steam coal from this region.
Tons
of coal sold in our Central Appalachia segment increased by approximately 196.4% to approximately 1.1 million tons for the nine
months ended September 30, 2017 compared to the nine months ended September 30, 2016, due to an increase in met and steam coal
tons sold in the nine months ended September 30, 2017 compared to 2016 resulting from increased market demand for coal from this
region.
For
our Northern Appalachia segment, tons of coal sold decreased by approximately 28.8% for the nine months ended September 30, 2017
compared to the nine months ended September 30, 2016 as we experienced a decrease in tons sold from our Northern Appalachia segment
due to weak demand for coal in this region.
Tons
of coal sold from our Rhino Western segment remained relatively flat at 0.7 million tons for the nine months ended September 30,
2017 compared to the same period in 2016.
For
our Illinois Basin segment, tons of coal sold increased by approximately 6.3% for the nine months ended September 30, 2017 compared
to the nine months ended September 30, 2016 as we increased production and sales year-to-year from our Pennyrile mine in western
Kentucky to meet our contracted sales commitments.
Revenues.
The following table presents revenues and coal revenues per ton by reportable segment for the nine months ended September
30, 2017 and 2016:
|
|
Nine months
|
|
|
Nine months
|
|
|
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
Increase/(Decrease)
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
$
|
|
|
%*
|
|
|
|
(in millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
76.8
|
|
|
$
|
21.6
|
|
|
$
|
55.2
|
|
|
|
255.9
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
9.7
|
%
|
Total revenues
|
|
$
|
76.9
|
|
|
$
|
21.7
|
|
|
$
|
55.2
|
|
|
|
254.7
|
%
|
Coal revenues per ton*
|
|
$
|
70.38
|
|
|
$
|
58.62
|
|
|
$
|
11.76
|
|
|
|
20.1
|
%
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
11.7
|
|
|
$
|
24.6
|
|
|
$
|
(12.9
|
)
|
|
|
(52.6
|
%)
|
Freight and handling revenues
|
|
|
0.5
|
|
|
|
1.6
|
|
|
|
(1.1
|
)
|
|
|
(67.1
|
%)
|
Other revenues
|
|
|
4.8
|
|
|
|
5.5
|
|
|
|
(0.7
|
)
|
|
|
(11.7
|
%)
|
Total revenues
|
|
$
|
17.0
|
|
|
$
|
31.7
|
|
|
$
|
(14.7
|
)
|
|
|
(46.3
|
%)
|
Coal revenues per ton*
|
|
$
|
37.86
|
|
|
$
|
56.91
|
|
|
$
|
(19.05
|
)
|
|
|
(33.5
|
%)
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
25.1
|
|
|
$
|
25.1
|
|
|
$
|
-
|
|
|
|
0.0
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
25.1
|
|
|
$
|
25.1
|
|
|
$
|
-
|
|
|
|
0.0
|
%
|
Coal revenues per ton*
|
|
$
|
37.99
|
|
|
$
|
38.55
|
|
|
$
|
(0.56
|
)
|
|
|
(1.4
|
%)
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
49.4
|
|
|
$
|
45.5
|
|
|
$
|
3.9
|
|
|
|
8.7
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
49.4
|
|
|
$
|
45.5
|
|
|
$
|
3.9
|
|
|
|
8.6
|
%
|
Coal revenues per ton*
|
|
$
|
48.71
|
|
|
$
|
47.65
|
|
|
$
|
1.06
|
|
|
|
2.2
|
%
|
Other**
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Freight and handling revenues
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
0.4
|
|
|
|
(0.4
|
)
|
|
|
(94.6
|
%)
|
Total revenues
|
|
$
|
-
|
|
|
$
|
0.4
|
|
|
$
|
(0.4
|
)
|
|
|
(94.6
|
%)
|
Coal revenues per ton*
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
163.0
|
|
|
$
|
116.8
|
|
|
$
|
46.2
|
|
|
|
39.5
|
%
|
Freight and handling revenues
|
|
|
0.5
|
|
|
|
1.6
|
|
|
|
(1.1
|
)
|
|
|
(67.1
|
%)
|
Other revenues
|
|
|
4.9
|
|
|
|
6.0
|
|
|
|
(1.1
|
)
|
|
|
(16.9
|
%)
|
Total revenues
|
|
$
|
168.4
|
|
|
$
|
124.4
|
|
|
$
|
44.0
|
|
|
|
35.4
|
%
|
Coal revenues per ton*
|
|
$
|
53.00
|
|
|
$
|
48.52
|
|
|
$
|
4.48
|
|
|
|
9.2
|
%
|
*
|
Percentages
and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
|
|
|
**
|
The
Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses also
do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the
Other category.
|
Our
coal revenues for the nine months ended September 30, 2017 increased by approximately $46.2 million, or 39.5%, to approximately
$163.0 million from approximately $116.8 million for the nine months ended September 30, 2016. The increase in coal revenues was
primarily due to an increase in met and steam coal tons sold in Central Appalachia as we saw increased demand for coal from this
region during the nine months ended September 30, 2017. Coal revenues per ton was $53.00 for the nine months ended September 30,
2017, an increase of $4.48, or 9.2%, from $48.52 per ton for the nine months ended September 30, 2016. This increase in coal revenues
per ton was primarily due to a higher mix of higher priced met coal tons sold in Central Appalachia compared to the prior period.
For
our Central Appalachia segment, coal revenues increased by approximately $55.2 million, or 255.9%, to approximately $76.8 million
for the nine months ended September 30, 2017 from approximately $21.6 million for the nine months ended September 30, 2016. This
increase was primarily due to the increase in coal prices and demand for met and steam coal tons sold from this region. Coal revenues
per ton for our Central Appalachia segment increased by $11.76, or 20.1%, to $70.38 per ton for the nine months ended September
30, 2017 as compared to $58.62 for the nine months ended September 30, 2016, which was primarily due to a higher mix of higher
priced met coal tons sold in Central Appalachia compared to the prior period.
For
our Northern Appalachia segment, coal revenues were approximately $11.7 million for the nine months ended September 30, 2017,
a decrease of approximately $12.9 million, or 52.6%, from approximately $24.6 million for the nine months ended September 30,
2016. This decrease was primarily due to a decrease in tons sold from our Northern Appalachia segment due to weak market demand
in the region. Coal revenues per ton for our Northern Appalachia segment decreased by $19.05, or 33.5%, to $37.86 per ton for
the nine months ended September 30, 2017 as compared to $56.91 per ton for the nine months ended September 30, 2016. This decrease
was primarily due to the larger mix of lower priced tons being sold from our Sands Hill complex compared to higher priced tons
sold from our Hopedale complex.
For
our Rhino Western segment, coal revenues remained flat at $25.1 million for the nine months ended September 30, 2017 compared
to the same period in 2016. Coal revenues per ton for our Rhino Western segment remained relatively flat at $37.99 for the nine
months ended September 30, 2017, compared to $38.55 for the nine months ended September 30, 2016.
For
our Illinois Basin segment, coal revenues of approximately $49.4 million for the nine months ended September 30, 2017 increased
by approximately $4.0 million, or 8.7%, compared to $45.5 million for the nine months ended September 30, 2016. The increase was
due to increased sales from our Pennyrile mine in western Kentucky to fulfill our customer contracts. Coal revenues per ton for
our Illinois Basin segment were $48.71 for the nine months ended September 30, 2017, an increase of $1.06, or 2.2%, from $47.65
for the nine months ended September 30, 2016. The increase in coal revenues per ton was due to higher contracted prices for tons
sold.
Other
revenues for our Other category decreased by $0.4 million for the nine months ended September 30, 2017 as compared to the same
period in 2016 due to lower activities in our ancillary businesses during the current period.
Central
Appalachia Overview of Results by Product.
Additional information for the Central Appalachia segment detailing the types
of coal produced and sold, premium high-vol met coal and steam coal, is presented below. Note that our Northern Appalachia, Rhino
Western and Illinois Basin segments currently produce and sell only steam coal.
(In thousands, except per ton data and %)
|
|
Nine months ended September 30, 2017
|
|
|
Nine months ended September 30, 2016
|
|
|
Increase (Decrease) %*
|
|
Met coal tons sold
|
|
|
575.2
|
|
|
|
135.4
|
|
|
|
324.8
|
%
|
Steam coal tons sold
|
|
|
515.5
|
|
|
|
232.5
|
|
|
|
121.7
|
%
|
Total tons sold
|
|
|
1,090.7
|
|
|
|
367.9
|
|
|
|
196.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenue
|
|
$
|
50,131
|
|
|
$
|
9,553
|
|
|
|
424.8
|
%
|
Steam coal revenue
|
|
$
|
26,634
|
|
|
$
|
12,016
|
|
|
|
121.7
|
%
|
Total coal revenue
|
|
$
|
76,765
|
|
|
$
|
21,569
|
|
|
|
255.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenues per ton
|
|
$
|
87.16
|
|
|
$
|
70.55
|
|
|
|
23.5
|
%
|
Steam coal revenues per ton
|
|
$
|
51.66
|
|
|
$
|
51.67
|
|
|
|
(0.2
|
%)
|
Total coal revenues per ton
|
|
$
|
70.38
|
|
|
$
|
58.62
|
|
|
|
20.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal tons produced
|
|
|
504.6
|
|
|
|
165.8
|
|
|
|
204.4
|
%
|
Steam coal tons produced
|
|
|
631.8
|
|
|
|
242.3
|
|
|
|
160.7
|
%
|
Total tons produced
|
|
|
1,136.4
|
|
|
|
408.1
|
|
|
|
178.5
|
%
|
*
Percentage amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
Costs
and Expenses.
The following table presents costs and expenses (including the cost of purchased coal) and cost of operations
per ton by reportable segment for the nine months ended September 30, 2017 and 2016:
|
|
Nine months
|
|
|
Nine months
|
|
|
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
Increase/(Decrease)
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
$
|
|
|
%*
|
|
|
|
(in millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
59.7
|
|
|
$
|
21.8
|
|
|
$
|
37.9
|
|
|
|
174.0
|
%
|
Freight and handling costs
|
|
|
1.8
|
|
|
|
-
|
|
|
|
1.8
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
5.8
|
|
|
|
4.9
|
|
|
|
0.9
|
|
|
|
17.4
|
%
|
Selling, general and administrative
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
n/a
|
|
Cost of operations per ton*
|
|
$
|
54.76
|
|
|
$
|
59.23
|
|
|
$
|
(4.47
|
)
|
|
|
(7.6
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
18.2
|
|
|
$
|
18.5
|
|
|
$
|
(0.3
|
)
|
|
|
(1.3
|
%)
|
Freight and handling costs
|
|
|
0.7
|
|
|
|
1.5
|
|
|
|
(0.8
|
)
|
|
|
(52.9
|
%)
|
Depreciation, depletion and amortization
|
|
|
1.3
|
|
|
|
2.6
|
|
|
|
(1.3
|
)
|
|
|
(49.1
|
%)
|
Selling, general and administrative
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
(20.0
|
%)
|
Cost of operations per ton*
|
|
$
|
59.09
|
|
|
$
|
42.67
|
|
|
$
|
16.42
|
|
|
|
38.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
20.1
|
|
|
$
|
19.9
|
|
|
$
|
0.2
|
|
|
|
0.9
|
%
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
3.4
|
|
|
|
4.1
|
|
|
|
(0.7
|
)
|
|
|
(17.3
|
%)
|
Selling, general and administrative
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
88.8
|
%
|
Cost of operations per ton*
|
|
$
|
30.30
|
|
|
$
|
30.47
|
|
|
$
|
(0.17
|
)
|
|
|
(0.6
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
41.8
|
|
|
$
|
39.9
|
|
|
$
|
1.9
|
|
|
|
4.9
|
%
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
5.7
|
|
|
|
6.3
|
|
|
|
(0.6
|
)
|
|
|
(9.7
|
%)
|
Selling, general and administrative
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
(3.9
|
%)
|
Cost of operations per ton*
|
|
$
|
41.26
|
|
|
$
|
41.81
|
|
|
$
|
(0.55
|
)
|
|
|
(1.3
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
(1.7
|
)
|
|
$
|
(2.0
|
)
|
|
$
|
0.3
|
|
|
|
(8.2
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
0.3
|
|
|
|
0.4
|
|
|
|
(0.1
|
)
|
|
|
(32.8
|
%)
|
Selling, general and administrative
|
|
|
8.0
|
|
|
|
12.0
|
|
|
|
(4.0
|
)
|
|
|
(32.8
|
%)
|
Cost of operations per ton**
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
138.1
|
|
|
$
|
98.1
|
|
|
$
|
40.0
|
|
|
|
40.7
|
%
|
Freight and handling costs
|
|
|
2.5
|
|
|
|
1.5
|
|
|
|
1.0
|
|
|
|
73.3
|
%
|
Depreciation, depletion and amortization
|
|
|
16.5
|
|
|
|
18.3
|
|
|
|
(1.8
|
)
|
|
|
(10.1
|
%)
|
Selling, general and administrative
|
|
|
8.5
|
|
|
|
12.3
|
|
|
|
(3.8
|
)
|
|
|
(31.0
|
%)
|
Cost of operations per ton*
|
|
$
|
44.91
|
|
|
$
|
40.77
|
|
|
$
|
4.14
|
|
|
|
10.2
|
%
|
*
Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
**
Cost of operations presented for our Other category includes costs incurred by our ancillary businesses and our oil and natural
gas investments. The activities performed by these ancillary businesses do not directly relate to coal production. As a result,
per ton measurements are not presented for this category.
Cost
of Operations.
Total cost of operations was $138.1 million for the nine months ended September 30, 2017 as compared to
$98.1 million for the nine months ended September 30, 2016. Our cost of operations per ton was $44.91 for the nine months ended
September 30, 2017, an increase of $4.14, or 10.2%, from the nine months ended September 30, 2016. Total cost of operations and
cost of operations per ton increased primarily due to higher costs in Central Appalachia due to an increase in coal production
and sales resulting from increased market demand in this region during the nine months ended September 30, 2017.
Our
cost of operations for the Central Appalachia segment increased by $37.9 million, or 174.0%, to $59.7 million for the nine months
ended September 30, 2017 from $21.8 million for the nine months ended September 30, 2016. Total cost of operations increased year-to-year
as we increased production in our Central Appalachia segment in response to increased demand for met and steam coal from this
region. Our cost of operations per ton of $54.76 for the nine months ended September 30, 2017 was a decrease of 7.6% compared
to $59.23 per ton for the nine months ended September 30, 2016. We increased sales during the current period due to increased
met and steam coal demand that resulted in lower cost of operations per ton compared to the prior period.
In
our Northern Appalachia segment, our cost of operations decreased by $0.3 million, or 1.3%, to $18.2 million for the nine months
ended September 30, 2017 from $18.5 million for the nine months ended September 30, 2016. Our cost of operations per ton was $59.09
for the nine months ended September 30, 2017, an increase of $16.42, or 38.5%, compared to $42.67 for the nine months ended September
30, 2016. The cost of operations for the nine months ended September 30, 2016 decreased by a prior service cost benefit of $3.9
million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation during the 2016 period. The
increase in the cost of operations per ton was primarily due to fixed operating costs being allocated to lower sales tons at our
Northern Appalachia segment during the nine months ended September 30, 2017.
Our
cost of operations for the Rhino Western segment increased by $0.2 million, or 0.9%, to $20.1 million for the nine months ended
September 30, 2017 from $19.9 million for the nine months ended September 30, 2016. Our cost of operations per ton was $30.30
for the nine months ended September 30, 2017, a decrease of $0.17, or 0.6%, compared to $30.47 for the nine months ended September
30, 2016. Our cost of operations and cost of operations per ton for our Rhino Western segment were both relatively flat period
over period.
Cost
of operations in our Illinois Basin segment was $41.8 million while cost of operations per ton was $41.26 for the nine months
ended September 30, 2017, both of which related to our Pennyrile mining complex in western Kentucky. For the nine months ended
September 30, 2016, cost of operations in our Illinois Basin segment was $39.9 million and cost of operations per ton was $41.81.
The increase in cost of operations was primarily the result of increased production year-to-year at the Pennyrile complex, while
cost of operations per ton remained relatively flat.
Freight
and Handling.
Total freight and handling cost increased to $2.5 million for the nine months ended September 30, 2017 as
compared to $1.5 million for the nine months ended September 30, 2016. The increase in freight and handling costs was primarily
the result of rail transportation costs in our Central Appalachia operations as we executed more export coal sales in the current
period that require us to pay for railroad transportation to the port of export.
Depreciation,
Depletion and Amortization.
Total DD&A expense for the nine months ended September 30, 2017 was $16.5 million as compared
to $18.3 million for the nine months ended September 30, 2016.
For
the nine months ended September 30, 2017, our depreciation cost decreased to $12.8 million compared to $15.9 million for the nine
months ended September 30, 2016. This decrease primarily resulted from lower depreciation costs in our Central Appalachia, Northern
Appalachia and Illinois Basin segments in the current period compared to the prior year as assets became fully depreciated in
these regions.
For
the nine months ended September 30, 2017, our depletion cost remained relatively flat at $1.2 million compared to the nine months
ended September 30, 2016.
For
the nine months ended September 30, 2017, our amortization cost increased to $2.5 million compared to $1.2 million for the nine
months ended September 30, 2016. The increase is a result of increased production in our Central Appalachia segment during the
nine months ended September 30, 2017 compared to the same period in 2016.
Selling,
General and Administrative.
SG&A expense for the nine months ended September 30, 2017 decreased to $8.5 million as
compared to $12.3 million for the nine months ended September 30, 2016. This decrease was the result of lower corporate overhead
expenses for the nine months ended September 30, 2017 compared to the prior period and the impact of a $2.0 million impairment
charge related to the note receivable from the sale of our Deane mining complex during the nine months ended September 30, 2016.
Interest
Expense
.
Interest expense for the nine months ended September 30, 2017 decreased to $3.1 million as compared to
$5.2 million for the nine months ended September 30, 2016. This decrease was primarily due to lower outstanding balances on our
senior secured credit facility. See the discussion on our credit agreement in “Liquidity and Capital Resources - Amended
and Restated Credit Agreement.”
Net
Income (Loss) from Continuing Operations.
The following table presents net income (loss) from continuing operations by
reportable segment for the nine months ended September 30, 2017 and 2016:
|
|
Nine months Ended
|
|
|
Nine months Ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
Central Appalachia
|
|
$
|
9.4
|
|
|
$
|
(5.5
|
)
|
|
$
|
14.9
|
|
Northern Appalachia
|
|
|
(3.3
|
)
|
|
|
10.6
|
|
|
|
(13.9
|
)
|
Rhino Western
|
|
|
1.6
|
|
|
|
1.0
|
|
|
|
0.6
|
|
Illinois Basin
|
|
|
1.7
|
|
|
|
(1.0
|
)
|
|
|
2.7
|
|
Other
|
|
|
(9.5
|
)
|
|
|
(14.1
|
)
|
|
|
4.6
|
|
Total
|
|
$
|
(0.1
|
)
|
|
$
|
(9.0
|
)
|
|
$
|
8.9
|
|
For
the nine months ended September 30, 2017, net loss from continuing operations was approximately $0.1 million compared to net loss
from continuing operations of approximately $9.0 million for the nine months ended September 30, 2016. For the nine months ended
September 30, 2017, our net loss from continuing operations was positively impacted by increased production and sales from our
Central Appalachia operations compared to the prior period. For the nine months ended September 30, 2016, our net loss from continuing
operations was impacted by a prior service cost benefit of $3.9 million resulting from the cancellation of the postretirement
benefit plan at our Hopedale operation during the 2016 period and the $2.0 million impairment charge incurred during the nine
months ended September 30, 2016 for the note receivable discussed earlier.
For
our Central Appalachia segment, net income from continuing operations was approximately $9.4 million for the nine months ended
September 30, 2017, a $14.9 million increase in net income from continuing operations as compared to the nine months ended September
30, 2016, which was primarily related to the increase in sales at our Central Appalachia operation.
Net
loss from continuing operations in our Northern Appalachia segment was $3.3 million for the nine months ended September 30, 2017
compared to net income from continuing operations of $10.6 million for the same period in 2016. The decrease in net income from
continuing operations for the nine months ended September 30, 2017 was primarily due to decreased coal sales in our Northern Appalachia
segment. The net income from continuing operations for the nine months ended September 30, 2016 was positively impacted by the
prior service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at
our Hopedale operation as well as the gain of $1.7 million for extinguishment of debt discussed earlier.
Net
income from continuing operations in our Rhino Western segment was $1.6 million for the nine months ended September 30, 2017,
compared to net income from continuing operations of $1.0 million for the nine months ended September 30, 2016. This increase
in net income from continuing operations was primarily the result of lower depreciation expense at our Castle Valley operation
during the nine months ended September 30, 2017 compared to 2016 as assets become fully depreciated.
For
our Illinois Basin segment, we generated net income from continuing operations of $1.7 million for the nine months ended September
30, 2017, which was an improvement of $2.7 million compared to the nine months ended September 30, 2016. This increase in net
income from continuing operations was primarily the result of increased coal sales at our Pennyrile mining complex.
For
the Other category, we had a net loss from continuing operations of $9.5 million for the nine months ended September 30, 2017
as compared to a net loss from continuing operations of $14.1 million for the nine months ended September 30, 2016. This decrease
in results period over period was attributable to lower corporate overhead charges and the $2.0 million impairment charge related
to the note receivable from the sale of our Deane mining complex during the nine months ended September 30, 2016.
Adjusted
EBITDA from Continuing Operations.
The following table presents Adjusted EBITDA from continuing operations by reportable
segment for the nine months ended September 30, 2017 and 2016:
|
|
Nine months Ended
|
|
|
Nine months Ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2017
|
|
|
September 30, 2016
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
Central Appalachia
|
|
$
|
15.2
|
|
|
$
|
0.1
|
|
|
$
|
15.1
|
|
Northern Appalachia
|
|
|
(1.9
|
)
|
|
|
11.7
|
|
|
|
(13.6
|
)
|
Rhino Western
|
|
|
5.0
|
|
|
|
5.3
|
|
|
|
(0.3
|
)
|
Illinois Basin
|
|
|
7.4
|
|
|
|
5.5
|
|
|
|
1.9
|
|
Other
|
|
|
(6.1
|
)
|
|
|
(7.7
|
)
|
|
|
1.6
|
|
Total
|
|
$
|
19.6
|
|
|
$
|
14.9
|
|
|
$
|
4.7
|
|
Adjusted
EBITDA from continuing operations increased to $19.6 million for the nine months ended September 30, 2017 from $14.9 million for
the nine months ended September 30, 2016. Adjusted EBITDA from continuing operations increased period over period primarily due
to the decrease in net loss during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016
discussed earlier. Adjusted EBITDA for the nine months ended September 30, 2016 was positively impacted by the $3.9 million prior
service cost benefit resulting from the cancellation of the postretirement benefit plan at our Hopedale operation. Adjusted EBITDA
for the nine months ended September 30, 2016 was $16.7 million once the results from discontinued operations were included. We
did not incur a gain or loss from discontinued operations for the nine months ended September 30, 2017. Please read “—Reconciliations
of Adjusted EBITDA” for reconciliations of Adjusted EBITDA from continuing operations to net income on a segment basis.
Reconciliations
of Adjusted EBITDA
The
following tables present reconciliations of Adjusted EBITDA to the most directly comparable GAAP financial measures for each of
the periods indicated:
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
|
|
Three months ended September 30, 2017
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Total
|
|
|
|
(in millions)
|
|
Net income/(loss) from continuing operations
|
|
$
|
3.8
|
|
|
$
|
(0.9
|
)
|
|
$
|
1.4
|
|
|
$
|
0.1
|
|
|
$
|
(2.7
|
)
|
|
$
|
1.7
|
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
1.9
|
|
|
|
0.4
|
|
|
|
1.1
|
|
|
|
1.8
|
|
|
|
-
|
|
|
|
5.2
|
|
Interest expense
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1.0
|
|
|
|
1.0
|
|
EBITDA from continuing operations†
|
|
$
|
5.7
|
|
|
$
|
(0.5
|
)
|
|
$
|
2.5
|
|
|
$
|
1.9
|
|
|
$
|
(1.7
|
)
|
|
$
|
7.9
|
|
Adjusted EBITDA from continuing operations†
|
|
|
5.7
|
|
|
|
(0.5
|
)
|
|
|
2.5
|
|
|
|
1.9
|
|
|
|
(1.7
|
)
|
|
|
7.9
|
|
EBITDA from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Adjusted EBITDA †
|
|
$
|
5.7
|
|
|
$
|
(0.5
|
)
|
|
$
|
2.5
|
|
|
$
|
1.9
|
|
|
$
|
(1.7
|
)
|
|
$
|
7.9
|
|
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
|
|
Three months ended September 30, 2016
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other*
|
|
|
Total*
|
|
|
|
(in millions)
|
|
Net (loss)/income from continuing operations
|
|
$
|
(0.2
|
)
|
|
$
|
3.6
|
|
|
$
|
0.6
|
|
|
$
|
(1.6
|
)
|
|
$
|
(5.6
|
)
|
|
$
|
(3.2
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
1.6
|
|
|
|
0.8
|
|
|
|
1.3
|
|
|
|
2.6
|
|
|
|
0.2
|
|
|
|
6.5
|
|
Interest expense
|
|
|
0.2
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
1.6
|
|
|
|
2.0
|
|
EBITDA from continuing operations†
|
|
$
|
1.6
|
|
|
$
|
4.4
|
|
|
$
|
2.0
|
|
|
$
|
1.1
|
|
|
$
|
(3.8
|
)
|
|
$
|
5.3
|
|
Plus: Non-cash asset impairment (1)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2.0
|
|
|
|
2.0
|
|
Plus: Gain on extinguishment of debt (2)
|
|
|
-
|
|
|
|
(1.7
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1.7
|
)
|
Adjusted EBITDA from continuing operations†
|
|
|
1.6
|
|
|
|
2.7
|
|
|
|
2.0
|
|
|
|
1.1
|
|
|
|
(1.9
|
)
|
|
|
5.5
|
|
EBITDA from discontinued operations
|
|
|
0.1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
0.1
|
|
Adjusted EBITDA
|
|
$
|
1.7
|
|
|
$
|
2.7
|
|
|
$
|
2.0
|
|
|
$
|
1.1
|
|
|
$
|
(1.9
|
)
|
|
$
|
5.6
|
|
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
|
|
Nine months ended September 30, 2017
|
|
Appalachia
|
|
|
Appalachia*
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Total*
|
|
|
|
(in millions)
|
|
Net income/(loss) from continuing operations
|
|
$
|
9.4
|
|
|
$
|
(3.3
|
)
|
|
$
|
1.6
|
|
|
$
|
1.7
|
|
|
$
|
(9.5
|
)
|
|
$
|
(0.1
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
5.8
|
|
|
|
1.3
|
|
|
|
3.4
|
|
|
|
5.7
|
|
|
|
0.3
|
|
|
|
16.5
|
|
Interest expense
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3.1
|
|
|
|
3.1
|
|
EBITDA from continuing operations†
|
|
$
|
15.2
|
|
|
$
|
(1.9
|
)
|
|
$
|
5.0
|
|
|
$
|
7.4
|
|
|
$
|
(6.1
|
)
|
|
$
|
19.6
|
|
Adjusted EBITDA from continuing operations†
|
|
|
15.2
|
|
|
|
(1.9
|
)
|
|
|
5.0
|
|
|
|
7.4
|
|
|
|
(6.1
|
)
|
|
|
19.6
|
|
EBITDA from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Adjusted EBITDA †
|
|
$
|
15.2
|
|
|
$
|
(1.9
|
)
|
|
$
|
5.0
|
|
|
$
|
7.4
|
|
|
$
|
(6.1
|
)
|
|
$
|
19.6
|
|
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
|
|
Nine months ended September 30, 2016
|
|
Appalachia*
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Total*
|
|
|
|
(in millions)
|
|
Net (loss)/income from continuing operations
|
|
$
|
(5.5
|
)
|
|
$
|
10.6
|
|
|
$
|
1.0
|
|
|
$
|
(1.0
|
)
|
|
$
|
(14.1
|
)
|
|
$
|
(9.0
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
4.9
|
|
|
|
2.6
|
|
|
|
4.1
|
|
|
|
6.3
|
|
|
|
0.4
|
|
|
|
18.3
|
|
Interest expense
|
|
|
0.6
|
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
0.2
|
|
|
|
4.1
|
|
|
|
5.2
|
|
EBITDA from continuing operations†
|
|
$
|
0.1
|
|
|
$
|
13.4
|
|
|
$
|
5.2
|
|
|
$
|
5.5
|
|
|
$
|
(9.6
|
)
|
|
$
|
14.6
|
|
Plus: Non-cash asset impairment (1)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2.0
|
|
|
|
2.0
|
|
Plus: Gain on extinguishment of debt (2)
|
|
|
-
|
|
|
|
(1.7
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1.7
|
)
|
Adjusted EBITDA from continuing operations†
|
|
|
0.1
|
|
|
|
11.7
|
|
|
|
5.2
|
|
|
|
5.5
|
|
|
|
(7.6
|
)
|
|
|
14.9
|
|
EBITDA from discontinued operations
|
|
|
1.8
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1.8
|
|
Adjusted EBITDA †
|
|
$
|
1.9
|
|
|
$
|
11.7
|
|
|
$
|
5.2
|
|
|
$
|
5.5
|
|
|
$
|
(7.6
|
)
|
|
$
|
16.7
|
|
*
|
Totals
may not foot due to rounding.
|
|
|
†
|
EBITDA
is calculated based on actual amounts and not the rounded amounts presented in this table.
|
(1)
|
During
the three and nine months ended September 30, 2016, we recorded a $2.0 million asset impairment related to a note receivable
that was recorded in 2015 related to the sale of the Deane mining complex discussed earlier. We believe that the isolation
and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding
of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional
information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides
investors with enhanced comparability to prior and future periods of our operating results.
|
|
|
(2)
|
For
the three and nine months ended September 30, 2016, we recorded a gain of approximately $1.7 million for the extinguishment
of debt. We executed an agreement with the third party that held approximately $2.8 million of other notes payable to settle
the debt for $1.1 million of cash consideration, which resulted in an approximate $1.7 million gain from the extinguishment
of this debt. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful
because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment
of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally,
we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating
results.
|
|
|
Three
months ended September 30,
|
|
|
Nine
months ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
|
|
(in
millions)
|
|
Net
cash provided by operating activities
|
|
$
|
5.9
|
|
|
$
|
1.1
|
|
|
$
|
13.2
|
|
|
$
|
5.1
|
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
in net operating assets
|
|
|
2.0
|
|
|
|
5.1
|
|
|
|
6.9
|
|
|
|
6.1
|
|
Gain
on sale of assets
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
0.4
|
|
Amortization
of deferred revenue
|
|
|
-
|
|
|
|
0.6
|
|
|
|
-
|
|
|
|
1.3
|
|
Amortization
of actuarial gain
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4.8
|
|
Interest
expense
|
|
|
1.0
|
|
|
|
2.0
|
|
|
|
3.1
|
|
|
|
5.2
|
|
Equity
in net income of unconsolidated affiliate
|
|
|
-
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
of advance royalties
|
|
|
0.3
|
|
|
|
0.2
|
|
|
|
0.9
|
|
|
|
0.7
|
|
Amortization
of debt issuance costs
|
|
|
0.4
|
|
|
|
1.0
|
|
|
|
1.1
|
|
|
|
2.0
|
|
Loss
on retirement of advanced royalties
|
|
|
-
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
0.1
|
|
Loss
on disposal of business
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
119.2
|
|
Loss
on impairment of asset
|
|
|
-
|
|
|
|
2.0
|
|
|
|
-
|
|
|
|
2.0
|
|
Equity-based
compensation
|
|
|
-
|
|
|
|
0.5
|
|
|
|
0.3
|
|
|
|
0.5
|
|
Accretion
on asset retirement obligations
|
|
|
0.4
|
|
|
|
0.4
|
|
|
|
1.4
|
|
|
|
1.1
|
|
Gain
on extinguishment of debt
|
|
|
-
|
|
|
|
1.7
|
|
|
|
-
|
|
|
|
1.7
|
|
Equity
in net loss of unconsolidated affiliates
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
0.1
|
|
EBITDA†
|
|
$
|
7.9
|
|
|
$
|
3.1
|
|
|
$
|
19.6
|
|
|
$
|
(104.5
|
)
|
Plus:
Loss on disposal of business (1)
|
|
|
-
|
|
|
|
0.5
|
|
|
|
-
|
|
|
|
119.2
|
|
Plus: Non-cash
asset impairment (2)
|
|
|
-
|
|
|
|
2.0
|
|
|
|
-
|
|
|
|
2.0
|
|
Adjusted
EBITDA†
|
|
|
7.9
|
|
|
|
5.6
|
|
|
|
19.6
|
|
|
|
16.7
|
|
Less:
EBITDA from discontinued operations
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
1.8
|
|
Adjusted
EBITDA from continuing operations †
|
|
$
|
7.9
|
|
|
$
|
5.5
|
|
|
$
|
19.6
|
|
|
$
|
14.9
|
|
†
EBITDA is calculated based on actual amounts and not the rounded amounts presented in this table.
(1)
|
For
the three and nine months ended September 30, 2016, we recorded losses of $0.5 million and $119.2 million related to the sale
of our Elk Horn coal leasing company that was discussed earlier. We believe that the isolation and presentation
of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we
assess the performance of our business. We believe the adjustment of this item provides investors with additional information
that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors
with enhanced comparability to prior and future periods of our operating results.
|
|
|
(2)
|
During
the three and nine months ended September 30, 2016, we recorded a $2.0 million asset impairment related to a note receivable
that was recorded in 2015 related to the sale of the Deane mining complex discussed earlier. We believe that the isolation
and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding
of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional
information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides
investors with enhanced comparability to prior and future periods of our operating results.
|
Liquidity
and Capital Resources
Liquidity
Since
our credit facility has an expiration date of December 31, 2017, we determined that our credit facility debt liability at September
30, 2017 and December 31, 2016 of $9.9 million and $10.0 million, respectively, should be classified as a current liability on
our unaudited condensed consolidated statements of financial position. The classification of our credit facility balance as a
current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months.
We
are evaluating and negotiating alternative credit facilities. We currently anticipate repaying the debt outstanding under our
credit facility with the proceeds from one of these alternative facilities in the fourth quarter of 2017. If it becomes apparent
this refinancing will not occur prior to December 31, 2017, we may seek a short-term extension of our existing credit facility.
There can be no assurance that we will be able to refinance our credit facility or that the lenders will be willing to grant an
extension to provide us with additional time to refinance. If we are unable to secure a replacement facility, we will lose a primary
source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including repaying
amounts due under our credit facility upon expiration, which could cause us to further curtail our operations and reduce our spending
and to alter our business plan. We may also be required to consider other options, such as selling additional assets, and depending
on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not
able to fund our liquidity requirements, we may not be able to continue as a going concern.
Further,
even if we are able to refinance our credit facility, the replacement credit facility may include a significantly higher interest
rate, significant amortization payments, or liens on a substantial portion of our assets, all of which could adversely impact
our future plans and operations.
Since
the current maturity date of our credit facility is December 31, 2017, we are unable to demonstrate that we have sufficient liquidity
to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going
concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our
ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31,
2016. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship
with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise
additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of
operations, financial condition and prospects could be materially adversely affected.
Our
business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment
used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations.
Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from
time to time, and service our debt. Historically, our sources of liquidity included cash generated by our operations, borrowings
under our credit agreement and issuances of equity securities. Our ability to access the capital markets on economic terms in
the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial
performance, the value and performance of our equity securities, prevailing commodity prices and other macroeconomic factors outside
of our control. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to significantly
reduce our spending and to alter our short- or long-term business plan. We may also be required to consider other options, such
as selling assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue
such an option at an inopportune time.
Our
principal indicators of our liquidity are our cash on hand and availability under our amended and restated credit agreement. As
of September 30, 2017, our available liquidity was $8.3 million, including cash on hand of $0.1 million and $8.2 million available
under our credit facility. On May 13, 2016, we entered into a Fifth Amendment of our amended and restated agreement that initially
extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility
automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December
31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum
of $75 million and maintained the amount available for letters of credit at $30 million. In December 2016, we entered into a Seventh
Amendment of our amended and restated credit agreement. The Seventh Amendment immediately reduced the revolving credit commitments
by $11.0 million and provided for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and
September 30, 2017. The Seventh Amendment further reduced the revolving credit commitments over time on a dollar-for-dollar basis
for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds
received exceeds $2.0 million. For more information about our amended and restated credit agreement, please read — “Amended
and Restated Credit Agreement.”
We
continue to take measures, including the suspension of cash distributions on our common and subordinated units and cost and productivity
improvements, to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures
and meet our financial commitments and debt service obligations.
Cash
Flows
Net
cash provided by operating activities was $13.2 million for the nine months ended September 30, 2017 as compared to cash provided
by operating activities of $5.1 million for the nine months ended September 30, 2016. This increase in cash provided by operating
activities for the nine months ended September 30, 2017 was primarily the result of the increase in production and sales in our
Central Appalachia segment for the nine months ended September 30, 2017 as compared to 2016.
Net
cash used in investing activities was $12.9 million for the nine months ended September 30, 2017 as compared to cash provided
by investing activities of $5.1 million for the nine months ended September 30, 2016. Net cash used in investing activities for
the nine months ended September 30, 2017 was primarily related to capital expenditures necessary for maintaining our mining operations.
Net cash provided by investing activities for the nine months ended September 30, 2016 was primarily related to the proceeds from
the sale of the Elk Horn coal leasing operation.
Net
cash used in financing activities for the nine months ended September 30, 2017 was $0.3 million, which was primarily attributable
to payment of debt issuance costs during the period. Net cash used in financing activities for the nine months ended September
30, 2016 was $10.3 million, which was attributable to net repayments on our revolving credit facility resulting from contributions
from Royal’s acquisition of common units.
Capital
Expenditures
Our
mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations.
Maintenance capital expenditures are those capital expenditures required to maintain our long term operating capacity. Examples
of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether
through the expansion of an existing mine or the acquisition or development of new reserves to the extent such expenditures are
made to maintain our long term operating capacity. Expansion capital expenditures are those capital expenditures that we expect
will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of
reserves, acquisition of equipment for a new mine or the expansion of an existing mine to the extent such expenditures are expected
to expand our long-term operating capacity.
Actual
maintenance capital expenditures for the nine months ended September 30, 2017 were approximately $9.2 million. These amounts were
primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the nine months ended
September 30, 2017 were approximately $5.1 million and primarily related to purchases of additional equipment to be used to expand
our met coal production capacity in Central Appalachia.
Amended
and Restated Credit Agreement
On
July 29, 2011, we executed the Amended and Restated Credit Agreement. The maximum availability under the amended and restated
credit facility was $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million.
Of the $300.0 million, $75.0 million was available for letters of credit. In April 2015, the Amended and Restated Credit Agreement
was amended and the borrowing commitment under the facility was reduced to $100.0 million and the amount available for letters
of credit was reduced to $50.0 million. As described below, in March 2016 and May 2016, the borrowing commitment under the facility
was further reduced to $80.0 million and $75.0 million, respectively, and the amount available for letters of credit was reduced
to $30.0 million. In addition, as described below, the borrowing commitment under the facility was further reduced by amendments
in July 2016 and December 2016 to $44.3 million as of September 30, 2017. The amount available for letters of credit was unchanged
from these amendments.
Loans
under the senior secured credit facility currently bear interest at a base rate equaling the prime rate plus an applicable margin
of 3.50%. The amended and restated credit agreement also contains letter of credit fees equal to an applicable margin of 5.00%
multiplied by the aggregate amount available to be drawn on the letters of credit, and a 0.15% fronting fee payable to the administrative
agent. In addition, we incur a commitment fee on the unused portion of the senior secured credit facility at a rate of 1.00% per
annum. Borrowings on the line of credit are collateralized by all of our unsecured assets.
Our
Amended and Restated Credit Agreement requires us to maintain certain minimum financial ratios and contains certain restrictive
provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness,
guaranteeing indebtedness, creating liens, and selling or assigning stock.
On
March 17, 2016, we entered into the Fourth Amendment (“Fourth Amendment”) of our amended and restated credit agreement.
The Fourth Amendment amended the definition of change of control in the amended and restated credit agreement to permit Royal
to purchase the membership interests of our general partner. The Fourth Amendment reduced the borrowing capacity under the credit
facility to a maximum of $80 million and reduced the amount available for letters of credit to $30 million. The Fourth Amendment
eliminated the option to borrow funds utilizing the LIBOR rate plus an applicable margin and established the borrowing rate for
all borrowings under the facility to be based upon the current PRIME rate plus an applicable margin of 3.50%. The Fourth Amendment
eliminated the capability to make Swing Loans under the facility and eliminated our ability to pay distributions to our common
or subordinated unitholders. The Fourth Amendment altered the maximum leverage ratio, calculated as of the end of the most recent
month, on a trailing twelve-month basis, to 6.75 to 1.00. The leverage ratio shall be reduced by 0.50 to 1.00 for every $10 million
of net cash proceeds, in the aggregate, received by us after the date of the Fourth Amendment from a liquidity event; provided,
however, that in no event shall the maximum permitted leverage ratio be reduced below 3.00 to 1.00. A liquidity event is defined
in the Fourth Amendment as the issuance of any equity by us on or after the Fourth Amendment effective date (other than the Royal
equity contribution discussed above), or the disposition of any assets by us. The Fourth Amendment required us to maintain minimum
liquidity of $5 million and minimum EBITDA (as defined in the credit agreement), calculated as of the end of the most recent month,
on a trailing twelve month basis, of $8 million. The Fourth Amendment limited the amount of our capital expenditures to $15 million,
calculated as of end of the most recent month, on a trailing twelve-month basis. The Fourth Amendment required us to provide monthly
financial statements and a weekly rolling thirteen-week cash flow forecast to the Administrative Agent.
On
May 13, 2016, we entered into the Fifth Amendment of our amended and restated credit agreement that extended the term to July
31, 2017. Per the Fifth Amendment, the credit facility will be automatically extended to December 31, 2017 if revolving credit
commitments are reduced to $55 million or less on or before July 31, 2017. The Fifth Amendment immediately reduced the revolving
credit commitments under the credit facility to a maximum of $75 million and maintained the amount available for letters of credit
at $30 million. The Fifth Amendment further reduced the revolving credit commitments over time on a dollar-for-dollar basis in
amounts equal to each of the following: (i) the face amount of any letter of credit that expires or whose face amount is reduced
by any such dollar amount, (ii) the net proceeds received from any asset sales, (iii) the Royal scheduled capital contributions
(as outline below), (iv) the net proceeds from the issuance of any equity by us up to $20.0 million (other than equity issued
in exchange for any Royal contribution as outlined in the Securities Purchase Agreement or the Royal scheduled capital contributions
to us as outlined below), and (v) the proceeds from the incurrence of any subordinated debt. The first $11 million of proceeds
received from any equity issued by us described in clause (iv) above shall also satisfy the Royal scheduled capital contributions
as outlined below. The Fifth Amendment requires Royal to contribute $2 million each quarter beginning September 30, 2016 through
September 30, 2017 and $1 million on December 1, 2017, for a total of $11 million. The Fifth Amendment further reduces the revolving
credit commitments as follows:
Date
of Reduction
|
|
Reduction
Amount
|
|
|
|
September
30, 2016
|
|
The
lesser of (i) $2 million or (ii) the positive difference (if any) of $2 million minus the proceeds from the issuance of any
of our equity (excluding any Royal equity contributions)
|
|
|
|
December
31, 2016
|
|
The
lesser of (i) $2 million or (ii) the positive difference (if any) of $4 million minus the proceeds from the issuance of any
of our equity (excluding any Royal equity contributions)
|
|
|
|
March
31, 2017
|
|
The
lesser of (i) $2 million or (ii) the positive difference (if any) of $6 million minus the proceeds from the issuance of any
of our equity (excluding any Royal equity contributions)
|
|
|
|
June
30, 2017
|
|
The
lesser of (i) $2 million or (ii) the positive difference (if any) of $8 million minus the proceeds from the issuance of any
of our equity (excluding any Royal equity contributions)
|
|
|
|
September
30, 2017
|
|
The
lesser of (i) $2 million or (ii) the positive difference (if any) of $10 million minus the proceeds from the issuance of any
of our equity (excluding any Royal equity contributions)
|
|
|
|
December
1, 2017
|
|
The
lesser of (i) $1 million or (ii) the positive difference (if any) of $11 million minus the proceeds from the issuance of any
of our equity (excluding any Royal equity contributions)
|
The
Fifth Amendment required that on or before March 31, 2017, we solicit bids for the potential sale of certain non-core assets,
satisfactory to the administrative agent, and provided the administrative agent, and any other lender upon its request, with a
description of the solicitation process, interested parties and any potential bids. The Fifth Amendment limits any payments by
us to our general partner to: (i) the usual and customary payroll and benefits of the our management team so long as our management
team remains employees of our general partner, (2) the usual and customary board fees of our general partner, and (3) the usual
and customary general and administrative costs and expenses of our general partner incurred in connection with the operation of
its business in an amount not to exceed $0.3 million per fiscal year. The Fifth Amendment limits asset sales to a maximum of $5
million unless we receive consent from the lenders. The Fifth Amendment removes the $5.0 million minimum liquidity requirement
and requires us to have any deposit, securities or investment accounts with a member of the lending group.
In
July 2016, we entered into the Sixth Amendment (“Sixth Amendment”) of our amended and restated senior secured credit
facility that permitted the sale of Elk Horn that was discussed earlier. The Sixth Amendment reduced the maximum commitment amount
allowed under the credit facility based on the initial cash proceeds of $10.5 million that were received for the Elk Horn sale.
The Sixth Amendment further reduces the maximum commitment amount allowed under the credit facility by $375,000 each quarterly
period beginning September 30, 2016 through June 30, 2017 for the additional $1.5 million received from the Elk Horn sale.
In
December, 2016, we entered into a Seventh Amendment, which allows for the Series A preferred units as outlined in the Fourth Amended
and Restated Agreement of Limited Partnership of the Partnership, which is further discussed in “Recent Developments”.
The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provides for additional revolving
credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces
the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales
after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. The Seventh Amendment alters
the maximum leverage ratio to 4.0 to 1.0 effective December 31, 2016 through May 31, 2017 and 3.5 to 1.0 from June 30, 2017 through
December 31, 2017. The maximum leverage ratio shall be reduced by 0.50 to 1.0 for every $10.0 million of net cash proceeds, in
the aggregate, received after the Seventh Amendment date from (i) the issuance of any equity by us and/or (ii) the disposition
of any assets in excess of $2.0 million in the aggregate, provided, however, that in no event will the maximum leverage ratio
be reduced below 3.0 to 1.0. The Seventh Amendment alters the minimum consolidated EBITDA figure, as calculated on a rolling twelve
months basis, to $12.5 million from December 31, 2016 through May 31, 2017 and $15.0 million from June 30, 2017 through December
31, 2017. The Seventh Amendment alters the maximum capital expenditures allowed, as calculated on a rolling twelve months basis,
to $20.0 million through the expiration of the credit facility. A condition precedent to the effectiveness of the Seventh Amendment
was the receipt of the $13.0 million of cash proceeds received by us from the issuance of the Series A preferred units pursuant
to the Preferred Unit Agreement, which we used to repay outstanding borrowings under the revolving credit facility. Per the Seventh
Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contributions as outlined in the previous
amendments to our credit agreement.
On
March 23, 2017, we entered into an Eighth Amendment (“Eighth Amendment”) of our amended and restated credit agreement
that allows the annual auditor’s report for the years ended December 31, 2016 and 2015 to contain a qualification with respect
to the short-term classification of our credit facility balance without creating a default under the credit agreement.
On
June 9, 2017, we entered into a ninth amendment (the “Ninth Amendment”) of our amended and restated credit agreement
that permitted outstanding letters of credit to be replaced with different counterparties without affecting the revolving credit
commitments under the credit agreement. The Ninth Amendment also permits certain lease and sale leaseback transactions under the
credit agreement that do not affect the revolving credit commitments under the credit agreement for asset dispositions and also
do into factor in the calculation of the maximum capital expenditures allowed under the credit agreement.
As
of and for the twelve months ended September 30, 2017, we are in compliance with respect to all covenants contained in the credit
agreement.
At
September 30, 2017, the Operating Company had borrowings outstanding (excluding letters of credit) of $9.9 million at a variable
interest rate of prime plus 3.50% (7.75% at September 30, 2017). In addition, the Operating Company had outstanding letters of
credit of approximately $26.1 million at a fixed interest rate of 5.00% at September 30, 2017. Based upon a maximum borrowing
capacity of 3.50 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company
had available borrowing capacity of approximately $8.2 million at September 30, 2017. During the three months ended September
30, 2017, we had average borrowings outstanding of approximately $12.6 million under our credit agreement.
Off-Balance
Sheet Arrangements
In
the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees
and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. No liabilities related
to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our
financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
Federal
and state laws require us to secure certain long-term obligations related to mine closure and reclamation costs. We typically
secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for
us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of
our amended and restated credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower
cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank
letters of credit as a percentage of our aggregate bond liability. To the extent that surety bonds become unavailable, we would
seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.
As
of September 30, 2017, we had $26.1 million in letters of credit outstanding, of which $20.7 million served as collateral for
surety bonds.
Critical
Accounting Policies and Estimates
Our
financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The
preparation of these financial statements requires management to make estimates and judgments that affect the reported amount
of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates
its estimates and judgments on an on-going basis. Management bases its estimates and judgments on historical experience and other
factors that are believed to be reasonable under the circumstances. Nevertheless, actual results may differ from the estimates
used and judgments made.
The
accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements
are fully described in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no significant changes
in these policies and estimates as of September 30, 2017.
Recent
Accounting Pronouncements
Refer
to Part-I— Item 1. Financial Statements, Note 2 of the notes to the unaudited condensed consolidated financial statements
for a discussion of recent accounting pronouncements, which is incorporated herein by reference. There are no known future impacts
or material changes or trends of new accounting guidance beyond the disclosures provided in Note 2.