Item
1. Financial Statements (Unaudited)
RHINO
RESOURCE PARTNERS LP
UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(in
thousands)
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
ASSETS
|
|
|
|
|
|
|
|
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
36
|
|
|
$
|
59
|
|
Accounts receivable, net of allowance for doubtful accounts ($0 as of
September 30, 2016 and $0 as of December 31, 2015)
|
|
|
13,272
|
|
|
|
12,597
|
|
Inventories
|
|
|
8,807
|
|
|
|
8,570
|
|
Advance royalties, current portion
|
|
|
1,091
|
|
|
|
753
|
|
Prepaid expenses and other
|
|
|
6,854
|
|
|
|
5,467
|
|
Current assets held for sale
|
|
|
-
|
|
|
|
1,998
|
|
Total current assets
|
|
|
30,060
|
|
|
|
29,444
|
|
PROPERTY, PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
At cost, including coal properties, mine development and construction
costs
|
|
|
449,204
|
|
|
|
484,309
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(261,473
|
)
|
|
|
(258,739
|
)
|
Net property, plant and equipment
|
|
|
187,731
|
|
|
|
225,570
|
|
Advance royalties, net of current portion
|
|
|
7,697
|
|
|
|
7,172
|
|
Investment in unconsolidated affiliates
|
|
|
7,446
|
|
|
|
7,578
|
|
Other non-current assets
|
|
|
26,006
|
|
|
|
26,306
|
|
Non-current assets held for sale
|
|
|
-
|
|
|
|
108,596
|
|
TOTAL
|
|
$
|
258,940
|
|
|
$
|
404,666
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
8,789
|
|
|
$
|
9,199
|
|
Accrued expenses and other
|
|
|
9,101
|
|
|
|
11,049
|
|
Current portion of long-term debt
|
|
|
-
|
|
|
|
41,479
|
|
Current portion of asset retirement obligations
|
|
|
1,430
|
|
|
|
767
|
|
Current portion of postretirement benefits
|
|
|
-
|
|
|
|
45
|
|
Current liabilities held for sale
|
|
|
-
|
|
|
|
930
|
|
Total current liabilities
|
|
|
19,320
|
|
|
|
63,469
|
|
NON-CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term debt, net of current portion
|
|
|
30,350
|
|
|
|
2,595
|
|
Asset retirement obligations, net of current portion
|
|
|
22,600
|
|
|
|
22,310
|
|
Other non-current liabilities
|
|
|
42,964
|
|
|
|
44,765
|
|
Non-current liabilities held for sale
|
|
|
-
|
|
|
|
3,599
|
|
Total non-current liabilities
|
|
|
95,914
|
|
|
|
73,269
|
|
Total liabilities
|
|
|
115,234
|
|
|
|
136,738
|
|
COMMITMENTS AND CONTINGENCIES (NOTE 13)
|
|
|
|
|
|
|
|
|
PARTNERS’ CAPITAL:
|
|
|
|
|
|
|
|
|
Limited partners
|
|
|
136,722
|
|
|
|
253,312
|
|
Subscription receivable from limited partners
|
|
|
(2,000
|
)
|
|
|
-
|
|
General partner
|
|
|
8,984
|
|
|
|
9,821
|
|
Accumulated other comprehensive income
|
|
|
-
|
|
|
|
4,795
|
|
Total partners’ capital
|
|
|
143,706
|
|
|
|
267,928
|
|
TOTAL
|
|
$
|
258,940
|
|
|
$
|
404,666
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
40,992
|
|
|
$
|
45,468
|
|
|
$
|
116,777
|
|
|
$
|
139,493
|
|
Freight and handling revenues
|
|
|
424
|
|
|
|
735
|
|
|
|
1,634
|
|
|
|
1,942
|
|
Other revenues
|
|
|
1,999
|
|
|
|
5,693
|
|
|
|
5,947
|
|
|
|
16,899
|
|
Total revenues
|
|
|
43,415
|
|
|
|
51,896
|
|
|
|
124,358
|
|
|
|
158,334
|
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation,
depletion and amortization shown separately below)
|
|
|
35,249
|
|
|
|
47,678
|
|
|
|
98,105
|
|
|
|
139,733
|
|
Freight and handling costs
|
|
|
385
|
|
|
|
709
|
|
|
|
1,451
|
|
|
|
1,915
|
|
Depreciation, depletion and amortization
|
|
|
6,489
|
|
|
|
7,838
|
|
|
|
18,341
|
|
|
|
24,456
|
|
Selling, general and administrative (exclusive
of depreciation, depletion and amortization shown separately above)
|
|
|
4,305
|
|
|
|
2,866
|
|
|
|
12,248
|
|
|
|
11,805
|
|
Loss on asset impairments
|
|
|
-
|
|
|
|
2,332
|
|
|
|
-
|
|
|
|
4,512
|
|
(Gain) on sale/disposal
of assets—net
|
|
|
(125
|
)
|
|
|
(453
|
)
|
|
|
(420
|
)
|
|
|
(435
|
)
|
Total costs and expenses
|
|
|
46,303
|
|
|
|
60,970
|
|
|
|
129,725
|
|
|
|
181,986
|
|
INCOME/(LOSS) FROM OPERATIONS
|
|
|
(2,888
|
)
|
|
|
(9,074
|
)
|
|
|
(5,367
|
)
|
|
|
(23,652
|
)
|
INTEREST AND OTHER (EXPENSE)/INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(1,904
|
)
|
|
|
(1,385
|
)
|
|
|
(5,195
|
)
|
|
|
(3,652
|
)
|
Interest income and other
|
|
|
(54
|
)
|
|
|
-
|
|
|
|
11
|
|
|
|
38
|
|
Gain on extinguishment of debt
|
|
|
1,663
|
|
|
|
-
|
|
|
|
1,663
|
|
|
|
-
|
|
Equity in net (loss)/income
of unconsolidated affiliates
|
|
|
(27
|
)
|
|
|
77
|
|
|
|
(132
|
)
|
|
|
342
|
|
Total interest and other
(expense)
|
|
|
(322
|
)
|
|
|
(1,308
|
)
|
|
|
(3,653
|
)
|
|
|
(3,272
|
)
|
NET (LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS
|
|
|
(3,210
|
)
|
|
|
(10,382
|
)
|
|
|
(9,020
|
)
|
|
|
(26,924
|
)
|
INCOME TAXES
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
NET (LOSS) FROM CONTINUING
OPERATIONS
|
|
|
(3,210
|
)
|
|
|
(10,382
|
)
|
|
|
(9,020
|
)
|
|
|
(26,924
|
)
|
DISCONTINUED OPERATIONS (NOTE 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)/income from discontinued
operations
|
|
|
(575
|
)
|
|
|
1,076
|
|
|
|
(117,940
|
)
|
|
|
5,666
|
|
NET (LOSS)
|
|
|
(3,785
|
)
|
|
|
(9,306
|
)
|
|
|
(126,960
|
)
|
|
|
(21,258
|
)
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of actuarial
gain under ASC Topic 715
|
|
|
-
|
|
|
|
(44
|
)
|
|
|
-
|
|
|
|
(133
|
)
|
COMPREHENSIVE (LOSS)
|
|
$
|
(3,785
|
)
|
|
$
|
(9,350
|
)
|
|
$
|
(126,960
|
)
|
|
$
|
(21,391
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner’s interest in net (loss)/income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(21
|
)
|
|
$
|
(208
|
)
|
|
$
|
(87
|
)
|
|
$
|
(538
|
)
|
Net income from discontinued
operations
|
|
|
(4
|
)
|
|
|
22
|
|
|
|
(750
|
)
|
|
|
113
|
|
General partner’s interest in net (loss)/income
|
|
$
|
(25
|
)
|
|
$
|
(186
|
)
|
|
$
|
(837
|
)
|
|
$
|
(425
|
)
|
Common unitholders’ interest in net (loss)/income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(2,758
|
)
|
|
$
|
(5,840
|
)
|
|
$
|
(7,144
|
)
|
|
$
|
(15,143
|
)
|
Net income from discontinued
operations
|
|
|
(494
|
)
|
|
|
605
|
|
|
|
(93,734
|
)
|
|
|
3,187
|
|
Common unitholders’ interest in net (loss)/income
|
|
$
|
(3,252
|
)
|
|
$
|
(5,235
|
)
|
|
$
|
(100,878
|
)
|
|
$
|
(11,956
|
)
|
Subordinated unitholders’ interest in net (loss)/income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(431
|
)
|
|
$
|
(4,334
|
)
|
|
$
|
(1,788
|
)
|
|
$
|
(11,243
|
)
|
Net income from discontinued
operations
|
|
|
(77
|
)
|
|
|
449
|
|
|
|
(23,456
|
)
|
|
|
2,366
|
|
Subordinated unitholders’ interest in
net (loss)/income
|
|
$
|
(508
|
)
|
|
$
|
(3,885
|
)
|
|
$
|
(25,244
|
)
|
|
$
|
(8,877
|
)
|
Net (loss)/income per limited partner unit, basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
$
|
(0.35
|
)
|
|
$
|
(3.49
|
)
|
|
$
|
(1.45
|
)
|
|
$
|
(8.99
|
)
|
Net income per unit from
discontinued operations
|
|
|
(0.06
|
)
|
|
|
0.36
|
|
|
|
(18.98
|
)
|
|
|
1.91
|
|
Net (loss)/income per common unit, basic
|
|
$
|
(0.41
|
)
|
|
$
|
(3.13
|
)
|
|
$
|
(20.43
|
)
|
|
$
|
(7.08
|
)
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
$
|
(0.35
|
)
|
|
$
|
(3.49
|
)
|
|
$
|
(1.45
|
)
|
|
$
|
(9.19
|
)
|
Net income per unit from
discontinued operations
|
|
|
(0.06
|
)
|
|
|
0.36
|
|
|
|
(18.98
|
)
|
|
|
1.91
|
|
Net (loss)/income per subordinated unit, basic
|
|
$
|
(0.41
|
)
|
|
$
|
(3.13
|
)
|
|
$
|
(20.43
|
)
|
|
$
|
(7.28
|
)
|
Net (loss)/income per limited partner unit, diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
$
|
(0.35
|
)
|
|
$
|
(3.49
|
)
|
|
$
|
(1.45
|
)
|
|
$
|
(8.99
|
)
|
Net income per unit from
discontinued operations
|
|
|
(0.06
|
)
|
|
|
0.36
|
|
|
|
(18.98
|
)
|
|
|
1.91
|
|
Net (loss)/income per common unit, diluted
|
|
$
|
(0.41
|
)
|
|
$
|
(3.13
|
)
|
|
$
|
(20.43
|
)
|
|
$
|
(7.08
|
)
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
$
|
(0.35
|
)
|
|
$
|
(3.49
|
)
|
|
$
|
(1.45
|
)
|
|
$
|
(9.19
|
)
|
Net income per unit from
discontinued operations
|
|
|
(0.06
|
)
|
|
|
0.36
|
|
|
|
(18.98
|
)
|
|
|
1.91
|
|
Net (loss)/income per subordinated unit, diluted
|
|
$
|
(0.41
|
)
|
|
$
|
(3.13
|
)
|
|
$
|
(20.43
|
)
|
|
$
|
(7.28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions paid per limited partner unit (1)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
0.07
|
|
Weighted average number of limited partner units outstanding, basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
7,906
|
|
|
|
1,671
|
|
|
|
4,937
|
|
|
|
1,670
|
|
Subordinated units
|
|
|
1,236
|
|
|
|
1,240
|
|
|
|
1,236
|
|
|
|
1,240
|
|
Weighted average number of limited partner units outstanding, diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
7,906
|
|
|
|
1,671
|
|
|
|
4,937
|
|
|
|
1,670
|
|
Subordinated units
|
|
|
1,236
|
|
|
|
1,240
|
|
|
|
1,236
|
|
|
|
1,240
|
|
(1)
No distributions were paid on the subordinated units for the three and nine months ended September 30, 2016 and 2015
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,
|
|
|
|
2016
|
|
|
2015
|
|
CASH FLOWS FROM CONTINUING AND DISCONTINUED OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Net (loss)
|
|
$
|
(126,961
|
)
|
|
$
|
(21,259
|
)
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
18,753
|
|
|
|
25,695
|
|
Accretion on asset retirement obligations
|
|
|
1,141
|
|
|
|
1,651
|
|
Accretion on interest-free debt
|
|
|
-
|
|
|
|
-
|
|
Amortization of deferred revenue
|
|
|
(1,337
|
)
|
|
|
(2,058
|
)
|
Amortization of advance royalties
|
|
|
773
|
|
|
|
602
|
|
Amortization of debt issuance costs
|
|
|
1,976
|
|
|
|
1,079
|
|
Amortization of actuarial gain
|
|
|
(4,796
|
)
|
|
|
(133
|
)
|
Provision for doubtful accounts
|
|
|
2,000
|
|
|
|
496
|
|
Equity in net loss/(income) of unconsolidated affiliates
|
|
|
132
|
|
|
|
(342
|
)
|
Distributions from unconsolidated affiliate
|
|
|
-
|
|
|
|
232
|
|
Loss on retirement of advance royalties
|
|
|
144
|
|
|
|
40
|
|
Loss on asset impairments
|
|
|
-
|
|
|
|
4,512
|
|
Loss on business disposal
|
|
|
119,160
|
|
|
|
-
|
|
(Gain) on sale/disposal of assets—net
|
|
|
(420
|
)
|
|
|
(1,172
|
)
|
Equity-based compensation
|
|
|
528
|
|
|
|
25
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(54
|
)
|
|
|
3,308
|
|
Inventories
|
|
|
(237
|
)
|
|
|
3,373
|
|
Advance royalties
|
|
|
(1,782
|
)
|
|
|
(1,456
|
)
|
Prepaid expenses and other assets
|
|
|
21
|
|
|
|
561
|
|
Accounts payable
|
|
|
(78
|
)
|
|
|
(1,390
|
)
|
Accrued expenses and other liabilities
|
|
|
(3,648
|
)
|
|
|
421
|
|
Asset retirement obligations
|
|
|
(161
|
)
|
|
|
(467
|
)
|
Postretirement benefits
|
|
|
(45
|
)
|
|
|
210
|
|
Net cash provided by operating activities
|
|
|
5,109
|
|
|
|
13,928
|
|
CASH FLOWS FROM CONTINUING AND DISCONTINUED INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Additions to property, plant, and equipment
|
|
|
(5,892
|
)
|
|
|
(12,060
|
)
|
Proceeds from sales of property, plant, and equipment
|
|
|
348
|
|
|
|
7,519
|
|
Proceeds from sale of Elk Horn
|
|
|
10,650
|
|
|
|
|
|
Return of capital from unconsolidated affiliates
|
|
|
-
|
|
|
|
35
|
|
Net cash used in investing activities
|
|
|
5,106
|
|
|
|
(4,506
|
)
|
CASH FLOWS FROM CONTINUING AND DISCONTINUED FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Borrowings on line of credit
|
|
|
80,450
|
|
|
|
75,650
|
|
Repayments on line of credit
|
|
|
(91,300
|
)
|
|
|
(82,100
|
)
|
Restricted cash from Royal contribution
|
|
|
(2,000
|
)
|
|
|
|
|
Repayments on long-term debt
|
|
|
(1,210
|
)
|
|
|
(156
|
)
|
Gain on debt extinguishment
|
|
|
(1,663
|
)
|
|
|
|
|
Distributions to unitholders
|
|
|
(24
|
)
|
|
|
(1,267
|
)
|
General partner’s contributions
|
|
|
-
|
|
|
|
1
|
|
Payments on debt issuance costs
|
|
|
(1,510
|
)
|
|
|
(2,062
|
)
|
Limited partner contributions
|
|
|
7,000
|
|
|
|
-
|
|
Net cash used in financing activities
|
|
|
(10,257
|
)
|
|
|
(9,934
|
)
|
NET DECREASE IN CASH AND CASH EQUIVALENTS
|
|
|
(42
|
)
|
|
|
(512
|
)
|
CASH AND CASH EQUIVALENTS—Beg of period
|
|
|
78
|
|
|
|
626
|
|
CASH AND CASH EQUIVALENTS—End of period
|
|
$
|
36
|
|
|
$
|
114
|
|
See
notes to unaudited condensed consolidated financial statements.
RHINO
RESOURCE PARTNERS LP
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
AS
OF SEPTEMBER 30, 2016 AND DECEMBER 31, 2015 AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015
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, 2016, condensed consolidated statements of operations and comprehensive income for the three and
nine months ended September 30, 2016 and 2015 and the condensed consolidated statements of cash flows for the nine months ended
September 30, 2016 and 2015 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, 2015 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, 2015 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, 2015 filed with the SEC.
Organization
—Rhino
Resource Partners LP is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor”
or 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 domestic utilities
and other coal-related organizations in the United States.
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 6,769,112 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 9,455,252 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 Rhino GP LLC as well
as the 9,455,252 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 60,000,000 common units in the Partnership to Royal in a private placement at $0.15 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 in the amount of $7.0 million. The promissory note is 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 determine that the Partnership does 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
has the option to rescind Royal’s purchase of 13,333,333 common units and the applicable installment will not be payable
(each, a “Rescission Right”). If the Partnership fails to exercise a Rescission Right, in each case, the Partnership
has the option to repurchase 13,333,333 common units at $0.30 per common unit from Royal (each, a “Repurchase Option”).
The Repurchase Options terminate on December 31, 2017. Royal’s obligation to pay any installment of the promissory note
is subject to certain conditions, including that the Operating Company has entered into an agreement to extend the amended and
restated credit agreement, as amended, to a date no sooner than December 31, 2017. In the event such conditions are not satisfied
as of the date each installment is due, Royal has the right to cancel the remaining unpaid balance of the promissory note in exchange
for the surrender of such number of common units equal to the principal balance of the promissory note divided by $0.15. 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. See Note 8 for more information on the fifth
amendment to the amended and restated credit agreement.
On
September 30, 2016, the Partnership entered into an equity exchange agreement (the “Agreement”) with Royal, Rhino
Resource Partners Holdings, LLC (“Rhino Holdings”), an entity wholly owned by certain investment partnerships managed
by Yorktown Partners LLC (“Yorktown”) and the General Partner. Investment partnerships managed by Yorktown own substantially
all of the outstanding common stock of Armstrong Energy, Inc. (“Armstrong Energy”), a coal producing company with
mines located in the Illinois Basin in western Kentucky. The Agreement contemplates that prior to closing, Yorktown will contribute
its shares of common stock of Armstrong Energy to Rhino Holdings. At the closing, Rhino Holdings will contribute those shares
to the Partnership in exchange for 10 million newly issued common units of the Partnership. The Agreement also contemplates that
the General Partner, currently owned and controlled by Royal, will issue a 50% ownership of the General Partner to Rhino Holdings
in connection with the issuance of the common units of the Partnership for the common stock of Armstrong Energy. Closing of the
Agreement is conditioned upon (i) the current bondholders of Armstrong Energy agreeing to restructure their bonds and (ii) the
Partnership refinancing its amended and restated credit agreement with funds from an equity investment into the Partnership to
be arranged by Rhino Holdings. The Agreement is also subject to other standard closing conditions and required approvals. The
Agreement contains customary covenants, representations and warranties and indemnification obligations for breaches of, or the
inaccuracy of representations or warranties or breaches of covenants contained in, the Agreement and associated agreements. The
Partnership has also agreed to enter into a registration rights agreement with Rhino Holdings 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. The Agreement may be terminated by the mutual written consent of the Partnership and Rhino Holdings or by either the Partnership
or Rhino Holdings if: (i) the closing has not occurred on or before December 31, 2016 (unless the closing is as a result of such
terminating party’s inability or failure to satisfy the conditions to the closing or if the non-terminating party has filed
an action seeking specific performance); (ii) a law or order issued by a governmental authority prevents the closing from occurring
(unless such law or order resulted from such party’s failure to perform its obligations under the Agreement); (iii) the
board of directors of the General Partner fails to approve the transactions or transaction documents contemplated by the Agreement;
or (iv) the lenders of the Partnership’s credit facility fail to approve the transactions and transaction documents contemplated
by the Agreement. The parties anticipate the Agreement will be consummated on or before December 31, 2016.
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. Any fractional units resulting
from the reverse unit split were rounded to the nearest whole unit. The reverse unit split was intended to increase the market
price per unit of Rhino’s common units in order to comply with the New York Stock Exchange’s (“NYSE”)
continued listing standards.
As
previously reported, on December 17, 2015, the Partnership was notified by the NYSE 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. 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 its common units. The NYSE held a hearing regarding the Partnership’s 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 the Partnership’s 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.”
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
May 2008, the Operating Company entered into a joint venture, Rhino Eastern LLC (“Rhino Eastern”), with an affiliate
of Patriot Coal Corporation (“Patriot”) to acquire the Eagle mining complex located in Central Appalachia. The Partnership
accounted for the investment in the joint venture and its results of operations under the equity method. In January 2015, the
Partnership completed a Membership Transfer Agreement (the “Transfer Agreement”) with an affiliate of Patriot that
terminated the Rhino Eastern joint venture. Pursuant to the Transfer Agreement, Patriot sold and assigned its 49% membership interest
in the Rhino Eastern joint venture to the Partnership and, in consideration of this transfer, Patriot received certain fixed assets,
leased equipment and coal reserves associated with the mining area previously operated by the Rhino Eastern joint venture. Patriot
also assumed substantially all of the active workforce related to the Eagle mining area that was previously employed by the Rhino
Eastern joint venture. The Partnership retained approximately 34 million tons of coal reserves that are not related to the Eagle
mining area as well as a prepaid advanced royalty balance. As part of the closing of the Transfer Agreement, the Partnership and
Patriot agreed to a dissolution payment based upon a final working capital adjustment calculation as defined in the Transfer Agreement.
Refer to Note 16 for information on the financial statement impact of the Rhino Eastern dissolution completed in January 2015.
In
December 2012, the Partnership made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant
LLC (“Muskie”), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers
in the Utica Shale region and other oil and natural gas basins in the United States. The Partnership accounted for the investment
in the joint venture and results of operations under the equity method. In November 2014, the Partnership contributed its interest
in Muskie to Mammoth Energy Partners LP (“Mammoth”), which is discussed below.
In
November 2014, the Partnership contributed its investment interest in Muskie to Mammoth in return for a limited partner interest
in Mammoth. Mammoth was formed to own various companies that provide services to companies, which engage in the exploration and
development of North American onshore unconventional oil and natural gas reserves. Mammoth’s companies provide services
that include completion and production services, contract land and directional drilling services and remote accommodation services.
The non-cash transaction was a contribution of the Partnership’s investment interest in the Muskie entity for an investment
interest in Mammoth. Thus, the Partnership determined that the non-cash exchange of the Partnership’s ownership interest
in Muskie did not result in any gain or loss. As of September 30, 2016 and 2015, the Partnership has recorded its investment in
Mammoth of $1.9 million as a long-term asset, which the Partnership records as a cost method investment based upon its ownership
percentage. In October 2016, the Partnership contributed its limited partner interests in Mammoth to Mammoth Energy Services,
Inc. in exchange for 234,300 shares of common stock of Mammoth Energy Services, Inc. See Subsequent Events Note 18 for further
details. The Partnership has included its investment in Mammoth and its prior investment in Muskie in its Other category for segment
reporting purposes.
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 (“Gulfport”), a publicly traded company. Sturgeon subsequently
acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac
sand for oil and natural gas drillers in the United States. The Partnership accounts for the investment in the joint venture and
results of operations under the equity method. The Partnership recorded its proportionate share of the operating (loss) for Sturgeon
for the three and nine months ended September 30, 2016 of approximately ($27,000) and ($0.1) million, respectively. The Partnership
recorded its proportionate share of the operating income for Sturgeon for the three and nine months ended September 30, 2015 of
approximately $0.1 million and $0.3 million, respectively. The Partnership has included the operating activities of 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”).
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.
In
January 2015, the FASB issued ASU 2015-01, “Income Statement-Extraordinary and Unusual Items”. ASC 225-20, Income
Statement—Extraordinary and Unusual Items, required that an entity separately classify, present, and disclose extraordinary
events and transactions. ASU 2015-01 eliminates the concept of extraordinary items. The amendments in ASU 2015-01 are effective
for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply
the amendments prospectively. A reporting entity also may apply the amendments retrospectively to all prior periods presented
in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal
year of adoption. The effective date is the same for both public business entities and all other entities. The adoption of ASU
2015-01 on January 1, 2016 did not have a material impact on the Partnership’s financial statements.
In
February 2015, the FASB issued ASU 2015-02, “Consolidation”. ASU 2015-02 affects reporting entities that are required
to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised
consolidation model. Specifically, the amendments of ASU 2015-02: a) modify the evaluation of whether limited partnerships and
similar legal entities are variable interest entities (VIEs) or voting interest entities, b) eliminate the presumption that a
general partner should consolidate a limited partnership, c) affect the consolidation analysis of reporting entities that are
involved with VIEs, particularly those that have fee arrangements and related party relationships and d) provide a scope exception
from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate
in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money
market funds. ASU 2015-02 is effective for public business entities for fiscal years, and for interim periods within those fiscal
years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. If an entity early
adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes
that interim period. A reporting entity may apply the amendments in this Update using a modified retrospective approach by recording
a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. A reporting entity also may apply
the amendments retrospectively. The adoption of ASU 2015-02 on January 1, 2016 did not have a material impact on the Partnership’s
financial statements.
In
April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30)-Simplifying the Presentation
of Debt Issuance Costs”. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented
in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior
to ASU 2015-03, debt issuance costs have been presented in the balance sheet as a deferred charge, or asset. The recognition and
measurement guidance for debt issuance costs are not affected by the amendments in this ASU. For public business entities, ASU
2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within
those fiscal years. Early adoption of ASU 2015-03 is permitted for financial statements that have not been previously issued.
In addition, ASU 2015-03 requires entities to apply the new guidance on a retrospective basis, wherein the balance sheet of each
individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The adoption
of ASU 2015-03 on January 1, 2016 did not have a material impact on the Partnership’s financial statements.
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 will be paid in ten equal monthly installments
of $150,000 on the 20
th
of each calendar month beginning on September 20, 2016. Elk Horn is a coal leasing company
located in eastern Kentucky that has provided the Partnership with coal royalty revenues from coal properties owned by Elk Horn
and leased to third-party operators. As of December 31, 2015, Elk Horn controlled approximately 100 million tons of proven and
probable steam coal reserves. During the second quarter of 2016, the Partnership evaluated the Elk Horn assets for potential impairment
based upon the initial purchase price offered by the buyer and the continued deterioration of the Central Appalachia steam coal
markets that had adversely affected Elk Horn’s financial results. The Partnership’s impairment analysis determined
that a potential impairment existed since the carrying amount of the Elk Horn long-lived asset group exceeded the cash flows that
would be generated from the purchase price offered from the buyer. Based on a market approach used to estimate the fair value
of the Elk Horn long-lived asset group, the Partnership recorded total asset impairment charges of approximately $118.7 million
related to Coal properties as of June 30, 2016. The disposal of the Elk Horn assets and liabilities in August 2016 resulted in
an additional loss of $0.5 million. The total loss of $119.2 million from the Elk Horn disposal is recorded on the Loss on business
disposal line in the Partnership’s unaudited condensed consolidated statements of cash flows for the nine months ended September
30, 2016. The total loss on the Elk Horn disposal as well as the previous operating results of Elk Horn have been reclassified
and reported on the (Loss)/gain 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 and 2015. The current
and non-current assets and liabilities previously related to Elk Horn have been reclassified to the appropriate held for sale
categories on the Partnership’s unaudited condensed consolidated statements of financial position for the year ended December
31, 2015.
Utica
Shale Oil and Natural Gas Assets
Beginning
in 2011, the Partnership and an affiliate of Wexford Capital participated with Gulfport to acquire interests in a portfolio of
oil and natural gas leases in the Utica Shale, which consisted of a 5% interest in a total of approximately 152,300 gross acres,
or approximately 7,615 net acres. In March 2014, the Partnership completed a purchase and sale agreement with Gulfport to sell
the Partnership’s oil and natural gas properties in the Utica Shale region. In addition, in January 2014, the Partnership
received approximately $8.4 million of net proceeds from the sale by Blackhawk Midstream LLC (“Blackhawk”) of its
equity interest in two entities, Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, to Summit Midstream Partners, LLC.
As part of the joint operating agreement for the Utica Shale investment discussed above, the Partnership had the right to approximately
5% of the proceeds of the sale by Blackhawk. In February 2015, the Partnership received approximately $0.7 million in additional
proceeds from the sale by Blackhawk that had been held in escrow. For the nine months ended September 30, 2015, the Partnership
recorded the $0.7 million in Income from discontinued operations in the unaudited condensed consolidated statements of operations
and comprehensive income. The gain from the Blackhawk transaction is included in the (Gain) on sale/disposal of assets—net
line in the operating activities section of the Partnership’s unaudited condensed consolidated statements of cash flows.
The proceeds from the Blackhawk transaction are included in the Proceeds from sales of property, plant, and equipment line in
the investing activities section of the Partnership’s unaudited condensed consolidated statements of cash flows.
4.
PREPAID EXPENSES AND OTHER CURRENT ASSETS
Prepaid
expenses and other current assets as of September 30, 2016 and December 31, 2015 consisted of the following:
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
|
|
(in thousands)
|
|
Other prepaid expenses
|
|
$
|
402
|
|
|
$
|
675
|
|
Debt issuance costs—net
|
|
|
-
|
|
|
|
2,155
|
|
Prepaid insurance
|
|
|
1,969
|
|
|
|
1,492
|
|
Prepaid leases
|
|
|
97
|
|
|
|
80
|
|
Supply inventory
|
|
|
872
|
|
|
|
901
|
|
Deposits
|
|
|
164
|
|
|
|
164
|
|
Restricted cash from Royal contribution
|
|
|
2,000
|
|
|
|
-
|
|
Note receivable
|
|
|
1,350
|
|
|
|
-
|
|
Total Prepaid expenses and other
|
|
$
|
6,854
|
|
|
$
|
5,467
|
|
Debt
issuance costs were included in Prepaid expenses and other current assets as of December 31, 2015 since the Partnership classified
its credit facility balance as a current liability prior to the fifth amendment to the credit facility completed in May 2016.
See Note 6 for further information on debt issuance costs and accumulated amortization of debt issuance costs as of September
30, 2016 and December 31, 2015. See Note 8 for further information on the amendments to the amended and restated senior secured
credit facility.
The
$2.0 million of restricted cash relates to the Royal contribution made to the Partnership on September 30, 2016 and described
in Note 1. The contribution was completed after the close of business on September 30, 2016 and was restricted to reduce the Partnership’s
outstanding balance on its credit facility balance per the fifth amendment to the Partnership’s amended and restated credit
agreement described further in Note 8.
The
$1.4 million note receivable relates to the $1.5 million of consideration to be paid in ten equal monthly installments of $150,000
for the Elk Horn sale discussed earlier. The first installment was paid in September 2016.
5.
PROPERTY, PLANT AND EQUIPMENT
Property,
plant and equipment, including coal properties and mine development and construction costs, as of September 30, 2016 and December
31, 2015 are summarized by major classification as follows:
|
|
Useful Lives
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
|
|
|
|
(in thousands)
|
|
Land and land improvements
|
|
|
|
$
|
17,671
|
|
|
$
|
18,285
|
|
Mining and other equipment and related facilities
|
|
2 - 20 Years
|
|
|
305,186
|
|
|
|
304,692
|
|
Mine development costs
|
|
1 - 15 Years
|
|
|
57,365
|
|
|
|
64,262
|
|
Coal properties
|
|
1 - 15 Years
|
|
|
68,383
|
|
|
|
94,390
|
|
Construction work in process
|
|
|
|
|
599
|
|
|
|
2,680
|
|
Total
|
|
|
|
|
449,204
|
|
|
|
484,309
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
|
|
(261,473
|
)
|
|
|
(258,739
|
)
|
Net
|
|
|
|
$
|
187,731
|
|
|
$
|
225,570
|
|
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, 2016 and 2015 were as follows:
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
(in thousands)
|
|
Depreciation expense-mining and other equipment and related facilities
|
|
$
|
5,597
|
|
|
$
|
7,194
|
|
|
$
|
15,908
|
|
|
$
|
22,138
|
|
Depletion expense for coal properties and oil and natural gas properties
|
|
|
404
|
|
|
|
307
|
|
|
|
1,224
|
|
|
|
1,053
|
|
Amortization expense for mine development costs
|
|
|
511
|
|
|
|
465
|
|
|
|
1,294
|
|
|
|
1,545
|
|
Amortization expense for intangible assets
|
|
|
-
|
|
|
|
12
|
|
|
|
-
|
|
|
|
35
|
|
Amortization expense for asset retirement costs
|
|
|
(23
|
)
|
|
|
(140
|
)
|
|
|
(85
|
)
|
|
|
(315
|
)
|
Total depreciation, depletion and amortization
|
|
$
|
6,489
|
|
|
$
|
7,838
|
|
|
$
|
18,341
|
|
|
$
|
24,456
|
|
6.
OTHER NON-CURRENT ASSETS
Other
non-current assets as of September 30, 2016 and December 31, 2015 consisted of the following:
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
|
|
(in thousands)
|
|
Deposits and other
|
|
$
|
185
|
|
|
$
|
138
|
|
Debt issuance costs—net
|
|
|
1,690
|
|
|
|
-
|
|
Non-current receivable
|
|
|
23,908
|
|
|
|
23,908
|
|
Note Receivable
|
|
|
-
|
|
|
|
2,000
|
|
Deferred expenses
|
|
|
223
|
|
|
|
260
|
|
Total
|
|
$
|
26,006
|
|
|
$
|
26,306
|
|
Debt
issuance costs were included in Prepaid expenses and other current assets as of December 31, 2015 since the Partnership classified
its credit facility balance as a current liability prior to the fifth amendment to the credit facility completed in May 2016 and
discussed further below (see Note 4 for Prepaid expenses and other current assets). Debt issuance costs were $13.1 million and
$11.6 million as of September 30, 2016 and December 31, 2015, respectively. Accumulated amortization of debt issuance costs were
$11.4 million and $9.4 million as of September 30, 2016 and December 31, 2015, respectively.
In
April 2015, the Partnership entered into a third amendment of its amended and restated senior secured credit facility that reduced
the borrowing commitment to $100 million. As part of executing the third amendment to the amended and restated senior secured
credit facility, the Operating Company paid a fee of approximately $2.1 million to the lenders in April 2015, which was recorded
as an addition to Debt issuance costs. The Partnership wrote-off approximately $0.2 million of its remaining unamortized debt
issuance costs since the third amendment reduced the borrowing commitment under the amended and restated senior secured credit
facility.
In
March 2016, the Partnership entered into a fourth amendment of its amended and restated senior secured credit facility that reduced
the borrowing commitment to $80 million. As part of executing the fourth amendment to the amended and restated senior secured
credit facility, the Operating Company paid a fee of approximately $0.4 million to the lenders in March 2016, which was recorded
as an addition to Debt issuance costs. The Partnership wrote-off approximately $0.2 million of its remaining unamortized debt
issuance costs since the fourth amendment reduced the borrowing commitment under the amended and restated senior secured credit
facility.
In
May 2016, the Partnership entered into a fifth amendment of its amended and restated senior secured credit facility that reduced
the borrowing commitment to $75 million. As part of executing the fifth amendment to the amended and restated senior secured credit
facility, the Operating Company paid a fee of approximately $1.2 million to the lenders in May 2016, which was recorded as an
addition to Debt issuance costs. The Partnership wrote-off approximately $0.1 million of its remaining unamortized debt issuance
costs since the fifth amendment reduced the borrowing commitment under the amended and restated senior secured credit facility.
See Note 8 for further information on the amendments to the amended and restated senior secured credit facility.
The
non-current receivable balance of $23.9 million as of September 30, 2016 and December 31, 2015 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 $23.9 million
is also included in the Partnership’s accrued workers’ compensation benefits liability balance, which is included
in the 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.
The
Partnership recorded a $2.0 million note receivable from a third party at December 31, 2015 related to the sale of the Partnership’s
Deane mining complex in eastern Kentucky. The note accrued interest with initial interest payments due beginning June 2016 and
the final principal due December 31, 2017. The Partnership has not received any of the scheduled interest payments from the third
party as of September 30, 2016 and ongoing discussions with the third party indicated it was more likely than not that the Partnership
would not receive the balance of the note receivable. While the Partnership continues discussions with the third party for collection
of the note receivable, the Partnership recorded a $2.0 million reserve against the note receivable as of September 30, 2016.
7.
ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES
Accrued
expenses and other current liabilities as of September 30, 2016 and December 31, 2015 consisted of the following:
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
|
|
(in thousands)
|
|
Payroll, bonus and vacation expense
|
|
$
|
1,106
|
|
|
$
|
1,439
|
|
Non income taxes
|
|
|
2,595
|
|
|
|
2,993
|
|
Royalty expenses
|
|
|
1,656
|
|
|
|
1,566
|
|
Accrued interest
|
|
|
1,039
|
|
|
|
571
|
|
Health claims
|
|
|
688
|
|
|
|
817
|
|
Workers’ compensation & pneumoconiosis
|
|
|
1,150
|
|
|
|
1,150
|
|
Accrued insured litigation claims
|
|
|
302
|
|
|
|
266
|
|
Other
|
|
|
565
|
|
|
|
2,247
|
|
Total
|
|
$
|
9,101
|
|
|
$
|
11,049
|
|
The
$0.3 million accrued for insured litigation claims as of September 30, 2016 and December 31, 2015 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, 2016 and December 31, 2015 consisted of the following:
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
|
|
(in thousands)
|
|
Senior secured credit facility with PNC Bank, N.A.
|
|
$
|
30,350
|
|
|
$
|
41,200
|
|
Other notes payable
|
|
|
-
|
|
|
|
2,874
|
|
Total
|
|
|
30,350
|
|
|
|
44,074
|
|
Less current portion
|
|
|
-
|
|
|
|
(41,479
|
)
|
Long-term debt
|
|
$
|
30,350
|
|
|
$
|
2,595
|
|
Senior
Secured Credit Facility with PNC Bank, N.A.
—On July 29, 2011, the Operating Company and the Partnership, as a guarantor,
executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders,
which are parties thereto. 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. As described below, in April 2015, March 2016 and May 2016, the amended and restated credit facility
was amended and the borrowing commitment under the facility was reduced to $75 million, with the amount available for letters
of credit reduced to $30 million. Borrowings under the facility bear interest, which per the March 2016 amendment described further
below, is based upon the current PRIME rate plus an applicable margin of 3.50%. As part of the agreement, the Operating Company
is required to pay a commitment fee on the unused portion of the borrowing availability. Borrowings on the amended and restated
senior secured credit facility are collateralized by all of the unsecured assets of the Partnership. The amended and restated
senior secured credit facility requires the Partnership 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. The Partnership was in compliance with all covenants
contained in the amended and restated senior secured credit facility as of and for the twelve-month period ended September 30,
2016. Per the May 2016 amendment described further below, the amended and restated senior secured credit facility is set to expire
on July 31, 2017, with the possibility to extend the facility to December 31, 2017 if certain conditions are met as described
below.
In
April 2015, the Partnership entered into a third amendment of its amended and restated senior secured credit facility. The third
amendment reduced the borrowing commitment under the credit facility to a maximum of $100 million and reduced the amount available
for letters of credit to $50 million. The third amendment also provides that the disposition of any assets by the Partnership
consisting of net cash proceeds up to an aggregate $35 million shall reduce the total commitment under the facility on a dollar-for-dollar
basis by up to a total of $10 million, and any dispositions of assets in excess of $35 million in the aggregate shall reduce the
commitment under the facility on a dollar-for-dollar basis. The third amendment limits the Partnership’s quarterly distributions
to a maximum of $0.035 per unit unless (i) the pro forma leverage ratio of the Partnership, immediately prior to and after giving
effect to such distribution, is less than or equal to 3.0 to 1.0 and (ii) the amount of borrowings available under the credit
facility, immediately prior to and after giving effect to such distribution, is at least $20 million. In addition, the third amendment
removed the interest coverage ratio covenant and replaced it with a minimum fixed charge coverage ratio, which consists of the
ratio of consolidated EBITDA minus maintenance capital expenditures to fixed charges. Fixed charges are defined in the third amendment
to include the sum of cash interest expense, scheduled principal installments on indebtedness (as adjusted for prepayments), dividends
and distributions. Commencing with the quarter ended September 30, 2015, the fixed charge coverage ratio for the trailing four
quarters must be a minimum of 1.1 to 1.0. The third amendment also limits any investments made by the Partnership, including investments
in hydrocarbons, to $10 million provided that the leverage ratio is less than or equal to 3.0 to 1.0 and the borrowers’
available liquidity is at least $20 million. The third amendment does not permit the Partnership to issue any new equity of the
Partnership unless the proceeds of such equity issuance are used to reduce the outstanding borrowings under the facility. Issuances
of equity under the Partnership’s long-term incentive plan are excluded from this requirement. The third amendment limits
the amount of the Partnership’s capital expenditures to $20.0 million for fiscal year 2015 and limits capital expenditures
to $27.5 million for each fiscal year after 2015. However, to the extent that capital expenditures for any fiscal year are less
than indicated above, the Partnership may increase the following year’s capital expenditures by the lesser of such unused
amount or $5.0 million. As part of executing the third amendment to the amended and restated senior secured credit facility, the
Operating Company paid a fee of approximately $2.1 million to the lenders in April 2015, which was recorded in Debt issuance costs
in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position. In addition,
the Partnership recorded a non-cash charge of approximately $0.2 million to write-off a portion of its unamortized debt issuance
costs since the third amendment reduced the borrowing commitment under the amended and restated senior secured credit facility,
which was recorded in Interest expense on the Partnership’s unaudited condensed consolidated statements of operations and
comprehensive income.
In
March 2016, the Partnership entered into a fourth amendment (the “Fourth Amendment”) of its amended and restated senior
secured credit facility. 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 and set the expiration of the facility to July 29,
2016. 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 the ability of the Partnership to pay distributions to its 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 the Partnership 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 the Partnership on or after the Fourth Amendment effective date (other than the Royal
equity contribution discussed above), or the disposition of any assets by the Partnership. The Fourth Amendment requires the Partnership
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 limits the amount of the Partnership’s
capital expenditures to $15 million, calculated as of end of the most recent month, on a trailing twelve-month basis. The Fourth
Amendment requires the Partnership to provide monthly financial statements and a weekly rolling thirteen-week cash flow forecast
to the administrative agent.
On
May 13, 2016, the Partnership entered into a fifth amendment (the “Fifth Amendment”) of its amended and restated senior
secured credit facility that extends the term of the senior secured credit facility 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 reduces 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. The Fifth Amendment
further reduces 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 outlined below), (iv) the net proceeds
from the issuance of any equity by the Partnership 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 the Partnership 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 the Partnership 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
Partnership 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
Partnership 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
Partnership 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
Partnership 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
Partnership 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
Partnership equity (excluding any Royal equity contributions)
|
The
Fifth Amendment requires that on or before March 31, 2017, the Partnership shall have solicited 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 the Partnership to the General Partner to: (i) the usual and customary payroll and benefits of the Partnership’s
management team so long as the Partnership’s management team remains employees of the General Partner, (2) the usual and
customary board fees of the General Partner and (3) the usual and customary general and administrative costs and expenses of the
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 the Partnership receives consent from the lenders. The
Fifth Amendment alters the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve-month
basis, as follows:
Period
|
|
Ratio
|
|
|
|
For
the month ending April 30, 2016, through the month ending May 31, 2016
|
|
7.50
to 1.00
|
|
|
|
For
the month ending June 30, 2016, through the month ending August 31, 2016
|
|
7.25
to 1.00
|
|
|
|
For
the month ending September 30, 2016, through the month ending November 30, 2016
|
|
7.00
to 1.00
|
|
|
|
For
the month ending December 31, 2016, through the month ending March 31, 2017
|
|
6.75
to 1.00
|
|
|
|
For
the month ending April 30, 2017, through the month ending June 30, 2017
|
|
6.25
to 1.00
|
|
|
|
For
the month ending July 31, 2017, through the month ending November 30, 2017
|
|
6.0
to 1.00
|
|
|
|
For
the month ending December 31, 2017
|
|
5.50
to 1.00
|
The
leverage ratios above shall be reduced by 0.50 to 1.00 for every $10 million of aggregate proceeds received by the Partnership
from: (i) the issuance of equity by the Partnership (excluding any Royal capital contributions) and/or (ii) the proceeds received
from the sale of assets, provided that the leverage ratio shall not be reduced below 3.50 to 1.00. The Fifth Amendment removes
the $5.0 million minimum liquidity requirement and requires the Partnership to have any deposit, securities or investment accounts
with a member of the lending group.
In
July 2016, the Partnership entered into a sixth amendment (the “Sixth Amendment”) of its 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 for the
additional $1.5 million to be received from the Elk Horn sale by $375,000 each quarterly period beginning September 30, 2016 through
June 30, 2017.
At
September 30, 2016, the Operating Company had borrowings outstanding (excluding letters of credit) of $30.4 million at a variable
interest rate of PRIME plus 3.50% (7.00% at September 30, 2016). In addition, the Operating Company had outstanding letters of
credit of approximately $27.8 million at a fixed interest rate of 5.00% at September 30, 2016. Based upon a maximum borrowing
capacity of 6.50 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company
had available borrowing capacity of approximately $4.0 million at September 30, 2016.
Other
Notes Payable
—On July 7, 2016, the Partnership executed an agreement with the third party that held the approximately
$2.8 million of other notes payable to settle the debt for $1.1 million of cash consideration. The Partnership paid the $1.1 million
in July 2016 and recognized an approximate $1.7 million gain from the extinguishment of this debt.
9.
ASSET RETIREMENT OBLIGATIONS
The
changes in asset retirement obligations for the nine months ended September 30, 2016 and the year ended December 31, 2015 are
as follows:
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
|
|
(in thousands)
|
|
Balance at beginning of period (including current portion)
|
|
$
|
23,077
|
|
|
$
|
29,883
|
|
Accretion expense
|
|
|
1,114
|
|
|
|
2,082
|
|
Adjustment resulting from addition of property
|
|
|
-
|
|
|
|
1,235
|
|
Adjustment resulting from disposal of property (1)
|
|
|
-
|
|
|
|
(7,531
|
)
|
Adjustments to the liability from annual recosting and other
|
|
|
-
|
|
|
|
(2,078
|
)
|
Liabilities settled
|
|
|
(161
|
)
|
|
|
(514
|
)
|
Balance at end of period
|
|
|
24,030
|
|
|
|
23,077
|
|
Less current portion of asset retirement obligation
|
|
|
(1,430
|
)
|
|
|
(767
|
)
|
Long-term portion of asset retirement obligation
|
|
$
|
22,600
|
|
|
$
|
22,310
|
|
(1)
|
The
($7.5) million adjustment for the year ended December 31, 2015 relates to the sale of the Partnership’s Deane mining
complex.
|
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.
Net
periodic benefit cost for the three and nine months ended September 30, 2016 and 2015 are as follows:
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
(in thousands)
|
|
Service costs
|
|
$
|
-
|
|
|
$
|
67
|
|
|
$
|
-
|
|
|
$
|
202
|
|
Interest cost
|
|
|
-
|
|
|
|
51
|
|
|
|
-
|
|
|
|
152
|
|
Amortization of (gain)
|
|
|
-
|
|
|
|
(44
|
)
|
|
|
(4,796
|
)
|
|
|
(133
|
)
|
Total
|
|
$
|
-
|
|
|
$
|
74
|
|
|
$
|
(4,796
|
)
|
|
$
|
221
|
|
For
the three and nine months ended September 30, 2016 and 2015, net periodic benefit costs, including the amortization of actuarial
gain included in the table above, are included in Cost of operations in the Partnership’s 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, 2016 and
2015 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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
(in thousands)
|
|
401(k) plan expense
|
|
$
|
406
|
|
|
$
|
501
|
|
|
$
|
1,113
|
|
|
$
|
1,640
|
|
11.
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
of September 30, 2016, the General Partner had granted phantom units to certain employees and restricted units and unit awards
to its directors. These grants consisted of annual restricted unit awards to directors and phantom unit awards with tandem distribution
equivalent rights (“DERs”) granted in the first quarters from 2012 through 2015 to certain employees in connection
with the prior year’s performance. The DERs consist of rights to accrue quarterly cash distributions in an amount equal
to the cash distribution the Partnership makes to unitholders during the vesting period. These awards are subject to service based
vesting conditions and any accrued distributions will be forfeited if the related awards fail to vest according to the relevant
service based vesting conditions.
The
Partnership accounts for its unit-based awards as liabilities with applicable mark-to-market adjustments at each reporting period
because the Compensation Committee of the board of directors of the General Partner has historically elected to pay some of the
awards in cash in lieu of issuing common units.
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 9,455,252 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 will become immediately vested upon a change in control. The Partnership recognized approximately
$10,000 of expense from the vesting of these units as a result of the change in control.
During
the nine months ended September 30, 2016, the General Partner granted fully vested common units to its board of directors as well
as certain members of management. The Partnership recognized approximately $0.6 million of expense for the nine months ended September
30, 2016 in relation to the common units granted.
12.
COMMITMENTS AND CONTINGENCIES
Coal
Sales Contracts and Contingencies
—As of September 30, 2016, the Partnership had commitments under sales contracts
to deliver annually scheduled base quantities of coal as follows:
Year
|
|
Tons (in thousands)
|
|
|
Number of customers
|
|
2016 Q4
|
|
|
797
|
|
|
|
14
|
|
2017
|
|
|
2,910
|
|
|
|
10
|
|
2018
|
|
|
701
|
|
|
|
3
|
|
Some
of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of
factors and indices.
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, 2016 and 2015 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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
(in thousands)
|
|
Lease expense
|
|
$
|
1,438
|
|
|
$
|
2,582
|
|
|
$
|
3,517
|
|
|
$
|
5,001
|
|
Royalty expense
|
|
$
|
2,409
|
|
|
$
|
2,301
|
|
|
$
|
7,350
|
|
|
$
|
8,659
|
|
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, 2016 or 2015.
The
Partnership may contribute 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, 2016 or 2015.
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, 2016 and 2015, which include the retrospective application of the 1-for-10 reverse unit split:
Three months ended September 30, 2016
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
|
(in thousands, except per unit data)
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest in net (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(21
|
)
|
|
$
|
(2,758
|
)
|
|
$
|
(431
|
)
|
Net income from discontinued operations
|
|
|
(4
|
)
|
|
|
(494
|
)
|
|
|
(77
|
)
|
Total interest in net (loss)
|
|
$
|
(25
|
)
|
|
$
|
(3,252
|
)
|
|
$
|
(508
|
)
|
Impact of subordinated distribution suspension:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) from continuing operations
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Net income from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Interest in net income
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Interest in net (loss) for EPU purposes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(21
|
)
|
|
$
|
(2,758
|
)
|
|
$
|
(431
|
)
|
Net income from discontinued operations
|
|
|
(4
|
)
|
|
|
(494
|
)
|
|
|
(77
|
)
|
Interest in net (loss)
|
|
$
|
(25
|
)
|
|
$
|
(3,252
|
)
|
|
$
|
(508
|
)
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
7,906
|
|
|
|
1,236
|
|
Effect of dilutive securities — LTIP awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive securities for net (loss) from continuing operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Dilutive securities for net income from discontinued
operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Total dilutive securities
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Weighted average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
7,906
|
|
|
|
1,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)/income per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.35
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(0.06
|
)
|
|
|
(0.06
|
)
|
Net (loss) per common unit, basic
|
|
|
n/a
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.41
|
)
|
Net (loss)/income per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(0.35
|
)
|
|
$
|
(0.35
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(0.06
|
)
|
|
|
(0.06
|
)
|
Net (loss) per common unit, diluted
|
|
|
n/a
|
|
|
$
|
(0.41
|
)
|
|
$
|
(0.41
|
)
|
Nine months ended September 30, 2016
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
|
(in thousands, except per unit data)
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest in net (loss)/income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(87
|
)
|
|
$
|
(7,144
|
)
|
|
$
|
(1,788
|
)
|
Net income from discontinued operations
|
|
|
(750
|
)
|
|
|
(93,734
|
)
|
|
|
(23,456
|
)
|
Total interest in net (loss)
|
|
$
|
(837
|
)
|
|
$
|
(100,878
|
)
|
|
$
|
(25,244
|
)
|
Impact of subordinated distribution suspension:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) from continuing operations
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Net income from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Interest in net income/(loss)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Interest in net (loss)/income for EPU purposes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(87
|
)
|
|
$
|
(7,144
|
)
|
|
$
|
(1,788
|
)
|
Net income from discontinued operations
|
|
|
(750
|
)
|
|
|
(93,734
|
)
|
|
|
(23,456
|
)
|
Interest in net (loss)
|
|
$
|
(837
|
)
|
|
$
|
(100,878
|
)
|
|
$
|
(25,244
|
)
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
4,937
|
|
|
|
1,236
|
|
Effect of dilutive securities — LTIP awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive securities for net (loss) from continuing operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Dilutive securities for net income from discontinued
operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Total dilutive securities
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Weighted average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
4,937
|
|
|
|
1,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)/income per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(1.45
|
)
|
|
$
|
(1.45
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(18.98
|
)
|
|
|
(18.98
|
)
|
Net income per common unit, basic
|
|
|
n/a
|
|
|
$
|
(20.43
|
)
|
|
$
|
(20.43
|
)
|
Net (loss)/income per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(1.45
|
)
|
|
$
|
(1.45
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
(18.98
|
)
|
|
|
(18.98
|
)
|
Net income per common unit, diluted
|
|
|
n/a
|
|
|
$
|
(20.43
|
)
|
|
$
|
(20.43
|
)
|
Three months ended September 30, 2015
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
|
(in thousands, except per unit data)
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest in net (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(208
|
)
|
|
$
|
(5,840
|
)
|
|
$
|
(4,334
|
)
|
Net income from discontinued operations
|
|
|
22
|
|
|
|
605
|
|
|
|
449
|
|
Total interest in net (loss)
|
|
$
|
(186
|
)
|
|
$
|
(5,235
|
)
|
|
$
|
(3,885
|
)
|
Impact of subordinated distribution suspension:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) from continuing operations
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Net income from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Interest in net income/(loss)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Interest in net (loss) for EPU purposes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(208
|
)
|
|
$
|
(5,840
|
)
|
|
$
|
(4,334
|
)
|
Net income from discontinued operations
|
|
|
22
|
|
|
|
605
|
|
|
|
449
|
|
Interest in net (loss)
|
|
$
|
(186
|
)
|
|
$
|
(5,235
|
)
|
|
$
|
(3,885
|
)
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
1,671
|
|
|
|
1,240
|
|
Effect of dilutive securities — LTIP awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive securities for net (loss) from continuing operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Dilutive securities for net income from discontinued
operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Total dilutive securities
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Weighted average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
1,671
|
|
|
|
1,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)/income per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(3.49
|
)
|
|
$
|
(3.49
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
0.36
|
|
|
|
0.36
|
|
Net (loss) per common unit, basic
|
|
|
n/a
|
|
|
$
|
(3.13
|
)
|
|
$
|
(3.13
|
)
|
Net (loss)/income per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(3.49
|
)
|
|
$
|
(3.49
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
0.36
|
|
|
|
0.36
|
|
Net (loss) per common unit, diluted
|
|
|
n/a
|
|
|
$
|
(3.13
|
)
|
|
$
|
(3.13
|
)
|
Nine months ended September 30, 2015
|
|
General
Partner
|
|
|
Common
Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
|
(in thousands, except per unit data)
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest in net (loss)/income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(538
|
)
|
|
$
|
(15,143
|
)
|
|
$
|
(11,243
|
)
|
Net income from discontinued operations
|
|
|
113
|
|
|
|
3,187
|
|
|
|
2,366
|
|
Total interest in net income
|
|
$
|
(425
|
)
|
|
$
|
(11,956
|
)
|
|
$
|
(8,877
|
)
|
Impact of subordinated distribution suspension:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) from continuing operations
|
|
$
|
5
|
|
|
$
|
139
|
|
|
$
|
(144
|
)
|
Net income from discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Interest in net income/(loss)
|
|
$
|
5
|
|
|
$
|
139
|
|
|
$
|
(144
|
)
|
Interest in net (loss)/income for EPU purposes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) from continuing operations
|
|
$
|
(534
|
)
|
|
$
|
(15,003
|
)
|
|
$
|
(11,387
|
)
|
Net income from discontinued operations
|
|
|
113
|
|
|
|
3,187
|
|
|
|
2,366
|
|
Interest in net income
|
|
$
|
(421
|
)
|
|
$
|
(11,816
|
)
|
|
$
|
(9,021
|
)
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average units used to compute basic EPU
|
|
|
n/a
|
|
|
|
1,669
|
|
|
|
1,240
|
|
Effect of dilutive securities — LTIP awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive securities for net income from continuing
operations and discontinued operations
|
|
|
n/a
|
|
|
|
-
|
|
|
|
-
|
|
Weighted average units used to compute diluted EPU
|
|
|
n/a
|
|
|
|
1,669
|
|
|
|
1,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(8.99
|
)
|
|
$
|
(9.19
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
1.91
|
|
|
|
1.91
|
|
Net income per common unit, basic
|
|
|
n/a
|
|
|
$
|
(7.08
|
)
|
|
$
|
(7.28
|
)
|
Net income per limited partner unit, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per unit from continuing operations
|
|
|
n/a
|
|
|
$
|
(8.99
|
)
|
|
$
|
(9.19
|
)
|
Net income per unit from discontinued operations
|
|
|
n/a
|
|
|
|
1.91
|
|
|
|
1.91
|
|
Net income per common unit, diluted
|
|
|
n/a
|
|
|
$
|
(7.08
|
)
|
|
$
|
(7.28
|
)
|
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 three and nine months ended September 30, 2016 and 2015, all potential dilutive
units were excluded from the diluted EPU calculation for these periods.
14.
MAJOR CUSTOMERS
The
Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues
(Note: customers with “n/a” had revenue below the 10% threshold in any period where this is indicated):
|
|
|
|
|
|
|
|
Nine months
|
|
|
Nine months
|
|
|
|
September 30 2016
|
|
|
December 31 2015
|
|
|
ended
|
|
|
ended
|
|
|
|
Receivable
|
|
|
Receivable
|
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
|
Balance
|
|
|
Balance
|
|
|
Sales
|
|
|
Sales
|
|
|
|
(in thousands)
|
|
PPL Corporation
|
|
$
|
1,646
|
|
|
$
|
1,881
|
|
|
$
|
31,333
|
|
|
|
24,457
|
|
PacifiCorp Energy
|
|
|
668
|
|
|
|
1,969
|
|
|
|
14,418
|
|
|
|
16,831
|
|
Big Rivers Electric Corporation
|
|
|
1,314
|
|
|
|
n/a
|
|
|
|
14,044
|
|
|
|
n/a
|
|
NRG Energy, Inc. (fka GenOn Energy, Inc.)
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
20,356
|
|
15.
FAIR VALUE OF FINANCIAL INSTRUMENTS
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, 2016.
For
the year ended December 31, 2015, the Partnership had nonrecurring fair value measurements related to its asset impairment actions.
The nonrecurring fair value measurements for the asset impairments for the year ended December 31, 2015 were Level 3 measurements.
16.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
The
unaudited condensed consolidated statements of cash flows for the nine months ended September 30, 2016 and 2015 excludes approximately
$0.2 million and $0.1 million, respectively, of property additions, which are recorded in accounts payable.
In
January 2015, the Partnership dissolved the Rhino Eastern joint venture with Patriot. As part of the dissolution, the Partnership
retained coal reserves, a prepaid advanced royalty balance and other assets and liabilities. In addition, the Partnership and
Patriot agreed to a dissolution payment as part of the dissolution based upon a final working capital adjustment calculation,
which is a liability of the Partnership. The Partnership recorded the dissolution of the joint venture by removing the investment
in the Rhino Eastern unconsolidated subsidiary and recording the specific assets and liabilities retained in the dissolution.
The dissolution of the Rhino Eastern joint venture completed in January 2015 had no impact on the Partnership’s unconsolidated
statements of operations and comprehensive income for the three and six months ended September 30, 2015. The unaudited condensed
consolidated statement of cash flows for the six months ended September 30, 2015 excludes the removal of the investment in the
unconsolidated subsidiary and the recognition of the retained assets and liabilities, which are detailed in the table below.
|
|
(in thousands)
|
|
Coal properties (incl asset retirement costs)
|
|
$
|
12,104
|
|
Advance royalties, net of current portion
|
|
|
4,706
|
|
Other non-current assets - acquired
|
|
|
229
|
|
Other non-current assets - written off
|
|
|
(642
|
)
|
Accrued expenses and other
|
|
|
(2,012
|
)
|
Asset retirement obligations
|
|
|
(1,235
|
)
|
Net assets acquired
|
|
|
13,150
|
|
Investment in unconsolidated affiliates-Rhino Eastern - written off
|
|
$
|
(13,150
|
)
|
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, 2016, 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.
Reportable
segment results of operations for the three months ended September 30, 2016 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
|
|
$
|
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
|
|
|
536
|
|
|
|
57
|
|
|
|
116
|
|
|
|
301
|
|
|
|
895
|
|
|
|
1,905
|
|
Net income (loss) from continuing operations
|
|
$
|
(1,544
|
)
|
|
$
|
3,166
|
|
|
$
|
(21
|
)
|
|
$
|
(2,800
|
)
|
|
$
|
(2,011
|
)
|
|
$
|
(3,210
|
)
|
Reportable
segment results of operations for the nine months ended September 30, 2016 are as 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
|
|
|
1,795
|
|
|
|
287
|
|
|
|
304
|
|
|
|
762
|
|
|
|
2,047
|
|
|
|
5,195
|
|
Net income (loss) from continuing operations
|
|
$
|
(10,126
|
)
|
|
$
|
9,006
|
|
|
$
|
(649
|
)
|
|
$
|
(4,237
|
)
|
|
$
|
(3,014
|
)
|
|
$
|
(9,020
|
)
|
Reportable
segment results of operations for the three months ended September 30, 2015 are as follows:
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
Total
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(in thousands)
|
|
Total revenues
|
|
$
|
14,975
|
|
|
$
|
18,382
|
|
|
$
|
8,698
|
|
|
$
|
9,649
|
|
|
$
|
192
|
|
|
$
|
51,896
|
|
DD&A
|
|
|
2,565
|
|
|
|
1,894
|
|
|
|
1,593
|
|
|
|
1,624
|
|
|
|
162
|
|
|
|
7,838
|
|
Interest expense
|
|
|
602
|
|
|
|
145
|
|
|
|
97
|
|
|
|
175
|
|
|
|
366
|
|
|
|
1,385
|
|
Net income (loss) from continuing operations
|
|
$
|
(8,436
|
)
|
|
$
|
1,959
|
|
|
$
|
(526
|
)
|
|
$
|
(3,067
|
)
|
|
$
|
(312
|
)
|
|
$
|
(10,382
|
)
|
Reportable
segment results of operations for the nine months ended September 30, 2015 are as follows:
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
Total
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(in thousands)
|
|
Total revenues
|
|
$
|
49,727
|
|
|
$
|
52,469
|
|
|
$
|
27,251
|
|
|
$
|
27,411
|
|
|
$
|
1,476
|
|
|
$
|
158,334
|
|
DD&A
|
|
|
9,075
|
|
|
|
5,699
|
|
|
|
4,822
|
|
|
|
4,274
|
|
|
|
586
|
|
|
|
24,456
|
|
Interest expense
|
|
|
1,446
|
|
|
|
381
|
|
|
|
228
|
|
|
|
429
|
|
|
|
1,169
|
|
|
|
3,653
|
|
Net income (loss) from continuing operations
|
|
$
|
(16,359
|
)
|
|
$
|
4,643
|
|
|
$
|
(3,055
|
)
|
|
$
|
(10,255
|
)
|
|
$
|
(1,898
|
)
|
|
$
|
(26,924
|
)
|
18.
SUBSEQUENT EVENTS
For
the quarter ended September 30, 2016, the Partnership continued the suspension of the cash distribution for its common units,
which was initially suspended for the quarter ended June 30, 2015. No distribution will be paid for common or subordinated units
for the quarter ended September 30, 2016. The Partnership’s common units accrue arrearages every quarter when the distribution
level is below the minimum level of $0.445 per unit, as outlined in the Partnership’s limited partnership agreement. The
Partnership initially lowered its quarterly common unit distribution below the minimum level of $0.445 per unit with the quarter
ended September 30, 2014. Thus, the Partnership’s distributions for each of the quarters ended September 30, 2014 through
the quarter ended September 30, 2016 were below the minimum level and the current amount of accumulated arrearages as of September
30, 2016 related to the common unit distribution was approximately $149.7 million.
In
October 2016, the Partnership contributed its limited partner interests in Mammoth to Mammoth Energy Services, Inc. (“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. The Partnership’s remaining shares
of Mammoth Inc. are subject to a 180 day lock-up period from the date of Mammoth Inc.’s initial public offering.
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, 2015 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, 2015 and in Part
II, Item 1A, “Risk Factors” in this Quarterly Report on Form 10-Q.
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, 2015, we controlled an estimated 363.6 million tons of proven and probable
coal reserves, consisting of an estimated 310.1 million tons of steam coal and an estimated 53.5 million tons of metallurgical
coal. In addition, as of December 31, 2015, we controlled an estimated 436.8 million tons of non-reserve coal deposits. In August
2016, we sold our Elk Horn coal leasing business, as described further below, which controlled, as of December 31, 2015, an estimated
100.1 million tons of proven and probable coal reserves and an estimated 197.5 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, 2016, we generated revenues of approximately $43.4 million and $124.4 million, respectively,
and we generated net losses of approximately $3.2 million and $9.0 million, respectively. For the three months ended September
30, 2016, we produced and sold approximately 0.8 million tons of coal, of which approximately 93% were sold pursuant to supply
contracts. For the nine months ended September 30, 2016, we produced and sold approximately 2.4 million tons of coal, of which
approximately 88% were sold pursuant to supply contracts.
Current
Liquidity and Outlook
As
of September 30, 2016, our available liquidity was $4.0 million, which consisted of the amount available under our amended and
restated credit agreement dated July 29, 2011 (as amended and restated, the “Amended and Restated Credit Agreement”).
On May 13, 2016, we entered into a fifth amendment of the Amended and Restated Credit Agreement (the “Fifth Amendment”),
which extends the term of the Amended and Restated Credit Agreement to July 31, 2017 (see “—Liquidity and Capital
Resources—Amended and Restated Credit Agreement” for further details of the Fifth Amendment).
Prior
to our entry into the Fifth Amendment, we were unable to demonstrate that we had sufficient liquidity to operate our business
over the subsequent twelve months and thus, substantial doubt was raised about our ability to continue as a going concern. Accordingly,
our independent registered public accounting firm 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, 2015. 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.
Given
the continued weak demand and low prices for met and steam coal, we may not be able to continue to give the required representations
or meet all of the covenants and restrictions included in our credit agreement. If we violate any of the covenants or restrictions
in our Amended and Restated Credit Agreement, including the maximum leverage ratio and minimum EBITDA requirements, some or all
of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may
terminate. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver
from our lenders in order to continue to borrow under our Amended and Restated Credit Agreement. Although we believe our lenders
loans are well secured under the terms of our Amended and Restated Credit Agreement, there is no assurance that the lenders would
agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations 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 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. If we are not able to fund our liquidity requirements for the next twelve
months, 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.”
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
Yorktown
Transaction
On
September 30, 2016, we entered into an equity exchange agreement (the “Agreement”) with Royal, Rhino Resource Partners
Holdings, LLC (“Rhino Holdings”), an entity wholly-owned by certain investment partnerships managed by Yorktown Partners
LLC (“Yorktown”) and our general partner. Investment partnerships managed by Yorktown own substantially all of the
outstanding common stock of Armstrong Energy, Inc. (“Armstrong Energy”), a coal producing company with mines located
in the Illinois Basin in western Kentucky. The Agreement contemplates that prior to closing, Yorktown will contribute its shares
of common stock of Armstrong Energy to Rhino Holdings. At the closing, Rhino Holdings will contribute those shares to us in exchange
for 10 million newly issued of our common units. The Agreement also contemplates that our general partner, currently owned and
controlled by Royal, will issue a 50% ownership inherent in it to Rhino Holdings in connection with the issuance of our common
units for the common stock of Armstrong Energy. Closing of the Agreement is conditioned upon (i) the current bondholders of Armstrong
Energy agreeing to restructure their bonds and (ii) the refinancing of our Amended and Restated Credit Agreement with funds from
an equity investment into us to be arranged by Rhino Holdings. The Agreement is also subject to other standard closing conditions
and required approvals. The Agreement contains customary covenants, representations and warranties and indemnification obligations
for breaches of, or the inaccuracy of representations or warranties or breaches of covenants contained in, the Agreement and associated
agreements. We also agreed to enter into a registration rights agreement with Rhino Holdings 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. The Agreement may be terminated by the mutual written consent of us and Rhino Holdings or by either us or Rhino Holdings
if: (i) the closing has not occurred on or before December 31, 2016 (unless the closing is as a result of such terminating party’s
inability or failure to satisfy the conditions to the closing or if the non-terminating party has filed an action seeking specific
performance); (ii) a law or order issued by a governmental authority prevents the closing from occurring (unless such law or order
resulted from such party’s failure to perform its obligations under the Agreement); (iii) the board of directors of our
general partner fails to approve the transactions or transaction documents contemplated by the Agreement; or (iv) the lenders
of our credit facility fail to approve the transactions and transaction documents contemplated by the Agreement. The parties anticipate
the Agreement will be consummated on or before December 31, 2016.
Elk
Horn Coal Leasing Disposition
In
August 2016, we entered into an agreement to sell our Elk Horn coal leasing company to a third party for total cash consideration
of $12.0 million. We received $10.5 million in cash consideration upon the closing of the Elk Horn transaction and the remaining
$1.5 million of consideration will be paid in ten equal monthly installments of $150,000 on the 20th of each calendar month beginning
on September 20, 2016. Elk Horn is a coal leasing company located in eastern Kentucky that has provided us with coal royalty revenues
from coal properties owned by Elk Horn and leased to third-party operators. As of December 31, 2015, Elk Horn controlled approximately
100 million tons of proven and probable steam coal reserves. During the second quarter of 2016, we evaluated the Elk Horn assets
for potential impairment based upon the initial purchase price offered by the buyer and the continued deterioration of the Central
Appalachia steam coal markets that had adversely affected Elk Horn’s financial results. Our impairment analysis determined
that a potential impairment existed since the carrying amount of the Elk Horn long-lived asset group exceeded the cash flows that
would be generated from the purchase price offered from the buyer. Based on a market approach used to estimate the fair value
of the Elk Horn long-lived asset group, we recorded total asset impairment charges of approximately $118.7 million related to
Coal properties as of June 30, 2016. The disposal of the Elk Horn assets and liabilities in August 2016 resulted in an additional
loss of $0.5 million. The total loss of $119.2 million from the Elk Horn disposal is recorded as discontinued operations along
with the previous operating results of Elk Horn that have been reclassified for the three and nine months ended September 30,
2016 and 2015.
Sale
of our General Partner by Wexford Capital LP
On
January 21, 2016, a definitive agreement was completed between Royal Energy Resources, Inc. (“Royal”) and Wexford
Capital LP (“Wexford”) where Royal acquired 6,769,112 of our issued and outstanding common units from Wexford. The
definitive agreement also included the committed acquisition by Royal within 60 days from the date of the definitive agreement,
or March 21, 2016, of all of the issued and outstanding membership interests of Rhino GP LLC, our general partner, as well as
9,455,252 of our issued and outstanding subordinated units from Wexford. 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.
On
March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of our general partner
as well as the 9,455,252 issued and outstanding subordinated units from Wexford. Royal obtained control of, and a majority limited
partner interest, in us with the completion of this transaction. Immediately subsequent to the consummation of the transaction,
the following members of the board of directors of our general partner tendered their resignations effective immediately: Mark
Zand, Philip Braunstein, Ken Rubin, Arthur Amron, Douglas Lambert and Mark Plaumann. As the owner of our general partner, Royal
has the right to appoint the members of the board of directors of our general partner and so appointed new directors to fill the
vacancies resulting from the resignations, which included the following: William Tuorto, Ronald Phillips, Michael Thompson, Douglas
Holsted, Brian Hughs and David Hanig.
Private
Placement of Common Units to Royal
On
March 21, 2016, we and Royal entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant
to which we issued 60,000,000 of our common units to Royal in a private placement at $0.15 per common unit for an aggregate purchase
price of $9.0 million. Royal paid us $2.0 million in cash and delivered a promissory note payable to us in the amount of $7.0
million. The promissory note is 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 our general partner determine that we do not need the capital that would be provided by either or both installments
set forth in (ii) and (iii) above, in each case, we have the option to rescind Royal’s purchase of 13,333,333 common units
and the applicable installment will not be payable (each, a “Rescission Right”). If we fail to exercise a Rescission
Right, in each case, we have the option to repurchase 13,333,333 of our common units at $0.30 per common unit from Royal (each,
a “Repurchase Option”). The Repurchase Options terminate on December 31, 2017. Royal’s obligation to pay any
installment of the promissory note is subject to certain conditions, including that we have entered into an agreement to extend
the amended and restated credit agreement to a date no sooner than December 31, 2017. In the event such conditions are not satisfied
as of the date each installment is due, Royal has the right to cancel the remaining unpaid balance of the promissory note in exchange
for the surrender of such number of common units equal to the principal balance of the promissory note divided by $0.15. On May
13, 2016 and September 30, 2016, Royal paid us $3.0 million and $2.0 million, respectively, of 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, which is discussed further below.
Fourth,
Fifth and Sixth Amendments to Amended and Restated Credit Agreement
On
March 17, 2016, our operating company, as borrower, and we and certain of our subsidiaries, as guarantors, entered into an amendment
(the “Fourth Amendment”) of our Amended and Restated Credit Agreement. The Fourth Amendment amended the definition
of change of control in our Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of our
general partner.
On
May 13, 2016, we entered into the Fifth Amendment of the Amended and Restated Credit Agreement, which extended the term to July
31, 2017.
In
July 2016, we entered into a sixth amendment (the “Sixth Amendment”) of our amended and restated senior secured credit
facility that permitted the sale of Elk Horn that was discussed earlier. (see “—Liquidity and Capital Resources—Amended
and Restated Credit Agreement” for further details of the Fourth, Fifth and Sixth Amendments).
Suspension
and Delisting of Common Units from the New York Stock Exchange (“NYSE”)
As
previously disclosed, on December 17, 2015, the NYSE notified us that that the NYSE had determined to commence proceedings to
delist our common units from the NYSE as a result of our 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 our common units at the close of trading
on December 17, 2015.
On
January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our common units. The
NYSE held a hearing regarding our appeal on April 20, 2016 and affirmed its prior decision to delist our 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 our common
units and terminate the registration of our 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.”
We
are exploring the possibility of listing our common units on the NASDAQ Stock Market (“NASDAQ”), pending our capability
to meet the NASDAQ initial listing standards.
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. Any fractional units resulting from the reverse
unit split were rounded to the nearest whole unit. The reverse unit split was intended to increase the market price per unit of
our common units in order to comply with the NYSE’s continued listing standards.
Distribution
Suspension
Beginning
with the quarter ended June 30, 2015 and continuing through the current quarter ended September 30, 2016, we have suspended the
cash distribution for our common units. For the quarters ended September 30, 2014 and December 31, 2014, we announced cash distributions
of $0.05 per common unit, or $0.20 per unit on an annualized basis, and for the quarter ended March 31, 2015, we announced cash
distributions of $0.02 per common unit, or $0.08 per unit on an annualized basis. Each of these quarters’ distribution levels
were lower than the historical quarters’ distribution amounts of $0.445 per common unit, or $1.78 per unit on an annualized
basis. 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.
Our
common units accrue arrearages every quarter when the distribution level is below the minimum level of $0.445 per unit, as outlined
in our limited partnership agreement. Since our distributions for the quarters ended September 30, 2014, December 31, 2014 and
March 31, 2015 were below the minimum level and we suspended the distribution for the quarters ended June 30, 2015 through September
30, 2016, we have accumulated arrearages at September 30, 2016 related to the common unit distribution of approximately $149.7
million.
Deane
Mining Complex
On
October 30, 2015, we executed a binding letter of intent with a third party for the purchase of our Deane mining complex. The
sale of the Deane mining complex was completed on December 30, 2015. Our Deane mining complex is located in eastern Kentucky and
includes one underground mine. The infrastructure at the Deane mining complex consists of a preparation plant and a unit train
loadout facility. We evaluated the appropriate held for sale accounting criteria to determine if the Deane mining complex should
be classified as held for sale as of September 30, 2015. Based on this evaluation, we determined the Deane mining complex met
the held for sale criteria at September 30, 2015 and, accordingly, the Deane mining complex asset group was written down to its
estimated fair value of $2.0 million. Due to the determination that the Deane mining complex met the held for sale criteria, we
recorded an impairment charge of approximately $2.3 million for the three and nine months ended September 30, 2015. The sale of
the Deane complex in December 2015 transferred the underground mine, related equipment, the preparation plant and loadout facility
in exchange for $2.0 million in the form of a promissory note receivable from the third party. The note accrued interest with
initial interest payments due beginning June 2016 and the final principal due December 31, 2017. We had not received any of the
scheduled interest payments from the third party as of September 30, 2016 and ongoing discussions with the third party indicated
it was more likely than not that we would not receive the balance of the note receivable. While we continue discussions with the
third party for collection of the note receivable, we recorded a $2.0 million reserve against the note receivable as of September
30, 2016.
Cana
Woodford
We
had an oil and natural gas investment of approximately 1,900 net mineral acres in the Cana Woodford region of western Oklahoma.
During the second quarter of 2015, we received unsolicited offers from third parties to purchase this oil and natural gas investment.
We evaluated these offers in contemplation of a potential sale of these mineral rights. Due to the receipt of these offers and
our potential sale of these mineral rights, we evaluated the appropriate held for sale accounting criteria to determine if the
Cana Woodford mineral rights should be classified as held for sale as of June 30, 2015. Based on this evaluation, we determined
these mineral rights met the held for sale criteria at June 30, 2015 and, accordingly, these mineral rights were written down
to their estimated fair value. Due to the determination that the mineral rights met the held for sale criteria, we recorded an
impairment charge of approximately $2.2 million for the Cana Woodford mineral rights during the nine months ended September 30,
2015.
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 supply contracts and anticipate that we will continue to do so. As of September
30, 2016, we had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:
Year
|
|
|
Tons (in thousands)
|
|
|
Number of customers
|
|
2016
Q4
|
|
|
|
797
|
|
|
|
14
|
|
2017
|
|
|
|
2,910
|
|
|
|
10
|
|
2018
|
|
|
|
701
|
|
|
|
3
|
|
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, 2016, 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, 2016, together
included one underground mine, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and
southern West Virginia. We idled a majority of operations beginning in the third quarter of 2015 to reduce excess coal inventory.
We have resumed mining operations at all of our Central Appalachia operations during the three months ended September 30, 2016.
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, 2016. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant
and a river terminal as of September 30, 2016. Our Rhino Western segment includes our 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.
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 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 “—Reconciliation of Adjusted EBITDA to Net
Income by Segment” 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, 2016 and 2015:
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
(in millions)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
43.4
|
|
|
$
|
51.9
|
|
|
$
|
124.4
|
|
|
$
|
158.3
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
|
35.3
|
|
|
|
47.7
|
|
|
|
98.1
|
|
|
|
139.7
|
|
Freight and handling costs
|
|
|
0.4
|
|
|
|
0.7
|
|
|
|
1.5
|
|
|
|
1.9
|
|
Depreciation, depletion and amortization
|
|
|
6.5
|
|
|
|
7.8
|
|
|
|
18.3
|
|
|
|
24.5
|
|
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown
separately above)
|
|
|
4.3
|
|
|
|
2.9
|
|
|
|
12.3
|
|
|
|
11.8
|
|
Loss on asset impairments
|
|
|
-
|
|
|
|
2.3
|
|
|
|
-
|
|
|
|
4.5
|
|
(Gain) on sale/disposal of assets-net
|
|
|
(0.1
|
)
|
|
|
(0.4
|
)
|
|
|
(0.4
|
)
|
|
|
(0.5
|
)
|
(Loss) from operations
|
|
|
(3.0
|
)
|
|
|
(9.1
|
)
|
|
|
(5.4
|
)
|
|
|
(23.6
|
)
|
Interest and other (expense)/income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(1.9
|
)
|
|
|
(1.4
|
)
|
|
|
(5.2
|
)
|
|
|
(3.6
|
)
|
Gain on extinguishment of debt
|
|
|
1.7
|
|
|
|
-
|
|
|
|
1.7
|
|
|
|
-
|
|
Equity in net (loss)/income of unconsolidated affiliates
|
|
|
-
|
|
|
|
0.1
|
|
|
|
(0.1
|
)
|
|
|
0.3
|
|
Total interest and other (expense)
|
|
|
(0.2
|
)
|
|
|
(1.3
|
)
|
|
|
(3.6
|
)
|
|
|
(3.3
|
)
|
Net (loss) from continuing operations
|
|
|
(3.2
|
)
|
|
|
(10.4
|
)
|
|
|
(9.0
|
)
|
|
|
(26.9
|
)
|
Net income (loss) from discontinued operations
|
|
|
(0.6
|
)
|
|
|
1.1
|
|
|
|
(117.9
|
)
|
|
|
5.6
|
|
Net (loss)
|
|
$
|
(3.8
|
)
|
|
$
|
(9.3
|
)
|
|
$
|
(126.9
|
)
|
|
$
|
(21.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA from continuing operations
|
|
$
|
5.5
|
|
|
$
|
1.2
|
|
|
$
|
14.9
|
|
|
$
|
5.7
|
|
EBITDA from discontinued operations
|
|
|
0.1
|
|
|
|
1.6
|
|
|
|
1.8
|
|
|
|
7.4
|
|
Total Adjusted EBITDA
|
|
$
|
5.6
|
|
|
$
|
2.8
|
|
|
$
|
16.7
|
|
|
$
|
13.1
|
|
Three
Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015
Summary.
For the three months ended September 30, 2016, our total revenues decreased to $43.4 million from $51.9 million for the
three months ended September 30, 2015, which is a 16.3% decrease. We sold approximately 0.8 million tons of coal for the three
months ended September 30, 2016, which is a 12.9% decrease compared to the tons of coal sold for the three months ended September
30, 2015. The decrease in revenue and tons sold was primarily the result of continued weak demand and low prices in the met and
steam coal markets, particularly in Central Appalachia, partially offset by increased sales from our Pennyrile operation in the
Illinois Basin. We believe the weak demand in the steam coal markets was primarily driven by a continued over-supply of low-priced
natural gas, which electric utilities utilize as a source of electricity generation in lieu of steam coal. We believe the weak
demand in the met coal markets was primarily driven by a decrease in worldwide steel production due to ongoing global economic
weakness, particularly in China. While coal prices have increased recently, particularly met coal prices, we do not anticipate
the recent price increase will benefit our financial results until 2017.
Net
loss from continuing operations improved for the three months ended September 30, 2016 compared to the three months ended September
30, 2015. We generated a net loss from continuing operations of approximately $3.2 million for the three months ended September
30, 2016 compared to a net loss from continuing operations of approximately $10.4 million for the three months ended September
30, 2015. For the three months ended September 30, 2016, our total net loss from continuing operations was impacted by a charge
of $2.0 million related to the reserve taken against the note receivable from our Deane mining complex sale discussed earlier.
For the three months ended September 30, 2015, our total net loss from continuing operations was impacted by an asset impairment
charge of $2.3 million related to our Deane mining complex discussed earlier.
Adjusted
EBITDA from continuing operations increased to $5.5 million for the three months ended September 30, 2016 from $1.2 million for
the three months ended September 30, 2015. Adjusted EBITDA from continuing operations increased period to period primarily due
to the lower net loss generated year-to-year.
Including
the loss from discontinued operations of approximately $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. Including the income from discontinued operations of
approximately $1.1 million, our total net loss and Adjusted EBITDA for the three months ended September 30, 2015 were $9.3 million
and $2.8 million, respectively.
Tons
Sold.
The following table presents tons of coal sold by reportable segment for the three months ended September 30, 2016
and 2015:
|
|
Three months
|
|
|
Three months
|
|
|
Increase/
|
|
|
|
|
|
|
Ended
|
|
|
ended
|
|
|
(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
Tons
|
|
|
% *
|
|
|
|
(in thousands, except %)
|
|
Central Appalachia
|
|
|
179.7
|
|
|
|
231.9
|
|
|
|
(52.2
|
)
|
|
|
(22.5
|
%)
|
Northern Appalachia
|
|
|
149.1
|
|
|
|
264.2
|
|
|
|
(115.1
|
)
|
|
|
(43.6
|
%)
|
Rhino Western
|
|
|
185.1
|
|
|
|
234.3
|
|
|
|
(49.2
|
)
|
|
|
(21.0
|
%)
|
Illinois Basin
|
|
|
304.5
|
|
|
|
209.4
|
|
|
|
95.1
|
|
|
|
45.4
|
%
|
Total *
|
|
|
818.4
|
|
|
|
939.8
|
|
|
|
(121.4
|
)
|
|
|
(12.9
|
%)
|
*
|
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 0.8 million tons of coal for the three months ended September 30
,
2016, which was a 12.9% decrease compared to
the three months ended September 30
, 2015.
The decrease in tons sold year-to-year was primarily due to lower sales from our Central Appalachia
segment due to weak demand for met and steam coal from this region. Tons of coal sold in our Central Appalachia segment decreased
by approximately 22.5% to approximately 0.2 million tons for the three months ended September 30
, 2016
compared
to the three months ended September 30
, 2015
, primarily due to a decrease in steam coal
tons sold in the three months ended September 30
, 2016
compared to 2015 due to ongoing
weak market demand for coal from this region. For our Northern Appalachia segment, tons of coal sold decreased by approximately
43.6% for the three months ended September 30
, 2016
compared to the three months ended
September 30
, 2015 as we experienced a decrease in tons sold from our Hopedale complex due to weak demand for coal from
this region
. Coal sales from our Rhino Western segment decreased by approximately 21.0% for
the three months ended September 30
, 2016
compared to the same period in 2015 due to
decreased customer demand from our Castle Valley operation. For our Illinois Basin segment, tons of coal sold increased by approximately
45.4% for the three months ended September 30
, 2016
compared to the three months ended
September 30
, 2015 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 three months ended
September
30
, 2016 and 2015:
|
|
Three months
|
|
|
Three months
|
|
|
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
Increase/(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
$
|
|
|
%*
|
|
|
|
(in millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
10.4
|
|
|
$
|
11.5
|
|
|
$
|
(1.1
|
)
|
|
|
(9.5
|
%)
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
3.5
|
|
|
|
(3.5
|
)
|
|
|
(99.3
|
%)
|
Total revenues
|
|
$
|
10.4
|
|
|
$
|
15.0
|
|
|
$
|
(4.6
|
)
|
|
|
(30.3
|
%)
|
Coal revenues per ton*
|
|
$
|
57.91
|
|
|
$
|
49.59
|
|
|
$
|
8.32
|
|
|
|
16.8
|
%
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
8.8
|
|
|
$
|
15.7
|
|
|
$
|
(6.9
|
)
|
|
|
(43.9
|
%)
|
Freight and handling revenues
|
|
|
0.4
|
|
|
|
0.7
|
|
|
|
(0.3
|
)
|
|
|
(42.4
|
%)
|
Other revenues
|
|
|
1.8
|
|
|
|
2.0
|
|
|
|
(0.2
|
)
|
|
|
(11.6
|
%)
|
Total revenues
|
|
$
|
11.0
|
|
|
$
|
18.4
|
|
|
$
|
(7.4
|
)
|
|
|
(40.3
|
%)
|
Coal revenues per ton*
|
|
$
|
58.75
|
|
|
$
|
59.13
|
|
|
$
|
(0.38
|
)
|
|
|
(0.7
|
%)
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
7.2
|
|
|
$
|
8.7
|
|
|
$
|
(1.5
|
)
|
|
|
(17.0
|
%)
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
7.2
|
|
|
$
|
8.7
|
|
|
$
|
(1.5
|
)
|
|
|
(17.0
|
%)
|
Coal revenues per ton*
|
|
$
|
39.00
|
|
|
$
|
37.13
|
|
|
$
|
1.87
|
|
|
|
5.0
|
%
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
14.6
|
|
|
$
|
9.6
|
|
|
$
|
5.0
|
|
|
|
51.4
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
14.6
|
|
|
$
|
9.6
|
|
|
$
|
5.0
|
|
|
|
51.1
|
%
|
Coal revenues per ton*
|
|
$
|
47.97
|
|
|
$
|
46.07
|
|
|
$
|
1.90
|
|
|
|
4.1
|
%
|
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
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
0.2
|
|
|
$
|
0.2
|
|
|
$
|
-
|
|
|
|
n/a
|
|
Coal revenues per ton*
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
41.0
|
|
|
$
|
45.5
|
|
|
$
|
(4.5
|
)
|
|
|
(9.8
|
%)
|
Freight and handling revenues
|
|
|
0.4
|
|
|
|
0.7
|
|
|
|
(0.3
|
)
|
|
|
(42.4
|
%)
|
Other revenues
|
|
|
2.0
|
|
|
|
5.7
|
|
|
|
(3.7
|
)
|
|
|
(64.9
|
%)
|
Total revenues
|
|
$
|
43.4
|
|
|
$
|
51.9
|
|
|
$
|
(8.5
|
)
|
|
|
(16.3
|
%)
|
Coal revenues per ton*
|
|
$
|
50.09
|
|
|
$
|
48.38
|
|
|
$
|
1.71
|
|
|
|
3.5
|
%
|
*
|
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
, 2016 decreased by approximately
$4.5 million, or 9.8%, to approximately $41.0 million from approximately $45.5 million for the three months ended
September
30
, 2015. The decrease in coal revenues was primarily due to fewer steam coal tons sold in Northern Appalachia,
partially
offset by
increased sales from our Pennyrile mine in the Illinois Basin
.
Coal
revenues per ton was $50.09 for the three months ended
September 30
, 2016, an increase
of $1.71, or 3.50%, from $48.38 per ton for the three months ended
September 30
, 2015.
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 decreased by approximately $1.1 million, or 9.5%, to approximately $10.4 million
for the three months ended
September 30
, 2016 from approximately $11.5 million for the
three months ended
September 30
, 2015. This decrease was primarily due to fewer steam
coal tons sold, which reflects the weak coal market conditions for coal from this region. Coal revenues per ton for our Central
Appalachia segment increased by $8.32, or 16.8%, to $57.91 per ton for the three months ended
September
30
, 2016 as compared to $49.59 for the three months ended
September 30
, 2015,
primarily due to a higher mix of higher priced met coal tons sold as steam coal tons decreased year-to-year due to ongoing weak
demand for steam coal from this region.
For
our Northern Appalachia segment, coal revenues were approximately $8.8 million for the three months ended
September
30
, 2016, a decrease of approximately $6.9 million, or 43.9%, from approximately $15.7 million for the three months ended
September 30
, 2015. This decrease was primarily due to a decrease in tons sold from our
Hopedale complex in Northern Appalachia due to weak demand for coal from the Northern Appalachia region during the three months
ended
September 30
, 2016. Coal revenues per ton for our Northern Appalachia segment was
primarily flat at $58.75 per ton for the three months ended
September 30
, 2016 as compared
to $59.13 per ton for the three months ended
September 30
, 2015.
For
our Rhino Western segment, coal revenues decreased by approximately $1.5 million, or 17.0%, to approximately $7.2 million for
the three months ended
September 30
, 2016 from approximately $8.7 million for the three
months ended
September 30
, 2015, primarily due to a decrease in tons sold due to decreased
customer demand at our Castle Valley operation. Coal revenues per ton for our Rhino Western segment was $39.00 for the three months
ended
September 30
, 2016, an increase of $1.87, or 5.0%, from $37.13 for the three months
ended
September 30
, 2015. The increase in coal revenues per ton was due to an increase
in the contracted sales prices for steam coal sales from our Castle Valley mine for the three months ended
September
30
, 2016 compared to the same period in 2015.
For
our Illinois Basin segment, coal revenues of approximately $14.6 million for the three months ended
September
30
, 2016 increased by approximately $5.0 million, or 51.4%, compared to $9.6 million for the three months ended
September
30
, 2015. 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 was $47.97 for the three months ended
September
30
, 2016, an increase of $1.90, or 4.1%, from $46.07 for the three months ended
September
30
, 2015. The increase in coal revenues per ton was due to higher contracted prices for tons sold.
Other
revenues for our Other category was relatively flat at approximately $0.2 million for 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, 2016
|
|
|
Three months ended
September 30, 2015
|
|
|
Increase (Decrease) %*
|
|
Met coal tons sold
|
|
|
88.4
|
|
|
|
32.2
|
|
|
|
174.7
|
%
|
Steam coal tons sold
|
|
|
91.3
|
|
|
|
199.7
|
|
|
|
(54.3
|
%)
|
Total tons sold
|
|
|
179.7
|
|
|
|
231.9
|
|
|
|
(22.5
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenue
|
|
$
|
5,654
|
|
|
$
|
2,634
|
|
|
|
114.6
|
%
|
Steam coal revenue
|
|
$
|
4,753
|
|
|
$
|
8,865
|
|
|
|
(46.4
|
%)
|
Total coal revenue
|
|
$
|
10,407
|
|
|
$
|
11,499
|
|
|
|
(9.5
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenues per ton
|
|
$
|
63.95
|
|
|
$
|
81.85
|
|
|
|
(21.9
|
%)
|
Steam coal revenues per ton
|
|
$
|
52.07
|
|
|
$
|
44.39
|
|
|
|
17.3
|
%
|
Total coal revenues per ton
|
|
$
|
57.91
|
|
|
$
|
49.59
|
|
|
|
16.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal tons produced
|
|
|
108.0
|
|
|
|
26.5
|
|
|
|
307.7
|
%
|
Steam coal tons produced
|
|
|
104.0
|
|
|
|
67.9
|
|
|
|
52.6
|
%
|
Total tons produced
|
|
|
212.0
|
|
|
|
94.4
|
|
|
|
124.2
|
%
|
*
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
, 2016 and 2015:
|
|
Three months
|
|
|
Three months
|
|
|
Increase/
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
$
|
|
|
%*
|
|
|
|
(in millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately
below)
|
|
$
|
6.9
|
|
|
$
|
14.7
|
|
|
$
|
(7.8
|
)
|
|
|
(52.8
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
1.6
|
|
|
|
2.6
|
|
|
|
(1.0
|
)
|
|
|
(36.0
|
%)
|
Selling, general and administrative
|
|
|
2.0
|
|
|
|
2.6
|
|
|
|
(0.6
|
)
|
|
|
(23.7
|
%)
|
Cost of operations per ton*
|
|
$
|
38.51
|
|
|
$
|
63.19
|
|
|
$
|
(24.68
|
)
|
|
|
(39.1
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
7.8
|
|
|
$
|
13.1
|
|
|
$
|
(5.3
|
)
|
|
|
(40.8
|
%)
|
Freight and handling costs
|
|
|
0.4
|
|
|
|
0.7
|
|
|
|
(0.3
|
)
|
|
|
(45.7
|
%)
|
Depreciation, depletion and amortization
|
|
|
0.8
|
|
|
|
1.9
|
|
|
|
(1.1
|
)
|
|
|
(59.0
|
%)
|
Selling, general and administrative
|
|
|
-
|
|
|
|
0.1
|
|
|
|
(0.1
|
)
|
|
|
(56.8
|
%)
|
Cost of operations per ton*
|
|
$
|
52.13
|
|
|
$
|
49.68
|
|
|
$
|
2.45
|
|
|
|
4.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
5.3
|
|
|
$
|
7.2
|
|
|
$
|
(1.9
|
)
|
|
|
(26.3
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
1.3
|
|
|
|
1.6
|
|
|
|
(0.3
|
)
|
|
|
(18.9
|
%)
|
Selling, general and administrative
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Cost of operations per ton*
|
|
$
|
28.82
|
|
|
$
|
30.91
|
|
|
$
|
(2.09
|
)
|
|
|
(6.8
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
13.4
|
|
|
$
|
10.5
|
|
|
$
|
2.9
|
|
|
|
28.3
|
%
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
2.6
|
|
|
|
1.6
|
|
|
|
1.0
|
|
|
|
62.4
|
%
|
Selling, general and administrative
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
116.1
|
%
|
Cost of operations per ton*
|
|
$
|
43.99
|
|
|
$
|
49.86
|
|
|
$
|
(5.87
|
)
|
|
|
(11.8
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
1.8
|
|
|
$
|
2.2
|
|
|
$
|
(0.4
|
)
|
|
|
(17.6
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
(13.6
|
%)
|
Selling, general and administrative
|
|
|
2.2
|
|
|
|
0.2
|
|
|
|
2.0
|
|
|
|
1046.0
|
%
|
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)
|
|
$
|
35.2
|
|
|
$
|
47.7
|
|
|
$
|
(12.5
|
)
|
|
|
(26.1
|
%)
|
Freight and handling costs
|
|
|
0.4
|
|
|
|
0.7
|
|
|
|
(0.3
|
)
|
|
|
(45.7
|
%)
|
Depreciation, depletion and amortization
|
|
|
6.5
|
|
|
|
7.8
|
|
|
|
(1.3
|
)
|
|
|
(17.2
|
%)
|
Selling, general and administrative
|
|
|
4.3
|
|
|
|
2.9
|
|
|
|
1.4
|
|
|
|
50.2
|
%
|
Cost of operations per ton*
|
|
$
|
43.07
|
|
|
$
|
50.73
|
|
|
$
|
(7.66
|
)
|
|
|
(15.1
|
%)
|
*
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 $35.2 million for the three months ended
September
30
, 2016 as compared to $47.7 million for the three months ended
September 30
,
2015. Our cost of operations per ton was $43.07 for the three months ended
September 30
,
2016, a decrease of $7.66, or 15.1%, from the three months ended
September 30
, 2015.
Total cost of operations decreased primarily due to lower costs in Central Appalachia and Northern Appalachia, partially offset
by increased costs from higher production at our Pennyrile mine in the Illinois Basin. The decrease in the cost of operations
on a per ton basis was primarily due to a decrease from our Central Appalachia segment as we idled a majority of operations beginning
in the third quarter of 2015 to reduce excess coal inventory, which resulted in lower production and higher cost of operations
per ton during this 2015 period.
Our
cost of operations for the Central Appalachia segment decreased by $7.8 million, or 52.8%, to $6.9 million for the three months
ended
September 30
, 2016 from $14.7 million for the three months ended
September
30
, 2015. Total cost of operations decreased year-to-year since as we optimized production during the three months ended
September 30
, 2016 compared to the prior period. Our cost of operations per ton of $38.51
for the three months ended
September 30
, 2016 was a reduction of 39.1% compared to $63.19
per ton for the three months ended
September 30
, 2015, as we idled a majority of operations
beginning in the third quarter of 2015 to reduce excess coal inventory, which resulted in lower production and higher cost of
operations per ton during this 2015 period.
In
our Northern Appalachia segment, our cost of operations decreased by $5.3 million, or 40.8%, to $7.8 million for the three months
ended
September 30
, 2016 from $13.1 million for the three months ended
September
30
, 2015. The decrease in cost of operations was due to reduced production in this region in response to weak market demand.
Our cost of operations per ton was $52.13 for the three months ended
September 30
, 2016,
an increase of $2.45, or 4.9%, compared to $49.68 for the three months ended
September 30
,
2015. Cost of operations per ton increased slightly primarily due to fixed operating costs being allocated to lower production
and sales tons for the three months ended
September 30
, 2016 compared to the prior period.
Our
cost of operations for the Rhino Western segment decreased by $1.9 million, or 26.3%, to $5.3 million for the three months ended
September 30
, 2016 from $7.2 million for the three months ended
September
30
, 2015. Total cost of operations decreased for the three months ended September 30, 2016 compared to the same period
in 2015 due to decreased tons produced and sold from our Castle Valley operation due to weak customer demand. Our cost of operations
per ton was $28.82 for the three months ended
September 30
, 2016, a decrease of $2.09,
or 6.8%, compared to $30.91 for the three months ended
September 30
, 2015. Cost of operations
per ton decreased for the three months ended September 30, 2016 compared to the same period in 2015 due to lower maintenance and
other costs incurred at our Castle Valley operation.
Cost
of operations in our Illinois Basin segment was $13.4 million while cost of operations per ton was $43.99 for the three months
ended
September 30
, 2016, both of which related to our Pennyrile mining complex in western
Kentucky. For the three months ended
September 30
, 2015, cost of operations in our Illinois
Basin segment was $10.5 million and cost of operations per ton was $49.86. 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 decreased as we continued
to optimize the cost structure at this mining complex.
Cost
of operations in our Other category decreased to $1.8 million for the three months ended
September
30
, 2016 compared to $2.2 million for the three months ended September 30, 2015. Cost of operations decreased primarily
due to decreased activity in our ancillary businesses.
Freight
and Handling.
Total freight and handling cost decreased to $0.4 million for the three months ended
September
30
, 2016 as compared to $0.7 million for the three months ended
September 30
,
2015 as we sold fewer tons from our Sands Hill mining complex that requires trucking to customers.
Depreciation,
Depletion and Amortization.
Total depreciation, depletion and amortization (“DD&A”) expense for the three
months ended
September 30
, 2016 was $6.5 million as compared to $7.8 million for the
three months ended
September 30
, 2015.
For
the three months ended
September 30
, 2016, our depreciation cost decreased to $5.6 million
compared to $7.2 million for the three months ended
September 30
, 2015. This decrease
primarily resulted from lower depreciation costs in our Central Appalachia segment in the current quarter compared to the prior
year as we disposed of excess equipment in this region.
For
the three months ended
September 30
, 2016, our depletion cost was relatively flat at
$0.4 million compared to $0.3 million for the three months ended
September 30
, 2015.
For
the three months ended
September 30
, 2016, our amortization cost was relatively flat
at $0.5 million compared to $0.3 million for the three months ended
September 30
, 2015.
Selling,
General and Administrative.
Selling, general and administrative (“SG&A”) expense for the three months
ended
September 30
, 2016 increased to $4.3 million as compared to $2.9 million for the
three months ended
September 30
, 2015. This increase was primarily attributable to a
$2.0 million charge incurred during the three months ended
September 30
, 2016 for a reserve
against a note receivable that was recorded in 2015 related to the sale of the Deane mining complex discussed earlier.
Interest
Expense
.
Interest expense for the three months ended
September 30
, 2016
increased to $1.9 million as compared to $1.4 million for the three months ended
September 30
,
2015. This increase was primarily due to higher interest rates on our senior secured credit facility.
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
, 2016 and 2015:
|
|
Three months ended
|
|
|
Three months ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
Central Appalachia
|
|
$
|
(1.6
|
)
|
|
$
|
(8.4
|
)
|
|
$
|
6.8
|
|
Northern Appalachia
|
|
|
3.2
|
|
|
|
1.9
|
|
|
|
1.3
|
|
Rhino Western
|
|
|
-
|
|
|
|
(0.5
|
)
|
|
|
0.5
|
|
Illinois Basin
|
|
|
(2.8
|
)
|
|
|
(3.1
|
)
|
|
|
0.3
|
|
Other
|
|
|
(2.0
|
)
|
|
|
(0.3
|
)
|
|
|
(1.7
|
)
|
Total
|
|
$
|
(3.2
|
)
|
|
$
|
(10.4
|
)
|
|
$
|
7.2
|
|
For
the three months ended
September 30
, 2016, total net loss from continuing operations
was a loss of approximately $3.2 million compared to net loss from continuing operations of approximately $10.4 million for the
three months ended
September 30
, 2015. For the three months ended September 30, 2016,
our total net loss from continuing operations was impacted by a charge of $2.0 million related to the reserve taken against the
note receivable from our Deane mining complex sale discussed earlier. For the three months ended September 30, 2015, our total
net loss from continuing operations was impacted by an asset impairment charge of $2.3 million related to our Deane mining complex
discussed earlier.
For
our Central Appalachia segment, net loss from continuing operations was approximately $1.6 million for the three months ended
September 30
, 2016, a $6.8 million smaller net loss as compared to the three months ended
September 30
, 2015, which was primarily related to the $2.3 million asset impairment
charge incurred during the three months ended
September 30
, 2015 for the Deane mining
complex discussed earlier. Net income from continuing operations in our Northern Appalachia segment increased by $1.3 million
to $3.2 million for the three months ended
September 30
, 2016 from $1.9 million for the
three months ended
September 30
, 2015. This increase was primarily due to reducing costs
at our Northern Appalachia operations. Net income (loss) from continuing operations in our Rhino Western segment was at a break-even
level for the three months ended
September 30
, 2016, compared to a net loss from continuing
operations of $0.5 million for the three months ended
September 30
, 2015. This decrease
in net loss was primarily the result of lower costs at our Castle Valley operation during the three months ended
September
30
, 2016 compared to the prior year. For our Illinois Basin segment, we generated a net loss from continuing operations
of $2.8 million for the three months ended
September 30
, 2016, which was an improvement
of $0.3 million compared to the three months ended
September 30
, 2015. This decrease
in net loss was primarily the result of increased coal sales at our Pennyrile mining complex as well as lower costs per ton as
we continued to optimize the operations at this mining facility. For the Other category, we had a net loss from continuing operations
of $2.0 million for the three months ended
September 30
, 2016 as compared to net loss
from continuing operations of $0.3 million for the three months ended
September 30
, 2015.
This increase in net loss year to year was primarily attributable to a $2.0 million charge incurred during the three months ended
September 30
, 2016 for a reserve against a note receivable that was recorded in 2015
related to the sale of the Deane mining complex discussed earlier.
Adjusted
EBITDA from Continuing Operations.
The following table presents Adjusted EBITDA from continuing operations by reportable
segment for the three months ended
September 30
, 2016 and 2015:
|
|
Three months ended
|
|
|
Three months ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
(Decrease)
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
Central Appalachia
|
|
$
|
0.6
|
|
|
$
|
(2.9
|
)
|
|
$
|
3.5
|
|
Northern Appalachia
|
|
|
2.4
|
|
|
|
4.0
|
|
|
|
(1.6
|
)
|
Rhino Western
|
|
|
1.4
|
|
|
|
1.2
|
|
|
|
0.2
|
|
Illinois Basin
|
|
|
0.1
|
|
|
|
(1.3
|
)
|
|
|
1.4
|
|
Other
|
|
|
1.0
|
|
|
|
0.2
|
|
|
|
0.8
|
|
Total
|
|
$
|
5.5
|
|
|
$
|
1.2
|
|
|
$
|
4.3
|
|
Adjusted
EBITDA from continuing operations for the three months ended
September 30
, 2016 was $5.5
million, an increase of $4.3 million from the three months ended
September 30
, 2015.
Adjusted EBITDA from continuing operations increased period to period primarily due to the lower net loss generated year-to-year
discussed above. Adjusted EBITDA for the three months ended September 30, 2016 and 2015 were $5.6 million and $2.8 million, respectively,
once the results from discontinued operations were included. Please read “—Reconciliations of Adjusted EBITDA”
for reconciliations of Adjusted EBITDA from continuing operations to net income on a segment basis.
Nine
Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015
Summary.
For the nine months ended September 30, 2016, our total revenues decreased to $124.3 million from $158.3 million for the
nine months ended September 30, 2015, which is a 21.5% decrease. We sold approximately 2.4 million tons of coal for the nine months
ended September 30, 2016, which is a 13.8% decrease compared to the tons of coal sold for the nine months ended September 30,
2015. The decrease in revenue and tons sold was primarily the result of continued weak demand and low prices in the met and steam
coal markets, particularly in Central Appalachia, partially offset by increased sales from our Pennyrile operation in the Illinois
Basin. We believe the weak demand in the steam and met coal markets for the nine months ended September 30, 2016 was due to the
same factors discussed earlier.
Net
loss from continuing operations decreased for the nine months ended September 30, 2016 compared to the nine months ended September
30, 2015. We generated a net loss from continuing operations of approximately $9.0 million for the nine months ended September
30, 2016 compared to a net loss from continuing operations of approximately $27.0 million for the nine months ended September
30, 2015. For the nine months ended September 30, 2016, our total net loss from continuing operations was benefited from a prior
service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale
operation, partially offset by a charge of $2.0 million related to the reserve taken against the note receivable from our Deane
mining complex sale discussed earlier. Net loss from continuing operations for the nine months ended September 30, 2015 was impacted
by the $2.2 million asset impairment charge incurred for our Cana Woodford oil and gas properties discussed above as well as the
asset impairment charge of $2.3 million related to our Deane mining complex discussed earlier.
Adjusted
EBITDA from continuing operations increased to $14.9 million for the nine months ended September 30, 2016 from $5.7 million for
the nine months ended September 30, 2015. Adjusted EBITDA from continuing operations increased period to period primarily due
to the $3.9 million prior service cost benefit discussed above.
Including
the loss from discontinued operations of approximately $117.9 million, our total net loss and Adjusted EBITDA for the nine months
ended September 30, 2016 were $126.9 million and $16.7 million, respectively. Including the income from discontinued operations
of approximately $5.6 million, our total net loss and Adjusted EBITDA for the nine months ended September 30, 2015 were $21.3
million and $13.1 million, respectively.
Tons
Sold.
The following table presents tons of coal sold by reportable segment for the nine months ended September 30, 2016
and 2015:
|
|
Nine months
|
|
|
Nine months
|
|
|
Increase/
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
Tons
|
|
|
% *
|
|
|
|
|
(in
thousands, except %)
|
|
Central Appalachia
|
|
|
367.9
|
|
|
|
702.1
|
|
|
|
(334.2
|
)
|
|
|
(47.6
|
%)
|
Northern Appalachia
|
|
|
432.8
|
|
|
|
767.9
|
|
|
|
(335.1
|
)
|
|
|
(43.6
|
%)
|
Rhino Western
|
|
|
652.1
|
|
|
|
731.7
|
|
|
|
(79.6
|
)
|
|
|
(10.9
|
%)
|
Illinois Basin
|
|
|
953.7
|
|
|
|
590.2
|
|
|
|
363.5
|
|
|
|
61.6
|
%
|
Total *
|
|
|
2,406.5
|
|
|
|
2,791.9
|
|
|
|
(385.4
|
)
|
|
|
(13.8
|
%)
|
*
|
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 2.4 million tons of coal for the nine months ended September 30
,
2016, which was a 13.8% decrease compared to
the nine months ended September 30
, 2015.
The decrease in tons sold year-to-year was primarily due to lower sales from our Central Appalachia
and Northern Appalachia segments due to weak demand for steam coal from this region. Tons of coal sold in our Central Appalachia
segment decreased by approximately 47.6% to approximately 0.4 million tons for the nine months ended September 30
, 2016
compared to the nine months ended September 30
, 2015
,
primarily due to a decrease in steam coal tons sold in the nine months ended September 30
, 2016
compared
to 2015 due to ongoing weak market demand for coal from this region. For our Northern Appalachia segment, tons of coal sold decreased
by approximately 43.6% for the nine months ended September 30
, 2016
compared to the nine
months ended September 30
, 2015 as we experienced a decrease in tons sold from our Hopedale complex due to weak demand
for coal from this region
. Coal sales from our Rhino Western segment decreased by approximately
10.9% for the nine months ended September 30
, 2016
compared to the same period in 2015
due to decreased customer demand from our Castle Valley operation. For our Illinois Basin segment, tons of coal sold increased
by approximately 61.6% for the nine months ended September 30
, 2016
compared to the nine
months ended September 30
, 2015 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
, 2016 and 2015:
|
|
Nine months
|
|
|
Nine months
|
|
|
Increase/
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
$
|
|
|
%*
|
|
|
|
|
(in
millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
21.6
|
|
|
$
|
40.4
|
|
|
$
|
(18.8
|
)
|
|
|
(46.6
|
%)
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
0.1
|
|
|
|
9.3
|
|
|
|
(9.2
|
)
|
|
|
(98.9
|
%)
|
Total revenues
|
|
$
|
21.7
|
|
|
$
|
49.7
|
|
|
$
|
(28.0
|
)
|
|
|
(56.4
|
%)
|
Coal revenues per ton*
|
|
$
|
58.62
|
|
|
$
|
57.54
|
|
|
$
|
1.08
|
|
|
|
1.9
|
%
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
24.6
|
|
|
$
|
44.7
|
|
|
$
|
(20.1
|
)
|
|
|
(44.9
|
%)
|
Freight and handling revenues
|
|
|
1.6
|
|
|
|
1.9
|
|
|
|
(0.3
|
)
|
|
|
(15.9
|
%)
|
Other revenues
|
|
|
5.5
|
|
|
|
5.9
|
|
|
|
(0.4
|
)
|
|
|
(7.1
|
%)
|
Total revenues
|
|
$
|
31.7
|
|
|
$
|
52.5
|
|
|
$
|
(20.8
|
)
|
|
|
(39.6
|
%)
|
Coal revenues per ton*
|
|
$
|
56.91
|
|
|
$
|
58.18
|
|
|
$
|
(1.27
|
)
|
|
|
(2.2
|
%)
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
25.1
|
|
|
$
|
27.2
|
|
|
$
|
(2.1
|
)
|
|
|
(7.7
|
%)
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Total revenues
|
|
$
|
25.1
|
|
|
$
|
27.2
|
|
|
$
|
(2.1
|
)
|
|
|
(7.8
|
%)
|
Coal revenues per ton*
|
|
$
|
38.55
|
|
|
$
|
37.23
|
|
|
$
|
1.32
|
|
|
|
3.5
|
%
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
45.4
|
|
|
$
|
27.2
|
|
|
$
|
18.2
|
|
|
|
67.1
|
%
|
Freight and handling revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Other revenues
|
|
|
-
|
|
|
|
0.2
|
|
|
|
(0.2
|
)
|
|
|
(92.3
|
%)
|
Total revenues
|
|
$
|
45.4
|
|
|
$
|
27.4
|
|
|
$
|
18.0
|
|
|
|
65.8
|
%
|
Coal revenues per ton*
|
|
$
|
47.65
|
|
|
$
|
46.06
|
|
|
$
|
1.59
|
|
|
|
3.4
|
%
|
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
|
|
|
|
1.5
|
|
|
|
(1.1
|
)
|
|
|
(74.1
|
%)
|
Total revenues
|
|
$
|
0.4
|
|
|
$
|
1.5
|
|
|
$
|
(1.1
|
)
|
|
|
(74.1
|
%)
|
Coal revenues per ton*
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal revenues
|
|
$
|
116.7
|
|
|
$
|
139.5
|
|
|
$
|
(22.8
|
)
|
|
|
(16.3
|
%)
|
Freight and handling revenues
|
|
|
1.6
|
|
|
|
1.9
|
|
|
|
(0.3
|
)
|
|
|
(15.9
|
%)
|
Other revenues
|
|
|
6.0
|
|
|
|
16.9
|
|
|
|
(10.9
|
)
|
|
|
(64.8
|
%)
|
Total revenues
|
|
$
|
124.3
|
|
|
$
|
158.3
|
|
|
$
|
(34.0
|
)
|
|
|
(21.5
|
%)
|
Coal revenues per ton*
|
|
$
|
48.52
|
|
|
$
|
49.96
|
|
|
$
|
(1.44
|
)
|
|
|
(2.9
|
%)
|
*
|
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
, 2016 decreased by approximately
$22.8 million, or 16.3%, to approximately $116.7 million from approximately $139.5 million for the nine months ended
September
30
, 2015. The decrease in coal revenues was primarily due to fewer steam coal tons sold in Northern Appalachia and Central
Appalachia,
partially offset by
increased sales from our Pennyrile mine in the Illinois
Basin
.
Coal revenues per ton was $48.52 for the nine months ended
September
30
, 2016, a decrease of $1.44, or 2.9%, from $49.96 per ton for the nine months ended
September
30
, 2015. This decrease in coal revenues per ton was primarily the result of a larger mix of lower priced tons sold from
Pennyrile.
For
our Central Appalachia segment, coal revenues decreased by approximately $18.8 million, or 46.6%, to approximately $21.6 million
for the nine months ended
September 30
, 2016 from approximately $40.4 million for the
nine months ended
September 30
, 2015. This decrease was primarily due to fewer steam
coal tons sold, which reflects the weak coal market conditions for coal from this region. Coal revenues per ton for our Central
Appalachia segment increased by $1.08, or 1.9%, to $58.62 per ton for the nine months ended
September
30
, 2016 as compared to $57.54 for the nine months ended
September 30
, 2015, primarily
due to a higher mix of higher priced met coal tons sold compared to the prior year.
For
our Northern Appalachia segment, coal revenues were approximately $24.6 million for the nine months ended
September
30
, 2016, a decrease of approximately $20.1 million, or 44.9%, from approximately $44.7 million for the nine months ended
September 30
, 2015. This decrease was primarily due to a decrease in tons sold from our
Hopedale complex in Northern Appalachia due to weak demand for coal from this region. Coal revenues per ton for our Northern Appalachia
segment decreased by $1.27, or 2.2%, to $56.91 per ton for the nine months ended
September 30
,
2016 as compared to $58.18 per ton for the nine months ended
September 30
, 2015. 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 decreased by approximately $2.1 million, or 7.7%, to approximately $25.1 million for
the nine months ended
September 30
, 2016 from approximately $27.2 million for the nine
months ended
September 30
, 2015, primarily due to a decrease in tons sold due to decreased
customer demand at our Castle Valley operation. Coal revenues per ton for our Rhino Western segment was $38.55 for the nine months
ended
September 30
, 2016, an increase of $1.32, or 3.5%, from $37.23 for the nine months
ended
September 30
, 2015. The increase in coal revenues per ton was due to an increase
in the contracted sales prices for steam coal sales from our Castle Valley mine for the nine months ended
September
30
, 2016 compared to the same period in 2015.
For
our Illinois Basin segment, coal revenues of approximately $45.4 million for the nine months ended
September
30
, 2016 increased by approximately $18.2 million, or 67.1%, compared to $27.2 million for the nine months ended
September
30
, 2015. 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 was $47.65 for the nine months ended
September
30
, 2016, an increase of $1.59, or 3.4%, from $46.06 for the nine months ended
September
30
, 2015. The increase in coal revenues per ton was due to higher contracted prices for tons sold.
Other
revenues for our Other category decreased to approximately $0.4 million for the nine months ended
September
30
, 2016 as compared to approximately $1.5 million for the nine months ended
September
30
, 2015. This decrease in revenue was primarily due to the decreased business activity in our ancillary businesses and
oil and natural gas investments.
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, 2016
|
|
|
Nine months ended September 30, 2015
|
|
|
Increase (Decrease) %*
|
|
Met coal tons sold
|
|
|
135.4
|
|
|
|
158.9
|
|
|
|
(14.8
|
%)
|
Steam coal tons sold
|
|
|
232.5
|
|
|
|
543.2
|
|
|
|
(57.2
|
%)
|
Total tons sold
|
|
|
367.9
|
|
|
|
702.1
|
|
|
|
(47.6
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenue
|
|
$
|
9,553
|
|
|
$
|
12,654
|
|
|
|
(24.5
|
%)
|
Steam coal revenue
|
|
$
|
12,016
|
|
|
$
|
27,743
|
|
|
|
(56.7
|
%)
|
Total coal revenue
|
|
$
|
21,569
|
|
|
$
|
40,397
|
|
|
|
(46.6
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal revenues per ton
|
|
$
|
70.55
|
|
|
$
|
79.65
|
|
|
|
(11.4
|
%)
|
Steam coal revenues per ton
|
|
$
|
51.67
|
|
|
$
|
51.07
|
|
|
|
1.2
|
%
|
Total coal revenues per ton
|
|
$
|
58.62
|
|
|
$
|
57.54
|
|
|
|
1.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met coal tons produced
|
|
|
165.8
|
|
|
|
201.7
|
|
|
|
(17.8
|
%)
|
Steam coal tons produced
|
|
|
242.3
|
|
|
|
424.5
|
|
|
|
(42.9
|
%)
|
Total tons produced
|
|
|
408.1
|
|
|
|
626.2
|
|
|
|
(34.8
|
%)
|
*
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
, 2016 and 2015:
|
|
Nine months
|
|
|
Nine months
|
|
|
Increase/
|
|
|
|
|
|
|
ended
|
|
|
ended
|
|
|
(Decrease)
|
|
|
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
$
|
|
|
%*
|
|
|
|
(in millions, except per ton data and %)
|
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately
below)
|
|
$
|
12.5
|
|
|
$
|
38.9
|
|
|
$
|
(26.4
|
)
|
|
|
(68.0
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
4.9
|
|
|
|
9.1
|
|
|
|
(4.2
|
)
|
|
|
(45.4
|
%)
|
Selling, general and administrative
|
|
|
9.4
|
|
|
|
11.0
|
|
|
|
(1.6
|
)
|
|
|
(14.3
|
%)
|
Cost of operations per ton*
|
|
$
|
33.86
|
|
|
$
|
55.41
|
|
|
$
|
(21.55
|
)
|
|
|
(38.9
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
18.5
|
|
|
$
|
37.8
|
|
|
$
|
(19.3
|
)
|
|
|
(51.2
|
%)
|
Freight and handling costs
|
|
|
1.5
|
|
|
|
1.9
|
|
|
|
(0.4
|
)
|
|
|
(24.2
|
%)
|
Depreciation, depletion and amortization
|
|
|
2.6
|
|
|
|
5.7
|
|
|
|
(3.1
|
)
|
|
|
(55.4
|
%)
|
Selling, general and administrative
|
|
|
0.1
|
|
|
|
0.2
|
|
|
|
(0.1
|
)
|
|
|
(43.9
|
%)
|
Cost of operations per ton*
|
|
$
|
42.67
|
|
|
$
|
49.27
|
|
|
$
|
(6.60
|
)
|
|
|
(13.4
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rhino Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
19.9
|
|
|
$
|
24.1
|
|
|
$
|
(4.2
|
)
|
|
|
(17.6
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
4.1
|
|
|
|
4.8
|
|
|
|
(0.7
|
)
|
|
|
(14.8
|
%)
|
Selling, general and administrative
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Cost of operations per ton*
|
|
$
|
30.47
|
|
|
$
|
32.98
|
|
|
$
|
(2.51
|
)
|
|
|
(7.6
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
39.9
|
|
|
$
|
31.3
|
|
|
$
|
8.6
|
|
|
|
27.6
|
%
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
6.3
|
|
|
|
4.3
|
|
|
|
2.0
|
|
|
|
47.8
|
%
|
Selling, general and administrative
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
166.4
|
%
|
Cost of operations per ton*
|
|
$
|
41.81
|
|
|
$
|
52.95
|
|
|
$
|
(11.14
|
)
|
|
|
(21.0
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)
|
|
$
|
7.4
|
|
|
$
|
7.6
|
|
|
$
|
(0.2
|
)
|
|
|
(2.4
|
%)
|
Freight and handling costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
n/a
|
|
Depreciation, depletion and amortization
|
|
|
0.4
|
|
|
|
0.6
|
|
|
|
(0.2
|
)
|
|
|
(27.7
|
%)
|
Selling, general and administrative
|
|
|
2.6
|
|
|
|
0.6
|
|
|
|
2.0
|
|
|
|
345.9
|
%
|
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)
|
|
$
|
98.2
|
|
|
$
|
139.7
|
|
|
$
|
(41.5
|
)
|
|
|
(29.8
|
%)
|
Freight and handling costs
|
|
|
1.5
|
|
|
|
1.9
|
|
|
|
(0.4
|
)
|
|
|
(24.2
|
%)
|
Depreciation, depletion and amortization
|
|
|
18.3
|
|
|
|
24.5
|
|
|
|
(6.2
|
)
|
|
|
(25.0
|
%)
|
Selling, general and administrative
|
|
|
12.2
|
|
|
|
11.8
|
|
|
|
0.4
|
|
|
|
(3.8
|
%)
|
Cost of operations per ton*
|
|
$
|
40.77
|
|
|
$
|
50.05
|
|
|
$
|
(9.28
|
)
|
|
|
(18.6
|
%)
|
*
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 $98.2 million for the nine months ended
September
30
, 2016 as compared to $139.7 million for the nine months ended
September 30
,
2015. Our cost of operations per ton was $40.77 for the nine months ended
September 30
,
2016, a decrease of $9.28, or 18.6%, from the nine months ended
September 30
, 2015. Total
cost of operations decreased primarily due to lower costs in Central Appalachia and Northern Appalachia as we reduced production
in these regions in response to weak market demand, partially offset by increased costs from higher production at our Pennyrile
mine in the Illinois Basin. The decrease in the cost of operations on a per ton basis was primarily due to a decrease from our
Pennyrile mine in the Illinois Basin as we increased and optimized production during the nine months ended
September
30
, 2016 compared to the same period in 2015, as well as the $3.9 million benefit in Northern Appalachia during the nine
months ended
September 30
, 2016 from the prior service cost benefit resulting from the
cancellation of the postretirement benefit plan at our Hopedale operation.
Our
cost of operations for the Central Appalachia segment decreased by $26.4 million, or 68.0%, to $12.5 million for the nine months
ended
September 30
, 2016 from $38.9 million for the nine months ended
September
30
, 2015. Total cost of operations decreased year-to-year since we decreased production during the nine months ended
September
30
, 2016 in response to weak market conditions. Our cost of operations per ton of $33.86 for the nine months ended
September
30
, 2016 was a reduction of 38.9% compared to $55.41 per ton for the nine months ended
September
30
, 2015, as we produced coal from lower cost operations during the nine months ended
September
30
, 2016.
In
our Northern Appalachia segment, our cost of operations decreased by $19.3 million, or 51.2%, to $18.5 million for the nine months
ended
September 30
, 2016 from $37.8 million for the nine months ended
September
30
, 2015. Our cost of operations per ton was $42.67 for the nine months ended
September
30
, 2016, a decrease of $6.60, or 13.4%, compared to $49.27 for the nine months ended
September
30
, 2015. The decrease in cost of operations and cost of operations per ton was primarily due to the $3.9 million prior
service cost benefit during the nine months ended
September 30
, 2016 resulting from the
cancellation of the postretirement benefit plan at our Hopedale operation.
Our
cost of operations for the Rhino Western segment decreased by $4.2 million, or 17.6%, to $19.9 million for the nine months ended
September 30
, 2016 from $24.1 million for the nine months ended
September
30
, 2015. Our cost of operations per ton was $30.47 for the nine months ended
September
30
, 2016, a decrease of $2.51, or 7.6%, compared to $32.98 for the nine months ended
September
30
, 2015. Total cost of operations and cost of operations per ton decreased for the nine months ended
September
30
, 2016 compared to the same period in 2015 due to lower maintenance and other costs from our Castle Valley operation.
Cost
of operations in our Illinois Basin segment was $39.9 million while cost of operations per ton was $41.81 for the nine months
ended
September 30
, 2016, both of which related to our Pennyrile mining complex in western
Kentucky. For the nine months ended
September 30
, 2015, cost of operations in our Illinois
Basin segment was $31.3 million and cost of operations per ton was $52.95. 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 decreased as we continued
to optimize the cost structure at this mining complex.
Cost
of operations in our Other category was relatively flat at $7.4 million for the nine months ended
September
30
, 2016 as compared to $7.6 million for the nine months ended September 30, 2015.
Freight
and Handling.
Total freight and handling cost decreased to $1.5 million for the nine months ended
September
30
, 2016 as compared to $1.9 million for the nine months ended
September 30
, 2015
as we sold fewer tons from our Sands Hill mining complex that requires trucking to customers.
Depreciation,
Depletion and Amortization.
Total depreciation, depletion and amortization (“DD&A”) expense for the nine
months ended
September 30
, 2016 was $18.3 million as compared to $24.5 million for the
nine months ended
September 30
, 2015.
For
the nine months ended
September 30
, 2016, our depreciation cost decreased to $15.9 million
compared to $22.2 million for the nine months ended
September 30
, 2015. This decrease
primarily resulted from lower depreciation costs in our Central Appalachia segment compared to the prior year as we disposed of
excess equipment in this region.
For
the nine months ended
September 30
, 2016, our depletion cost was relatively flat at $1.2
million compared to $1.1 million for the nine months ended
September 30
, 2015.
For
the nine months ended
September 30
, 2016, our amortization cost was relatively flat at
$1.2 million compared to the nine months ended
September 30
, 2015.
Selling,
General and Administrative.
Selling, general and administrative (“SG&A”) expense for the nine months ended
September 30
, 2016 increased to $12.2 million as compared to $11.8 million for the nine
months ended
September 30
, 2015. This increase was primarily attributable to a $2.0 million
charge incurred during the nine months ended September 30, 2016 for a reserve against a note receivable that was recorded in 2015
related to the sale of the Deane mining complex discussed earlier.
Interest
Expense
.
Interest expense for the nine months ended
September 30
, 2016
increased to $5.2 million as compared to $3.7 million for the nine months ended
September 30
,
2015. This increase was primarily due to higher interest rates on our senior secured credit facility along with the write-off
of approximately $0.3 million of our unamortized debt issuance costs during the nine months ended
September
30
, 2016. This write-off was due to the fourth and fifth amendments of our credit facility during the nine months ended
September 30
, 2016 that reduced the borrowing capacity from $100 million to $75 million.
See the discussion on our credit agreement in “Liquidity and Capital Resources - Amended and Restated Credit Agreement”
for more information on these amendments.
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
, 2016 and 2015:
|
|
Nine months Ended
|
|
|
Nine months Ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
Central Appalachia
|
|
$
|
(10.1
|
)
|
|
$
|
(16.3
|
)
|
|
$
|
6.2
|
|
Northern Appalachia
|
|
|
9.0
|
|
|
|
4.6
|
|
|
|
4.4
|
|
Rhino Western
|
|
|
(0.6
|
)
|
|
|
(3.0
|
)
|
|
|
2.4
|
|
Illinois Basin
|
|
|
(4.2
|
)
|
|
|
(10.3
|
)
|
|
|
6.1
|
|
Other
|
|
|
(3.1
|
)
|
|
|
(1.9
|
)
|
|
|
(1.2
|
)
|
Total
|
|
$
|
(9.0
|
)
|
|
$
|
(26.9
|
)
|
|
$
|
17.9
|
|
For
the nine months ended
September 30
, 2016, total net loss from continuing operations was
a loss of approximately $9.0 million compared to net loss from continuing operations of approximately $26.9 million for the nine
months ended
September 30
, 2015. For the nine months ended September 30, 2016, our total
net loss from continuing operations was benefited from a prior service cost benefit of approximately $3.9 million resulting from
the cancellation of the postretirement benefit plan at our Hopedale operation. Net loss from continuing operations for the nine
months ended September 30, 2015 was impacted by the $2.2 million asset impairment charge incurred for our Cana Woodford oil and
gas properties discussed above as well as the asset impairment charge of $2.3 million related to our Deane mining complex discussed
earlier. Including the 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. Including the income from discontinued operations of approximately $5.6 million,
our total net loss for the nine months ended September 30, 2015 was $21.3 million.
For
our Central Appalachia segment, net loss from continuing operations was approximately $10.1 million for the nine months ended
September 30
, 2016, a $6.2 million smaller net loss as compared to the nine months ended
September 30
, 2015, which was primarily related to the $2.3 million asset impairment
charge incurred during the three months ended
September 30
, 2015 for the Deane mining
complex discussed earlier. Net income from continuing operations in our Northern Appalachia segment increased by $4.4 million
to $9.0 million for the nine months ended
September 30
, 2016 from $4.6 million for the
nine months ended
September 30
, 2015. This increase was primarily due the prior service
cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale
operation. Net loss from continuing operations in our Rhino Western segment was a loss of $0.6 million for the nine months ended
September 30
, 2016, compared to a net loss from continuing operations of $3.0 million
for the nine months ended
September 30
, 2015. This decrease in net loss was primarily
the result of lower costs at our Castle Valley operation during the nine months ended
September
30
, 2016 compared to the prior year. For our Illinois Basin segment, we generated a net loss from continuing operations
of $4.2 million for the nine months ended
September 30
, 2016, which was an improvement
of $6.1 million compared to the nine months ended
September 30
, 2015. This decrease in
net loss was primarily the result of increased coal sales at our Pennyrile mining complex as well as lower costs per ton as we
continued to optimize the operations at this mining facility. For the Other category, we had a net loss from continuing operations
of $3.1 million for the nine months ended
September 30
, 2016 as compared to a net loss
from continuing operations of $1.9 million for the nine months ended
September 30
, 2015.
This increase in net loss year to year was primarily attributable to a $2.0 million charge incurred during the three months ended
September 30, 2016 for a reserve against a note receivable that was recorded in 2015 related to the sale of the Deane mining complex
discussed earlier.
Adjusted
EBITDA from Continuing Operations.
The following table presents Adjusted EBITDA from continuing operations by reportable
segment for the nine months ended S
eptember 30
, 2016 and 2015:
|
|
Nine months Ended
|
|
|
Nine months Ended
|
|
|
Increase
|
|
Segment
|
|
September 30, 2016
|
|
|
September 30, 2015
|
|
|
(Decrease)
|
|
|
|
(in millions)
|
|
Central Appalachia
|
|
$
|
(3.4
|
)
|
|
$
|
(3.5
|
)
|
|
$
|
0.1
|
|
Northern Appalachia
|
|
|
10.2
|
|
|
|
10.8
|
|
|
|
(0.6
|
)
|
Rhino Western
|
|
|
3.8
|
|
|
|
2.0
|
|
|
|
1.8
|
|
Illinois Basin
|
|
|
2.8
|
|
|
|
(5.6
|
)
|
|
|
8.4
|
|
Other
|
|
|
1.5
|
|
|
|
2.0
|
|
|
|
(0.5
|
)
|
Total
|
|
$
|
14.9
|
|
|
$
|
5.7
|
|
|
$
|
9.2
|
|
Adjusted
EBITDA from continuing operations for the nine months ended
September 30
, 2016 was $14.9
million, an increase of $9.2 million from the nine months ended
September 30
, 2015. Adjusted
EBITDA from continuing operations increased period to period due to the improvement year-to-year in our loss from continuing operations
as well as the prior service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement
benefit plan at our Hopedale operation. Adjusted EBITDA for the nine months ended
September
30
, 2016 and 2015 were $16.7 million and $13.1 million, respectively, once the results from discontinued operations were
included. 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, 2016
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Total**
|
|
|
|
|
(in
millions)
|
|
|
Net income/(loss) from continuing operations
|
|
$
|
(1.5
|
)
|
|
$
|
3.2
|
|
|
$
|
-
|
|
|
$
|
(2.8
|
)
|
|
$
|
(2.1
|
)
|
|
$
|
(3.2
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
1.6
|
|
|
|
0.8
|
|
|
|
1.3
|
|
|
|
2.6
|
|
|
|
0.2
|
|
|
|
6.5
|
|
Interest expense
|
|
|
0.5
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
0.3
|
|
|
|
1.0
|
|
|
|
1.9
|
|
EBITDA from continuing operations†
|
|
$
|
0.6
|
|
|
$
|
4.0
|
|
|
$
|
1.4
|
|
|
$
|
0.1
|
|
|
$
|
(0.9
|
)
|
|
$
|
5.2
|
|
Plus: Provision for doubtful accounts (1)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2.0
|
|
|
|
2.0
|
|
Plus: Gain on extinguishment of debt (2)
|
|
|
-
|
|
|
|
(1.7
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1.7
|
)
|
Adjusted EBITDA from continuing operations†
|
|
|
0.6
|
|
|
|
2.3
|
|
|
|
1.4
|
|
|
|
0.1
|
|
|
|
1.1
|
|
|
|
5.5
|
|
EBITDA from discontinued operations
|
|
|
0.1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
0.1
|
|
Adjusted EBITDA †
|
|
$
|
0.7
|
|
|
$
|
2.3
|
|
|
$
|
1.4
|
|
|
$
|
0.1
|
|
|
$
|
1.1
|
|
|
$
|
5.6
|
|
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
|
|
Nine months ended September 30, 2016
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Total**
|
|
|
|
(in millions)
|
|
Net income/(loss) from continuing operations
|
|
$
|
(10.1
|
)
|
|
$
|
9.0
|
|
|
$
|
(0.6
|
)
|
|
$
|
(4.2
|
)
|
|
$
|
(3.1
|
)
|
|
$
|
(9.0
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
4.9
|
|
|
|
2.6
|
|
|
|
4.1
|
|
|
|
6.3
|
|
|
|
0.4
|
|
|
|
18.3
|
|
Interest expense
|
|
|
1.7
|
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
0.7
|
|
|
|
2.2
|
|
|
|
5.2
|
|
EBITDA from continuing operations† **
|
|
$
|
|
|
|
$
|
11.9
|
|
|
$
|
3.8
|
|
|
$
|
2.8
|
|
|
$
|
(0.5
|
)
|
|
$
|
14.6
|
|
Plus: Provision for doubtful accounts (1)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2.0
|
|
|
|
2.0
|
|
Plus: Gain on extinguishment of debt (2)
|
|
|
-
|
|
|
|
(1.7
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1.7
|
)
|
Adjusted EBITDA from continuing operations†
|
|
|
(3.4
|
)
|
|
|
10.2
|
|
|
|
3.8
|
|
|
|
2.8
|
|
|
|
1.5
|
|
|
|
14.9
|
|
EBITDA from discontinued operations
|
|
|
1.8
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1.8
|
|
Adjusted EBITDA †
|
|
$
|
(1.6
|
)
|
|
$
|
10.2
|
|
|
$
|
3.8
|
|
|
$
|
2.8
|
|
|
$
|
1.5
|
|
|
$
|
16.7
|
|
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
|
|
Three months ended September 30, 2015
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Total**
|
|
|
|
(in millions)
|
|
Net income/(loss) from continuing operations
|
|
$
|
(8.4
|
)
|
|
$
|
2.0
|
|
|
$
|
(0.5
|
)
|
|
$
|
(3.1
|
)
|
|
$
|
(0.4
|
)
|
|
$
|
(10.4
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
2.6
|
|
|
|
1.9
|
|
|
|
1.6
|
|
|
|
1.6
|
|
|
|
0.1
|
|
|
|
7.8
|
|
Interest expense
|
|
|
0.5
|
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
0.2
|
|
|
|
0.5
|
|
|
|
1.4
|
|
EBITDA from continuing operations†
|
|
$
|
(5.3
|
)
|
|
$
|
4.0
|
|
|
$
|
1.2
|
|
|
$
|
(1.3
|
)
|
|
$
|
0.2
|
|
|
$
|
(1.2
|
)
|
Plus: Non-cash asset impairment (3)
|
|
|
2.3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2.3
|
|
Adjusted EBITDA from continuing operations†
|
|
|
(3.0
|
)
|
|
|
4.0
|
|
|
|
1.2
|
|
|
|
(1.3
|
)
|
|
|
0.3
|
|
|
|
1.2
|
|
EBITDA from discontinued operations
|
|
|
1.6
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1.6
|
|
Adjusted EBITDA †
|
|
$
|
(1.4
|
)
|
|
$
|
4.0
|
|
|
$
|
1.2
|
|
|
$
|
(1.3
|
)
|
|
$
|
0.3
|
|
|
$
|
2.8
|
|
|
|
Central
|
|
|
Northern
|
|
|
Rhino
|
|
|
Illinois
|
|
|
|
|
|
|
|
Nine months ended September 30, 2015
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Western
|
|
|
Basin
|
|
|
Other
|
|
|
Total**
|
|
|
|
(in millions)
|
|
Net income/(loss) from continuing operations
|
|
$
|
(16.3
|
)
|
|
$
|
4.6
|
|
|
$
|
(3.0
|
)
|
|
$
|
(10.3
|
)
|
|
$
|
(1.9
|
)
|
|
$
|
(26.9
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
9.1
|
|
|
|
5.7
|
|
|
|
4.8
|
|
|
|
4.3
|
|
|
|
0.6
|
|
|
|
24.5
|
|
Interest expense
|
|
|
1.4
|
|
|
|
0.5
|
|
|
|
0.2
|
|
|
|
0.4
|
|
|
|
1.1
|
|
|
|
3.6
|
|
EBITDA from continuing operations† **
|
|
$
|
(5.8
|
)
|
|
$
|
10.8
|
|
|
$
|
2.0
|
|
|
$
|
(5.6
|
)
|
|
$
|
(0.2
|
)
|
|
$
|
1.2
|
|
Plus: Non-cash asset impairment (3)
|
|
|
2.3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2.2
|
|
|
|
4.5
|
|
Adjusted EBITDA from continuing operations†
|
|
$
|
(3.5
|
)
|
|
|
10.8
|
|
|
|
2.0
|
|
|
|
(5.6
|
)
|
|
|
2.0
|
|
|
|
5.7
|
|
EBITDA from discontinued operations
|
|
|
6.7
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
0.7
|
|
|
|
7.4
|
|
Adjusted EBITDA †
|
|
$
|
3.2
|
|
|
$
|
10.8
|
|
|
$
|
2.0
|
|
|
$
|
(5.6
|
)
|
|
$
|
2.7
|
|
|
$
|
13.1
|
|
*
|
Includes
our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia
and for which we serve as manager.
|
|
|
**
|
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 reserve against 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.
|
|
|
(3)
|
During
the three and nine months ended September 30, 2015, we recorded asset impairment losses of approximately $2.3 million and
$4.5 million, respectively. For the three months ended September 30, 2015, we recorded an asset impairment loss of approximately
$2.3 million for our Deane mining complex since this asset is classified as held for sale and was written down to its estimated
fair value less costs to sell as of September 30, 2015. For the nine months ended September 30, 2015, we recorded an additional
asset impairment loss of approximately $2.2 million for our Cana Woodford mineral rights since this asset was classified as
held for sale and was written down to its estimated fair value less costs to sell as of June 30, 2015. We believe that the
isolation and presentation of these specific items 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 these items provides investors
with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of
these items provides investors with enhanced comparability to prior and future periods of our operating results.
|
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
(in millions)
|
|
Net cash provided by operating activities
|
|
$
|
1.1
|
|
|
$
|
2.5
|
|
|
$
|
5.1
|
|
|
$
|
13.9
|
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in net operating assets
|
|
|
5.1
|
|
|
|
-
|
|
|
|
6.1
|
|
|
|
-
|
|
Gain on sale of assets
|
|
|
0.1
|
|
|
|
0.5
|
|
|
|
0.4
|
|
|
|
1.2
|
|
Amortization of deferred revenue
|
|
|
0.6
|
|
|
|
0.4
|
|
|
|
1.3
|
|
|
|
2.1
|
|
Amortization of actuarial gain
|
|
|
-
|
|
|
|
-
|
|
|
|
4.8
|
|
|
|
0.1
|
|
Interest expense
|
|
|
1.9
|
|
|
|
1.4
|
|
|
|
5.2
|
|
|
|
3.7
|
|
Equity in net income of unconsolidated affiliate
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.3
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in net operating assets
|
|
|
-
|
|
|
|
1.1
|
|
|
|
-
|
|
|
|
4.6
|
|
Amortization of advance royalties
|
|
|
0.1
|
|
|
|
0.2
|
|
|
|
0.7
|
|
|
|
0.6
|
|
Amortization of debt issuance costs
|
|
|
1.0
|
|
|
|
0.3
|
|
|
|
2.0
|
|
|
|
1.1
|
|
Loss on retirement of advanced royalties
|
|
|
-
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Equity-based compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
0.5
|
|
|
|
-
|
|
Provision for doubtful accounts
|
|
|
2.0
|
|
|
|
0.1
|
|
|
|
2.0
|
|
|
|
0.5
|
|
Loss on asset impairments
|
|
|
-
|
|
|
|
2.3
|
|
|
|
-
|
|
|
|
4.5
|
|
Loss on disposal of business
|
|
|
0.5
|
|
|
|
-
|
|
|
|
119.2
|
|
|
|
-
|
|
Accretion on asset retirement obligations
|
|
|
0.4
|
|
|
|
0.5
|
|
|
|
1.1
|
|
|
|
1.7
|
|
Distribution from unconsolidated affiliates
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
0.2
|
|
Equity in net loss of unconsolidated affiliates
|
|
|
-
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Gain on extinguishment of debt
|
|
|
1.7
|
|
|
|
-
|
|
|
|
1.7
|
|
|
|
-
|
|
EBITDA†
|
|
$
|
3.1
|
|
|
$
|
0.4
|
|
|
$
|
(104.5
|
)
|
|
$
|
8.1
|
|
Plus: Loss on disposal of business and asset impairments (1)
|
|
|
0.5
|
|
|
|
2.3
|
|
|
|
119.2
|
|
|
|
4.5
|
|
Plus: Provision for doubtful accounts (2)
|
|
|
2.0
|
|
|
|
0.1
|
|
|
|
2.0
|
|
|
|
0.5
|
|
Adjusted EBITDA† **
|
|
|
5.6
|
|
|
|
2.8
|
|
|
|
16.7
|
|
|
|
13.1
|
|
Less: EBITDA from discontinued operations
|
|
|
0.1
|
|
|
|
1.6
|
|
|
|
1.8
|
|
|
|
7.4
|
|
Adjusted EBITDA from continuing operations †
|
|
$
|
5.5
|
|
|
$
|
1.2
|
|
|
$
|
14.9
|
|
|
$
|
5.7
|
|
†
|
EBITDA
is calculated based on actual amounts and not the rounded amounts presented in this table.
|
|
|
**
|
Totals
may not foot due to rounding.
|
|
|
(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. For the three and nine months ended September 30, 2015, we
recorded asset impairment losses of approximately $2.3 million and $4.5 million, respectively. For the three months ended
September 30, 2015, we recorded an asset impairment loss of approximately $2.3 million for our Deane mining complex since
this asset is classified as held for sale and was written down to its estimated fair value less costs to sell as of September
30, 2015. For the nine months ended September 30, 2015, we recorded an additional asset impairment loss of approximately $2.2
million for our Cana Woodford mineral rights since this asset was classified as held for sale and was written down to its
estimated fair value less costs to sell as of June 30, 2015. 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 $2.0 million reserve against a note receivable that was
recorded in 2015 related to the sale of the Deane mining complex discussed earlier. During the three and nine months ended
September 30, 2015, we recorded provisions for doubtful accounts of approximately $0.1 million and $0.5 million, respectively,
related to a few of our Elk Horn lessee customers in Central Appalachia that were in bankruptcy proceedings. 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
The
principal indicators of our liquidity are our cash on hand and availability under our Amended and Restated Credit Agreement. As
of September 30, 2016, our available liquidity was $4.0 million, which was comprised of our availability under our credit agreement.
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.
Prior
to our entry into the Fifth Amendment, we were unable to demonstrate that we had sufficient liquidity to operate our business
over the subsequent twelve months and thus, substantial doubt was raised about our ability to continue as a going concern. Accordingly,
our independent registered public accounting firm 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, 2015. 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.
On
March 17, 2016, our Operating Company, as borrower, and we and certain of our subsidiaries, as guarantors, entered into a fourth
amendment (the “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 the General.
On
May 13, 2016, we entered into the Fifth Amendment of the Amended and Restated Credit Agreement, which extended the term to July
31, 2017.
In
July 2016, we entered into a sixth amendment (the “Sixth Amendment”) of our amended and restated senior secured credit
facility that permitted the sale of Elk Horn that was discussed earlier. (see “—Liquidity and Capital Resources—Amended
and Restated Credit Agreement” for further details of the Fourth, Fifth and Sixth Amendments).
In
order to borrow under our senior secured credit facility, we must make certain representations and warranties to our lenders at
the time of each borrowing. If we are unable to make these representations and warranties, we would be unable to borrow under
our senior secured credit facility, absent a waiver. Furthermore, if we violate any of the covenants or restrictions in our Amended
and Restated Credit Agreement, including the maximum leverage ratio and minimum EBITDA requirement, some or all of our indebtedness
may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. Given the
continued weak demand and low prices for met and steam coal, we may not be able to continue to give the required representations
or meet all of the covenants and restrictions included in our senior secured credit facility. If we are unable to give a required
representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow
under our Amended and Restated Credit Agreement. Although we believe our lenders loans are well secured under the terms of our
Amended and Restated Credit Agreement, there is no assurance that the lenders would agree to any such waiver.
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. For the quarter ended September 30, 2016, we continued the suspension
of the cash distribution for our common units, which was initially suspended beginning with the quarter ended June 30, 2015. For
the quarters ended September 30, 2014 and December 31, 2014, we announced cash distributions of $0.05 per common unit, or $0.20
per unit on an annualized basis, and for the quarter ended March 31, 2015, we announced cash distributions of $0.02 per common
unit, or $0.08 per unit on an annualized basis. Each of these quarters’ distribution levels were lower than the previous
quarters’ distribution amounts of $0.445 per common unit, or $1.78 per unit on an annualized basis. 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.
Cash
Flows
Net
cash provided by operating activities was $5.1 million for the nine months ended September 30, 2016 as compared to cash provided
by operating activities of $13.9 million for the nine months ended September 30, 2015. This decrease in cash provided by operating
activities was primarily the result of ongoing weak coal market conditions discussed above for the nine months ended September
30, 2016 as compared to 2015.
Net
cash provided by investing activities was $5.1 million for the nine months ended September 30, 2016 as compared to cash used for
investing activities of $4.5 million for the nine months ended September 30, 2015. Net cash provided by investing activities for
the nine months ended September 30, 2016 was primarily related to the proceeds from the sale of Elk Horn coal leasing operation,
partially offset by our capital expenditures necessary for maintaining our mining operations. Net cash used for investing activities
for the nine months ended September 30, 2015 is primarily related to our capital expenditures necessary for maintaining our mining
operations.
Net
cash used in financing activities for the nine months ended September 30, 2016 was $10.3 million, which was primarily attributable
to net repayments on our revolving credit facility this period with the proceeds from the sale of our Elk Horn coal leasing operation
as well as contributions from Royal’s acquisition of common units. Net cash used in financing activities for the nine months
ended September 30, 2015 was $9.9 million, which was primarily attributable to fees paid for the third amendment of our credit
facility, as well as distributions paid to unitholders.
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, 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, 2016 were approximately $1.1 million. These amounts were
primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the nine months ended
September 30, 2016 were approximately $4.8 million, which were primarily related to the payments for the final development of
our new Riveredge mine on our Pennyrile property in western Kentucky.
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.
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. As of and for the twelve months ended September 30,
2016, we are in compliance with respect to all covenants contained in the credit agreement.
On
March 17, 2016, we entered into the 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 requires that on or before March 31, 2017, we shall have solicited 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 alters the maximum leverage ratio, calculated as of the
end of the most recent month, on a trailing twelve-month basis, as follows:
Period
|
|
Ratio
|
For
the month ending April 30, 2016, through the month ending May 31, 2016
|
|
7.50
to 1.00
|
|
|
|
For
the month ending June 30, 2016, through the month ending August 31, 2016
|
|
7.25
to 1.00
|
|
|
|
For
the month ending September 30, 2016, through the month ending November 30, 2016
|
|
7.00
to 1.00
|
|
|
|
For
the month ending December 31, 2016, through the month ending March 31, 2017
|
|
6.75
to 1.00
|
|
|
|
For
the month ending April 30, 2017, through the month ending June 30, 2017
|
|
6.25
to 1.00
|
|
|
|
For
the month ending July 31, 2017, through the month ending November 30, 2017
|
|
6.0
to 1.00
|
|
|
|
For
the month ending December 31, 2017
|
|
5.50
to 1.00
|
The
leverage ratios above shall be reduced by 0.50 to 1.00 for every $10 million of aggregate proceeds received by us from: (i) the
issuance of our equity (excluding any Royal capital contributions) and/or (ii) the proceeds received from the sale of assets,
provided that the leverage ratio shall not be reduced below 3.50 to 1.00. 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 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 for the additional $1.5 million to be received from the Elk Horn
sale by $375,000 each quarterly period beginning September 30, 2016 through June 30, 2017.
At
September 30, 2016, the Operating Company had borrowings outstanding (excluding letters of credit) of $30.4 million at a variable
interest rate of PRIME plus 3.50% (7.00% at September 30, 2016). In addition, the Operating Company had outstanding letters of
credit of approximately $27.8 million at a fixed interest rate of 5.00% at September 30, 2016. Based upon a maximum borrowing
capacity of 6.50 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company
had available borrowing capacity of approximately $4.0 million at September 30, 2016. During the three months ended September
30, 2016, we had average borrowings outstanding of approximately $37.7 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 in an amount of up to 25% of the 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, 2016, we had $27.8 million in letters of credit outstanding, of which $22.4 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, 2015. There have been no significant changes
in these policies and estimates as of September 30, 2016.
Recent
Accounting Pronouncements
Refer
to Part-I— Item 1. 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.