Colorado
|
001-3473
|
84-1014610
|
(State or Other Jurisdiction
of Incorporation)
|
(Commission
File Number)
|
(IRS Employer
Identification No.)
|
1660 Lincoln Street, Suite 2700, Denver Colorado
|
80264-2701
|
|
(Address of principal executive offices)
|
(Zip Code)
|
Registrant’s telephone number, including area code: 303-839-5504
|
r
|
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
|
r
|
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
|
r
|
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
|
r
|
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
|
Year
|
Contracted Tons
|
Average Price/Ton
|
||||||
2014
|
3,504,000*
|
$42.72
|
||||||
2015
|
1,650,000
|
41.99
|
||||||
2016
|
689,000
|
40.93**
|
.
|
|||||
Total
|
5,843,000
|
Year-End Reserves
|
||||||||||||||
Annual Capacity
|
2013
|
2012
|
||||||||||||
Proven
|
Probable
|
Total
|
Proven
|
Probable
|
Total
|
|||||||||
Carlisle (assigned)
|
3.4
|
33.5
|
8.6
|
42.1
|
34.2
|
9.3
|
43.5
|
|||||||
Ace-in-the-Hole (assigned)
|
0.5
|
3.1
|
3.1
|
3.1
|
3.1
|
|||||||||
Bulldog (unassigned)
|
19.6
|
16.2
|
35.8
|
19.5
|
16.1
|
35.6
|
||||||||
War Eagle (unassigned)
|
27.7
|
15.4
|
43.1
|
15.5
|
13.9
|
29.4
|
||||||||
Total
|
3.9
|
83.9
|
40.2
|
124.1
|
72.3
|
39.3
|
111.6
|
|||||||
Assigned
|
45.2
|
46.6
|
||||||||||||
Unassigned
|
78.9
|
65.0
|
||||||||||||
|
124.1
|
111.6
|
•
|
SO2 - Historically, Carlisle has guaranteed a 6# SO2 product; however, with the addition of the Ace-in-the-Hole Mine we can blend lower sulfur coal with Carlisle coal and guarantee a mid-sulfur product which should command a higher price and increase our customer base. Few mines in the ILB have the ability to offer their customers various ranges of SO2. Carlisle has supplied coal to 11 different power plants.
|
•
|
Chlorine - Our reserves have lower chlorine (<0.10%) than average ILB reserves of 0.22%. Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%. The relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants.
|
•
|
Transportation - Carlisle has a double 100 rail car loop facility and a four-hour certified batch load-out facility connected to the CSX railroad. The Indiana Rail Road (INRD) also has limited running rights on the CSX to our mine. Dual rail access gives us a freight advantage to more customers. Long term, the CSX anticipates our coal being shipped to southeast markets via their railroad. We sell our coal FOB the mine and substantially all of our coal is transported by rail. However, on occasion we have shipped to three power plants via truck.
|
Carlisle - maintenance capex
|
$ | 14,602 | ||
Carlisle - expansion/improvements
|
2,973 | |||
Carlisle - land and minerals
|
346 | |||
Ace - mine development
|
4,013 | |||
Ace - surface equipment
|
5,858 | |||
Other projects
|
3,685 | |||
Items accrued for but not paid
|
(85 | ) | ||
Capex per the Cash Flow Statement
|
$ | 31,392 |
2013
|
||||||||||||||||||||
1st
|
2nd
|
3rd
|
4th
|
Full Year
|
||||||||||||||||
Tons sold
|
840 | 774 | 817 | 757 | 3,188 | |||||||||||||||
Coal sales
|
$ | 33,995 | $ | 34,149 | $ | 34,985 | $ | 34,307 | $ | 137,436 | ||||||||||
Average price/ton
|
40.47 | 44.12 | 42.82 | 45.32 | 43.11 | |||||||||||||||
Wash plant recovery
|
74.0 | % | 70.9 | % | 68.0 | % | 63.2 | % | 69.0 | % | ||||||||||
Operating costs
|
$ | 23,290 | $ | 22,262 | $ | 23,407 | $ | 23,934 | $ | 92,893 | ||||||||||
Average cost/ton
|
27.73 | 28.76 | 28.65 | 31.62 | 29.14 | |||||||||||||||
Margin
|
10,705 | 11,887 | 11,578 | 10,373 | 44,543 | |||||||||||||||
Margin/ton
|
12.74 | 15.36 | 14.17 | 13.70 | 13.97 | |||||||||||||||
Capex
|
8,604 | 6,174 | 8,780 | 7,834 | 31,392 |
2012
|
||||||||||||||||||||
1st
|
2nd
|
3rd
|
4th
|
Full Year
|
||||||||||||||||
Tons sold
|
701 | 743 | 810 | 752 | 3,006 | |||||||||||||||
Coal sales
|
$ | 29,620 | $ | 32,487 | $ | 36,152 | $ | 33,111 | $ | 131,370 | ||||||||||
Average price/ton
|
42.25 | 43.72 | 44.63 | 44.03 | 43.70 | |||||||||||||||
Wash plant recovery
|
73.1 | % | 71.2 | % | 71.1 | % | 71.7 | % | 71.8 | % | ||||||||||
Operating costs
|
$ | 18,433 | $ | 18,816 | $ | 20,745 | $ | 21,745 | $ | 79,739 | ||||||||||
Average cost/ton
|
26.29 | 25.32 | 25.61 | 28.91 | 26.53 | |||||||||||||||
Margin
|
11,187 | 13,671 | 15,407 | 11,366 | 51,631 | |||||||||||||||
Margin/ton
|
15.96 | 18.40 | 19.02 | 15.12 | 17.17 | |||||||||||||||
Capex
|
2,372 | 1,857 | 4,993 | 16,987 | 26,209 |
Year
|
Tons
|
Average Sales
Price/ton
|
Average
Cost/ton
|
Margin/
ton
|
Margin
(in millions)
|
||||||
2012
|
3,006,000
|
$43.70
|
$26.53
|
$17.17
|
$51.6
|
||||||
2013
|
3,188,000
|
43.11
|
29.14
|
13.97
|
44.5
|
||||||
2014*
|
3,504,000
|
42.72
|
28.50
|
14.22
|
49.8
|
2013
|
2012
|
|||||||
Revenue:
|
||||||||
Oil
|
$
|
32,057
|
$
|
25,830
|
||||
NGLs (natural gas liquids)
|
900
|
926
|
||||||
Natgas
|
709
|
368
|
||||||
Contract drilling
|
5,409
|
4,555
|
||||||
Other
|
3,173
|
373
|
||||||
Total revenue
|
42,248
|
32,052
|
||||||
Costs and expenses:
|
||||||||
LOE (lease operating expenses)
|
3,262
|
2,659
|
||||||
Severance tax
|
2,476
|
2,015
|
||||||
Contract drilling costs
|
3,520
|
3,161
|
||||||
DD&A (depreciation, depletion & amortization)
|
5,802
|
6,387
|
||||||
G&G (geological and geophysical costs)
|
5,084
|
3,208
|
||||||
Dry hole costs
|
3,066
|
3,244
|
||||||
Impairment of unproved properties
|
3,999
|
3,778
|
||||||
Other exploration costs
|
451
|
340
|
||||||
G&A (general & administrative)
|
1,662
|
1,287
|
||||||
Stock option expense
|
1,448
|
|||||||
Total expenses
|
29,322
|
27,527
|
||||||
Net income
|
$
|
12,926
|
$
|
4,525
|
The information below is not in thousands:
|
||||||||
Oil production – barrels
|
337,950
|
295,000
|
||||||
Average oil prices/barrel
|
$
|
95.00
|
$
|
88.00
|
||||
Oil reserves in barrels
|
3,246,000
|
1,545,000
|
||||||
NGL reserves in barrels
|
218,000
|
64,000
|
||||||
Natgas reserves in Mcf
|
2,875,000
|
2,448,000
|
||||||
Oil prices/barrel used for PV 10
|
$
|
94.66
|
$
|
91.00
|
||||
PV 10: proved reserves
|
$
|
200,707,000
|
$
|
78,000,000
|
||||
PV 10: proved developed reserves
|
$
|
105,922,000
|
$
|
48,000,000
|
PV 10: proved reserves
|
$ | 90,820,000 | $ | 35,303,000 | ||||
PV 10: proved developed reserves
|
$ | 47,930,000 | $ | 21,725,000 |
ASSETS
|
2013
|
2012
|
||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$
|
16,228
|
$
|
21,888
|
||||
Accounts receivable
|
10,577
|
8,127
|
||||||
Prepaid income taxes
|
4,661
|
|||||||
Coal inventory
|
4,778
|
2,342
|
||||||
Parts and supply inventory
|
2,826
|
2,264
|
||||||
Other
|
291
|
242
|
||||||
Total current assets
|
39,361
|
34,863
|
||||||
Coal properties, at cost:
|
||||||||
Land and mineral rights
|
26,476
|
22,705
|
||||||
Buildings and equipment
|
148,077
|
131,566
|
||||||
Mine development
|
85,333
|
71,046
|
||||||
259,886
|
225,317
|
|||||||
Less - accumulated DD&A
|
(77,545
|
)
|
(58,479
|
)
|
||||
182,341
|
166,838
|
|||||||
Investment in Savoy
|
16,733
|
12,230
|
||||||
Investment in Sunrise Energy
|
4,573
|
3,969
|
||||||
Other assets (Note 9)
|
17,405
|
11,307
|
||||||
$
|
260,413
|
$
|
229,207
|
|||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||
Current liabilities:
|
||||||||
Accounts payable and accrued liabilities
|
$
|
10,357
|
$
|
9,386
|
||||
Income taxes
|
1,660
|
|||||||
Total current liabilities
|
10,357
|
11,046
|
||||||
Long-term liabilities:
|
||||||||
Bank debt
|
16,000
|
11,400
|
||||||
Deferred income taxes
|
43,304
|
35,863
|
||||||
Asset retirement obligations
|
5,290
|
2,573
|
||||||
Other
|
2,128
|
6,316
|
||||||
Total long-term liabilities
|
66,722
|
56,152
|
||||||
Total liabilities
|
77,079
|
67,198
|
||||||
Commitments and contingencies
|
||||||||
Stockholders’ equity:
|
||||||||
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
|
||||||||
Common stock, $.01 par value, 100,000 shares authorized; 28,751 and 28,529 outstanding, respectively
|
287
|
285
|
||||||
Additional paid-in capital
|
87,872
|
86,576
|
||||||
Retained earnings
|
94,796
|
75,118
|
||||||
Accumulated other comprehensive income
|
379
|
30
|
||||||
Total stockholders’ equity
|
183,334
|
162,009
|
||||||
$
|
260,413
|
$
|
229,207
|
2013
|
2012
|
|||||||
Revenue:
|
||||||||
Coal sales
|
$
|
137,436
|
$
|
131,370
|
||||
Equity income – Savoy
|
5,827
|
2,039
|
||||||
Equity income - Sunrise Energy
|
629
|
167
|
||||||
Liability extinguishment (Note 12)
|
4,300
|
|||||||
Gain on sale of land
|
2,748
|
|||||||
Other income (Note 9)
|
5,678
|
4,999
|
||||||
153,870
|
141,323
|
|||||||
Costs and expenses:
|
||||||||
Operating costs and expenses
|
92,893
|
79,739
|
||||||
DD&A
|
18,585
|
16,028
|
||||||
Coal exploration costs
|
2,360
|
2,453
|
||||||
SG&A
|
7,669
|
7,532
|
||||||
Interest
|
1,547
|
1,096
|
||||||
123,054
|
106,848
|
|||||||
Income before income taxes
|
30,816
|
34,475
|
||||||
Less income taxes:
|
||||||||
Current
|
221
|
5,905
|
||||||
Deferred
|
7,441
|
4,763
|
||||||
7,662
|
10,668
|
|||||||
Net income*
|
$
|
23,154
|
$
|
23,807
|
||||
Net income per share:
|
||||||||
Basic
|
$
|
.81
|
$
|
.84
|
||||
Diluted
|
$
|
.80
|
$
|
.83
|
||||
Weighted average shares outstanding:
|
||||||||
Basic
|
28,595
|
28,331
|
||||||
Diluted
|
28,906
|
28,843
|
2013
|
2012
|
|||||||
Operating activities:
|
||||||||
Net income
|
$
|
23,154
|
$
|
23,807
|
||||
Gain on sale
|
(2,748
|
)
|
||||||
Liability extinguishment
|
(4,300
|
)
|
||||||
Deferred income taxes
|
7,441
|
4,763
|
||||||
Equity income – Savoy and Sunrise Energy
|
(6,456
|
)
|
(2,206
|
)
|
||||
Cash distributions from Savoy and Sunrise Energy
|
1,325
|
1,943
|
||||||
DD&A
|
18,585
|
16,028
|
||||||
Stock-based compensation
|
2,155
|
2,655
|
||||||
Taxes paid on vesting of RSUs
|
(780
|
)
|
(739
|
)
|
||||
Change in current assets and liabilities:
|
||||||||
Accounts receivable
|
(2,394
|
)
|
(1,058
|
)
|
||||
Coal inventory
|
(2,436
|
)
|
(479
|
)
|
||||
Income taxes
|
(6,327
|
)
|
(3,465
|
)
|
||||
Accounts payable and accrued liabilities
|
1,130
|
1,060
|
||||||
Other
|
(3,916
|
)
|
(2,519
|
)
|
||||
Cash provided by operating activities
|
27,181
|
37,042
|
||||||
Investing activities:
|
||||||||
Proceeds from sale of properties
|
7,630
|
|||||||
Capital expenditures for coal properties
|
(31,392
|
)
|
(26,209
|
)
|
||||
Ohio River terminal
|
(2,836
|
)
|
||||||
Investment in Sunrise Energy
|
(506
|
)
|
||||||
Marketable securities
|
(1,221
|
)
|
||||||
Other
|
263
|
(48
|
)
|
|||||
Cash used in investing activities
|
(33,965
|
)
|
(20,354
|
)
|
||||
Financing activities:
|
||||||||
Payments of bank debt
|
(7,500
|
)
|
||||||
Bank borrowings
|
4,600
|
1,400
|
||||||
Deferred financing costs
|
(1,544
|
)
|
||||||
Dividends
|
(3,476
|
)
|
(23,374
|
)
|
||||
Stock option buy-out
|
(1,461
|
)
|
||||||
Other
|
137
|
|||||||
Cash provided by (used in) financing activities
|
1,124
|
(32,342
|
)
|
|||||
Decrease in cash and cash equivalents
|
(5,660
|
)
|
(15,654
|
)
|
||||
Cash and cash equivalents, beginning of year
|
21,888
|
37,542
|
||||||
Cash and cash equivalents, end of year
|
$
|
16,228
|
$
|
21,888
|
||||
Cash paid for interest
|
$
|
1,028
|
$
|
622
|
||||
Cash paid for income taxes
|
6,045
|
9,250
|
||||||
Increase in ARO
|
2,535
|
159
|
Shares
|
Common Stock
|
Additional Paid-in Capital
|
Retained Earnings
|
Accumulated
Other Comprehensive Income
|
Total
|
|||||||||||||||||||
Balance January 1, 2012
|
28,309
|
$ |
283
|
$ |
85,984
|
$ |
74,685
|
$ |
41
|
$ |
160,993
|
|||||||||||||
Stock-based compensation
|
20
|
2,655
|
2,655
|
|||||||||||||||||||||
Stock issued on vesting of RSUs
|
290
|
2
|
2
|
|||||||||||||||||||||
Taxes paid on vesting of RSUs
|
(90
|
)
|
(739
|
)
|
(739
|
)
|
||||||||||||||||||
Stock option buy-out for cash
|
(1,461
|
)
|
(1,461
|
)
|
||||||||||||||||||||
Dividends
|
(23,374
|
)
|
(23,374
|
)
|
||||||||||||||||||||
Net income
|
23,807
|
23,807
|
||||||||||||||||||||||
Other
|
137
|
(11
|
)
|
126
|
||||||||||||||||||||
Balance December 31, 2012
|
28,529
|
285
|
86,576
|
75,118
|
30
|
162,009
|
||||||||||||||||||
Stock-based compensation
|
13
|
2,155
|
2,155
|
|||||||||||||||||||||
Stock issued on vesting of RSUs
|
316
|
2
|
2
|
|||||||||||||||||||||
Taxes paid on vesting of RSUs
|
(107
|
)
|
(780
|
)
|
(780
|
)
|
||||||||||||||||||
Dividends
|
(3,476
|
)
|
(3,476
|
)
|
||||||||||||||||||||
Net income
|
23,154
|
23,154
|
||||||||||||||||||||||
Other
|
(79
|
)
|
349
|
270
|
||||||||||||||||||||
Balance December 31, 2013
|
28,751
|
$
|
287
|
$
|
87,872
|
$
|
94,796
|
$ |
|
379
|
$
|
183,334
|
2013
|
2012
|
|||||||
Balance beginning of year
|
$
|
2,573
|
$
|
2,276
|
||||
Accretion
|
182
|
138
|
||||||
Additions – primarily Ace for 2013
|
2,535
|
159
|
||||||
Balance end of year
|
$
|
5,290
|
$
|
2,573
|
2013
|
2012
|
|||||||
Expected amount
|
$
|
10,784
|
$
|
12,064
|
||||
State income taxes, net of federal benefit
|
1,540
|
1,723
|
||||||
Percentage depletion
|
(4,373
|
)
|
(1,816
|
)
|
||||
Other
|
(289
|
)
|
(1,303
|
)
|
||||
$
|
7,662
|
$
|
10,668
|
2013
|
2012
|
|||||||
Long-term deferred tax assets:
|
||||||||
Stock-based compensation
|
$
|
372
|
$
|
582
|
||||
Investment in Savoy
|
1,885
|
1,582
|
||||||
Oil and gas properties
|
913
|
1,778
|
||||||
Net long-term deferred tax assets
|
3,170
|
3,942
|
||||||
Long-term deferred tax liabilities:
|
||||||||
Coal properties
|
(46,474
|
)
|
(39,805
|
)
|
||||
Net deferred tax liability
|
$
|
43,304
|
$
|
35,863
|
2013
|
2012
|
|||||||
Current assets
|
$
|
29,182
|
$
|
16,207
|
||||
Oil and gas properties, net
|
25,408
|
21,065
|
||||||
Other
|
260
|
263
|
||||||
$
|
54,850
|
$
|
37,535
|
|||||
Total liabilities
|
$
|
16,447
|
$
|
9,116
|
||||
Partners' capital
|
38,403
|
28,419
|
||||||
$
|
54,850
|
$
|
37,535
|
2013
|
2012
|
|||||||
Revenue
|
$
|
42,248
|
$
|
32,052
|
||||
Expenses
|
(29,322
|
)
|
(27,527
|
)
|
||||
Net income
|
$
|
12,926
|
$
|
4,525
|
2013
|
||||
Unproved property acquisition
|
$ | 1,287 | ||
Development
|
858 | |||
Exploration
|
7,061 | |||
Total
|
$ | 9,206 |
Oil
(Bbls)
|
NGLs
(Bbls)
|
Natgas
(Mcf)
|
||||||||||
January 1, 2013
|
700 | 29 | 1,108 | |||||||||
Extensions and discoveries
|
898 | 58 | 442 | |||||||||
Production
|
(153 | ) | (11 | ) | (96 | ) | ||||||
Revisions to previous estimates
|
24 | 23 | (153 | ) | ||||||||
December 31, 2013
|
1,469 | 99 | 1,301 | |||||||||
Proved developed reserves
|
746 | 60 | 450 | |||||||||
Proved undeveloped reserves (PUDs)
|
723 | 39 | 851 |
Proved
Developed
|
PUDs
|
Total
Proved
|
||||||||||
Future cash flows:
|
||||||||||||
Oil
|
$ | 70,582 | $ | 70,662 | $ | 141,244 | ||||||
NGLs
|
2,551 | 1,669 | 4,220 | |||||||||
Natgas
|
1,365 | 976 | 2,341 | |||||||||
Total cash flows
|
74,498 | 73,307 | 147,805 | |||||||||
Future production costs
|
(12,213 | ) | (12,233 | ) | (24,446 | ) | ||||||
Future development costs
|
(3,073 | ) | (3,073 | ) | ||||||||
Future income tax (none since Savoy is a pass-through entity for income tax purposes)
|
||||||||||||
Future net cash flows
|
62,285 | 58,001 | 120,286 | |||||||||
10% annual discount for estimated timing of cash flows
|
(14,355 | ) | (15,111 | ) | (29,466 | ) | ||||||
Standardized measure of discounted future net cash flows
|
$ | 47,930 | $ | 42,890 | $ | 90,820 | ||||||
2013
|
||||
Beginning of year
|
$ | 35,300 | ||
Sales, net of production costs
|
(12,640 | ) | ||
Net changes in prices and production costs
|
1,600 | |||
Extensions and discoveries
|
57,200 | |||
Revisions of previous quantity estimates
|
2,100 | |||
Change in production timing and other
|
3,700 | |||
Accretion of discount
|
3,560 | |||
End of year
|
$ | 90,820 | ||
Average wellhead prices:
|
||||
Oil (per Bbl)
|
$ | 94.66 | ||
NGLs (per Bbl)
|
42.45 | |||
Natgas (per Mcf)
|
3.04 |
2013
|
2012
|
|||||||
Current assets
|
$
|
3,109
|
$
|
1,754
|
||||
Oil and gas properties, net
|
6,781
|
6,934
|
||||||
$
|
9,890
|
$
|
8,688
|
|||||
Total liabilities
|
$
|
756
|
$
|
762
|
||||
Members' capital
|
9,134
|
7,926
|
||||||
$
|
9,890
|
$
|
8,688
|
2013
|
2012
|
|||||||
Revenue
|
$
|
3,399
|
$
|
2,450
|
||||
Expenses
|
(2,141
|
)
|
(2,117
|
)
|
||||
Net income
|
$
|
1,258
|
$
|
333
|
2013
|
2012
|
|||||||
Long-term assets:
|
||||||||
Advance coal royalties
|
$
|
4,693
|
$
|
3,324
|
||||
Deferred financing costs, net
|
1,195
|
1,494
|
||||||
Marketable equity securities available for sale, at fair value (restricted)*
|
3,889
|
3,548
|
||||||
Ohio River Terminal (see Note 11)
|
2,836
|
|||||||
Miscellaneous
|
4,792
|
2,941
|
||||||
$
|
17,405
|
$
|
11,307
|
|||||
_____________________________________
*Held by Sunrise Indemnity, Inc., our wholly-owned captive insurance company.
|
||||||||
Other income:
|
||||||||
MSHA reimbursements**
|
$
|
3,672
|
$
|
4,236
|
||||
Coal storage fees
|
1,238
|
304
|
||||||
Miscellaneous
|
768
|
459
|
||||||
$
|
5,678
|
$
|
4,999
|
High
|
Low
|
|||||||
2014
|
||||||||
January 1 through February 27, 2014
|
$ | 8.29 | $ | 7.63 | ||||
2013
|
||||||||
Fourth quarter
|
8.55 | 6.58 | ||||||
Third quarter
|
8.41 | 6.82 | ||||||
Second quarter
|
8.37 | 6.46 | ||||||
First quarter
|
8.35 | 6.90 | ||||||
2012
|
||||||||
Fourth quarter
|
10.11 | 8.03 | ||||||
Third quarter
|
8.51 | 7.25 | ||||||
Second quarter
|
9.01 | 6.56 | ||||||
First quarter
|
10.83 | 8.70 |
1.
|
The Carlisle mine currently has road frontage on State Highway 58, and is adjacent to the CSX railroad. The Carlisle mine has a double 100 car loop facility. Substantially all of our coal is shipped by rail.
|
2.
|
Currently only the Indiana V seam is planned to be mined, and all of the controlled tonnage is leased to Sunrise. Most leases have unlimited terms once mining has begun, and yearly payments or earned royalties are kept current. Mineable coal thickness used is greater than four feet. The current Carlisle mine plan is broken into four areas– North Main – South Main – West Main – 2 South Main. It is believed that all additional property that would be required to access all lease areas can be obtained but, if some properties cannot be leased, some modification of the current mine plan would be required. All coal should be mined within the terms of the leases. Leasing programs are continuing by our staff.
|
3.
|
The Carlisle mine has a dual-use slope for the main coal conveyor and the moving of supplies and personnel. There are two 8' diameter shafts, known as the “main fans”, at the base of the slope for mine ventilation. Two additional air shafts (8’ and 10.5’ diameter), known as the “north fans”, were completed about three miles north of the original air shaft in 2009 to facilitate the mine expansion. The slope (9° or 15% grade) is 18' wide with concrete and steel arch construction. A 16’ hoist is about four miles north of the main slope. The hoist is currently facilitating two production units by efficiently moving personnel and materials into the north main and north main addition areas of the reserve. Two additional 8’ diameter airshafts, the “north portal fans”, were completed in 2013 at the North Portal facility to more effectively ventilate the north units, and facilitate more efficient use of the main set and north set of air shafts to units elsewhere in the mine. All underground mining equipment is powered with electricity and underground compliant diesel.
|
4.
|
The new slurry impoundment construction has been completed in 2013 as planned. The impoundment is currently being utilized as fine refuse disposal, with a final estimated storage capacity of 36 million clean tons.
|
5.
|
Current production capabilities are projected to be in the range of 3 to 3.3 million tons per year giving the mine a reserve life of about 15 years. The mine plan is basic room-and-pillar using a synchronized continuous miner section with no retreat mining. Plans are for pillars to be centered on a 60'x80' pattern with 18' entries for our mains, and pillars on 60'x60' centers with 20' entries in the rooms.
|
6.
|
The Carlisle mine has been in production since February 2007. The North Main, Sub Main #1, and the South Main have been developed with four units currently in production.
|
Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
|
•
|
quality of the coal;
|
|
•
|
geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;
|
|
•
|
the percentage of coal ultimately recoverable;
|
|
•
|
the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
|
|
•
|
assumptions concerning the timing for the development of the reserves; and
|
|
•
|
assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.
|
23.1
|
Consent of EKS&H LLLP
|
|
23.2
|
Consent of Brock Engineering, LLC
|
|
99.
|
2013 SEC Reserve Report by Brock Engineering, LLC
|
HALLADOR ENERGY COMPANY
|
||
Date: February 28, 2014
|
/s/W. ANDERSON BISHOP
|
|
W. Anderson Bishop, CFO and CAO
|
&O&UQXTD\013:4WEJ8K.&?
?%74)?$MK]CUA;,+:00G
M=$8,\MN[MG'ZUI^.O^1U\#_]A!__`$"K/ASPSK7_``DTOB3Q)=6SWWD?9X8+
M52(XTSDDD]35_P`2>';K6/$/AS4()(UBTRZ::56ZL"N.*`)?'5FE]X(U>%\9
M%NSJ=8#(/YU)X+U*75_!NDWTY)FEMD+D]V`P34'CZ]^Q>"M2*C=--$8(4Q
MDL[_`"J,?4U<\*Z2VA^%M-TUSF2WMU1_]['/ZT`6]NSD1_\`/-,=VZ9[5F_"6_TPZOXCTVRM98H7N?,BC:`JBQ@`8/H?:O6:
MY/PQX=U#0;OQ%G3/"+^YLFA=ESL\QEP3],T`9_@*>*V^&6A3SN$BCT^-
MG=N@`7DUI:/XKT'Q!,\6DZI;WDB*'98FR0I[TGAC1Y-'\(:9H]YY
Category
|
OIl
(Barrels)
|
Net Reserves NGL
(Barrels)
|
Gas
(MCF)
|
Future Net Revenue ($)
Total
|
Present Worth
at 10% ($)
|
|||||
Proved Developed Producing
Proved Developed Non- Producing
|
629,450
116,180
|
50,910
9,182
|
376,156
73,457
|
52,674,800
9,610,000
|
40,429,100
7,501,300
|
|||||
Proved Undeveloped
|
632,647
|
39,323
|
320,530
|
51,490,300
|
38,507,900
|
|||||
Total Proved | 1,378,277 | 99,415 | 770,143 | 113,775,100 | 86,438,300 |
Brock Engineering, LLC
|
Page 3 of 11
|
Brock Engineering, LLC
|
Page 4 of 11
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
Brock Engineering, LLC
|
Page 5 of 11
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
Brock Engineering, LLC
|
Page 6 of 11
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting
those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(14)
|
Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
|
(16)
|
Oil and gas producing activities.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine
|
|
|
Brock Engineering, LLC
|
Page 7 of 11
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.
Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(20)
|
Production costs.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
|
(21)
|
Proved area. The part of a property to which proved reserves have been specifically attributed.
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
Brock Engineering, LLC
|
Page 9 of 11
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(23)
|
Proved properties. Properties with proved reserves.
|
Brock Engineering, LLC
|
Page 10 of 11
|
a.
|
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
|
b.
|
Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
|
a.
|
Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
|
b.
|
Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
|
c.
|
Future income tax expenses. These expenses shall be computed by applying the appropriate year- end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
|
d.
|
Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
|
e.
|
Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
|
f.
|
Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
|
Brock Engineering, LLC
|
Page 11 of 11
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
Ÿ
|
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
|
Ÿ
|
The company's historical record at completing development of comparable long-term projects;
|
Ÿ
|
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
|
Ÿ
|
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
|
Ÿ
|
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|
(32)
|
Unproved properties. Properties with no proved reserves.
|