[ x ]
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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended: December 31, 2011 OR
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[ ]
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission file number: 0-14731
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“COAL KEEPS YOUR LIGHTS ON”
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![]() ![]() |
“COAL KEEPS YOUR LIGHTS ON”
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HALLADOR ENERGY COMPANY
(www.halladorenergy.com)
|
||||||
COLORADO
(State of incorporation)
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84-1014610
(IRS Employer Identification No.)
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|||||
1660 Lincoln Street, Suite 2700, Denver, Colorado
(Address of principal executive offices)
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80264-2701
(Zip Code)
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Issuer's telephone number: 303.839.5504
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o Large accelerated filer
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o Accelerated filer
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o Non-accelerated filer (do not check if a small reporting company)
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þ Smaller reporting company
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Year
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Contracted Tons
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Average
Price
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|||
|
|||||
2012
|
2,900,000
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$42.35
|
|||
2013*
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2,900,000
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40.14
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|||
2014*
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1,100,000
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46.34
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•
|
the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power or wind;
|
•
|
coal quality;
|
•
|
transportation costs from the mine to the customer; and
|
•
|
the reliability of fuel supply.
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1.
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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.
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2.
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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. Approximately 84% of the total mine plan is currently under lease ("controlled"). 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.
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3.
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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 at the base of the slope for mine ventilation. Two additional air shafts (8’ and 10.5’ diameter) 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 now open (spring 2011) approximately 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. All underground mining equipment is powered with electricity and underground compliant diesel.
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4.
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The new slurry impoundment continues to be under construction, due in part to design modifications, but is currently approved for, and being utilized for slurry disposal. When final construction is completed in 2012 the structure will handle disposal for roughly 36 million clean tons of coal.
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5.
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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.
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6.
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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.
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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;
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•
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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;
|
|
•
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the percentage of coal ultimately recoverable;
|
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•
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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;
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•
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assumptions concerning the timing for the development of the reserves; and
|
|
•
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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.
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High
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Low
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|||||||
2012
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||||||||
(January 1 through February 29, 2012)
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$
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10.45
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$
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9.54
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||||
2011
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||||||||
Fourth quarter
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10.47
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8.55
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||||||
Third quarter
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10.22
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8.25
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||||||
Second quarter
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12.05
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9.42
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||||||
First quarter
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11.43
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9.79
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||||||
2010
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||||||||
Fourth quarter
|
12.64
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10.47
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||||||
Third quarter
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12.10
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7.36
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||||||
Second quarter
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13.00
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8.25
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||||||
First quarter
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9.80
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7.50
|
2011
|
2010
|
|||||||
Revenue:
|
||||||||
Oil
|
$ | 25,781 | $ | 11,138 | ||||
Gas
|
566 | 760 | ||||||
NGLs (natural gas liquids)
|
868 | 227 | ||||||
Contract drilling
|
4,336 | 1,735 | ||||||
Gain on sale of unproved properties
|
2,225 | |||||||
Other
|
446 | 587 | ||||||
Total revenue
|
31,997 | 16,672 | ||||||
Costs and expenses:
|
||||||||
LOE (lease operating expenses)
|
2,257 | 1,725 | ||||||
Severance tax
|
2,037 | 818 | ||||||
Contract drilling costs
|
2,559 | 1,445 | ||||||
DD&A (depreciation, depletion & amortization)
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4,733 | 3,147 | ||||||
Geological and geophysical costs
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1,973 | 2,632 | ||||||
Dry hole costs
|
1,852 | 808 | ||||||
Impairment of unproved properties
|
2,963 | 2,543 | ||||||
Other exploration costs
|
357 | 204 | ||||||
G&A (general & administrative)
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1,166 | 1,116 | ||||||
Total expenses
|
19,897 | 14,438 | ||||||
Net income
|
$ | 12,100 | $ | 2,234 | ||||
The information below is not in thousands:
|
||||||||
Oil production in barrels
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283,000 | 149,000 | ||||||
4th quarter oil production in barrels
|
76,600 | 57,000 | ||||||
Gas production in Mcf
|
134,500 | 173,000 | ||||||
Average oil prices/barrel
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$ | 91 | $ | 75 | ||||
Average gas prices/Mcf
|
$ | 4.20 | $ | 4.38 | ||||
Oil reserves (Bbls)
|
1,921,000 | 774,000 | ||||||
Gas reserves (Mcf)
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2,491,000 | 787,000 | ||||||
PV 10 using SEC dictated average oil prices of $93.60 and $74
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$97 million
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$34 million
|
Report of Independent Registered Public Accounting Firm
|
27
|
|
Consolidated Balance Sheet
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28
|
|
Consolidated Statement of Operations
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29
|
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Consolidated Statement of Cash Flows
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30
|
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Consolidated Statement of Stockholders' Equity
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31
|
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Notes to Consolidated Financial Statements
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32
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|
||||||||
2011 | 2010 | |||||||
ASSETS
|
||||||||
Current assets: | ||||||||
Cash and cash equivalents
|
$ | 37,542 | $ | 10,277 | ||||
Certificates of deposit
|
1,291 | |||||||
Prepaid Federal income taxes
|
3,853 | |||||||
Accounts receivable
|
6,689 | 5,450 | ||||||
Coal inventory
|
1,863 | 2,100 | ||||||
Parts and supply inventory
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2,202 | 2,411 | ||||||
Other
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580 | 850 | ||||||
Total current assets
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48,876 | 26,232 | ||||||
Coal properties, at cost:
|
||||||||
Land, buildings and equipment
|
137,707 | 114,476 | ||||||
Mine development
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66,614 | 59,351 | ||||||
204,321 | 173,827 | |||||||
Less - accumulated DD&A
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(42,493 | ) | (28,435 | ) | ||||
161,828 | 145,392 | |||||||
Investment in Savoy
|
12,133 | 7,717 | ||||||
Investment in Sunrise Energy
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3,297 | 2,375 | ||||||
Other assets (Note 8)
|
6,294 | 4,948 | ||||||
$ | 232,428 | $ | 186,664 | |||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||
Current liabilities:
|
||||||||
Current portion of bank debt
|
$ | 17,500 | 10,000 | |||||
Accounts payable and accrued liabilities
|
10,411 | 8,809 | ||||||
Income taxes
|
5,125 | |||||||
Other
|
60 | 692 | ||||||
Total current liabilities
|
33,096 | 19,501 | ||||||
Long-term liabilities:
|
||||||||
Bank debt, net of current portion
|
17,500 | |||||||
Deferred income taxes
|
31,100 | 17,435 | ||||||
Asset retirement obligations
|
2,276 | 1,150 | ||||||
Other
|
4,963 | 4,345 | ||||||
Total long-term liabilities
|
38,339 | 40,430 | ||||||
Total liabilities
|
71,435 | 59,931 | ||||||
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;
28,309 and 27,924 outstanding, respectively
|
283 | 279 | ||||||
Additional paid-in capital
|
85,984 | 84,073 | ||||||
Retained earnings
|
74,685 | 42,381 | ||||||
Accumulated other comprehensive income
|
41 | |||||||
Total stockholders' equity
|
160,993 | 126,733 | ||||||
$ | 232,428 | $ | 186,664 | |||||
2011
|
2010
|
||||||
Revenue:
|
|||||||
Coal sales
|
$ | 137,998 | $ | 129,003 | |||
Gain on sale of unproved oil and gas properties
|
10,653 | ||||||
Equity income - Savoy
|
5,476 | 1,005 | |||||
Equity income - Sunrise Energy
|
922 | ||||||
Other income (loss) (Note 8)
|
2,305 | (772 | ) | ||||
157,354 | 129,236 | ||||||
Costs and expenses:
|
|||||||
Operating costs and expenses
|
77,094 | 72,527 | |||||
DD&A
|
14,096 | 11,818 | |||||
Coal exploration costs
|
1,132 | 780 | |||||
SG&A
|
7,004 | 5,556 | |||||
Interest
|
1,288 | 1,926 | |||||
100,614 | 92,607 | ||||||
Income before income taxes
|
56,740 | 36,629 | |||||
Less income taxes:
|
|||||||
Current
|
7,266 | 885 | |||||
Deferred
|
13,665 | 13,369 | |||||
20,931 | 14,254 | ||||||
Net income
|
$ | 35,809 | $ | 22,375 | |||
Net income per share:
|
|||||||
Basic
|
$ | 1.27 | $ | .81 | |||
Diluted
|
$ | 1.25 | $ | .78 | |||
Weighted average shares outstanding:
|
|||||||
Basic
|
28,135 | 27,790 | |||||
Diluted
|
28,694 | 28,571 |
2011
|
2010
|
||||||
Operating activities:
|
|||||||
Net income
|
$ | 35,809 | $ | 22,375 | |||
Gain on sale
|
(10,653 | ) | |||||
Deferred income taxes
|
13,665 | 13,369 | |||||
Equity income – Savoy and Sunrise Energy
|
(6,398 | ) | (1,005 | ) | |||
Cash distributions from Savoy
|
1,060 | ||||||
DD&A
|
14,096 | 11,818 | |||||
Change in fair value of interest rate swaps
|
(632 | ) | (712 | ) | |||
Stock-based compensation
|
2,331 | 2,194 | |||||
Other
|
576 | ||||||
Taxes paid on vesting of RSUs
|
(1,661 | ) | (746 | ) | |||
Change in current assets and liabilities:
|
|||||||
Accounts receivable
|
221 | (163 | ) | ||||
Coal inventory
|
236 | 66 | |||||
Income tax accounts
|
8,978 | (2,807 | ) | ||||
Accounts payable and accrued liabilities
|
1,751 | 1,415 | |||||
Other
|
1,341 | (259 | ) | ||||
Cash provided by operating activities
|
60,720 | 45,545 | |||||
Investing activities:
|
|||||||
Proceeds from sale of unproved oil and gas properties
|
13,195 | ||||||
Capital expenditures for coal properties
|
(32,995 | ) | (34,714 | ) | |||
Capital expenditures for unproved oil and gas properties
|
(1,710 | ) | (915 | ) | |||
Investment in Sunrise Energy
|
(2,375 | ) | |||||
Investment in Savoy
|
(453 | ) | |||||
Change in CDs
|
1,291 | 2,167 | |||||
Marketable securities
|
(2,257 | ) | |||||
Other
|
1,284 | (752 | ) | ||||
Cash used in investing activities
|
(21,192 | ) | (37,042 | ) | |||
Financing activities:
|
|||||||
Payments of bank debt
|
(10,000 | ) | (10,000 | ) | |||
Dividends
|
(3,505 | ) | (2,937 | ) | |||
Stock option buy-out
|
(679 | ) | |||||
Tax benefit from stock-based compensation
|
1,242 | 327 | |||||
Other
|
(163 | ) | |||||
Cash used in financing activities
|
(12,263 | ) | (13,452 | ) | |||
Increase (decrease) in cash and cash equivalents
|
27,265 | (4,949 | ) | ||||
Cash and cash equivalents, beginning of year
|
10,277 | 15,226 | |||||
Cash and cash equivalents, end of year
|
$ | 37,542 | $ | 10,277 | |||
Cash paid for interest
|
$ | 1,508 | $ | 2,255 | |||
Cash paid for income taxes | $ | 100 | $ | 4,400 | |||
Changes in accounts payable for coal properties
|
$ | (358 | ) | $ | (2,088 | ) |
Shares
|
Common Stock
|
Additional Paid-in Capital
|
Retained Earnings
|
AOCI*
|
Total
|
|||||||||||||
Balance January 1, 2010
|
27,782 | $ | 277 | $ | 85,245 | $ | 23,105 | $ | 108,627 | |||||||||
Stock issued to board member for director services
|
9 | 1 | 99 | 100 | ||||||||||||||
Stock-based compensation
|
2,194 | 2,194 | ||||||||||||||||
Stock issued on vesting of RSUs
|
133 | 1 | 1 | |||||||||||||||
Taxes paid on vesting of RSUs
|
(746 | ) | (746 | ) | ||||||||||||||
Tax benefit from stock-based compensation
|
327 | 327 | ||||||||||||||||
Stock option buy out for cash
|
(679 | ) | (679 | ) | ||||||||||||||
Reduction in deferred tax asset resulting from Sunrise acquisition
|
(2,367 | ) | (2,367 | ) | ||||||||||||||
Cash distributions to former noncontrolling interests for personal income taxes
|
(162 | ) | (162 | ) | ||||||||||||||
Dividends
|
(2,937 | ) | (2,937 | ) | ||||||||||||||
Net income
|
22,375 | 22,375 | ||||||||||||||||
Balance December 31, 2010
|
27,924 | $ | 279 | $ | 84,073 | $ | 42,381 | $ | 126,733 | |||||||||
Stock issued to board member for director services
|
11 | 100 | 100 | |||||||||||||||
Stock-based compensation
|
2,231 | 2,231 | ||||||||||||||||
Exercise of employee stock options for shares
|
181 | 1 | (1 | ) | ||||||||||||||
Taxes paid for shares issued to employees
|
(41 | ) | (469 | ) | (469 | ) | ||||||||||||
Stock issued on vesting of RSUs
|
345 | 3 | 3 | |||||||||||||||
Taxes paid on vesting of RSUs
|
(111 | ) | (1,192 | ) | (1,192 | ) | ||||||||||||
Tax benefit from stock-based compensation
|
1,242 | 1,242 | ||||||||||||||||
Increase in value of marketable securities available for sale, net of taxes
|
$ | 41 | 41 | |||||||||||||||
Dividends
|
(3,505 | ) | (3,505 | ) | ||||||||||||||
Net income
|
35,809 | 35,809 | ||||||||||||||||
Balance December 31, 2011
|
28,309 | $ | 283 | $ | 85,984 | $ | 74,685 | $ | 41 | $ | 160,993 |
Net income
|
$35,809
|
||
OCI
|
41
|
||
Comprehensive income
|
$35,850
|
*Accumulated Other Comprehensive Income
|
2011
|
2010
|
||||||
Balance beginning of year
|
$ | 1,150 | $ | 922 | |||
Accretion
|
76 | 66 | |||||
Change in cost estimate
|
|||||||
Additions
|
1,050 | 162 | |||||
Balance end of year
|
$ | 2,276 | $ | 1,150 | |||
2011 |
2010
|
||||||
Expected amount
|
$ | 19,859 | $ | 12,820 | |||
State income taxes, net of federal benefit
|
2,950 | 1,808 | |||||
Other
|
(1,878 | ) | (374 | ) | |||
$ | 20,931 | $ | 14,254 |
2011
|
2010
|
||||||
Long-term deferred tax assets:
|
|||||||
AMT credit carryforwards
|
$ | 1,137 | $ | 1,162 | |||
Stock-based compensation
|
596 | 113 | |||||
Investment in Savoy
|
960 | 1,575 | |||||
Oil and gas properties
|
1,540 | 873 | |||||
Net long-term deferred tax assets
|
4,233 | 3,723 | |||||
Long-term deferred tax liabilities:
|
|||||||
Coal properties
|
(35,333 | ) | (21,158 | ) | |||
Net deferred tax liability
|
$ | 31,100 | $ | 17,435 |
2011
|
2010
|
||||||
Current assets
|
$ | 16,200 | $ | 9,103 | |||
Oil and gas PP&E, net
|
17,973 | 15,978 | |||||
Other | 2,152 | 2,048 | |||||
$ | 36,325 | $ | 27,129 | ||||
Total liabilities
|
$ | 9,469 | $ | 10,004 | |||
Partners' capital
|
26,856 | 17,125 | |||||
$ | 36,325 | $ | 27,129 |
2011
|
2010
|
||||||
Revenue
|
$ | 31,997 | $ | 14,447 | |||
Gain on sale of unproved properties
|
2,225 | ||||||
Expenses
|
(19,897 | ) | (14,438 | ) | |||
Net income
|
$ | 12,100 | $ | 2,234 | |||
2011
|
||||
Unproved property acquisition
|
$ | 1,202 | ||
Development
|
1,024 | |||
Exploration
|
3,990 | |||
Total
|
$ | 6,216 |
Oil
(Bbls)
|
NGLs
(Bbls)
|
Natural Gas
(Mcf)
|
||||||||||
January 1, 2011
|
350 | 6 | 356 | |||||||||
Extensions and discoveries
|
509 | 21 | 689 | |||||||||
Production
|
(128 | ) | (6 | ) | (61 | ) | ||||||
Revisions to previous estimates
|
138 | 22 | 143 | |||||||||
December 31, 2011
|
869 | 43 | 1,127 | |||||||||
Proved developed reserves
|
361 | 22 | 438 | |||||||||
Proved undeveloped reserves
|
508 | 21 | 689 |
Proved
Developed
|
PUDs
|
Total
Proved
|
||||||||||
Future cash flows:
|
||||||||||||
Oil
|
$ | 33,760 | $ | 47,619 | $ | 81,379 | ||||||
NGLs
|
1,452 | 1,435 | 2,887 | |||||||||
Gas
|
2,170 | 3,199 | 5,369 | |||||||||
Total cash flows
|
37,382 | 52,253 | 89,635 | |||||||||
Future production costs
|
(10,866 | ) | (12,122 | ) | (22,988 | ) | ||||||
Future development costs
|
(385 | ) | (5,196 | ) | (5,581 | ) | ||||||
Future income tax (none since Savoy is a pass-through entity for income tax purposes)
|
0 | 0 | 0 | |||||||||
Future net cash flows
|
26,131 | 34,935 | 61,066 | |||||||||
10% annual discount for estimated timing of cash flows
|
(6,106 | ) | (10,870 | ) | (16,976 | ) | ||||||
Standardized measure of discounted future net cash flows
|
$ | 20,025 | $ | 24,065 | $ | 44,090 | ||||||
Beginning of year
|
$ | 15,496 | ||
Sale of oil and gas produced, net of production costs
|
(10,374 | ) | ||
Net changes in prices and production costs
|
4,806 | |||
Extension, discoveries and improved recoveries
|
24,066 | |||
Revisions of previous quantity estimates
|
8,547 | |||
Accretion of discount
|
1,549 | |||
End of year
|
$ | 44,090 | ||
Average wellhead prices
|
||||
Oil (per Bbl)
|
$ | 93.60 | ||
NGLs (per Bbl)
|
$ | 66.95 | ||
Gas (per Mcf)
|
$ | 4.76 |
2011
|
||||
Current assets
|
$ | 1,916 | ||
Oil and gas properties, net
|
6,236 | |||
$ | 8,152 | |||
Total liabilities
|
$ | 1,558 | ||
Members' capital
|
6,594 | |||
$ | 8,152 |
2011
|
||||
Revenue
|
$ | 3,951 | ||
Expenses
|
(2,107 | ) | ||
Net income
|
$ | 1,844 |
2011
|
2010
|
||||||||
Long-term assets:
|
|||||||||
Oil and gas properties
|
$ | 336 | $ | 1,744 | |||||
Advance coal royalties
|
3,205 | 1,863 | |||||||
Deferred financing costs, net
|
295 | 616 | |||||||
Marketable equity securities available for sale (restricted)*
|
2,326 | ||||||||
Miscellaneous
|
132 | 725 | |||||||
$ | 6,294 | $ | 4,948 | ||||||
*Held by Sunrise Indemnity, Inc., our wholly-owned captive insurance company.
|
|||||||||
Other income (loss):
|
|||||||||
MSHA reimbursements**
|
$ | 1,900 | |||||||
Exploration and dry hole costs
|
(677 | ) | $ | (1,302 | ) | ||||
Oil and gas sales, net of expenses
|
231 | 172 | |||||||
Miscellaneous
|
851 | 358 | |||||||
$ | 2,305 | $ | (772 | ) |
3.1
|
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009. (1)
|
3.2
|
By-laws of Hallador Energy Company, effective December 24, 2009 (1)
|
10.1
|
Purchase and Sale Agreement dated December 31, 2005 between Hallador Petroleum Company, as Purchaser and Yorktown Energy Partners II, L.P., as Seller relating to the purchase and sale of limited partnership interests in Savoy Energy Limited Partnership (2)
|
10.2
|
Letter of Intent dated January 5, 2006 between Hallador Petroleum Company and Sunrise Coal, LLC (3)
|
10.3
|
Subscription Agreement - by and between Hallador Petroleum Company and Yorktown Energy Partners VI, L.P., et al dated February 22, 2006. (2)
|
10.4
|
Subscription Agreements - by and between Hallador Petroleum Company and Hallador Alternative Assets Fund LLC, et al dated February 14, 2006. (3)
|
10.5
|
Continuing Guaranty, dated April 19, 2006, by Hallador Petroleum Company in favor of Old National Bank (6)
|
10.6
|
Collateral Assignment of Hallador Master Purchase/Sale Agreement, dated April 19, 2006, among Hallador Petroleum Company, Hallador Petroleum, LLLP, and Hallador Production Company and Old National Bank (6)
|
10.7
|
Reimbursement Agreement, dated April 19, 2006, between Hallador Petroleum Company and Sunrise Coal, LLC (6)
|
10.8
|
Membership Interest Purchase Agreement dated July 31, 2006 by and between Hallador Petroleum Company and Sunrise Coal, LLC. (7)
|
10.9
|
Subscription Agreements - by and between Hallador Petroleum Company and Yorktown Energy Partners VII, L.P., et al dated October 5, 2007 (7)
|
10.10
|
Purchase and Sale Agreement dated effective as of October 5, 2007 between Hallador Petroleum Company, as Purchaser and Savoy Energy Limited Partnership, as Seller (11)
|
10.11
|
First Amendment to Credit Agreement, Waiver and Ratification of Loan Documents dated June 28, 2007 by and between Sunrise Coal, LLC, Hallador Petroleum Company and Old National Bank (9)
|
10.12
|
Amended and Restated Continuing Guaranty, dated as of June 28, 2007, between Hallador Petroleum Company, Sunrise Coal, LLC, and Old National Bank. (10)
|
10.13
|
Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated as of June 28, 2007, between Hallador Petroleum Company and Victor P. Stabio(10)*
|
10.14
|
Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated as of July 19, 2007, between Hallador Petroleum Company and Brent Bilsland(11)*
|
10.15
|
Hallador Petroleum Company 2008 Restricted Stock Unit Plan. (12)*
|
10.16
|
Form of Amended and Restated Purchase and Sale Agreement dated July 24, 2008 to purchase additional minority interest from Sunrise Coal, LLC's minority members (13)
|
10.17
|
Form of Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated July 24, 2008 (13)*
|
10.18
|
Credit Agreement dated December 12, 2008, by and among Sunrise Coal, LLC, Hallador Petroleum Company as a Guarantor, PNC Bank, National Association as administrative agent for the lenders, and the other lenders party thereto. (14)
|
10.19
|
Continuing Agreement of Guaranty and Suretyship dated December 12, 2008, by Hallador Petroleum Company in favor of PNC Bank, National Association (14)
|
10.20
|
Amended and Restated Promissory Note dated December 12, 2008, in the principal amount of $13,000,000, issued by Sunrise Coal, LLC in favor of Hallador Petroleum Company (14)
|
10.21
|
Form of Purchase and Sale Agreement dated September 16, 2009 (15)
|
10.22
|
Form of Subscription Agreement dated September 15, 2009 (15)
|
10.23
|
Form of Hallador Petroleum Company Restricted Stock Unit Issuance Agreement. (15)*
|
10.24
|
2009 Stock Bonus Plan(16)*
|
14
|
Code Of Ethics For Senior Financial Officers. (5)
|
21.1
|
List of Subsidiaries (17)
|
23.1
|
Consent of EKSH, our auditors (17)
|
23.2
|
Consent of Netherland, Sewell & Associates, Inc. (17)
|
31
|
SOX 302 Certifications (17)
|
32
|
SOX 906 Certification (17)
|
95
|
Mine Safety Disclosure (17)
|
99
|
Report of Netherland, Sewell & Associates, Inc. (17)
|
(1) IBR to Form 8-K dated December 31, 2009.
|
(10) IBR to Form 8-K dated July 2, 2007.
|
(2) IBR to Form 8-K dated January 3, 2006.
|
(11) IBR to Form 10-KSB dated December 31, 2007.
|
(3 ) IBR to Form 8-K dated January 6, 2006.
|
(12) IBR to March 31, 2007 Form 10-Q.
|
(4) IBR to Form 8-K dated February 27, 2006.
|
(13) IBR to Form 8-K dated July 24, 2008.
|
(5) IBR to the 2005 Form 10-KSB.
|
(14) IBR to Form 8-K dated December 12, 2008.
|
(6) IBR to Form 8-K dated April 25, 2006.
|
(15) IBR to Form 8-K dated September 18, 2009.
|
(7) IBR to Form 8-K dated August 1, 2006.
|
(16) IBR to Form S-8 dated December 1, 2009.
|
(8) IBR to Form 10-QSB dated September 30, 2007.
|
(17) Filed herewith.
|
(9) IBR to Form 10-QSB dated June 30, 2007.
|
|
* Management contracts or compensatory plans.
|
|
HALLADOR ENERGY COMPANY
|
||
Date: March 2, 2012
|
/s/W. ANDERSON BISHOP
|
|
W. Anderson Bishop, CFO and CAO
|
/s/DAVID HARDIE
|
||
David Hardie
|
Chairman
|
March 2, 2012
|
/s/VICTOR P. STABIO
|
||
Victor P. Stabio
|
CEO and Director
|
March 2, 2012
|
/s/BRYAN LAWRENCE
|
||
Bryan Lawrence
|
Director
|
March 2, 2012
|
/s/BRENT BILSLAND
|
||
Brent Bilsland
|
President and Director
|
March 2, 2012
|
/s/JOHN VAN HEUVELEN
|
||
John Van Heuvelen
|
Director
|
March 2, 2012
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||||
By:
|
/s/ C. H. (Scott) Rees, III
|
|||
C. H. (Scott) Rees III, P. E.
|
||||
Chairman and CEO
|
||||
1.
|
I have reviewed this annual report on Form 10-K of Hallador Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
||
March 2, 2012
|
/s/VICTOR P. STABIO
Victor P. Stabio, CEO
|
1.
|
I have reviewed this annual report on Form 10-K of Hallador Energy Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
||
March 2, 2012
|
/s/W.ANDERSON BISHOP
W. Anderson Bishop, CFO
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
March 2, 2012
|
By:
|
/s/VICTOR P. STABIO
Victor P. Stabio, CEO
|
||
/s/W.ANDERSON BISHOP
W. Anderson Bishop, CFO
|
Net Reserves
|
Future Net Revenue ($)
|
|||||||||
Oil
|
NGL
|
Gas
|
Present Worth
|
|||||||
Category
|
(Barrels)
|
(Barrels)
|
(MCF)
|
Total
|
at 10%
|
|||||
Proved Developed Producing
|
771,693
|
46,308
|
839,850
|
55,457,900
|
42,410,000
|
|||||
Proved Developed Non-Producing
|
25,679
|
1,635
|
128,493
|
2,277,800
|
1,834,700
|
|||||
Proved Undeveloped
|
1,123,713
|
47,321
|
1,522,832
|
77,188,200
|
53,171,600
|
|||||
Total Proved
|
1,921,085
|
95,264
|
2,491,175
|
134,923,900
|
97,416,300
|
|
(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.
|
|
(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.
|
|
(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.
|
|
(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 terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
|
(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.
|
|
(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.
|
|
(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.
|
|
(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.
|
|
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.
|
|
(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.
|
(1) Summary of Significant Accounting Policies
|
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2011
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies [Text Block] |
(1) Summary
of Significant Accounting Policies
Basis
of Presentation and Consolidation
The
consolidated financial statements include the accounts of
Hallador Energy Company (the "Company") and its
wholly-owned subsidiary Sunrise Coal, LLC
(Sunrise). All significant intercompany accounts
and transactions have been eliminated. We are engaged
in the production of steam coal from an underground mine
located in western Indiana. We own a 45% equity
interest in Savoy Energy L.P., a private oil and gas
company which has operations in Michigan and a 50% interest
in Sunrise Energy LLC, a private entity engaged in natural
gas operations in the same vicinity as our coal
mine. We purchased our interest in Sunrise
Energy in December 2010.
Reclassification
To
maintain consistency and comparability, certain amounts in
the 2010 financial statements have been reclassified to
conform to current year presentation.
Inventories
Coal
and supplies inventories are valued at the lower of average
cost or market. Coal inventory costs include labor,
supplies, equipment costs and overhead.
Advance
Royalties
Coal
leases that require minimum annual or advance payments and
are recoverable from future production are generally
deferred and charged to expense as the coal is subsequently
produced.
Coal
Properties
Coal
properties are recorded at cost. Interest costs applicable
to major asset additions are capitalized during the
construction period. Expenditures that extend the useful
lives or increase the productivity of the assets are
capitalized. The cost of maintenance and repairs that do
not extend the useful lives or increase the productivity of
the assets are expensed as incurred. Other than
land and underground mining equipment, coal properties are
depreciated using the units-of-production method over the
estimated recoverable reserves. Surface and underground
mining equipment is depreciated using estimated useful
lives ranging from five to twenty years.
If
facts and circumstances suggest that a long-lived asset may
be impaired, the carrying value is reviewed for
recoverability. If this review indicates that the carrying
value of the asset will not be recoverable through
estimated undiscounted future net cash flows related to the
asset over its remaining life, then an impairment loss is
recognized by reducing the carrying value of the asset to
its estimated fair value.
Mine
Development
Costs
of developing new coal mines, including asset retirement
obligation assets, or significantly expanding the capacity
of existing mines, are capitalized and amortized using the
units-of-production method over estimated recoverable
(proved and probable) reserves.
Asset
Retirement Obligations (ARO) -
Reclamation
At
the time they are incurred, legal obligations associated
with the retirement of long-lived assets are reflected at
their estimated fair value, with a corresponding charge to
mine development. Obligations are typically incurred when
we commence development of underground mines, and include
reclamation of support facilities, refuse areas and slurry
ponds.
Obligations
are reflected at the present value of their future cash
flows. We reflect accretion of the obligations
for the period from the date they are incurred through the
date they are extinguished. The asset retirement obligation
assets are amortized using the units-of-production method
over estimated recoverable (proved and probable)
reserves. We are using a 6% discount
rate.
Federal
and state laws require that mines be reclaimed to their
previous condition in accordance with specific standards
and approved reclamation plans, as outlined in mining
permits. Activities include reclamation of pit
and support acreage at surface mines, sealing portals at
underground mines, and reclamation of refuse areas and
slurry ponds.
We
assess our ARO at least annually and reflect revisions for
permit changes, changes in our estimated reclamation costs
and changes in the estimated timing of such costs.
The
table below (in thousands) reflects the changes to our
ARO:
Statement
of Cash Flows
Cash
equivalents include investments with maturities when
purchased of three months or less.
Income
Taxes
Income
taxes are provided based on the liability method of
accounting. The provision for income taxes is based
on pretax financial income. Deferred tax assets and
liabilities are recognized for the future expected tax
consequences of temporary differences between income tax
and financial reporting and principally relate to
differences in the tax basis of assets and liabilities and
their reported amounts, using enacted tax rates in effect
for the year in which differences are expected to
reverse.
Earnings
per Share
Basic
earnings per share are computed on the basis of the
weighted average number of shares of common stock
outstanding during the period. Diluted earnings per share
is computed on the basis of the weighted average number of
shares of common stock plus the effect of dilutive
potential common shares outstanding during the period using
the treasury stock method. Dilutive potential common shares
include outstanding stock options and restricted stock
units.
Use
of Estimates in the Preparation of Financial
Statements
The
preparation of financial statements in conformity with
generally accepted accounting principles requires us to
make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenue
and expenses during the reporting period. Actual
amounts could differ from those estimates. The
most significant estimates included in the preparation of
the financial statements are related to deferred income tax
assets and liabilities and coal reserves.
Revenue
Recognition
We
recognize revenue from coal sales at the time risk of loss
passes to the customer at contracted amounts and amounts
are deemed collectible.
Long-term
Contracts
We
evaluate each of our contracts to determine whether they
meet the definition of a derivative and they do
not. As of December 31, 2011, we are committed
to supply to three customers about 7 million tons of coal
during the next three years. These contracts represent
about 15% of our recoverable reserves for the Carlisle
mine. During 2011 and 2010, three of our
customers accounted for 90% or more of our sales: for 2011
one customer accounted for 43%, the second for 29%, and the
third for 17%; for 2010 one customer accounted for 45%, the
second for 36%, and the third for 17%. We are paid every
two to four weeks and do not expect any credit
losses.
Stock-based
Compensation
Stock-based
compensation is measured at the grant date based on the
fair value of the award and is recognized as expense over
the applicable vesting period of the stock award (generally
three to four years) using the straight-line method.
New
Accounting Pronouncements
None
of the recent FASB pronouncements will have any material
effect on us.
Subsequent
Events
We
have evaluated all subsequent events through the date the
financial statements were issued. No material recognized or
non-recognizable subsequent events were identified.
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