þ
|
Annual report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year Ended December 31, 2011
|
¨
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Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from
___________
to
___________
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U.S. ENERGY CORP.
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(Exact Name of Company as Specified in its Charter)
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Wyoming
|
83-0205516
|
|
(State or other jurisdiction of
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(I.R.S. Employer
|
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incorporation or organization)
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Identification No.)
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877 North 8th West, Riverton, WY
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82501
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(Address of principal executive offices)
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(Zip Code)
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|
Registrant's telephone number, including area code:
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(307) 856-9271
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Securities registered pursuant to Section 12(b) of the Act:
None
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Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.01 par value
|
Class
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Outstanding at March 9, 2012
|
|
Common stock, $.01 par value
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27,449,075
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5
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PART I
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7
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ITEM 1. BUSINESS
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7
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7
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8
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8
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8
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8
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15
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ITEM 1 A. RISK FACTORS
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16
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16
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29
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30
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30
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45
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47
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PART II
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47
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47
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49
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS
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51
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51
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51
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56
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63
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63
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66
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68
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69
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72
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72
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73
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73
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75
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122
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122
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125
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PART III
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125
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125
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125
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125
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125
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126
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PART IV
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129
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129
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131
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·
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planned capital expenditures for oil and gas exploration;
|
·
|
cash expected to be available for continued work programs;
|
·
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recovered volumes and values of oil and gas approximating third-party estimates of oil and gas reserves;
|
·
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anticipated increases in oil and gas production;
|
·
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drilling and completion activities in the Williston Basin in North Dakota and the Eagle Ford shale in Texas and other areas;
|
·
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timing for drilling of additional wells;
|
·
|
expected spacing and the number of wells to be drilled with our industry partners including Brigham Exploration Company (“Brigham”), Zavanna, LLC (“Zavanna”), and Murex Petroleum Corporation (“Murex”), in the Bakken/Three Forks formations, Crimson Exploration Operating, Inc. (“Crimson”), in the Eagle Ford shale, and Houston Energy, L.P. (“Houston Energy”), Southern Resources Company (“Southern Resources”), PetroQuest Energy, LLC (“PetroQuest”) and Cirque Resources LP (“Cirque”) in other areas;
|
·
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when “Pooled Payout” or similar thresholds will be reached for the purposes of our agreements with Brigham and Zavanna;
|
·
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expected working and net revenue interests, and costs of wells, relating to the drilling programs with our partners;
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·
|
actual decline rates for producing wells in the Bakken/Three Forks and Eagle Ford formations;
|
·
|
submission of a plan of operations to the U.S. Forest Service and approval of such plan in connection with the Mt. Emmons molybdenum project (“Mt. Emmons Project”) and the expected length of time to permit and develop the Mt. Emmons Project;
|
·
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expected time to receive a return on investment from the geothermal prospects;
|
·
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future cash flows and borrowings;
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·
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pursuit of potential acquisition opportunities;
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·
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anticipated business activities in the Gillette, Wyoming area and their impact on our multi-family housing complex;
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·
|
our expected financial position;
|
·
|
other plans and objectives for future operations.
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·
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our ability to obtain sufficient cash flow from operations, borrowing and/or other sources to fully develop our undeveloped acreage positions;
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·
|
volatility in oil and natural gas prices, including potentially depressed natural gas prices and/or declines in oil prices, which would have a negative impact on operating cash flow and could require ceiling test write-downs on our oil and gas assets, and which could adversely impact the borrowing base available under our credit facility with BNP Paribas;
|
·
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the possibility that the oil and gas industry may be subject to new adverse regulatory or legislative actions (including changes to existing tax rules and regulations and changes in environmental regulation);
|
·
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the general risks of exploration and development activities, including the failure to find oil and natural gas in sufficient commercial quantities to provide a reasonable expectation of a return on investment;
|
·
|
future oil and natural gas production rates, and/or the ultimate recoverability of reserves, falling below estimates;
|
·
|
the ability to replace oil and natural gas reserves as they deplete from production;
|
·
|
environmental risks;
|
·
|
availability of pipeline capacity and other means of transporting crude oil and natural gas production;
|
·
|
competition in leasing new acreage and for drilling programs with operating companies, resulting in less favorable terms or fewer opportunities being available;
|
·
|
higher drilling and completion costs related to competition for drilling and completion services and shortages of labor and materials;
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·
|
unanticipated weather events resulting in possible delays of drilling and completions and the interruption of anticipated production streams of hydrocarbons, which could impact expenses and revenues, respectively; and
|
·
|
unanticipated downhole mechanical problems, which could result in higher than expected drilling and completion expenses and/or the loss of the wellbore or a portion thereof.
|
·
|
the ability to obtain permits required to initiate mining and processing operations;
|
·
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completion of a feasibility study based on a comprehensive mine plan, which indicates that the property warrants construction and operation of mine and processing facilities, taking into account projected capital expenditures and operating costs in the context of molybdenum price trends;
|
·
|
the ability to fund the capital expenditures required to build the mine and its infrastructure, and the related processing facilities, after all permits and a favorable feasibility study have been received;
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·
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the ability to find a suitable joint venture partner or raise sufficient capital for the project;
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·
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continued compliance with current environmental regulations and the possibility of new legislation or environmental regulations adverse to the mining industry;
|
·
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molybdenum prices and operating costs staying within the parameters established by the feasibility study;
|
·
|
successfully managing the substantial operating risks attendant to a large scale mining and processing operations; and
|
·
|
compliance and operating costs associated with the wastewater treatment plant.
|
·
|
insufficient demand for apartments in our multi-family apartment project in Gillette, Wyoming (“Remington Village Apartments”) which could impact our ability to sell the property; and
|
·
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inability of the Company to receive the anticipated sales price for Remington Village Apartments.
|
·
|
Estimated proved reserves of 3,195,361 BOE (86% oil and 14% natural gas), with a standardized measure value of $63.2 million and a PV10 of $72.5 million, representing increases of 63%, 42%, and 39% over our reserves, standardized measure and PV10, respectively, as of December 31, 2010.
|
·
|
Gross and net leases of 122,815 and 34,871 acres, respectively. At March 1, 2012, our leases covered 122,815 gross and 29,921 net acres.
|
·
|
Forty-one gross (12.79 net) producing wells (42 gross and 13.06 net at March 1, 2012).
|
·
|
1,212 BOE/D average for 2011.
|
(In thousands)
|
||||||||||||
At December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Standardized measure of discounted net cash flows
|
$ | 62,191 | $ | 44,653 | $ | 19,984 | ||||||
Future income tax expense (discounted)
|
10,346 | 7,420 | 5,776 | |||||||||
PV-10
|
$ | 72,537 | $ | 52,073 | $ | 25,760 | ||||||
·
|
unexpected drilling conditions;
|
·
|
inability to obtain required permits from State and Federal agencies;
|
·
|
inability to obtain, or limitations on, easements from land owners;
|
·
|
adverse weather;
|
·
|
high pressure or irregularities in geologic formations;
|
·
|
equipment failures;
|
·
|
title problems;
|
·
|
fires, explosions, blowouts, cratering, pollution and other environmental risks or accidents;
|
·
|
changes in government regulations;
|
·
|
reductions in commodity prices;
|
·
|
pipeline ruptures; and
|
·
|
unavailability or high cost of equipment and field services and labor.
|
·
|
Initial results from one or more of the oil and gas programs could be marginal but warrant investing in more wells. Dry holes, over-budget exploration costs, low commodity prices, or any combination of these or other adverse factors, could result in production revenues below projections, thus adversely impacting cash expected to be available for continued work in a program, its ultimate returns falling below projections, and a reduction in cash available for investment in other programs.
|
·
|
We are paying the annual costs (approximately $1.8 million) to operate and maintain the water treatment plant at the Mt. Emmons Project, and these costs could increase in the future.
|
·
|
the nature and timing of the operator’s drilling and other activities;
|
·
|
the timing and amount of required capital expenditures;
|
·
|
the operator’s geological and engineering expertise and financial resources;
|
·
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the approval of other participants in drilling wells; and
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·
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the operator’s selection of suitable technology.
|
·
|
the counter-party to the derivative instrument defaults on its contract obligations;
|
·
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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
|
·
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the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies.
|
·
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price swings in the oil and gas commodities markets;
|
·
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price and volume fluctuations in the stock market generally;
|
·
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relatively small amounts of stock trading on any given day;
|
·
|
fluctuations in our financial operating results;
|
·
|
industry trends;
|
·
|
legislative and regulatory changes; and
|
·
|
global economic uncertainty.
|
December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Net proved reserves
|
||||||||||||
Oil (Bbls)
|
||||||||||||
Developed
|
1,884,068 | 1,362,733 | 811,789 | |||||||||
Undeveloped
|
853,930 | 183,713 | -- | |||||||||
Total
|
2,737,998 | 1,546,446 | 811,789 | |||||||||
Natural gas (Mcf)
|
||||||||||||
Developed
|
1,973,453 | 1,996,490 | 1,502,296 | |||||||||
Undeveloped
|
760,595 | 139,286 | -- | |||||||||
Total
|
2,734,048 | 2,135,776 | 1,502,296 | |||||||||
Plant Products (Bbls)
|
||||||||||||
Developed
|
1,688 | 52,532 | 24,031 | |||||||||
Undeveloped
|
-- | -- | -- | |||||||||
Total
|
1,688 | 52,532 | 24,031 | |||||||||
Total proved reserves (BOE)
|
3,195,361 | 1,954,941 | 1,086,203 | |||||||||
(1)
|
Reserve estimates are based on average prices per barrel of oil and per MMbtu of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period. Reserve estimates as of December 31, 2011 are based on prices of $96.19 per barrel of oil and $4.12 per MMbtu of natural gas, in each case adjusted for regional price differentials and other factors.
|
December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Production Volume
|
||||||||||||
Oil (Bbls)
|
300,325 | 303,433 | 80,461 | |||||||||
Natural gas (Mcf)
|
736,261 | 757,905 | 467,691 | |||||||||
Natural gas liquids (Bbls)
|
19,325 | 19,104 | 5,987 | |||||||||
BOE
|
442,360 | 448,855 | 164,397 | |||||||||
Daily Average Production Volume
|
||||||||||||
Oil (Bbls/d)
|
823 | 831 | 220 | |||||||||
Natural gas (Mcf/d)
|
2,017 | 2,076 | 1,281 | |||||||||
Natural gas Liquids (Bbls/d)
|
53 | 52 | 16 | |||||||||
BOE/d
|
1,212 | 1,230 | 450 | |||||||||
Oil Price per Bbl Produced
|
||||||||||||
Realized Price
|
$ | 87.80 | $ | 72.11 | $ | 66.22 | ||||||
Natural Gas Price per Mcf Produced
|
||||||||||||
Realized Price
|
$ | 4.85 | $ | 4.96 | $ | 4.30 | ||||||
Natural Gas Liquids Price per Bbl Produced
|
||||||||||||
Realized Price
|
$ | 52.88 | $ | 47.53 | $ | 40.25 | ||||||
Average Sale Price per BOE
(1)
|
$ | 69.98 | $ | 59.15 | $ | 46.11 | ||||||
Expense per BOE
|
||||||||||||
Production costs
(2)
|
$ | 19.10 | $ | 6.81 | $ | 2.40 | ||||||
Depletion, depreciation and amortization
|
$ | 31.64 | $ | 23.64 | $ | 21.72 |
Years Ended December 31,
|
||||||||||||||||||||||||
2011
|
2010
|
2009
|
||||||||||||||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
Development:
|
||||||||||||||||||||||||
Productive
|
1.0000 | 0.2491 | -- | -- | -- | -- | ||||||||||||||||||
Non-productive
|
-- | -- | -- | -- | -- | -- | ||||||||||||||||||
1.0000 | 0.2491 | -- | -- | -- | -- | |||||||||||||||||||
Exploratory:
|
||||||||||||||||||||||||
Productive
|
12.0000 | 2.9817 | 8.0000 | 2.9409 | 8.0000 | 3.3286 | ||||||||||||||||||
Non-productive
|
4.0000 | 0.7954 | 5.0000 | 0.3902 | 2.0000 | 0.5833 | ||||||||||||||||||
16.0000 | 3.7771 | 13.0000 | 3.3311 | 10.0000 | 3.9119 | |||||||||||||||||||
Total
|
17.0000 | 4.0262 | 13.0000 | 3.3311 | 10.0000 | 3.9119 | ||||||||||||||||||
Gross Producing Wells
|
Net Producing Wells
|
Average Working Interest
(1)
|
||||
Oil
|
37.00
|
11.92
|
32.21514%
|
|||
Natural Gas
|
4.00
|
0.87
|
21.63750%
|
|||
Total
(1)
|
41.00
|
12.79
|
31.18317%
|
|||
(1)
|
The average working interest for the twenty-three Williston Basin wells producing at December 31, 2011 is 35.19%; the remaining eighteen wells (Texas and Louisiana) have an average working interest of 26.07%.
|
Developed
|
Undeveloped
|
Total
|
||||||||||||||||||||||
AREA
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||||||||
Williston Basin
|
||||||||||||||||||||||||
Rough Rider Prospect
|
19,200 | 1,175 | -- | -- | 19,200 | 1,175 | ||||||||||||||||||
Yellowstone and SEHR Prospects
|
6,400 | 1,186 | 29,440 | 5,414 | 35,840 | 6,600 | ||||||||||||||||||
Wolverine Prospect, Daniels County, MT
|
-- | -- | 29,664 | 18,690 | 29,664 | 18,690 | ||||||||||||||||||
Southeast Texas and Louisiana
|
4,414 | 978 | 12,734 | 845 | 17,148 | 1,823 | ||||||||||||||||||
Eagle Ford/Austin Chalk
|
||||||||||||||||||||||||
Leona River Prospect
|
-- | -- | 4,675 | 1,402 | 4,675 | 1,402 | ||||||||||||||||||
Booth Tortuga Prospect
|
-- | -- | 9,110 | 2,733 | 9,110 | 2,733 | ||||||||||||||||||
San Joaquin Basin
|
-- | -- | 7,178 | 2,448 | 7,178 | 2,448 | ||||||||||||||||||
TOTAL
|
30,014 | 3,339 | 92,801 | 31,532 | 122,815 | 34,871 | ||||||||||||||||||
Acres
|
Number of Claims
|
|||||||
Patented Claims / Fee Land
|
365 | 25 | ||||||
Unpatented Claims
|
6,075 | 664 | ||||||
Mill Site Claims
|
3,320 | 664 | ||||||
Fee Property
|
160 | n/a | ||||||
9,920 | 1,353 |
·
|
$20,000,000 cash when the Shootaring Canyon Mill has been operating at 60% or more of its design capacity of 750 short tons per day for 60 consecutive days.
|
·
|
$7,500,000 cash on the first delivery (after commercial production has occurred) of mineralized material from any of the claims we sold to a commercial mill (excluding existing ore stockpiles on the properties).
|
·
|
From and after commercial production occurs at the Shootaring Canyon Mill, a production payment royalty (up to but not more than $12,500,000) equal to five percent of (i) the gross value of uranium and vanadium products produced at and sold from the mill; or (ii) mill fees received by the purchaser from third parties for custom milling or tolling arrangements, as applicable. If production is sold to an affiliate of the purchaser, partner, or joint venturer, gross value shall be determined by reference to mining industry publications or data.
|
High
|
Low
|
|||||||
Calendar year ended December 31, 2011
|
||||||||
First quarter ended 03/31/11
|
$ | 6.60 | $ | 5.17 | ||||
Second quarter ended 06/30/11
|
6.49 | 3.88 | ||||||
Third quarter ended 09/30/11
|
4.57 | 2.20 | ||||||
Fourth quarter ended 12/31/11
|
3.40 | 2.05 | ||||||
Calendar year ended December 31, 2010
|
||||||||
First quarter ended 03/31/10
|
$ | 6.76 | $ | 5.14 | ||||
Second quarter ended 06/30/10
|
7.06 | 4.67 | ||||||
Third quarter ended 09/30/10
|
5.43 | 4.01 | ||||||
Fourth quarter ended 12/31/10
|
6.17 | 4.37 |
Plan category
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(a)
|
Weighted-average exercise price of outstanding options, warrants and rights
(b)
|
Number of securities remaining available for future issuance under equity compensaiton plans (excluding securities reflected in column (a))
(c)
|
|||||||||
Equity Compensation plans approved by security holders
|
||||||||||||
2001 Incentive Stock Option Plan
|
2,318,399 | $ | 3.94 | -- | ||||||||
2001 Stock Compensation Plan
|
(1) | (1) | (1) | |||||||||
2008 Stock Option plan for U.S. Energy Corp. Independent Directors and Advisory board members
|
110,000 | $ | 3.05 | 164,099 | ||||||||
Equity compensation plans not approved by security holders
|
-- | $ | -- | -- | ||||||||
Total
|
2,428,399 | $ | 3.90 | 164,099 | ||||||||
(1)
|
Officers of the Company are eligible to receive 5,000 shares of common stock at the beginning of each calendar quarter or 20,000 shares per year each under this plan. The Company pays the taxes on these shares as the Officers have agreed to not pledge, sell or in any other way leverage these shares. The shareholders of the Company approved this plan.
|
(In thousands)
|
||||||||||||||||||||
December 31,
|
||||||||||||||||||||
2011
|
2010
|
2009
|
2008
|
2007
|
||||||||||||||||
Current assets
|
$ | 37,136 | $ | 50,562 | $ | 85,300 | $ | 95,882 | $ | 94,500 | ||||||||||
Current liabilities
|
20,937 | 18,763 | 8,672 | 19,983 | 8,093 | |||||||||||||||
Working capital
|
16,199 | 31,799 | 53,428 | 75,899 | 86,407 | |||||||||||||||
Total assets
|
162,439 | 156,016 | 146,723 | 142,631 | 131,404 | |||||||||||||||
Long-term obligations
(1)
|
13,532 | 1,150 | 973 | 1,870 | 1,283 | |||||||||||||||
Shareholders' equity
|
126,781 | 130,688 | 129,133 | 111,833 | 115,100 |
(In thousands except per share data)
|
||||||||||||||||||||
For the years ended December 31,
|
||||||||||||||||||||
2011
|
2010
|
2009
|
2008
|
2007
|
||||||||||||||||
Operating revenues
|
$ | 30,110 | $ | 24,667 | $ | 7,581 | $ | 691 | $ | 1,174 | ||||||||||
Loss from continuing operations
|
(6,064 | ) | (2,867 | ) | (9,935 | ) | (10,296 | ) | (14,539 | ) | ||||||||||
Other income & expenses
|
131 | 1,549 | (1,331 | ) | (17 | ) | 108,824 | |||||||||||||
Gain (loss) before minority interest, income taxes and discontinued operations
|
(5,933 | ) | (1,318 | ) | (11,266 | ) | (10,313 | ) | 94,285 | |||||||||||
Minority interest in (income) loss of consolidated subsidiaries
|
-- | -- | -- | -- | (3,551 | ) | ||||||||||||||
Benefit from (provision for) income taxes
|
3,755 | 1,860 | 2,562 | 3,326 | (32,367 | ) | ||||||||||||||
Discontinued operations, net of tax
|
(2,629 | ) | (1,314 | ) | 526 | 5,599 | (2,004 | ) | ||||||||||||
Net (loss) income
|
$ | (4,807 | ) | $ | (772 | ) | $ | (8,178 | ) | $ | (1,388 | ) | $ | 56,363 | ||||||
Per share financial data
|
||||||||||||||||||||
Operating revenues
|
$ | 1.11 | $ | 0.92 | $ | 0.35 | $ | 0.03 | $ | 0.06 | ||||||||||
Loss from continuing operations
|
(0.22 | ) | (0.11 | ) | (0.46 | ) | (0.44 | ) | (0.71 | ) | ||||||||||
Other income & expenses
|
-- | 0.06 | (0.06 | ) | -- | 5.32 | ||||||||||||||
Gain (loss) before minority interest, income taxes and discontinued operations
|
(0.22 | ) | (0.05 | ) | (0.52 | ) | (0.44 | ) | 4.61 | |||||||||||
Minority interest in income of consolidated subsidiaries
|
-- | -- | -- | -- | (0.17 | ) | ||||||||||||||
Benefit from (provision for) income taxes
|
0.14 | 0.07 | 0.12 | 0.14 | (1.58 | ) | ||||||||||||||
Discontinued operations, net of tax
|
(0.10 | ) | (0.05 | ) | 0.02 | 0.24 | (0.10 | ) | ||||||||||||
Net (loss) income per share basic
|
$ | (0.18 | ) | $ | (0.03 | ) | $ | (0.38 | ) | $ | (0.06 | ) | $ | 2.76 | ||||||
Net (loss) income per share diluted
|
$ | (0.18 | ) | $ | (0.03 | ) | $ | (0.38 | ) | $ | (0.06 | ) | $ | 2.54 | ||||||
Basic shares outstanding
|
27,238,869 | 26,763,995 | 21,604,959 | 23,274,978 | 20,469,846 | |||||||||||||||
Diluted shares outstanding
|
27,238,869 | 26,763,995 | 21,604,959 | 23,274,978 | 22,189,828 |
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Unproved oil and gas properites
|
$ | 20,007 | $ | 21,620 | ||||
Proved oil and gas properties
|
99,496 | 63,317 | ||||||
Undeveloped mining properties
|
20,739 | 21,077 | ||||||
$ | 140,242 | $ | 106,014 | |||||
(In thousands)
|
||||||||
For the years ending
|
||||||||
December 31, 2011
|
December 31, 2010
|
|||||||
Oil and gas revenues
|
$ | 30,958 | $ | 26,548 | ||||
Realized (loss) from risk management activities
|
(1,974 | ) | (156 | ) | ||||
Unrealized gain (loss) from risk management activities
|
1,126 | (1,725 | ) | |||||
30,110 | 24,667 | |||||||
Operating expenses
|
11,552 | 6,073 | ||||||
Depreciation, depletion and amortization
|
13,997 | 10,610 | ||||||
25,549 | 16,683 | |||||||
Operating income
|
$ | 4,561 | $ | 7,984 | ||||
Year Ended
|
||||||||||||
December 31,
|
Increase
|
|||||||||||
2011
|
2010
|
(Decrease)
|
||||||||||
Production volumes
|
||||||||||||
Oil (Bbls)
|
300,329 | 303,433 | (3,104 | ) | ||||||||
Natural gas (Mcf)
|
736,261 | 757,905 | (21,644 | ) | ||||||||
Natural gas liquids (Bbls)
|
19,325 | 19,104 | 221 | |||||||||
Average sales prices
|
||||||||||||
Oil (per Bbl)
|
$ | 87.80 | $ | 72.11 | $ | 15.69 | ||||||
Natural gas (per Mcf)
|
4.85 | 4.96 | (0.11 | ) | ||||||||
Natural gas liquids (per Bbl)
|
52.88 | 47.53 | 5.36 | |||||||||
Operating revenues (in thousands)
|
||||||||||||
Oil
|
$ | 26,368 | $ | 21,881 | $ | 4,487 | ||||||
Natural gas
|
3,568 | 3,759 | (191 | ) | ||||||||
Natural gas liquids
|
1,022 | 908 | 114 | |||||||||
Total operating revenue
|
30,958 | 26,548 | 4,410 | |||||||||
Lease operating expense
|
(8,450 | ) | (3,056 | ) | (5,394 | ) | ||||||
Production taxes
|
(3,102 | ) | (3,017 | ) | (85 | ) | ||||||
Risk management activities
|
(848 | ) | (1,881 | ) | 1,033 | |||||||
Impairment
|
- | - | - | |||||||||
Income before depreciation, depletion and amortization
|
18,558 | 18,594 | (36 | ) | ||||||||
Depreciation, depletion and amortization
|
(13,997 | ) | (10,610 | ) | (3,387 | ) | ||||||
Income
|
$ | 4,561 | $ | 7,984 | $ | (3,423 | ) | |||||
(In thousands)
|
||||||||
For the years ending December 31,
|
||||||||
2010
|
2009
|
|||||||
Revenues
|
$ | 29,057 | $ | 10,349 | ||||
Realized (loss) from risk management activities
|
(156 | ) | -- | |||||
Unrealized gain from risk management activities
|
(1,725 | ) | -- | |||||
27,176 | 10,349 | |||||||
Operating expenses
|
17,738 | 13,086 | ||||||
Depreciation, depletion and amortization
|
12,130 | 5,066 | ||||||
Impairment
|
1,540 | 1,468 | ||||||
31,408 | 19,620 | |||||||
Operating loss
|
$ | (4,232 | ) | $ | (9,271 | ) | ||
(In thousands)
|
||||||||
For the years ending December 31,
|
||||||||
2010
|
2009
|
|||||||
Oil and gas revenues
|
$ | 26,548 | $ | 7,581 | ||||
Realized (loss) from risk management activities
|
(156 | ) | -- | |||||
Unrealized gain (loss) from risk management activities
|
(1,725 | ) | -- | |||||
24,667 | 7,581 | |||||||
Operating expenses
|
6,073 | 1,085 | ||||||
Depreciation, depletion and amortization
|
10,610 | 3,571 | ||||||
Impairment
|
-- | 1,468 | ||||||
16,683 | 6,124 | |||||||
Operating income
|
$ | 7,984 | $ | 1,457 | ||||
Year Ended
|
||||||||||||
December 31,
|
Increase
|
|||||||||||
2010
|
2009
|
(Decrease)
|
||||||||||
Production volumes
|
||||||||||||
Oil (Bbls)
|
303,433 | 80,461 | 222,972 | |||||||||
Natural gas (Mcf)
|
757,905 | 467,691 | 290,214 | |||||||||
Natural gas liquids (Bbls)
|
19,104 | 5,987 | 13,117 | |||||||||
Average sales prices
|
||||||||||||
Oil (per Bbl)
|
$ | 72.11 | $ | 66.22 | $ | 5.89 | ||||||
Natural gas (per Mcf)
|
4.96 | 4.30 | 0.66 | |||||||||
Natural gas liquids (per Bbl)
|
47.53 | 40.25 | 7.28 | |||||||||
Operating revenues (in thousands)
|
||||||||||||
Oil
|
$ | 21,881 | $ | 5,328 | $ | 16,553 | ||||||
Natural gas
|
3,759 | 2,012 | 1,747 | |||||||||
Natural gas liquids
|
908 | 241 | 667 | |||||||||
Total operating revenue
|
26,548 | 7,581 | 18,967 | |||||||||
Lease operating expense
|
(3,056 | ) | (394 | ) | (2,662 | ) | ||||||
Production taxes
|
(3,017 | ) | (691 | ) | (2,326 | ) | ||||||
Risk management activities
|
(1,881 | ) | - | (1,881 | ) | |||||||
Impairment
|
- | (1,468 | ) | 1,468 | ||||||||
Income before depreciation, depletion and amortization
|
18,594 | 5,028 | 13,566 | |||||||||
Depreciation, depletion and amortization
|
(10,610 | ) | (3,571 | ) | (7,039 | ) | ||||||
Income
|
$ | 7,984 | $ | 1,457 | $ | 6,527 | ||||||
(In thousands)
|
||||||||
For the years ending
|
||||||||
December 31, 2010
|
December 31, 2009
|
|||||||
Real estate revenues
|
$ | 2,509 | $ | 2,768 | ||||
Operating expenses
|
1,271 | 1,059 | ||||||
Interest expense
|
-- | 19 | ||||||
Depreciation, depletion and amortization
|
1,063 | 1,045 | ||||||
Impairment
|
1,540 | -- | ||||||
3,874 | 2,123 | |||||||
Operating income
|
$ | (1,365 | ) | $ | 645 | |||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Current ratio
(1)
|
1.77 to 1
|
2.69 to 1
|
||||||
Working capital
(2)
|
$ | 16,199 | $ | 31,799 | ||||
Total debt
|
$ | 12,400 | $ | 600 | ||||
Total cash and marketable securities less debt
|
$ | 640 | $ | 24,419 | ||||
Total stockholders' equity
|
$ | 126,787 | $ | 130,688 | ||||
Total debt to equity
|
0.10 to 1
|
0.00 to 1
|
||||||
(1)
Current assets divided by current liabilities
|
||||||||
(2)
Current assets less current liabilities
|
Estimated net proved reserves:
|
Bakken / Three Forks
|
Gulf Coast / Texas
|
Total
|
|||||||||
Producing:
|
||||||||||||
Oil (bbls)
|
1,466,406 | 60,934 | 1,527,340 | |||||||||
Gas (Mcf)
|
996,647 | 648,200 | 1,644,847 | |||||||||
NGL (bbls)
|
-- | 219 | 219 | |||||||||
Developed non-producing:
|
||||||||||||
Oil (bbls)
|
326,093 | 30,635 | 356,728 | |||||||||
Gas (Mcf)
|
239,606 | 89,000 | 328,606 | |||||||||
NGL (bbls)
|
-- | 1,469 | 1,469 | |||||||||
Undeveloped:
|
-- | |||||||||||
Oil (bbls)
|
853,930 | -- | 853,930 | |||||||||
Gas (Mcf)
|
760,595 | -- | 760,595 | |||||||||
NGL (bbls)
|
-- | -- | -- | |||||||||
Total (BOE)
|
2,979,237 | 216,124 | 3,195,361 | |||||||||
Future net income before income taxes
|
$ | 130,426 | $ | 8,322 | $ | 138,748 | ||||||
PV-10
|
$ | 66,154 | $ | 6,383 | $ | 72,537 |
(In thousands)
|
||||||||||||
At December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Standardized measure of discounted net cash flows
|
$ | 62,191 | $ | 44,653 | $ | 19,984 | ||||||
Future income tax expense (discounted)
|
10,346 | 7,420 | 5,776 | |||||||||
PV-10
|
$ | 72,537 | $ | 52,073 | $ | 25,760 | ||||||
(In thousands)
|
||||||||||||
For the years ending December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Cash provided by operations
|
$ | 2,567 | $ | 11,395 | $ | 980 | ||||||
Cash provided by (used in) investing activities
|
(17,775 | ) | (39,835 | ) | 17,283 | |||||||
Cash provided by financing activities
|
21,558 | 94 | 5,267 | |||||||||
(In thousands)
|
||||||||||||
For the years ending December 31,
|
||||||||||||
2011 | 2010 | 2009 | ||||||||||
Net increase (decrease) in cash and cash equivalents
|
$ | 7,062 | $ | (27,591 | ) | $ | 24,969 | |||||
Net (redemption) investment in U.S. Treasury investments
|
(17,843 | ) | (4,293 | ) | (29,277 | ) | ||||||
Net change in cash and U.S. Treasuries
|
$ | (10,781 | ) | $ | (31,884 | ) | $ | (4,308 | ) | |||
(In thousands)
|
||||||||||||||||||||
Payments due by period
|
||||||||||||||||||||
Less
|
One to
|
Three to
|
More than
|
|||||||||||||||||
than one
|
Three
|
Five
|
Five
|
|||||||||||||||||
Total
|
Year
|
Years
|
Years
|
Years
|
||||||||||||||||
Debt obligations
|
$ | 22,304 | $ | 481 | $ | 13,153 | $ | 8,670 | $ | -- | ||||||||||
Executive retirement
|
946 | 125 | 327 | 163 | 331 | |||||||||||||||
Asset retirement obligation
|
510 | 46 | 23 | 14 | 427 | |||||||||||||||
Totals
|
$ | 23,760 | $ | 652 | $ | 13,503 | $ | 8,847 | $ | 758 | ||||||||||
Quantity
|
|||||||||||
Settlement Period
|
Counterparty
|
Basis
|
(Bbl/d)
|
Strike Price
|
|||||||
Crude Oil Costless Collar
|
|||||||||||
10/01/11 - 09/30/12
|
BNP Parabis
|
WTI
|
400 |
Put:
|
$ | 80.00 | |||||
Call:
|
$ | 99.00 | |||||||||
Crude Oil Costless Collar
|
|||||||||||
01/01/12 - 12/31/12
|
BNP Parabis
|
WTI
|
200 |
Put:
|
$ | 90.00 | |||||
Call:
|
$ | 106.50 |
Quantity
|
|||||||||||
Settlement Period
|
Counterparty
|
Basis
|
(Bbl/d)
|
Strike Price
|
|||||||
Crude Oil Costless Collar
|
|||||||||||
10/01/12 - 09/30/13
|
BNP Parabis
|
WTI
|
200 |
Put:
|
$ | 95.00 | |||||
Call:
|
$ | 116.60 |
As of December 31, 2011
|
||||||||||
(in thousands)
|
||||||||||
Derivative Assets
|
Derivative Liabilities
|
|||||||||
Balance Sheet
|
Fair
|
Balance Sheet
|
Fair
|
|||||||
Classification
|
Value
|
Classification
|
Value
|
|||||||
Crude oil costless collars
|
Current Asset
|
$ | 3 |
Current Liability
|
$ | 601 | ||||
Page
|
|
Report of Independent Registered Public Accounting Firm
|
76
|
Financial Statements
|
|
Consolidated Balance Sheets as of December 31, 2011 and 2010
|
77
|
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009
|
79
|
Statement of Stockholders’ Equity and Comprehensive Income
|
81
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009
|
84
|
Notes to Consolidated Financial Statements
|
86
|
U.S. ENERGY CORP.
|
||||||||
CONSOLIDATED BALANCE SHEETS
|
||||||||
ASSETS
|
||||||||
(In thousands, except shares)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$ | 12,874 | $ | 5,812 | ||||
Marketable securities
|
||||||||
Held to maturity - treasuries
|
-- | 17,843 | ||||||
Available for sale securities
|
166 | 1,364 | ||||||
Accounts receivable
|
||||||||
Trade
|
5,496 | 3,890 | ||||||
Reimbursable project costs
|
-- | 114 | ||||||
Income taxes
|
113 | 104 | ||||||
Commodity risk management asset
|
3 | -- | ||||||
Assets held for sale
|
18,132 | 20,979 | ||||||
Other current assets
|
352 | 456 | ||||||
Total current assets
|
37,136 | 50,562 | ||||||
Investment
|
2,623 | 2,834 | ||||||
Properties and equipment
|
||||||||
Oil & gas properties under full cost method,
|
||||||||
net of $28,561 and $14,563 accumulated
|
||||||||
depletion, depreciation and amortization
|
90,942 | 70,374 | ||||||
Undeveloped mining claims
|
20,739 | 21,077 | ||||||
Property, plant and equipment, net
|
9,196 | 9,336 | ||||||
Net properties and equipment
|
120,877 | 100,787 | ||||||
Other assets
|
1,803 | 1,833 | ||||||
Total assets
|
$ | 162,439 | $ | 156,016 | ||||
U.S. ENERGY CORP.
|
||||||||
CONSOLIDATED BALANCE SHEETS
|
||||||||
LIABILITIES AND SHAREHOLDERS' EQUITY
|
||||||||
(In thousands, except shares)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Current liabilities:
|
||||||||
Accounts payable
|
$ | 9,370 | $ | 14,830 | ||||
Accrued compensation
|
501 | 1,669 | ||||||
Commodity risk management liability
|
601 | 1,725 | ||||||
Current portion of debt
|
200 | 200 | ||||||
Liabilities held for sale
|
10,241 | 323 | ||||||
Other current liabilities
|
24 | 16 | ||||||
Total current liabilities
|
20,937 | 18,763 | ||||||
Long-term debt, net of current portion
|
12,200 | 400 | ||||||
Deferred tax liability
|
1,189 | 5,015 | ||||||
Asset retirement obligations
|
510 | 303 | ||||||
Other accrued liabilities
|
822 | 847 | ||||||
Commitment and contigencies (Note N)
|
-- | -- | ||||||
Shareholders' equity
|
||||||||
Common stock, $.01 par value; unlimited shares
|
||||||||
authorized; 27,409,908 and 27,068,610
|
||||||||
shares issued, respectively
|
274 | 271 | ||||||
Additional paid-in capital
|
122,523 | 121,062 | ||||||
Accumulated surplus
|
3,906 | 8,713 | ||||||
Unrealized gain on marketable securities
|
78 | 642 | ||||||
Total shareholders' equity
|
126,781 | 130,688 | ||||||
Total liabilities and shareholders' equity
|
$ | 162,439 | $ | 156,016 | ||||
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS
|
||||||||||||
(In thousands except per share data)
|
||||||||||||
Years ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Operating revenues:
|
||||||||||||
Oil, gas, and NGL production revenue
|
$ | 30,958 | $ | 26,548 | $ | 7,581 | ||||||
Realized (loss) on risk management activities
|
(1,974 | ) | (156 | ) | -- | |||||||
Unrealized gain/(loss)on risk management activities
|
1,126 | (1,725 | ) | -- | ||||||||
30,110 | 24,667 | 7,581 | ||||||||||
Operating expenses:
|
||||||||||||
Oil and gas
|
11,552 | 6,073 | 3,611 | |||||||||
Oil and gas depreciation, depletion and amortization
|
13,997 | 10,610 | 1,045 | |||||||||
Impairment of oil and gas properties
|
-- | -- | 1,468 | |||||||||
Water treatment plant
|
1,878 | 1,793 | 1,636 | |||||||||
Mineral holding costs
|
486 | 85 | 323 | |||||||||
General and administrative
|
8,261 | 8,973 | 9,433 | |||||||||
36,174 | 27,534 | 17,516 | ||||||||||
Loss from operations
|
(6,064 | ) | (2,867 | ) | (9,935 | ) | ||||||
Other income and expenses:
|
||||||||||||
Gain/(loss) on the sale of assets
|
137 | 115 | (43 | ) | ||||||||
Equity (loss)/gain in unconsolidated investment
|
(211 | ) | 1,014 | (1,374 | ) | |||||||
Gain on sale of marketable securities
|
529 | 438 | -- | |||||||||
Miscellaneous income and (expenses)
|
(38 | ) | (60 | ) | (130 | ) | ||||||
Interest income
|
40 | 112 | 314 | |||||||||
Interest expense
|
(326 | ) | (70 | ) | (98 | ) | ||||||
131 | 1,549 | (1,331 | ) | |||||||||
Loss before income taxes and discontinued operations
|
(5,933 | ) | (1,318 | ) | (11,266 | ) |
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS
|
||||||||||||
(In thousands except per share data)
|
||||||||||||
Years ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Income taxes:
|
||||||||||||
Current benefit from (provision for)
|
-- | 104 | 210 | |||||||||
Deferred benefit from (provision for)
|
3,755 | 1,756 | 2,352 | |||||||||
3,755 | 1,860 | 2,562 | ||||||||||
(Loss) income from continuing operations
|
(2,178 | ) | 542 | (8,704 | ) | |||||||
Discontinued operations:
|
||||||||||||
Discontinued operations, net of taxes
|
434 | 226 | 526 | |||||||||
Impairment on discontinued operations
|
(3,063 | ) | (1,540 | ) | -- | |||||||
(2,629 | ) | (1,314 | ) | 526 | ||||||||
Net loss
|
$ | (4,807 | ) | $ | (772 | ) | $ | (8,178 | ) | |||
Net loss per share
|
||||||||||||
(Loss) income from continuing operations, basic
|
$ | (0.08 | ) | $ | 0.02 | $ | (0.40 | ) | ||||
(Loss) income from discontinued operations, basic
|
(0.10 | ) | (0.05 | ) | 0.02 | |||||||
Net (loss) income, basic
|
$ | (0.18 | ) | $ | (0.03 | ) | $ | (0.38 | ) | |||
(Loss) income from continuing operations, diluted
|
$ | (0.08 | ) | $ | 0.02 | $ | (0.40 | ) | ||||
(Loss) income from discontinued operations, diluted
|
(0.10 | ) | (0.05 | ) | 0.02 | |||||||
Net loss, basic and diluted
|
$ | (0.18 | ) | $ | (0.03 | ) | $ | (0.38 | ) | |||
Weighted average shares outstanding
|
||||||||||||
Basic
|
27,238,869 | 26,763,995 | 21,604,959 | |||||||||
Diluted
|
27,238,869 | 26,763,995 | 21,604,959 | |||||||||
U.S. ENERGY CORP
|
||||||||||||||||||||||||
STATEMENT OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
|
||||||||||||||||||||||||
(In thousands except share data)
|
||||||||||||||||||||||||
Unrealized
|
||||||||||||||||||||||||
Additional
|
Gain (Loss) on
|
Total
|
||||||||||||||||||||||
Common Stock
|
Paid-In
|
Retained
|
Marketable
|
Shareholders'
|
||||||||||||||||||||
Shares
|
Amount
|
Capital
|
Earnings
|
Securities
|
Equity
|
|||||||||||||||||||
Balance January 1, 2009
|
21,935,129 | $ | 219 | $ | 93,951 | $ | 17,663 | $ | -- | $ | 111,833 | |||||||||||||
Net loss available
|
||||||||||||||||||||||||
to common shareholders
|
-- | -- | -- | (8,178 | ) | -- | (8,178 | ) | ||||||||||||||||
Unrecognized gain on
|
||||||||||||||||||||||||
marketable securities
|
-- | -- | -- | -- | 602 | 602 | ||||||||||||||||||
Unrealized tax effect
|
||||||||||||||||||||||||
on the unrealized gain
|
-- | -- | -- | -- | (216 | ) | (216 | ) | ||||||||||||||||
Comprehensive (loss)
|
(7,792 | ) | ||||||||||||||||||||||
Issuance of common stock
|
5,000,000 | 50 | 24,267 | -- | -- | 24,317 | ||||||||||||||||||
Funding of ESOP
|
36,583 | -- | 217 | -- | -- | 217 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
2001 stock compensation plan
|
80,000 | 1 | 185 | -- | -- | 186 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock warrants
|
71,088 | 1 | 232 | -- | -- | 233 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock options
|
1,984 | -- | 5 | -- | -- | 5 | ||||||||||||||||||
Vesting of stock options
|
||||||||||||||||||||||||
issued to employees
|
-- | -- | 1,430 | -- | -- | 1,430 | ||||||||||||||||||
Vesting of stock warrants
|
||||||||||||||||||||||||
to outside contractor
|
-- | -- | 9 | -- | -- | 9 | ||||||||||||||||||
Vesting of stock options
|
||||||||||||||||||||||||
issued to outside directors
|
-- | -- | 56 | -- | -- | 56 | ||||||||||||||||||
Excess tax benefit on the exercise
|
||||||||||||||||||||||||
stock options and warrants
|
-- | -- | 38 | -- | -- | 38 | ||||||||||||||||||
Common stock buy back program
|
(706,071 | ) | (7 | ) | (1,392 | ) | -- | -- | (1,399 | ) | ||||||||||||||
Balance December 31, 2009
|
26,418,713 | 264 | 118,998 | 9,485 | 386 | 129,133 | ||||||||||||||||||
U.S. ENERGY CORP
|
||||||||||||||||||||||||
STATEMENT OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
|
||||||||||||||||||||||||
(continued)
|
||||||||||||||||||||||||
(In thousands except share data)
|
||||||||||||||||||||||||
Unrealized
|
||||||||||||||||||||||||
Additional
|
Gain (Loss) on
|
Total
|
||||||||||||||||||||||
Common Stock
|
Paid-In
|
Retained
|
Marketable
|
Shareholders'
|
||||||||||||||||||||
Shares
|
Amount
|
Capital
|
Earnings
|
Securities
|
Equity
|
|||||||||||||||||||
Balance December 31, 2009
|
26,418,713 | 264 | 118,998 | 9,485 | 386 | 129,133 | ||||||||||||||||||
Net loss
|
-- | -- | -- | (772 | ) | -- | (772 | ) | ||||||||||||||||
Unrecognized gain on
|
||||||||||||||||||||||||
marketable securities
|
-- | -- | -- | -- | 400 | 400 | ||||||||||||||||||
Unrealized tax effect
|
||||||||||||||||||||||||
on the unrealized gain
|
-- | -- | -- | -- | (144 | ) | (144 | ) | ||||||||||||||||
Comprehensive (loss)
|
(516 | ) | ||||||||||||||||||||||
Funding of ESOP
|
42,802 | -- | 260 | -- | -- | 260 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
2001 stock compensation plan
|
80,000 | 1 | 429 | -- | -- | 430 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock options
|
275,728 | 3 | (455 | ) | -- | -- | (452 | ) | ||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock warrants
|
251,367 | 3 | 743 | -- | -- | 746 | ||||||||||||||||||
Vesting of stock options
|
-- | -- | 1,021 | -- | -- | 1,021 | ||||||||||||||||||
Vesting of stock warrants
|
-- | -- | 66 | -- | -- | 66 | ||||||||||||||||||
Balance December 31, 2010
|
27,068,610 | 271 | 121,062 | 8,713 | 642 | 130,688 | ||||||||||||||||||
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Cash flows from operating activities:
|
||||||||||||
Net (loss)
|
$ | (4,807 | ) | $ | (772 | ) | $ | (8,178 | ) | |||
Loss (income) from discontinued operations includes
|
||||||||||||
non-cash impairment of $3,063, $1,540, and $0
|
2,629 | 1,314 | (526 | ) | ||||||||
(Loss) income from continuing operations
|
(2,178 | ) | 542 | (8,704 | ) | |||||||
Adjustments to reconcile net (loss) income to
|
||||||||||||
net cash provided by operations
|
||||||||||||
Depreciation, depletion & amortization
|
14,593 | 11,184 | 4,135 | |||||||||
Change in fair value of commodity price
|
||||||||||||
risk management activities, net
|
(1,126 | ) | 1,725 | -- | ||||||||
Accretion of discount on treasury investment
|
-- | (78 | ) | (183 | ) | |||||||
Impairment of oil and gas properties
|
-- | -- | 1,468 | |||||||||
Gain on sale of marketable securities
|
(529 | ) | (438 | ) | -- | |||||||
Equity (gain)/loss from Standard Steam
|
211 | (1,014 | ) | 1,374 | ||||||||
Net change in deferred income taxes
|
(3,990 | ) | (1,533 | ) | (2,207 | ) | ||||||
(Gain) on sale of assets
|
(137 | ) | (115 | ) | 43 | |||||||
Noncash compensation
|
1,604 | 1,710 | 1,935 | |||||||||
Noncash services
|
6 | 66 | 65 | |||||||||
Net changes in assets and liabilities
|
||||||||||||
Accounts receivable
|
(1,493 | ) | (174 | ) | (2,858 | ) | ||||||
Income tax receivable
|
(9 | ) | 249 | 5,543 | ||||||||
Other current assets
|
148 | (386 | ) | (192 | ) | |||||||
Accounts payable
|
(3,368 | ) | (498 | ) | 71 | |||||||
Accrued compensation expense
|
(1,194 | ) | 6 | 1,000 | ||||||||
Other liabilities
|
29 | 149 | (510 | ) | ||||||||
Net cash provided by operating activities
|
2,567 | 11,395 | 980 | |||||||||
Cash flows from investing activities:
|
||||||||||||
Net redemption of treasury investments
|
17,843 | 4,293 | 29,277 | |||||||||
Cash distributions from (investment in) Standard Steam
|
-- | 1,138 | (877 | ) | ||||||||
Acquisition & development of real estate
|
-- | -- | (3 | ) | ||||||||
Acquisition & development of oil & gas properties
|
(50,265 | ) | (45,933 | ) | (17,498 | ) | ||||||
Acquisition & development of mining properties
|
(221 | ) | (123 | ) | (1 | ) | ||||||
Mining property option payment
|
354 | 1,000 | 2,000 | |||||||||
Acquisition of property and equipment
|
(42 | ) | (624 | ) | (277 | ) | ||||||
Proceeds from sale of oil and gas properties
|
13,574 | -- | -- | |||||||||
Proceeds from sale of marketable securities
|
846 | 602 | -- | |||||||||
Proceeds from sale of property and equipment
|
147 | 142 | 11 | |||||||||
Net change in restricted investments
|
(11 | ) | (330 | ) | 4,651 | |||||||
Net cash (used in) provided by investing activities:
|
(17,775 | ) | (39,835 | ) | 17,283 | |||||||
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Cash flows financing activities:
|
||||||||||||
Issuance of common stock
|
(146 | ) | 294 | 24,516 | ||||||||
Tax benefit from the exercise of stock options
|
-- | -- | 38 | |||||||||
Proceeds from new debt
|
33,069 | -- | -- | |||||||||
Repayments of debt
|
(11,365 | ) | (200 | ) | (17,888 | ) | ||||||
Stock buyback program
|
-- | -- | (1,399 | ) | ||||||||
Net cash provided by financing activities
|
21,558 | 94 | 5,267 | |||||||||
Net cash provided by operating activities
|
||||||||||||
of discontinued operations
|
767 | 779 | 1,572 | |||||||||
Net cash used in investing activities
|
||||||||||||
of discontinued operations
|
(55 | ) | (24 | ) | (133 | ) | ||||||
Net increase (decrease) in cash and cash equivalents
|
7,062 | (27,591 | ) | 24,969 | ||||||||
Cash and cash equivalents at beginning of period
|
5,812 | 33,403 | 8,434 | |||||||||
Cash and cash equivalents at end of period
|
$ | 12,874 | $ | 5,812 | $ | 33,403 | ||||||
Supplemental disclosures:
|
||||||||||||
Income tax received
|
$ | -- | $ | (353 | ) | $ | (5,753 | ) | ||||
Interest paid
|
$ | 290 | $ | 22 | $ | 39 | ||||||
Non-cash investing and financing activities:
|
||||||||||||
Unrealized gain
|
$ | 78 | $ | 642 | $ | 386 | ||||||
Acquisition and development of oil and gas
|
||||||||||||
properties through accounts payable
|
$ | 2,092 | $ | 8,983 | $ | 5,522 | ||||||
Acquisition and development of oil and gas
|
||||||||||||
through asset retirement obligations
|
$ | 186 | $ | 75 | $ | 58 | ||||||
Machinery and Equipment:
|
||
Office Equipment
|
3 to 5 years
|
|
Aircraft
|
15 years
|
|
Field Tools and Hand Equipment
|
5 to 7 years
|
|
Vehicles and Trucks
|
3 to 7 years
|
|
Heavy Equipment
|
7 to 10 years
|
|
Buildings and Improvements:
|
||
Service Buildings
|
20 years
|
|
Corporate Headquarter Building
|
45 years
|
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Oil & Gas properties
|
||||||||
Unproved
|
$ | 17,098 | $ | 17,926 | ||||
Wells in progress
|
2,909 | 3,694 | ||||||
Proved
|
99,496 | 63,317 | ||||||
119,503 | 84,937 | |||||||
Less accumulated depreciation
|
||||||||
depletion and amortization
|
(28,561 | ) | (14,563 | ) | ||||
Net book value
|
90,942 | 70,374 | ||||||
Mining properties
|
20,739 | 21,077 | ||||||
Building, land and equipment
|
14,984 | 14,564 | ||||||
Less accumulated depreciation
|
(5,788 | ) | (5,228 | ) | ||||
Net book value
|
9,196 | 9,336 | ||||||
Totals
|
$ | 120,877 | $ | 100,787 | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Costs associated with Mount Emmons
|
||||||||
beginning of year
|
$ | 21,077 | $ | 21,969 | ||||
Development costs during the nine months
|
16 | 108 | ||||||
Option payment from Thompson Creek
|
(354 | ) | (1,000 | ) | ||||
Costs at the end of the period
|
$ | 20,739 | $ | 21,077 | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Beginning asset retirement obligation
|
$ | 303 | $ | 211 | ||||
Accretion of discount
|
23 | 17 | ||||||
Liabilities incurred
|
187 | 75 | ||||||
Liabilities sold
|
(3 | ) | -- | |||||
Ending asset retirement obligation
|
$ | 510 | $ | 303 | ||||
Mining properties
|
$ | 149 | $ | 139 | ||||
Oil & Gas wells
|
361 | 164 | ||||||
Ending asset retirement obligation
|
$ | 510 | $ | 303 | ||||
(In thousands)
|
||||||||||||||||
Fair Value Measurements at December 31, 2011 Using
|
||||||||||||||||
December 31,
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
|||||||||||||
Description
|
2011
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
Commodity risk management assets
|
$ | 3 | $ | -- | $ | 3 | $ | -- | ||||||||
Available for sale securities
|
166 | 166 | -- | -- | ||||||||||||
Assets held for sale
|
18,132 | -- | -- | 18,132 | ||||||||||||
Total assets
|
$ | 18,301 | $ | 166 | $ | 3 | $ | 18,132 | ||||||||
Commodity risk management liability
|
$ | 601 | $ | -- | $ | 601 | $ | -- | ||||||||
Other accrued liabilities
|
822 | -- | -- | 822 | ||||||||||||
Total
|
$ | 1,423 | $ | -- | $ | 601 | $ | 822 | ||||||||
(In thousands)
|
|||||||
Fair Value Measurements at December 31, 2010 Using
|
|||||||
December 31
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
||||
Description
|
2010
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
|||
Available for sale securities
|
$ 1,364
|
$ 1,364
|
$ --
|
$ --
|
|||
Assets held for sale
|
20,979
|
--
|
--
|
20,979
|
|||
Total assets
|
$ 22,343
|
$ 1,364
|
$ --
|
$ 20,979
|
|||
Commodity risk management liability
|
$ 1,725
|
$ --
|
$ 1,725
|
$ --
|
|||
Other accrued liabilities
|
762
|
--
|
--
|
762
|
|||
Total
|
$ 2,487
|
$ --
|
$ 1,725
|
$ 762
|
|||
Change in Level 3 Fair Value Measurements
|
||||||||||||
December 31,
|
December 31,
|
|||||||||||
Description
|
2010
|
Revision of Value |
2011
|
|||||||||
Assets held for sale
|
$ | 20,979 | $ | (2,847 | ) | $ | 18,132 | |||||
December 31,
|
Additions and
|
December 31,
|
||||||||||
Description
|
2010 |
Payments
|
2011 | |||||||||
Other accrued liabilities
|
$ | 762 | $ | 59 | $ | 821 | ||||||
(In thousands)
|
||||||||||||||||||||||||
December 31, 2011
|
||||||||||||||||||||||||
Less Than 12 Months
|
12 Months or Greater
|
Total
|
||||||||||||||||||||||
Unrealized
|
Unrealized
|
Unrealized
|
||||||||||||||||||||||
Description of Securities
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
||||||||||||||||||
Available for sale securities
|
$ | 166 | $ | 122 | $ | -- | $ | -- | $ | 166 | $ | 122 | ||||||||||||
Total
|
$ | 166 | $ | 122 | $ | -- | $ | -- | $ | 166 | $ | 122 | ||||||||||||
December 31, 2010
|
||||||||||||||||||||||||
Less Than 12 Months
|
12 Months or Greater
|
Total
|
||||||||||||||||||||||
Unrealized
|
Unrealized
|
Unrealized
|
||||||||||||||||||||||
Description of Securities
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
||||||||||||||||||
Available for sale securities
|
$ | 1,364 | $ | 1,003 | $ | -- | $ | -- | $ | 1,364 | $ | 1,003 | ||||||||||||
Total
|
$ | 1,364 | $ | 1,003 | $ | -- | $ | -- | $ | 1,364 | $ | 1,003 | ||||||||||||
Quantity
|
|||||||||||
Settlement Period
|
Counterparty
|
Basis
|
(Bbl/d)
|
Strike Price
|
|||||||
Crude Oil Costless Collar
|
|||||||||||
10/01/11 - 09/30/12
|
BNP Parabis
|
WTI
|
400 |
Put:
|
$ | 80.00 | |||||
Call:
|
$ | 99.00 | |||||||||
Crude Oil Costless Collar
|
|||||||||||
01/01/12 - 12/31/12
|
BNP Parabis
|
WTI
|
200 |
Put:
|
$ | 90.00 | |||||
Call:
|
$ | 106.50 |
Quantity
|
|||||||||||
Settlement Period
|
Counterparty
|
Basis
|
(Bbl/d)
|
Strike Price
|
|||||||
Crude Oil Costless Collar
|
|||||||||||
10/01/12 - 09/30/13
|
BNP Parabis
|
WTI
|
200 |
Put:
|
$ | 95.00 | |||||
Call:
|
$ | 116.60 |
As of December 31, 2011
|
||||||||||
(in thousands)
|
||||||||||
Derivative Assets
|
Derivative Liabilities
|
|||||||||
Balance Sheet
|
Fair
|
Balance Sheet
|
Fair
|
|||||||
Classification
|
Value
|
Classification
|
Value
|
|||||||
Crude oil costless collars
|
Current Asset
|
$ | 3 |
Current Liability
|
$ | 601 | ||||
As of December 31, 2010
|
||||||||||
(in thousands)
|
||||||||||
Balance Sheet
|
Fair
|
Balance Sheet
|
Fair
|
|||||||
Classification
|
Value
|
Classification
|
Value
|
|||||||
Crude oil costless collars
|
Current Asset
|
$ | -- |
Current Liability
|
$ | 1,725 | ||||
(In thousands)
|
||||||||
Year Ended December 31,
|
||||||||
2011
|
2010
|
|||||||
Oil & Gas properties
|
||||||||
Unproved oil and gas properties
|
$ | 17,098 | $ | 17,926 | ||||
Wells in progress
|
2,909 | 3,694 | ||||||
Proved oil and gas properties
|
99,496 | 63,317 | ||||||
Total capitalized costs
|
$ | 119,503 | $ | 84,937 | ||||
(In thousands)
|
||||||||||||||||
Acquisitions
|
Exploration
|
Exploration
|
Total
|
|||||||||||||
2010
|
$ | 8,131 | $ | -- | $ | -- | $ | 8,131 | ||||||||
2011
|
8,967 | 2,909 | -- | 11,876 | ||||||||||||
Total
|
$ | 17,098 | $ | 2,909 | $ | -- | $ | 20,007 | ||||||||
(In thousands)
|
||||||||||||
For the years ending December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Property acquisition costs:
|
||||||||||||
Proved
|
$ | 1,288 | $ | -- | $ | -- | ||||||
Unproved
|
10,679 | 14,237 | 560 | |||||||||
Exploration costs
|
32,787 | 35,899 | 21,107 | |||||||||
Development costs
|
4,550 | 4,846 | -- | |||||||||
Total capitalized costs
|
$ | 49,304 | $ | 54,982 | $ |
2,1667
|
||||||
(In thousands)
|
||||||||||||
For the years ending December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Oil and gas revenues
|
$ | 30,958 | $ | 26,548 | $ | 7,581 | ||||||
Realized (loss) from risk management activities
|
(1,974 | ) | (156 | ) | -- | |||||||
Unrealized gain (loss) from risk management activities
|
1,126 | (1,725 | ) | -- | ||||||||
30,110 | 24,667 | 7,581 | ||||||||||
Operating expenses
|
11,552 | 6,073 | 1,085 | |||||||||
Depreciation, depletion and amortization
|
13,997 | 10,610 | 3,571 | |||||||||
Impairment
|
-- | -- | 1,468 | |||||||||
25,549 | 16,683 | 6,124 | ||||||||||
Operating income
|
$ | 4,561 | $ | 7,984 | $ | 1,457 | ||||||
December 31, 2011
|
Oil (BBLS)
|
Natural Gas or NGL (MCFE)
|
||
Beginning of year
|
1,546,446
|
2,450,968
|
||
Revisions of previous quantity estimates
|
4,913
|
(864,513)
|
||
Extensions, discoveries and improved recoveries
|
1,516,797
|
2,004,535
|
||
Purchase of reserves in place
|
48,615
|
49,065
|
||
Sales of reserves in place
|
(78,477)
|
(43,716)
|
||
Production
|
(300,325)
|
(852,211)
|
||
End of Year
|
2,737,969
|
2,744,128
|
||
Proved developed reserves at end of year
|
1,884,068
|
1,983,581
|
||
December 31, 2010
|
Oil (BBLS)
|
Natural Gas or NGL (MCFE)
|
||
Beginning of year
|
811,789
|
1,646,482
|
||
Revisions of previous quantity estimates
|
(55,450)
|
(234,852)
|
||
Extensions, discoveries and improved recoveries
|
1,093,540
|
1,911,867
|
||
Sales of reserves in place
|
--
|
--
|
||
Production
|
(303,433)
|
(872,529)
|
||
End of Year
|
1,546,446
|
2,450,968
|
||
Proved developed reserves at end of year
|
1,362,733
|
2,311,682
|
||
(In thousands)
|
||||||||||||
Year Ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Future cash inflows
|
$ | 259,533 | $ | 124,629 | $ | 51,024 | ||||||
Future costs:
|
||||||||||||
Production
|
(77,813 | ) | (36,299 | ) | (14,025 | ) | ||||||
Development
|
(42,972 | ) | (6,774 | ) | (104 | ) | ||||||
Future income tax expense
|
(19,790 | ) | (11,622 | ) | (8,273 | ) | ||||||
Future net cash flows
|
118,958 | 69,934 | 28,622 | |||||||||
10% discount factor
|
(56,767 | ) | (25,281 | ) | (8,638 | ) | ||||||
Standardized measure of discounted future net cash flows
|
$ | 62,191 | $ | 44,653 | $ | 19,984 | ||||||
(In thousands)
|
||||||||||||
Year Ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Balance at beginning of period
|
$ | 44,653 | $ | 19,984 | $ | 3,318 | ||||||
Sales of oil and gas, net of production costs
|
(19,406 | ) | (20,476 | ) | (6,496 | ) | ||||||
Net change in prices and production costs
|
1,401 | 3,895 | 297 | |||||||||
Extensions and discoveries
|
26,574 | 40,011 | 26,721 | |||||||||
Purchase of reserves in place
|
3,082 | -- | -- | |||||||||
Sale of reserves in place
|
(1,947 | ) | -- | -- | ||||||||
Revisions of previous quantity estimates
|
(3,158 | ) | (2,519 | ) | 1,586 | |||||||
Development costs incurred during year
|
14,930 | -- | -- | |||||||||
Previously estimated development costs incurred
|
(2,719 | ) | -- | -- | ||||||||
Net change in income taxes
|
(4,270 | ) | (2,138 | ) | (4,385 | ) | ||||||
Accretion of discount
|
5,207 | 2,576 | 531 | |||||||||
Changes in production rates, timing and other
|
(2,156 | ) | 3,320 | (1,588 | ) | |||||||
Balance at end of period
|
$ | 62,191 | $ | 44,653 | $ | 19,984 | ||||||
(In thousands)
|
||||||||||||
For the years ending December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Revenues
|
$ | 2,147 | $ | 2,411 | $ | 2,630 | ||||||
Operating expenses
|
1,468 | 2,062 | 1,840 | |||||||||
Impairment
|
3,063 | 1,540 | -- | |||||||||
4,531 | 3,602 | 1,840 | ||||||||||
(Loss) income before income taxes
|
(2,384 | ) | (1,191 | ) | 790 | |||||||
Income tax benefit from (provision for)
|
(245 | ) | (123 | ) | (264 | ) | ||||||
Net (loss) income from discontinued operations
|
$ | (2,629 | ) | $ | (1,314 | ) | $ | 526 | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Cash and cash equivalents
|
$ | 170 | $ | 198 | ||||
Accounts receivable
|
13 | 43 | ||||||
Prepaid expenses
|
99 | -- | ||||||
Property, plant and equipment, net
|
17,730 | 20,738 | ||||||
Restricted investment
|
120 | -- | ||||||
Assets of discontinued operations held for sale
|
$ | 18,132 | $ | 20,979 | ||||
Accounts payable
|
$ | 117 | $ | 86 | ||||
Accrued and other liabilities
|
220 | 237 | ||||||
Long term debt
|
9,904 | -- | ||||||
Assets of discontinued operations held for sale
|
$ | 10,241 | $ | 323 | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Other liabilities and debt:
|
||||||||
Other liabilities
|
||||||||
Deferred rent
|
$ | 14 | $ | 16 | ||||
Employee health insurance self funding
|
10 | -- | ||||||
$ | 24 | $ | 16 | |||||
Other long term liabilities:
|
||||||||
Accrued executive retirement costs
|
$ | 822 | $ | 762 | ||||
Debt:
|
||||||||
Credit Facility - collateralized by
|
||||||||
oil and gas reserves, at 3.07%
|
$ | 12,000 | $ | -- | ||||
Long term Debt
|
||||||||
Real estate note - collateralized by
|
||||||||
property, interest at 5.5%
|
9,904 | -- | ||||||
Real estate note - collateralized by
|
||||||||
property, interest at 6%
|
400 | 600 | ||||||
22,304 | 600 | |||||||
Less current portion
|
(481 | ) | (200 | ) | ||||
Totals
|
$ | 21,823 | $ | 400 | ||||
(In thousands)
|
||||||||||||||||||||||||
Payments due by period
|
||||||||||||||||||||||||
Total
|
2012
|
2013
|
2014
|
2015
|
2016 and thereafter
|
|||||||||||||||||||
Credit facility
|
$ | 12,000 | $ | 12,000 | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||
Real estate note - 5.5%
|
9,904 | 281 | 312 | 326 | 345 | 8,640 | ||||||||||||||||||
Real estate note - 6.0%
|
400 | 200 | 200 | -- | -- | -- | ||||||||||||||||||
Total
|
$ | 22,304 | $ | 12,481 | $ | 512 | $ | 326 | $ | 345 | $ | 8,640 | ||||||||||||
(In thousands)
|
||||||||||||
Years ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Current income tax expense (benefit)
|
||||||||||||
Federal
|
$ | -- | $ | (104 | ) | $ | (210 | ) | ||||
State
|
-- | -- | -- | |||||||||
$ | -- | $ | (104 | ) | $ | (210 | ) | |||||
Deferred income tax expense (benefit)
|
||||||||||||
Federal
|
$ | (3,316 | ) | $ | (1,543 | ) | $ | (1,794 | ) | |||
State
|
(195 | ) | (91 | ) | (275 | ) | ||||||
$ | (3,511 | ) | $ | (1,634 | ) | $ | (2,069 | ) | ||||
(In thousands)
|
||||||||||||
Years ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Federal statutory income tax rate
|
$ | (2,828 | ) | $ | (853 | ) | $ | (3,555 | ) | |||
State income taxes, net of federal benefit
|
(166 | ) | (50 | ) | (209 | ) | ||||||
Incentive stock options
|
246 | 258 | 404 | |||||||||
percent depletion carryover
|
(807 | ) | (1,067 | ) | (128 | ) | ||||||
Other
|
44 | (26 | ) | 1,209 | ||||||||
$ | (3,511 | ) | $ | (1,738 | ) | $ | (2,279 | ) | ||||
(In thousands)
|
||||||||||||
December 31,
|
December 31,
|
December 31,
|
||||||||||
2011
|
2010
|
2009
|
||||||||||
Deferred tax assets:
|
||||||||||||
Net operating loss
|
$ | 2,547 | $ | 1,857 | $ | 2,078 | ||||||
Derivative instruments
|
215 | 621 | -- | |||||||||
Asset retirement obligation
|
184 | 109 | 40 | |||||||||
Stock based compensation
|
288 | 287 | 629 | |||||||||
Deferred compensation
|
357 | 372 | 534 | |||||||||
Alternative minimum tax credit
|
706 | 706 | 810 | |||||||||
Contribution carryover
|
28 | 27 | 19 | |||||||||
Equity investments
|
37 | 362 | -- | |||||||||
Percentage depletion carryover
|
1,924 | 1,198 | 128 | |||||||||
$ | 6,286 | $ | 5,539 | $ | 4,238 | |||||||
Deferred tax liabilities:
|
||||||||||||
Property and equipment
|
$ | (7,385 | ) | $ | (10,149 | ) | $ | (10,700 | ) | |||
Marketable securities
|
(44 | ) | (361 | ) | -- | |||||||
$ | (7,429 | ) | $ | (10,510 | ) | $ | (10,700 | ) | ||||
Net deferred tax assets (liabilities)
|
$ | (1,143 | ) | $ | (4,971 | ) | $ | (6,462 | ) | |||
Less: Valuation Allowance
|
-- | -- | -- | |||||||||
Deferred tax liability
|
$ | (1,143 | ) | $ | (4,971 | ) | $ | (6,462 | ) | |||
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Revenues:
|
||||||||||||
Oil and gas
|
$ | 30,110 | $ | 24,667 | $ | 7,581 | ||||||
Total revenues:
|
30,110 | 24,667 | 7,581 | |||||||||
Operating expenses:
|
||||||||||||
Oil and gas
|
25,549 | 16,683 | 6,124 | |||||||||
Mineral properties
|
2,364 | 1,878 | 1,959 | |||||||||
Total operating expenses:
|
27,913 | 18,561 | 8,083 | |||||||||
Interest expense
|
||||||||||||
Oil and gas
|
268 | -- | -- | |||||||||
Mineral properties
|
36 | 48 | 60 | |||||||||
Total interest expense:
|
304 | 48 | 60 | |||||||||
Operating (loss) income
|
||||||||||||
Oil and gas
|
$ | 4,293 | $ | 7,984 | $ | 1,457 | ||||||
Mineral properties
|
(2,400 | ) | (1,926 | ) | (2,019 | ) | ||||||
Operating income (loss)
|
||||||||||||
from identified segments
|
1,893 | 6,058 | (562 | ) | ||||||||
General and administrative expenses
|
(8,261 | ) | (8,973 | ) | (9,433 | ) | ||||||
Add back interest expense
|
304 | 48 | 60 | |||||||||
Other revenues and expenses:
|
131 | 1,549 | (1,331 | ) | ||||||||
(Loss) income before income taxes
|
||||||||||||
and discontinued operations
|
$ | (5,933 | ) | $ | (1,318 | ) | $ | (11,266 | ) | |||
Depreciation depletion and amortization expense:
|
||||||||||||
Oil and gas
|
$ | 13,997 | $ | 10,610 | $ | 1,045 | ||||||
Mineral properties
|
102 | 77 | 54 | |||||||||
Corporate
|
494 | 380 | 396 | |||||||||
Total depreciation expense
|
$ | 14,593 | $ | 11,067 | $ | 1,495 | ||||||
(In thousands)
|
||||||||||||
December 31,
|
||||||||||||
2011
|
2010
|
2009
|
||||||||||
Assets by segment
|
||||||||||||
Oil and Gas
|
$ | 109,141 | $ | 75,639 | $ | 30,016 | ||||||
Mineral
|
20,755 | 20,800 | 21,998 | |||||||||
Corporate
|
32,543 | 59,577 | 94,709 | |||||||||
Total assets
|
$ | 162,439 | $ | 156,016 | $ | 146,723 | ||||||
Year ended December 31, | ||||||||||||||||||||||||
2011
|
2010
|
2009
|
||||||||||||||||||||||
Options
|
Weighted Average Exercise Price
|
Options
|
Weighted Average Exercise Price
|
Options
|
Weighted Average Exercise Price
|
|||||||||||||||||||
Outstanding at beginning
|
||||||||||||||||||||||||
of the period
|
3,011,647 | $ | 3.87 | 3,711,114 | $ | 3.64 | 3,717,098 | $ | 3.63 | |||||||||||||||
Granted
|
-- | $ | -- | -- | $ | -- | -- | $ | -- | |||||||||||||||
Forfeited
|
-- | $ | -- | -- | $ | -- | -- | $ | -- | |||||||||||||||
Expired
|
(200,000 | ) | $ | 3.90 | -- | $ | -- | (4,000 | ) | $ | 2.46 | |||||||||||||
Exercised
|
(493,248 | ) | $ | 3.51 | (699,467 | ) | $ | 2.63 | (1,984 | ) | $ | 2.52 | ||||||||||||
Outstanding at period end
|
2,318,399 | $ | 3.94 | 3,011,647 | $ | 3.87 | 3,711,114 | $ | 3.64 | |||||||||||||||
Exercisable at period end
|
2,108,399 | $ | 3.84 | 2,404,148 | $ | 3.78 | 2,614,453 | $ | 3.43 | |||||||||||||||
Weighted average fair
|
||||||||||||||||||||||||
value of options
|
||||||||||||||||||||||||
granted during
|
||||||||||||||||||||||||
the period
|
$ | -- | $ | -- | $ | -- | ||||||||||||||||||
Grant Price Range
|
Options Outstanding at December 31, 2011
|
Weighted average remaining contractual life in years
|
Weighted average exercise price
|
Options exercisable at December 31, 2011
|
Weighted average exercise price
|
|||||||||||||||||
$ | 2.46 | 389,319 | 2.50 | $ | 2.46 | 389,319 | $ | 2.46 | ||||||||||||||
$ | 2.47 - $2.52 | 450,312 | 6.67 | $ | 2.52 | 450,312 | $ | 2.52 | ||||||||||||||
$ | 2.53 - $3.86 | 273,768 | 3.79 | $ | 3.86 | 273,768 | $ | 3.86 | ||||||||||||||
$ | 3.91 - $4.97 | 1,205,000 | 5.34 | $ | 4.97 | 995,000 | $ | 4.97 | ||||||||||||||
2,318,399 | 4.94 | $ | 3.94 | 2,108,399 | $ | 3.84 | ||||||||||||||||
2011
|
2010
|
2009
|
||||||||||
Available for future grant
|
-- | 3,765,506 | 3,327,780 | |||||||||
Intrinsic value of option exercised
|
$ | 888,000 | $ | 1,956,000 | $ | 14,000 | ||||||
Aggregate intrinsic value of options outstanding
|
$ | 351,000 | $ | 6,660,000 | $ | 8,514,000 | ||||||
Aggregate intrinsic value of options exercisable
|
$ | 351,000 | $ | 5,526,000 | $ | 6,543,000 |
Year ended December 31,
|
||||||||||||||||||||||||
2011
|
2010
|
2009
|
||||||||||||||||||||||
Warrants
|
Weighted Average Exercise Price
|
Warrants
|
Weighted Average Exercise Price
|
Warrants
|
Weighted Average Exercise Price
|
|||||||||||||||||||
Outstanding at beginning
|
||||||||||||||||||||||||
of the period
|
320,000 | $ | 2.95 | 581,367 | $ | 2.91 | 1,036,387 | $ | 3.43 | |||||||||||||||
Granted
|
20,000 | $ | 4.19 | 10,000 | $ | 5.04 | -- | $ | -- | |||||||||||||||
Forfeited
|
(20,000 | ) | $ | 2.52 | (20,000 | ) | $ | 2.52 | -- | $ | -- | |||||||||||||
Expired
|
(5,000 | ) | $ | 3.90 | -- | $ | -- | (383,932 | ) | $ | 4.26 | |||||||||||||
Exercised
|
(105,000 | ) | $ | 2.92 | (251,367 | ) | $ | 2.97 | (71,088 | ) | $ | 3.27 | ||||||||||||
Outstanding at period end
|
210,000 | $ | 3.10 | 320,000 | $ | 2.95 | 581,367 | $ | 2.91 | |||||||||||||||
Exercisable at period end
|
183,334 | $ | 2.91 | 276,667 | $ | 2.93 | 494,701 | $ | 2.98 | |||||||||||||||
Weighted average fair
|
||||||||||||||||||||||||
value of options
|
||||||||||||||||||||||||
granted during
|
||||||||||||||||||||||||
the period
|
$ | 2.34 | $ | 2.99 | $ | -- | ||||||||||||||||||
Grant Price Range
|
Warrants Outstanding at December 31, 2011
|
Weighted average remaining contractual life in years
|
Weighted average exercise price
|
Warrants exercisable at December 31, 2011
|
Weighted average exercise price
|
|||||||||||||||||
$ | 2.46 | 50,000 | 0.48 | $ | 2.46 | 50,000 | $ | 2.46 | ||||||||||||||
$ | 2.47 - $2.52 | 80,000 | 3.61 | $ | 2.52 | 80,000 | $ | 2.52 | ||||||||||||||
$ | 2.53 - $3.86 | 50,000 | 0.48 | $ | 3.86 | 50,000 | $ | 3.86 | ||||||||||||||
$ | 3.87 - $4.19 | 20,000 | 9.48 | $ | 4.19 | 3,334 | $ | 4.19 | ||||||||||||||
$ | 3.91 - $5.04 | 10,000 | 8.48 | $ | 5.04 | -- | $ | 5.04 | ||||||||||||||
210,000 | 2.91 | $ | 3.10 | 183,334 | $ | 2.91 | ||||||||||||||||
Year Ended
|
|||
December 31,
|
|||
2011
|
2010
|
2009
|
|
Risk-free interest rate
|
1.77%
|
2.24%
|
--
|
Expected lives (years)
|
6.0
|
6.0
|
--
|
Expected volatility
|
59.64%
|
63.79%
|
--
|
Expected dividend yield
|
--
|
--
|
--
|
(In thousands except per share data)
|
||||||||||||||||
Three Months Ended
|
||||||||||||||||
December 31,
|
September 30,
|
June 30,
|
March 31,
|
|||||||||||||
2011
|
2011
|
2011
|
2011
|
|||||||||||||
Operating revenues
|
$ | 7,107 | $ | 9,972 | $ | 8,148 | $ | 4,883 | ||||||||
Operating income (loss)
|
$ | (2,475 | ) | $ | 875 | $ | 400 | $ | (4,864 | ) | ||||||
Income (loss) before income tax and discontinued operations
|
$ | (2,362 | ) | $ | 1,022 | $ | 339 | $ | (4,932 | ) | ||||||
Benefit from (provision for) income taxes
|
$ | 2,671 | $ | (892 | ) | $ | (618 | ) | $ | 2,594 | ||||||
Discontinued operations, net of tax
|
$ | (3,100 | ) | $ | 138 | $ | 204 | $ | 129 | |||||||
Net income (loss)
|
$ | (2,791 | ) | $ | 268 | $ | (75 | ) | $ | (2,209 | ) | |||||
Income (loss) per share, basic
|
||||||||||||||||
Continuing operations
|
$ | 0.01 | $ | -- | $ | (0.01 | ) | $ | (0.08 | ) | ||||||
Discontinued operations
|
(0.12 | ) | 0.01 | 0.01 | -- | |||||||||||
$ | (0.11 | ) | $ | 0.01 | $ | -- | $ | (0.08 | ) | |||||||
Basic weighted average shares outstanding
|
27,288,470 | 27,259,174 | 27,220,049 | 27,186,438 | ||||||||||||
Income (loss) per share, diluted
|
||||||||||||||||
Continuing operations
|
$ | 0.01 | $ | -- | $ | (0.01 | ) | $ | (0.08 | ) | ||||||
Discontinued operations
|
(0.12 | ) | 0.01 | 0.01 | -- | |||||||||||
$ | (0.11 | ) | $ | 0.01 | $ | -- | $ | (0.08 | ) | |||||||
Diluted weighted average shares outstanding
|
27,288,470 | 27,862,098 | 27,866,544 | 27,186,438 |
(In thousands except per share data)
|
||||||||||||||||
Three Months Ended
|
||||||||||||||||
December 31,
|
September 30,
|
June 30,
|
March 31,
|
|||||||||||||
2010
|
2010
|
2010
|
2010
|
|||||||||||||
Operating revenues
|
$ | 5,023 | $ | 5,717 | $ | 6,218 | $ | 7,709 | ||||||||
Operating income (loss)
|
$ | (2,862 | ) | $ | (958 | ) | $ | (297 | ) | $ | 1,250 | |||||
Income (loss) before income tax and discontinued operations
|
$ | (2,359 | ) | $ | (950 | ) | $ | (176 | ) | $ | 2,340 | |||||
Benefit from (provision for) income taxes
|
$ | 1,975 | $ | 634 | $ | 17 | $ | (888 | ) | |||||||
Discontinued operations, net of tax
|
$ | (1,549 | ) | $ | 81 | $ | 28 | $ | 75 | |||||||
Net income (loss)
|
$ | (1,933 | ) | $ | (235 | ) | $ | (131 | ) | $ | 1,527 | |||||
Income (loss) per share, basic
|
||||||||||||||||
Continuing operations
|
$ | (0.02 | ) | $ | (0.01 | ) | $ | -- | $ | 0.06 | ||||||
Discontinued operations
|
(0.05 | ) | -- | -- | -- | |||||||||||
$ | (0.07 | ) | $ | (0.01 | ) | $ | -- | $ | 0.06 | |||||||
Basic weighted average shares outstanding
|
26,973,834 | 26,855,513 | 26,734,636 | 26,487,162 | ||||||||||||
Income (loss) per share, diluted
|
||||||||||||||||
Continuing operations
|
$ | (0.02 | ) | $ | (0.01 | ) | $ | -- | $ | 0.05 | ||||||
Discontinued operations
|
(0.05 | ) | -- | -- | -- | |||||||||||
$ | (0.07 | ) | $ | (0.01 | ) | $ | -- | $ | 0.05 | |||||||
Diluted weighted average shares outstanding
|
26,973,834 | 26,855,513 | 26,734,636 | 27,785,572 |
(In thousands except per share data)
|
||||||||||||||||
Three Months Ended
|
||||||||||||||||
December 31,
|
September 30,
|
June 30,
|
March 31,
|
|||||||||||||
2009
|
2009
|
2009
|
2009
|
|||||||||||||
Operating revenues
|
$ | 5,462 | $ | 691 | $ | 754 | $ | 674 | ||||||||
Operating income (loss)
|
$ | (1,370 | ) | $ | (2,476 | ) | $ | (2,441 | ) | $ | (3,648 | ) | ||||
Income (loss) before income tax and discontinued operations
|
$ | (2,254 | ) | $ | (2,823 | ) | $ | (2,479 | ) | $ | (3,710 | ) | ||||
Benefit from (provision for) income taxes
|
$ | 1,011 | $ | 941 | $ | (590 | ) | $ | 1,200 | |||||||
Discontinued operations, net of tax
|
$ | 41 | $ | 138 | $ | 184 | $ | 163 | ||||||||
Net income (loss)
|
$ | (1,202 | ) | $ | (1,744 | ) | $ | (2,885 | ) | $ | (2,347 | ) | ||||
Loss per share, basic
|
||||||||||||||||
Continuing operations
|
$ | (0.05 | ) | $ | (0.09 | ) | $ | (0.14 | ) | $ | (0.12 | ) | ||||
Discontinued operations
|
-- | 0.01 | 0.01 | 0.01 | ||||||||||||
$ | (0.05 | ) | $ | (0.08 | ) | $ | (0.13 | ) | $ | (0.11 | ) | |||||
Basic weighted average shares outstanding
|
22,195,694 | 21,288,841 | 21,311,266 | 21,654,519 | ||||||||||||
Loss per share, diluted
|
||||||||||||||||
Continuing operations
|
$ | (0.05 | ) | $ | (0.09 | ) | $ | (0.14 | ) | $ | (0.11 | ) | ||||
Discontinued operations
|
-- | 0.01 | 0.01 | -- | ||||||||||||
$ | (0.05 | ) | $ | (0.08 | ) | $ | (0.13 | ) | $ | (0.11 | ) | |||||
Diluted weighted average shares outstanding
|
22,195,694 | 21,288,841 | 21,311,266 | 21,654,519 |
(a)(1) and (a)(2)
|
Page
|
Report of Independent Registered Public Accounting Firm
|
76
|
Financial Statements
|
|
Consolidated Balance Sheets as of December 31, 2011 and 2010
|
77
|
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009
|
79
|
Statement of Stockholders’ Equity
|
81
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009
|
84
|
Notes to Consolidated Financial Statements
|
86
|
|
U.S. ENERGY CORP. (Registrant)
|
|||
Date: March 14, 2012
|
By:
|
/s/ Keith G. Larsen
|
||
KEITH G. LARSEN, Chief Executive Officer
|
||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
|
||||
Date: March 14, 2012
|
By:
|
/s/ Keith G. Larsen
|
||
KEITH G. LARSEN, Director, Chairman and CEO
|
||||
Date: March 14, 2012
|
By:
|
/s/ Bryon G. Mowry
|
||
BRYON G. MOWRY
|
||||
Principal Accounting Officer
|
||||
Date: March 14, 2012
|
By:
|
/s/ Mark J. Larsen
|
||
MARK J. LARSEN, President and Director
|
||||
Date: March 14, 2012
|
By:
|
/s/ Robert Scott Lorimer
|
||
ROBERT SCOTT LORIMER, Director
|
||||
Date: March 14, 2012
|
By:
|
/s/ Allen S. Winters
|
||
ALLEN S. WINTERS, Director
|
||||
Date: March 14, 2012
|
By:
|
/s/ Stephen V. Conrad
|
||
STEPHEN V. CONRAD, Director
|
||||
Date: March 14, 2012
|
By:
|
/s/ Jerry W. Danni
|
||
JERRY W. DANNI, Director
|
||||
Date: March 14, 2012
|
By:
|
/s/ Leo A. Heath
|
||
LEO A. HEATH, Director
|
Address:
|
ENERGY ONE LLC
|
||
877 N. 8
th
W.
|
|||
Riverton, WY 82501
|
|||
Fax: (307) 857-3050
|
|||
Phone: (307) 856-9271
|
|||
Email:
mark@usnrg.com
|
|||
Dated: 12/14/11
|
By:
|
/s/ Mark J. Larsen
|
|
Name Printed: Mark J. Larsen
|
|||
Its: President
|
|||
Address:
|
BRIGHAM OIL & GAS, L.P.
|
||
6300 Bridge Point Pkwy.
|
by Brigham, Inc.
|
||
Bldg.2, Suite 500
|
its General Partner
|
||
Austin, Texas 78730
|
|||
(512) 427-3300
|
|||
Fax: (512) 427-3400
|
|||
Email:
llangford@bexp3d.com
|
|||
Dated: 12-14-11
|
By:
|
/s/ A. Lance Langford
|
|
A. Lance Langford
|
|||
Its: Executive Vice President – Operations
|
Address:
|
Energy One LLC
|
||
877 N. 8
th
W.
|
|||
Riverton, WY 82501
|
|||
Fax: (307) 857-3050
|
|||
Phone: (307) 856-9271
|
|||
Email:
mark@usnrg.com
|
|||
Dated: December 15, 2011
|
By:
|
/s/ Mark J. Larsen
|
|
Name Printed: Mark J. Larsen
|
|||
Its: President
|
|||
Address:
|
GeoResources, Inc.
|
||
110 Cypress Station Dr., Suite 220
|
|||
Houston, TX 77090
|
|||
Fax: 281-537-8324
|
|||
Phone: 281-537-9920
|
|||
Email:
Robert@Georesourcesinc.com
|
|||
Dated: December 15, 2011
|
By:
|
/s/ Robert J. Anderson
|
|
Name Printed: Robert J. Anderson
|
|||
Its: Executive Vice President – Engineering & Acquisitions
|
1.
|
GeoResources hereby assigns to Yuma an undivided 25% interest in the Agreement to Yuma.
|
2.
|
Yuma agrees to be bound by the terms and conditions of the Agreement including, but not limited to, the terms and conditions of the SE HR Participation Agreement, the Yellowstone Participation Agreement and all associated JOA’s for the Conveyed Interests, copies of which have been provided to Yuma.
|
3.
|
GeoResources and Yuma agree to pay Energy One the following amounts as consideration for the Conveyed Interest:
|
a.
|
GeoResources agrees to pay Energy One $12,525,000.00 for the Conveyed Interest and $188,362.50 as reimbursement for prepaid costs (75% of the total consideration); and
|
b.
|
Yuma agrees to pay Energy One $4,175,000.00 for the Conveyed Interest and $62,787.50 as reimbursement for prepaid costs (25% of the total consideration).
|
4.
|
Energy One agrees to transfer to GeoResources and Yuma, as follows:
|
a.
|
To GeoResources or its designee an undivided 56.25% of Energy One’s interest in the Conveyed Interests; and
|
b.
|
To Yuma or its designee an undivided 18.75% of Energy One’s interest in the
|
5.
|
Except as otherwise provided in this Amendment, the terms, conditions and provisions of the Agreement remain unchanged and are hereby ratified and reaffirmed and continue in full force and effect.
|
6.
|
This Amendment may be executed in any number of counterparts; each of which when so executed and delivered shall be deemed an original, and all such counterparts together shall constitute one instrument.
|
1.
|
Section 1.1 of Article I. Assignment is amended to change the Closing to on or before on January 25, 2012, unless otherwise mutually extended by the Parties, which consent will not be unreasonably withheld.
|
a.
|
GeoResources agrees to pay Energy One $5,433,345.00 for the Conveyed Interest and $859,949.44 as reimbursement for prepaid costs (75% of the total consideration); and
|
b.
|
Yuma agrees to pay Energy One $1,811,115.00 for the Conveyed Interest and $286,649.81 as reimbursement for prepaid costs (25% of the total consideration).
|
a.
|
GeoResources agrees to pay Energy One $7,091,655.00 for the Conveyed Interest and $69,757.25 as reimbursement for prepaid costs (75% of the total consideration); and
|
b.
|
Yuma agrees to pay Energy One $2,363,885.00 for the Conveyed Interest and $23,252.42 as reimbursement for prepaid costs (25% of the total consideration).
|
c.
|
GeoResources agrees to pay Energy One $7,091,655.00 for the Conveyed Interest and $204,006.32 as reimbursement for prepaid costs (75% of the total consideration); and
|
d.
|
Yuma agrees to pay Energy One $2,363,885.00 for the Conveyed Interest and $68,002.10 as reimbursement for prepaid costs (25% of the total consideration).
|
1.
|
I have reviewed this annual report on Form 10-K of U.S. Energy Corp.;
|
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 officers 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 officers 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 functions):
|
|
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.
|
1.
|
I have reviewed this annual report on Form 10-K of U.S. Energy Corp.;
|
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 officers 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 officers 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 functions):
|
|
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.
|
\s\ James F. Latham
|
James F. Latham, P.E.
|
TBPE License No. 49586
|
Senior Vice President
|
|
[SEAL]
|
As of December 31, 2011
|
Proved
|
||||||||||||
Developed
|
Total
|
|||||||||||
Producing
|
Non-Producing
|
Proved
|
||||||||||
Net Remaining Reserves
|
||||||||||||
Oil/Condensate – Barrels
|
3,434 | 30,635 | 34,069 | |||||||||
Plant Products – Barrels
|
219 | 1,469 | 1,688 | |||||||||
Gas – MMCF
|
588 | 89 | 677 | |||||||||
Income Data
|
||||||||||||
Future Gross Revenue
|
$ | 2,680,947 | $ | 3,450,559 | $ | 6,131,506 | ||||||
Deductions
|
653,813 | 612,803 | 1,266,616 | |||||||||
Future Net Income (FNI)
|
$ | 2,027,134 | $ | 2,837,756 | $ | 4,864,890 | ||||||
Discounted FNI @ 10%
|
$ | 1,748,259 | $ | 2,160,979 | $ | 3,909,238 |
Discounted Future Net Income
|
||||||
As of December 31, 2011
|
||||||
Discount Rate
|
Total
|
|||||
Percent
|
Proved
|
|||||
5 | $ | 4,350,123 | ||||
15 | $ | 3,529,956 | ||||
20 | $ | 3,202,243 | ||||
30 | $ | 2,670,083 |
|
Senior Vice President
|
|
[SEAL]
|
|
JFL (FPR)/pl
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(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.
|
Proved
|
|||||||||
Total
|
Developed
|
Undeveloped
|
|||||||
Net Reserves
|
|||||||||
Oil
|
— bbl
|
2,646,429
|
1,792,499
|
853,930
|
|||||
Gas
|
— Mcf
|
1,996,848
|
1,236,253
|
760,595
|
|||||
Net Revenue
|
|||||||||
Oil
|
— $
|
230,973,859
|
156,467,062
|
74,506,773
|
|||||
Gas
|
— $
|
16,296,113
|
10,114,524
|
6,181,589
|
|||||
Net BOE Production
|
—
|
BOE
|
2,979,238
|
1,998,541
|
980,696
|
||||
Ad Valorem Tax
|
—
|
$
|
0
|
0
|
0
|
||||
Operating Expense
|
—
|
$
|
47,311,031
|
33,280,980
|
14,030,056
|
||||
Production Severance Tax
|
—
|
$
|
26,748,043
|
18,131,182
|
8,652,856
|
||||
Investments
|
—
|
$
|
42,749,039
|
6,876,118
|
35,872,9
|
||||
Future Net Cash Flow
|
—
|
$
|
130,425,844
|
108,293,312
|
22,132,529
|
||||
Discounted @ 10%
|
—
|
$
|
66,154,180
|
64,973,578
|
1,180,602
|
||||
(Present Worth)
|
|
(1) (11)
|
Calendar
or
Fiscal
years/months commencing on effective date.
|
|
(2) (3)
|
Gross Production
(8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(Gross MBOE is shown to right of Ultimate Recovery values in light gray font, calculated by dividing the ultimate gross gas production by six (6) then adding to the ultimate gross oil production.)
|
|
(4) (5)
|
Net Production
accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
|
|
(6)
|
Average (
volume weighted
)
Gross Liquid Price
per barrel adjusted for average differential above or below N
ymex
, but before deducting production-severance taxes.
(Composite differential in $/bbl shown at left in light gray font)
|
|
(7)
|
Average (
volume weighted
)
Gross Gas Price
per Mcf adjusted for average differential above or below N
ymex
, but before deducting production-severance taxes.
(Composite differential in $/mcf shown at left in light gray font)
|
|
(8)
|
Revenue
derived from oil sales -- column (4) times column (6).
|
|
(9)
|
Revenue
derived from gas sales -- column (5) times column (7).
|
|
(10)
|
Total Revenue
-- column (8) plus column (9).
|
|
(11)
|
Calendar
or
Fiscal
years/months commencing on effective date.
|
|
(12)
|
Net M
BOE
Production
(
equivalent net oil production
) – Accruable to evaluated interest is calculated by dividing the net gas production by six (6) then adding to the net oil production.
|
|
(13)
|
Ad Valorem Taxes
.
|
|
(14)
|
Average
Gross Wells
.
|
|
(15)
|
Average
Net Wells
are gross wells times working interest.
|
|
(16)
|
Operating Expenses
are direct operating expenses to the evaluated working interest.
|
|
(17)
|
Production Taxes
– Severance Taxes deducted from gross oil and gas revenue.
|
|
(18)
|
Investment
, if any, includes work-overs, future drilling costs, pumping units, etc. and may be included either tangible or intangible or both.
|
|
(19)
|
Future Net Cash Flow
is column (10) less columns (13), (16), (17) and (18). The data in column (19) are accumulated in column (20). Federal income taxes have not been considered.
|
|
(20)
|
Cumulative Future Net Cash Flow
.
|
|
(21)
|
Cumulative Cash Flow Discounted @ 10%
is calculated by discounting monthly cash flows at the specified annual rates.
|
|
DCF Profile
|
•
|
The cash flow discounted at six different rates are shown at the bottom of columns (20-21). Interest has been compounded monthly.
|
|
Life
|
•
|
The economic life of the appraised property is noted in the lower right-hand corner of the table.
|
|
Footnotes
|
•
|
Comments regarding the evaluation may be shown in the lower left-hand footnotes.
|
|
Price Deck
|
•
|
A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.
|
Net Reserves
|
Future Net Revenue (M$)
|
|||||||
Oil
|
Gas
|
Present Worth
|
||||||
Category
|
(MBBL)
|
(MMCF)
|
Total
|
at 10%
|
||||
Proved Developed Producing
|
57.5
|
60.2
|
3,456.8
|
2,474.0
|
|
(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
|
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
|
(v)
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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.
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a.
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Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
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b.
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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).
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a.
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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.
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b.
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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.
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c.
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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.
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d.
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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.
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e.
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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.
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f.
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Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
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(i)
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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.
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(ii)
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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.
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Ÿ
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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);
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Ÿ
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The company's historical record at completing development of comparable long-term projects;
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Ÿ
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The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
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Ÿ
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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
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Ÿ
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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).
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(iii)
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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.
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