þ
|
Annual report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year Ended December 31, 2013
|
¨
|
Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from
___________
to
___________
|
U.S. ENERGY CORP.
|
(Exact Name of Company as Specified in its Charter)
|
Wyoming
|
83-0205516
|
|
(State or other jurisdiction of
|
(I.R.S. Employer
|
|
incorporation or organization)
|
Identification No.)
|
|
877 North 8th West, Riverton, WY
|
82501
|
|
(Address of principal executive offices)
|
(Zip Code)
|
|
Registrant's telephone number, including area code:
|
(307) 856-9271
|
Title of each class
|
Name of exchange on which registered
|
|
Common Stock, $0.01 par value
|
NASDAQ Capital Market
|
Class
|
Outstanding at March 11, 2014
|
||
Common stock, $.01 par value
|
27,736,497 |
Cautionary Statement Regarding Forward-Looking Statements
|
5
|
PART I
|
7
|
ITEM 1. BUSINESS
|
7
|
7
|
|
7
|
|
7
|
|
8
|
|
8
|
|
14
|
|
15
|
|
15
|
|
29
|
|
30
|
|
30
|
|
46
|
|
48
|
|
PART II
|
49
|
49
|
|
51
|
|
52
|
|
52
|
|
52
|
|
57
|
|
65
|
|
66
|
|
66
|
|
67
|
|
68
|
|
71
|
|
71
|
|
72
|
|
72
|
|
74
|
|
122
|
|
122
|
|
125
|
|
PART III
|
125
|
125
|
|
125
|
|
125
|
|
126
|
|
126
|
|
PART IV
|
129
|
129
|
|
132
|
·
|
planned capital expenditures for oil and gas exploration and environmental compliance;
|
·
|
potential drilling locations and available spacing units, and possible changes in spacing rules;
|
·
|
cash expected to be available for continued work programs;
|
·
|
recovered volumes and values of oil and gas approximating third-party estimates of oil and gas reserves;
|
·
|
anticipated increases in oil and gas production;
|
·
|
drilling and completion activities in the Buda formation in South Texas, the Williston Basin in North Dakota, the Eagle Ford shale in South Texas and other areas;
|
·
|
timing of drilling additional wells and performing other exploration and development projects;
|
·
|
expected spacing and the number of wells to be drilled with our oil and gas industry partners;
|
·
|
when “Pooled Payout” or similar thresholds will be reached for the purposes of our agreements with Brigham, Zavanna and other partners;
|
·
|
expected working and net revenue interests, and costs of wells, relating to the drilling programs with our partners;
|
·
|
actual decline rates for producing wells in the Buda, Bakken/Three Forks, Eagle Ford and other formations;
|
·
|
review timing and potential approval of the plan of operations by the U.S. Forest Service in connection with the Mt. Emmons molybdenum project (“Mt. Emmons Project”), the receipt of necessary permits relating to the project, and the expected length of time to permit and develop the project;
|
·
|
future cash flows, expenses and borrowings;
|
·
|
pursuit of potential acquisition opportunities;
|
·
|
our expected financial position;
|
·
|
other plans and objectives for future operations.
|
·
|
our ability to obtain sufficient cash flow from operations, borrowing and/or other sources to fully develop our undeveloped acreage positions;
|
·
|
volatility in oil and natural gas prices, including declines in oil prices and/or natural gas 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 also could adversely impact the borrowing base available under our credit facility with Wells Fargo Bank (sometimes referred to as the “Credit Facility”);
|
·
|
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);
|
·
|
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 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, and related midstream infrastructure and services;
|
·
|
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;
|
·
|
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; and
|
·
|
unanticipated down-hole 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 and the risks associated with adverse rulings concerning these permits;
|
·
|
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;
|
·
|
the ability to find a suitable joint venture partner for the project if necessary;
|
·
|
continued compliance with current environmental regulations and the possibility of new legislation, environmental regulations or permit requirements adverse to the mining industry;
|
·
|
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 operation; and
|
·
|
compliance and operating costs associated with the wastewater treatment plant and stormwater management system.
|
·
|
Estimated proved reserves of 3,855,033 BOE (90% oil and 10% natural gas), with a standardized measure value of $104.9 million and a PV10 of $115.1 million.
|
·
|
At March 5, 2014, our leases covered 143,267 gross and 12,607 net acres.
|
·
|
113 gross (16.22 net) producing wells (120 gross (17.29 net) wells at March 5, 2014).
|
·
|
1,164 BOE/d average net production for 2013.
|
(In thousands)
|
||||||||||||
At December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Standardized measure of discounted net cash flows
|
$ | 104,853 | $ | 71,017 | $ | 62,191 | ||||||
Future income tax expense (discounted)
|
10,230 | 5,448 | 10,346 | |||||||||
PV-10
|
115,083 | 76,465 | 72,537 | |||||||||
·
|
unexpected drilling conditions;
|
·
|
inability to obtain required permits from State and Federal agencies;
|
·
|
inability to obtain, or limitations on, easements from land owners;
|
·
|
uncertainty regarding our operating partners drilling schedules;
|
·
|
high pressure or irregularities in geologic formations;
|
·
|
equipment failures;
|
·
|
title problems;
|
·
|
fires, explosions, blowouts, cratering, pollution, spills and other environmental risks or accidents;
|
·
|
changes in government regulations and issuance of local drilling restrictions or moratoria;
|
·
|
adverse weather;
|
·
|
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, and a reduction in cash available for investment in other programs.
|
·
|
We are paying the annual costs (approximately $1.7 million) to operate and maintain the water treatment plant and stormwater management system 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;
|
·
|
the approval of other participants in drilling wells; and
|
·
|
the operator’s selection of suitable technology.
|
·
|
the counter-party to the derivative instrument defaults on its contract obligations;
|
·
|
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
|
·
|
the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies.
|
·
|
acquired properties may not produce revenues, reserves, earnings or cash flow at anticipated levels, or at all;
|
·
|
we may assume liabilities that were not disclosed to us or that exceed our estimates;
|
·
|
we may be unable to integrate acquisitions successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and
|
·
|
acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.
|
·
|
price swings in the oil and gas commodities markets;
|
·
|
price and volume fluctuations in the stock market generally;
|
·
|
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,
|
||||||
2013
|
2012
|
2011
|
||||
Net proved reserves
|
||||||
Oil (Bbls)
|
||||||
Developed
|
1,875,528
|
1,770,659
|
1,884,068
|
|||
Undeveloped
|
1,584,187
|
842,984
|
853,930
|
|||
Total
|
3,459,715
|
2,613,643
|
2,737,998
|
|||
Natural gas (Mcf)
|
||||||
Developed
|
1,701,282
|
1,420,295
|
1,973,453
|
|||
Undeveloped
|
670,628
|
377,791
|
760,595
|
|||
Total
|
2,371,910
|
1,798,086
|
2,734,048
|
|||
Plant Products (Bbls)
|
||||||
Developed
|
--
|
--
|
1,688
|
|||
Undeveloped
|
--
|
--
|
--
|
|||
Total
|
--
|
--
|
1,688
|
|||
Total proved reserves (BOE)
|
3,855,033
|
2,913,324
|
3,195,361
|
|||
(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, 2013 are based on prices of $96.78 per barrel of oil and $3.67 per MMbtu of natural gas, in each case adjusted for regional price differentials and other factors.
|
December 31, 2013
|
BOE
|
|
Beginning of year
|
905,950
|
|
Conversion to Proved Developed Producing
|
(361,936)
|
|
Revisions of previous quantity estimates
|
(29,038)
|
|
Extensions, discoveries and improved recoveries
|
1,180,982
|
|
Purchase of reserves in place
|
--
|
|
Sales of reserves in place
|
--
|
|
End of year
|
1,695,958
|
|
December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Production Volume
|
||||||||||||
Oil (Bbls)
|
343,719 | 373,531 | 300,325 | |||||||||
Natural gas (Mcf)
|
408,352 | 347,810 | 736,261 | |||||||||
Natural gas liquids (Bbls)
|
13,155 | 13,203 | 19,325 | |||||||||
BOE
|
424,933 | 444,702 | 442,360 | |||||||||
Daily Average Production Volume
|
||||||||||||
Oil (Bbls/d)
|
942 | 1,021 | 823 | |||||||||
Natural gas (Mcf/d)
|
1,119 | 950 | 2,017 | |||||||||
Natural gas Liquids (Bbls/d)
|
36 | 36 | 53 | |||||||||
BOE/d
|
1,164 | 1,215 | 1,212 | |||||||||
Oil Price per Bbl Produced
|
||||||||||||
Realized Price
|
$ | 90.81 | $ | 82.38 | $ | 87.80 | ||||||
Natural Gas Price per Mcf Produced
|
||||||||||||
Realized Price
|
$ | 4.66 | $ | 3.25 | $ | 4.85 | ||||||
Natural Gas Liquids Price per Bbl Produced
|
||||||||||||
Realized Price
|
$ | 40.42 | $ | 47.84 | $ | 52.88 | ||||||
Average Sale Price per BOE
(1)
|
$ | 79.18 | $ | 73.16 | $ | 69.98 | ||||||
Expense per BOE
|
||||||||||||
Production costs
(2)
|
$ | 16.78 | $ | 16.42 | $ | 19.10 | ||||||
Depletion, depreciation and amortization
|
$ | 32.06 | $ | 33.49 | $ | 31.64 |
December 31,
|
||||||
2013
|
2012
|
2011
|
||||
Williston Basin
|
||||||
Oil (Bbls)
|
280,789
|
352,372
|
271,939
|
|||
Natural gas (Mcf)
|
145,586
|
124,077
|
129,635
|
|||
Natural gas liquids (Bbls)
|
9,654
|
12,113
|
--
|
|||
BOE
|
314,707
|
385,165
|
293,545
|
|||
Gulf Coast / South Texas
|
||||||
Oil (Bbls)
|
1,610
|
3,120
|
16,081
|
|||
Natural gas (Mcf)
|
190,311
|
194,888
|
590,982
|
|||
Natural gas liquids (Bbls)
|
124
|
477
|
19,325
|
|||
BOE
|
33,453
|
36,078
|
133,903
|
|||
Eagle Ford / Buda
|
||||||
Oil (Bbls)
|
53,603
|
10,283
|
4,290
|
|||
Natural gas (Mcf)
|
69,022
|
27,351
|
8,479
|
|||
Natural gas liquids (Bbls)
|
2,788
|
437
|
--
|
|||
BOE
|
67,895
|
15,279
|
5,703
|
|||
Austin Chalk
|
||||||
Oil (Bbls)
|
7,717
|
7,756
|
8,015
|
|||
Natural gas (Mcf)
|
3,433
|
1,494
|
7,165
|
|||
Natural gas liquids (Bbls)
|
589
|
176
|
--
|
|||
BOE
|
8,878
|
8,181
|
9,209
|
|||
Total
|
||||||
Oil (Bbls)
|
343,719
|
373,531
|
300,325
|
|||
Natural gas (Mcf)
|
408,352
|
347,810
|
736,261
|
|||
Natural gas liquids (Bbls)
|
13,155
|
13,203
|
19,325
|
|||
BOE
|
424,933
|
444,702
|
442,360
|
Years Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||
Development:
|
||||||||||||
Productive
|
15.00
|
1.33
|
11.00
|
1.76
|
1.00
|
0.25
|
||||||
Non-productive
|
--
|
--
|
--
|
--
|
--
|
--
|
||||||
15.00
|
1.33
|
11.00
|
1.76
|
1.00
|
0.25
|
|||||||
Exploratory:
|
||||||||||||
Productive
|
15.00
|
0.84
|
8.00
|
1.12
|
12.00
|
2.98
|
||||||
Non-productive
|
1.00
|
0.20
|
7.00
|
1.39
|
4.00
|
0.80
|
||||||
16.00
|
1.04
|
15.00
|
2.51
|
16.00
|
3.78
|
|||||||
Total
|
31.00
|
2.37
|
26.00
|
4.27
|
17.00
|
4.03
|
||||||
Gross Producing Wells
|
Net Producing Wells
|
Average Working Interest
(1)
|
||||
Oil
|
112.00
|
16.05
|
14.33%
|
|||
Natural Gas
|
1.00
|
0.17
|
17.00%
|
|||
Total
(1)
|
113.00
|
16.22
|
14.35%
|
|||
(1)
|
The average working interest for the ninety-one Williston Basin wells producing at December 31, 2013 is 11.46%; the remaining twenty-two wells (in Texas and Louisiana) have an average working interest of 26.28%.
|
Developed
|
Undeveloped
|
Total
|
|||||||
AREA
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||
Williston Basin
|
|||||||||
Rough Rider Prospect
(1)
|
19,200
|
1,175
|
--
|
--
|
19,200
|
1,175
|
|||
Yellowstone and SEHR Prospects
(1)
|
35,840
|
1,650
|
--
|
--
|
35,840
|
1,650
|
|||
ASEN North Dakota Acquisition
(1)
|
29,440
|
400
|
--
|
--
|
29,440
|
400
|
|||
Wolverine Prospect, Daniels County, MT
|
--
|
--
|
29,788
|
2,334
|
29,788
|
2,334
|
|||
East Texas and Louisiana
|
1,824
|
289
|
6,766
|
1,274
|
8,590
|
1,563
|
|||
Buda/Eagle Ford/Austin Chalk
|
|||||||||
Leona River Prospect
|
4,965
|
1,490
|
--
|
--
|
4,965
|
1,490
|
|||
Booth Tortuga Prospect
|
10,800
|
3,240
|
400
|
120
|
11,200
|
3,360
|
|||
Big Wells Prospect
|
120
|
18
|
4,123
|
618
|
4,243
|
636
|
|||
TOTAL
|
102,189
|
8,261
|
41,077
|
4,346
|
143,267
|
12,607
|
|||
(1)
The total gross acres for this area is calculated by multiplying the number of drilling units we participate in by 1,280 acres.
|
Williston Basin,
North Dakota and Montana
|
Buda / Eagle Ford / Austin Chalk,
Texas
|
East Texas
and Louisiana
|
TOTAL
|
||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||
2014
|
16,388
|
1,336
|
4,523
|
738
|
6,766
|
1,274
|
27,677
|
3,348
|
|||
2015
|
9,690
|
450
|
--
|
--
|
--
|
--
|
9,690
|
450
|
|||
2016
|
3,320
|
97
|
--
|
--
|
--
|
--
|
3,320
|
97
|
|||
2017
|
80
|
1
|
--
|
--
|
--
|
--
|
80
|
1
|
|||
29,478
|
1,884
|
4,523
|
738
|
6,766
|
1,274
|
40,767
|
3,896
|
||||
Acres
|
Claims
|
|||
Patented Claims / Fee Land
|
365
|
25
|
||
Unpatented Claims
|
5,923
|
664
|
||
Mill Site Claims
|
3,405
|
681
|
||
Fee Property
|
160
|
n/a
|
||
Total
|
9,853
|
1,370
|
||
·
|
$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 the time 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
|
High
|
Low
|
|||||||
Calendar year ended December 31, 2013
|
||||||||
First Quarter
|
$ | 2.50 | $ | 1.47 | ||||
Second Quarter
|
2.17 | 1.56 | ||||||
Third Quarter
|
2.24 | 1.82 | ||||||
Fourth Quarter
|
3.83 | 2.07 | ||||||
Calendar year ended December 31, 2012
|
||||||||
First Quarter
|
$ | 3.77 | $ | 2.85 | ||||
Second Quarter
|
3.14 | 2.15 | ||||||
Third Quarter
|
2.49 | 2.12 | ||||||
Fourth Quarter
|
2.18 | 1.50 |
(In thousands except per share data)
|
||||||||||||||||||||
For the years ended December 31,
|
||||||||||||||||||||
2013
|
2012
|
2011
|
2010
|
2009
|
||||||||||||||||
Operating revenues
|
$ | 33,647 | $ | 32,534 | $ | 30,958 | $ | 26,548 | $ | 7,581 | ||||||||||
Loss from continuing operations
|
(4,991 | ) | (10,344 | ) | (5,216 | ) | (986 | ) | (9,935 | ) | ||||||||||
Other income & expenses
|
(2,695 | ) | 849 | (717 | ) | (332 | ) | (1,331 | ) | |||||||||||
Loss before income taxes and discontinued operations
|
(7,686 | ) | (9,495 | ) | (5,933 | ) | (1,318 | ) | (11,266 | ) | ||||||||||
Benefit from income taxes
|
-- | 44 | 3,755 | 1,860 | 2,562 | |||||||||||||||
Discontinued operations, net of tax
|
307 | (1,794 | ) | (2,629 | ) | (1,314 | ) | 526 | ||||||||||||
Net loss
|
$ | (7,379 | ) | $ | (11,245 | ) | $ | (4,807 | ) | $ | (772 | ) | $ | (8,178 | ) | |||||
Per share financial data
|
||||||||||||||||||||
Operating revenues
|
$ | 1.22 | $ | 1.18 | $ | 1.14 | $ | 0.99 | $ | 0.35 | ||||||||||
Loss from continuing operations
|
(0.18 | ) | (0.38 | ) | (0.19 | ) | (0.04 | ) | (0.46 | ) | ||||||||||
Other income & expenses
|
(0.10 | ) | 0.03 | (0.03 | ) | (0.01 | ) | (0.06 | ) | |||||||||||
Gain (loss) before income taxes and discontinued operations
|
(0.28 | ) | (0.34 | ) | (0.22 | ) | (0.05 | ) | (0.52 | ) | ||||||||||
Benefit from income taxes
|
-- | -- | 0.14 | 0.07 | 0.12 | |||||||||||||||
Discontinued operations, net of tax
|
0.01 | (0.07 | ) | (0.10 | ) | (0.05 | ) | 0.02 | ||||||||||||
Net loss per share basic and diluted
|
$ | (0.27 | ) | $ | (0.41 | ) | $ | (0.18 | ) | $ | (0.03 | ) | $ | (0.38 | ) | |||||
Basic shares outstanding
|
27,678,698 | 27,466,549 | 27,238,869 | 26,763,995 | 21,604,959 | |||||||||||||||
Diluted shares outstanding
|
27,678,698 | 27,466,549 | 27,238,869 | 26,763,995 | 21,604,959 |
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Unproved oil and gas properties
|
$ | 7,478 | $ | 9,169 | ||||
Proved oil and gas properties
|
79,444 | 76,465 | ||||||
Undeveloped mining properties
|
20,739 | 20,739 | ||||||
$ | 107,661 | $ | 106,373 | |||||
December 31,
|
|||||||
2013
|
2012
|
||||||
Gross
|
Net
(1)
|
Gross
|
Net
(1)
|
||||
Williston Basin:
|
|||||||
Productive wells
|
91.00
|
10.43
|
66.00
|
10.61
|
|||
Wells being drilled or awaiting completion
|
10.00
|
0.27
|
4.00
|
0.20
|
|||
Gulf Coast/South Texas:
|
|||||||
Productive wells
|
3.00
|
0.56
|
3.00
|
0.56
|
|||
Wells being drilled or awaiting completion
|
--
|
--
|
--
|
--
|
|||
Eagle Ford/Buda:
|
|||||||
Productive wells
|
8.00
|
2.25
|
3.00
|
0.90
|
|||
Wells being drilled or awaiting completion
|
1.00
|
0.30
|
--
|
--
|
|||
Austin Chalk:
|
|||||||
Productive wells
|
11.00
|
2.98
|
11.00
|
2.98
|
|||
Wells being drilled or awaiting completion
|
--
|
--
|
--
|
--
|
|||
Total:
|
|||||||
Productive wells
|
113.00
|
16.22
|
83.00
|
15.05
|
|||
Wells being drilled or awaiting completion
|
11.00
|
0.57
|
4.00
|
0.20
|
(1)
|
Net working interests may vary over time under the terms of the applicable contracts.
|
Williston Basin
|
Gulf Coast / South Texas
|
Eagle Ford /
Buda
|
Austin Chalk
|
Total
|
||||||
2013 Production
|
||||||||||
Oil (Bbl)
|
280,789
|
1,610
|
53,603
|
7,717
|
343,719
|
|||||
Gas (Mcf)
|
145,586
|
190,311
|
69,022
|
3,433
|
408,352
|
|||||
NGLs (Bbl)
|
9,654
|
124
|
2,788
|
589
|
13,155
|
|||||
Equivalent (BOE)
|
314,707
|
33,453
|
67,895
|
8,878
|
424,933
|
|||||
Avg. Daily Equivalent (BOE/d)
|
862
|
92
|
186
|
24
|
1,164
|
|||||
Relative percentage
|
74%
|
8%
|
16%
|
2%
|
100%
|
For the Three Months Ended
|
||||||||||||||||
December 31,
2013
|
September 30,
2013
|
June 30,
2013
|
March 31,
2013
|
|||||||||||||
(in Thousands, except for production data)
|
||||||||||||||||
Production (BOE)
|
123,246 | 101,987 | 101,026 | 98,674 | ||||||||||||
Oil, gas and NGL production revenue
|
$ | 9,271 | $ | 8,582 | $ | 7,915 | $ | 7,879 | ||||||||
Unrealized and realized derivative gain (loss)
|
$ | 255 | $ | (1,075 | ) | $ | 347 | $ | (602 | ) | ||||||
Lease operating expense
|
$ | 1,393 | $ | 2,006 | $ | 1,765 | $ | 1,966 | ||||||||
Production taxes
|
$ | 835 | $ | 871 | $ | 800 | $ | 833 | ||||||||
DD&A
|
$ | 3,744 | $ | 3,205 | $ | 3,213 | $ | 3,461 | ||||||||
General and administrative
|
$ | 1,710 | $ | 1,337 | $ | 1,319 | $ | 1,307 | ||||||||
Mineral holding costs
|
$ | 294 | $ | 410 | $ | 297 | $ | 227 | ||||||||
Water treatment plant
|
$ | 603 | $ | 394 | $ | 403 | $ | 417 | ||||||||
Income (loss) from continuing operations
|
$ | (1,217 | ) | $ | (706 | ) | $ | 367 | $ | (6,130 | ) |
Three Months Ended
|
||||||||||||
December 31,
|
Increase
|
|||||||||||
2013
|
2012
|
(Decrease)
|
||||||||||
Production volumes
|
||||||||||||
Oil (Bbls)
|
96,399 | 90,798 | 5,601 | |||||||||
Natural gas (Mcf)
|
127,933 | 84,879 | 43,054 | |||||||||
Natural gas liquids (Bbls)
|
5,525 | 2,878 | 2,647 | |||||||||
Equivalent (BOE)
|
123,246 | 107,823 | 15,424 | |||||||||
Avg. Daily Equivalent (BOE/d)
|
1,340 | 1,172 | 168 | |||||||||
Average sales prices
|
||||||||||||
Oil (per Bbl)
|
$ | 87.26 | $ | 83.39 | $ | 3.87 | ||||||
Natural gas (per Mcf)
|
5.05 | 3.83 | 1.22 | |||||||||
Natural gas liquids (per Bbl)
|
38.55 | 49.00 | (10.45 | ) | ||||||||
Equivalent (BOE)
|
75.22 | 74.55 | 0.68 | |||||||||
Operating revenues (in thousands)
|
||||||||||||
Oil
|
$ | 8,412 | $ | 7,572 | $ | 840 | ||||||
Natural gas
|
646 | 325 | 321 | |||||||||
Natural gas liquids
|
213 | 141 | 72 | |||||||||
Total operating revenue
|
9,271 | 8,038 | 1,233 | |||||||||
Lease operating expense
|
(1,393 | ) | (1,969 | ) | 576 | |||||||
Production taxes
|
(835 | ) | (854 | ) | 19 | |||||||
Impairment
|
-- | (4,666 | ) | 4,666 | ||||||||
Income before depreciation, depletion and amortization
|
7,043 | 549 | 6,494 | |||||||||
Depreciation, depletion and amortization
|
(3,744 | ) | (3,812 | ) | 68 | |||||||
Income
|
$ | 3,299 | $ | (3,263 | ) | $ | 6,562 | |||||
Year Ended
|
||||||||||||
December 31,
|
Increase
|
|||||||||||
2013
|
2012
|
(Decrease)
|
||||||||||
Production volumes
|
||||||||||||
Oil (Bbls)
|
343,719 | 373,531 | (29,812 | ) | ||||||||
Natural gas (Mcf)
|
408,352 | 347,811 | 60,541 | |||||||||
Natural gas liquids (Bbls)
|
13,155 | 13,203 | (48 | ) | ||||||||
Equivalent (BOE)
|
424,933 | 444,702 | (19,770 | ) | ||||||||
Avg. Daily Equivalent (BOE/d)
|
1,164 | 1,215 | (51 | ) | ||||||||
Average sales prices
|
||||||||||||
Oil (per Bbl)
|
$ | 90.81 | $ | 82.38 | $ | 8.43 | ||||||
Natural gas (per Mcf)
|
4.66 | 3.25 | 1.41 | |||||||||
Natural gas liquids (per Bbl)
|
40.44 | 47.79 | (7.35 | ) | ||||||||
Equivalent (BOE)
|
79.18 | 73.16 | 6.03 | |||||||||
Operating revenues (in thousands)
|
||||||||||||
Oil
|
$ | 31,214 | $ | 30,772 | $ | 442 | ||||||
Natural gas
|
1,901 | 1,131 | 771 | |||||||||
Natural gas liquids
|
532 | 631 | (99 | ) | ||||||||
Total operating revenue
|
33,647 | 32,534 | 1,114 | |||||||||
Lease operating expense
|
(7,130 | ) | (7,301 | ) | 171 | |||||||
Production taxes
|
(3,339 | ) | (3,487 | ) | 148 | |||||||
Impairment
|
(5,828 | ) | (5,189 | ) | (639 | ) | ||||||
Income before depreciation, depletion and amortization
|
17,350 | 16,557 | 794 | |||||||||
Depreciation, depletion and amortization
|
(13,623 | ) | (14,893 | ) | 1,270 | |||||||
Income
|
$ | 3,727 | $ | 1,664 | $ | 2,064 | ||||||
Year Ended
|
||||||||||||
December 31,
|
Increase
|
|||||||||||
2012
|
2011
|
(Decrease)
|
||||||||||
Production volumes
|
||||||||||||
Oil (Bbls)
|
373,531 | 300,329 | 73,202 | |||||||||
Natural gas (Mcf)
|
347,811 | 736,261 | (388,450 | ) | ||||||||
Natural gas liquids (Bbls)
|
13,203 | 19,325 | (6,122 | ) | ||||||||
Equivalent (BOE)
|
444,702 | 442,364 | 2,338 | |||||||||
Avg. Daily Equivalent (BOE/d)
|
1,215 | 1,212 | 3 | |||||||||
Average sales prices
|
||||||||||||
Oil (per Bbl)
|
$ | 82.38 | $ | 87.80 | $ | (5.42 | ) | |||||
Natural gas (per Mcf)
|
3.25 | 4.85 | (1.59 | ) | ||||||||
Natural gas liquids (per Bbl)
|
47.79 | 52.88 | (5.09 | ) | ||||||||
Operating revenues (in thousands)
|
||||||||||||
Oil
|
$ | 30,772 | $ | 26,368 | $ | 4,404 | ||||||
Natural gas
|
1,131 | 3,568 | (2,437 | ) | ||||||||
Natural gas liquids
|
631 | 1,022 | (391 | ) | ||||||||
Total operating revenue
|
32,534 | 30,958 | 1,576 | |||||||||
Lease operating expense
|
(7,301 | ) | (8,450 | ) | 1,149 | |||||||
Production taxes
|
(3,487 | ) | (3,102 | ) | (385 | ) | ||||||
Impairment
|
(5,189 | ) | -- | (5,189 | ) | |||||||
Income before depreciation, depletion and amortization
|
16,557 | 19,406 | (2,849 | ) | ||||||||
Depreciation, depletion and amortization
|
(14,893 | ) | (13,997 | ) | (896 | ) | ||||||
Income
|
$ | 1,664 | $ | 5,409 | $ | (3,745 | ) | |||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Current ratio
(1)
|
1.83 to 1
|
1.96 to 1
|
||||||
Working capital
(2)
|
$ | 5,970 | $ | 12,762 | ||||
Total debt
|
$ | 9,000 | $ | 10,200 | ||||
Total cash and marketable securities less debt
|
$ | (3,076 | ) | $ | (7,192 | ) | ||
Total stockholders' equity
|
$ | 109,057 | $ | 116,117 | ||||
Total debt to equity
|
0.08 to 1
|
0.09 to 1
|
||||||
Total liabilities to equity
|
0.16 to 1
|
0.21 to 1
|
||||||
(1)
Current assets divided by current liabilities
|
||||||||
(2)
Current assets less current liabilities
|
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2013
|
2012
|
Change
|
||||||||||
Net cash provided by operating activities
|
$ | 17,098 | $ | 13,139 | $ | 3,951 | ||||||
Net cash (used in) provided by investing activities
|
(18,219 | ) | (20,877 | ) | 2,658 | |||||||
Net cash (used in) financing activities
|
(10,821 | ) | (2,433 | ) | (8,388 | ) |
(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
|
$ | 9,000 | $ | -- | $ | -- | $ | 9,000 | $ | -- | ||||||||||
Executive retirement
|
865 | 159 | 202 | -- | 505 | |||||||||||||||
Asset retirement obligation
|
812 | 96 | 16 | 51 | 650 | |||||||||||||||
Totals
|
$ | 10,677 | $ | 255 | $ | 218 | $ | 9,051 | $ | 1,155 | ||||||||||
Quantity
|
|||||||||||||
Settlement Period
|
Counterparty
|
Basis
|
(Bbls/day)
|
Strike Price
|
|||||||||
Crude Oil Costless Collar
|
|||||||||||||
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
Call:
|
$ | 95.00 | |||||||||||
Crude Oil Costless Collar
|
|||||||||||||
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
Call:
|
$ | 97.25 | |||||||||||
Crude Oil Costless Collar
|
|||||||||||||
07/01/14 - 12/31/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
Call:
|
$ | 98.40 |
Quantity
|
|||||||||||||
Settlement Period
|
Counterparty
|
Basis
|
(Bbls/day)
|
Strike Price
|
|||||||||
Crude Oil Costless Collar
|
|||||||||||||
07/01/14 - 12/31/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
Call:
|
$ | 97.40 |
Page
|
|
Report of Independent Registered Public Accounting Firm
|
75
|
Financial Statements
|
|
Consolidated Balance Sheets as of December 31, 2013 and 2012
|
76
|
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011
|
78
|
Consolidated Statements of Comprehensive Loss
|
80
|
Statement of Stockholders’ Equity
|
81
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011
|
84
|
Notes to Consolidated Financial Statements
|
86
|
U.S. ENERGY CORP.
|
||||||||
CONSOLIDATED BALANCE SHEETS
|
||||||||
ASSETS
|
||||||||
(In thousands, except shares)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$ | 5,855 | $ | 2,825 | ||||
Available for sale securities
|
69 | 183 | ||||||
Accounts receivable trade
|
6,801 | 5,182 | ||||||
Commodity risk management asset
|
14 | 472 | ||||||
Assets held for sale
|
-- | 17,051 | ||||||
Other current assets
|
422 | 302 | ||||||
Total current assets
|
13,161 | 26,015 | ||||||
Investment
|
-- | 2,264 | ||||||
Properties and equipment
|
||||||||
Oil & gas properties under full cost method,
|
||||||||
net of $57,077 and $43,454 accumulated
|
||||||||
depletion, depreciation and amortization
|
86,922 | 85,634 | ||||||
Undeveloped mining claims
|
20,739 | 20,739 | ||||||
Property, plant and equipment, net
|
4,199 | 4,435 | ||||||
Net properties and equipment
|
111,860 | 110,808 | ||||||
Other assets
|
1,780 | 1,740 | ||||||
Total assets
|
$ | 126,801 | $ | 140,827 | ||||
U.S. ENERGY CORP.
|
||||||||
CONSOLIDATED BALANCE SHEETS
|
||||||||
LIABILITIES AND SHAREHOLDERS' EQUITY
|
||||||||
(In thousands, except shares)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Current liabilities:
|
||||||||
Accounts payable
|
$ | 6,167 | $ | 2,692 | ||||
Accrued compensation
|
580 | 295 | ||||||
Commodity risk management liability
|
280 | -- | ||||||
Current portion of debt
|
-- | 200 | ||||||
Liabilities held for sale
|
-- | 10,022 | ||||||
Other current liabilities
|
164 | 44 | ||||||
Total current liabilities
|
7,191 | 13,253 | ||||||
Long-term debt, net of current portion
|
9,000 | 10,000 | ||||||
Asset retirement obligations
|
812 | 686 | ||||||
Other accrued liabilities
|
741 | 771 | ||||||
Commitment and contingencies (Note L)
|
||||||||
Shareholders' equity
|
||||||||
Common stock, $.01 par value; unlimited shares
|
||||||||
authorized; 27,735,878 and 27,652,602
|
||||||||
shares issued, respectively
|
277 | 277 | ||||||
Additional paid-in capital
|
123,510 | 123,078 | ||||||
Accumulated deficit
|
(14,718 | ) | (7,339 | ) | ||||
Other comprehensive (loss) income
|
(12 | ) | 101 | |||||
Total shareholders' equity
|
109,057 | 116,117 | ||||||
Total liabilities and shareholders' equity
|
$ | 126,801 | $ | 140,827 | ||||
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS
|
||||||||||||
(In thousands except per share data)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Oil, gas, and NGL production revenues:
|
$ | 33,647 | $ | 32,534 | $ | 30,958 | ||||||
Operating expenses:
|
||||||||||||
Oil and gas
|
10,469 | 10,788 | 11,552 | |||||||||
Oil and gas depreciation, depletion
|
||||||||||||
and amortization
|
13,623 | 14,893 | 13,997 | |||||||||
Impairment of oil and gas properties
|
5,828 | 5,189 | -- | |||||||||
Water treatment plant
|
1,817 | 1,978 | 1,878 | |||||||||
Mineral holding costs
|
1,228 | 921 | 486 | |||||||||
General and administrative
|
5,673 | 6,810 | 8,261 | |||||||||
Impairment of corporate aircraft
|
-- | 2,299 | -- | |||||||||
38,638 | 42,878 | 36,174 | ||||||||||
Loss from operations
|
(4,991 | ) | (10,344 | ) | (5,216 | ) | ||||||
Other income and expenses:
|
||||||||||||
Realized (loss) gain on risk
|
||||||||||||
management activities
|
(338 | ) | 21 | (1,974 | ) | |||||||
Unrealized (loss) gain on risk
|
||||||||||||
management activities
|
(737 | ) | 1,070 | 1,126 | ||||||||
Gain (loss) on the sale of assets
|
760 | (12 | ) | 137 | ||||||||
Equity loss in unconsolidated investment
|
(104 | ) | (359 | ) | (211 | ) | ||||||
Impairment of unconsolidated investment
|
(2,160 | ) | -- | -- | ||||||||
Gain on sale of marketable securities
|
-- | 82 | 529 | |||||||||
Miscellaneous income
|
160 | 241 | (38 | ) | ||||||||
Interest income
|
8 | 9 | 40 | |||||||||
Interest expense
|
(284 | ) | (203 | ) | (326 | ) | ||||||
(2,695 | ) | 849 | (717 | ) | ||||||||
Loss before income taxes
|
||||||||||||
and discontinued operations
|
(7,686 | ) | (9,495 | ) | (5,933 | ) |
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS
|
||||||||||||
(In thousands except per share data)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Income taxes:
|
||||||||||||
Current (provision for)
|
-- | (104 | ) | -- | ||||||||
Deferred benefit from
|
-- | 148 | 3,755 | |||||||||
-- | 44 | 3,755 | ||||||||||
Loss from continuing operations
|
(7,686 | ) | (9,451 | ) | (2,178 | ) | ||||||
Discontinued operations:
|
||||||||||||
Discontinued operations, net of taxes
|
427 | 97 | 434 | |||||||||
Loss on sale of discontinued
|
||||||||||||
operations, net of taxes
|
(120 | ) | -- | -- | ||||||||
Impairment on discontinued
|
||||||||||||
operations, net of taxes
|
-- | (1,891 | ) | (3,063 | ) | |||||||
307 | (1,794 | ) | (2,629 | ) | ||||||||
Net loss
|
$ | (7,379 | ) | $ | (11,245 | ) | $ | (4,807 | ) | |||
Net income (loss) per share basic and diluted
|
||||||||||||
Loss from continuing operations
|
$ | (0.28 | ) | $ | (0.34 | ) | $ | (0.08 | ) | |||
Income (loss) from discontinued operations
|
0.01 | (0.07 | ) | (0.10 | ) | |||||||
Net (loss) per share
|
$ | (0.27 | ) | $ | (0.41 | ) | $ | (0.18 | ) | |||
Weighted average shares outstanding
|
||||||||||||
Basic and Diluted
|
27,678,698 | 27,466,549 | 27,238,869 | |||||||||
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
|
||||||||||||
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Net (loss)
|
$ | (7,379 | ) | $ | (11,245 | ) | $ | (4,807 | ) | |||
Other comprehensive (loss) income:
|
||||||||||||
Marketable securities, net of tax
|
(113 | ) | 23 | (564 | ) | |||||||
Total comprehensive (loss)
|
$ | (7,492 | ) | $ | (11,222 | ) | $ | (5,371 | ) | |||
U.S. ENERGY CORP
|
||||||||||||||||||||||||
STATEMENT OF SHAREHOLDERS' EQUITY
|
||||||||||||||||||||||||
(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, 2011
|
27,068,610 | $ | 271 | $ | 121,062 | $ | 8,713 | $ | 642 | $ | 130,688 | |||||||||||||
Net loss
|
-- | -- | -- | (4,807 | ) | -- | (4,807 | ) | ||||||||||||||||
Recognized gain on
|
||||||||||||||||||||||||
marketable securities
|
-- | -- | -- | -- | (850 | ) | (850 | ) | ||||||||||||||||
Unrecognized loss on
|
||||||||||||||||||||||||
marketable securities
|
-- | -- | -- | -- | (30 | ) | (30 | ) | ||||||||||||||||
Unrealized tax effect on
|
||||||||||||||||||||||||
the unrealized gain
|
-- | -- | -- | -- | 316 | 316 | ||||||||||||||||||
Funding of ESOP
|
98,958 | 1 | 287 | -- | -- | 288 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
2001 stock compensation plan
|
75,000 | 1 | 369 | -- | -- | 370 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock options
|
124,444 | 1 | (209 | ) | -- | -- | (208 | ) | ||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock warrants
|
42,896 | -- | 61 | -- | -- | 61 | ||||||||||||||||||
Vesting of stock options
|
-- | -- | 947 | -- | -- | 947 | ||||||||||||||||||
Vesting of stock warrants
|
-- | -- | 6 | -- | -- | 6 | ||||||||||||||||||
Balance December 31, 2011
|
27,409,908 | 274 | 122,523 | 3,906 | 78 | 126,781 | ||||||||||||||||||
U.S. ENERGY CORP
|
||||||||||||||||||||||||
STATEMENT OF SHAREHOLDERS' EQUITY
|
||||||||||||||||||||||||
(continued)
|
||||||||||||||||||||||||
(In thousands except share data)
|
||||||||||||||||||||||||
Unrealized
|
||||||||||||||||||||||||
Additional
|
Gain (Loss) on
|
Total
|
||||||||||||||||||||||
Common Stock
|
Paid-In
|
Accumulated
|
Marketable
|
Shareholders'
|
||||||||||||||||||||
Shares
|
Amount
|
Capital
|
Deficit
|
Securities
|
Equity
|
|||||||||||||||||||
Balance December 31, 2011
|
27,409,908 | 274 | 122,523 | 3,906 | 78 | 126,781 | ||||||||||||||||||
Net loss
|
-- | -- | -- | (11,245 | ) | -- | (11,245 | ) | ||||||||||||||||
Recognized gain on
|
||||||||||||||||||||||||
marketable securities
|
-- | -- | -- | -- | (54 | ) | (54 | ) | ||||||||||||||||
Unrecognized loss on
|
||||||||||||||||||||||||
marketable securities
|
-- | -- | -- | -- | 90 | 90 | ||||||||||||||||||
Unrealized tax effect on
|
||||||||||||||||||||||||
the unrealized gain
|
-- | -- | -- | -- | (13 | ) | (13 | ) | ||||||||||||||||
Funding of ESOP
|
161,624 | 2 | 241 | -- | -- | 243 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
2001 stock compensation plan
|
60,000 | 1 | 162 | -- | -- | 163 | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock options
|
1,070 | -- | -- | -- | -- | -- | ||||||||||||||||||
Issuance of common stock
|
||||||||||||||||||||||||
from stock warrants
|
20,000 | -- | 50 | -- | -- | 50 | ||||||||||||||||||
Vesting of stock options
|
-- | -- | 33 | -- | -- | 33 | ||||||||||||||||||
Vesting of stock warrants
|
-- | -- | 69 | -- | -- | 69 | ||||||||||||||||||
Balance December 31, 2012
|
27,652,602 | 277 | 123,078 | (7,339 | ) | 101 | 116,117 | |||||||||||||||||
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Cash flows from operating activities:
|
||||||||||||
Net (loss)
|
$ | (7,379 | ) | $ | (11,245 | ) | $ | (4,807 | ) | |||
(Gain) loss from discontinued operations includes
|
||||||||||||
non-cash impairment of $2,955, $3,063, and $1,540
|
(307 | ) | 1,794 | 2,629 | ||||||||
Loss from continuing operations
|
(7,686 | ) | (9,451 | ) | (2,178 | ) | ||||||
Adjustments to reconcile net (loss) income to
|
||||||||||||
net cash provided by operations
|
||||||||||||
Depreciation, depletion & amortization
|
13,898 | 15,457 | 14,593 | |||||||||
Change in fair value of commodity price
|
||||||||||||
risk management activities, net
|
737 | (1,070 | ) | (1,126 | ) | |||||||
Impairment of oil and gas properties
|
5,828 | 5,189 | -- | |||||||||
Impairment of equity investment
|
2,160 | -- | -- | |||||||||
Impairment of corporate aircraft
|
-- | 2,299 | -- | |||||||||
Gain on sale of marketable securities
|
-- | (82 | ) | (529 | ) | |||||||
Equity loss from Standard Steam
|
104 | 359 | 211 | |||||||||
Net change in deferred income taxes
|
-- | (60 | ) | (3,990 | ) | |||||||
(Gain) loss on sale of assets
|
(760 | ) | 12 | (137 | ) | |||||||
Noncash compensation
|
452 | 518 | 1,604 | |||||||||
Noncash services
|
64 | 69 | 6 | |||||||||
Net changes in assets and liabilities
|
||||||||||||
Accounts receivable
|
(1,619 | ) | 315 | (1,493 | ) | |||||||
Income tax receivable
|
-- | 113 | (9 | ) | ||||||||
Other current assets
|
8 | 230 | 148 | |||||||||
Accounts payable
|
3,617 | (476 | ) | (3,368 | ) | |||||||
Accrued compensation expense
|
172 | (336 | ) | (1,194 | ) | |||||||
Other liabilities
|
123 | 53 | 29 | |||||||||
Net cash provided by operating activities
|
17,098 | 13,139 | 2,567 | |||||||||
Cash flows from investing activities:
|
||||||||||||
Net redemption of treasury investments
|
-- | -- | 17,843 | |||||||||
Acquisition & development of oil & gas properties
|
(20,757 | ) | (42,311 | ) | (50,265 | ) | ||||||
Acquisition & development of mining properties
|
-- | -- | (221 | ) | ||||||||
Mining property option payment
|
-- | -- | 354 | |||||||||
Acquisition of property and equipment
|
(42 | ) | (102 | ) | (42 | ) | ||||||
Proceeds from sale of oil and gas properties
|
-- | 21,475 | 13,574 | |||||||||
Proceeds from sale of marketable securities
|
-- | 101 | 846 | |||||||||
Proceeds from sale of property and equipment
|
2,628 | 76 | 147 | |||||||||
Net change in restricted investments
|
(48 | ) | (116 | ) | (11 | ) | ||||||
Net cash used in investing activities:
|
(18,219 | ) | (20,877 | ) | (17,775 | ) | ||||||
U.S. ENERGY CORP.
|
||||||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Cash flows from financing activities:
|
||||||||||||
Issuance of common stock
|
-- | 51 | (146 | ) | ||||||||
Proceeds from new debt
|
2,000 | 10,000 | 33,069 | |||||||||
Repayments of debt
|
(12,821 | ) | (12,484 | ) | (11,365 | ) | ||||||
Net cash (used in) provided by financing activities
|
(10,821 | ) | (2,433 | ) | 21,558 | |||||||
Net cash provided by operating activities
|
||||||||||||
of discontinued operations
|
317 | 122 | 767 | |||||||||
Net cash provided by (used in) investing activities
|
||||||||||||
of discontinued operations
|
14,655 | -- | (55 | ) | ||||||||
Net cash (used in) provided by discontinued operations
|
14,972 | 122 | 712 | |||||||||
Net (decrease) increase in cash and cash equivalents
|
3,030 | (10,049 | ) | 7,062 | ||||||||
Cash and cash equivalents at beginning of year
|
2,825 | 12,874 | 5,812 | |||||||||
Cash and cash equivalents at end of year
|
$ | 5,855 | $ | 2,825 | $ | 12,874 | ||||||
Supplemental disclosures:
|
||||||||||||
Income tax paid
|
$ | -- | $ | -- | $ | -- | ||||||
Interest paid
|
$ | 274 | $ | 179 | $ | 290 | ||||||
Non-cash investing and financing activities:
|
||||||||||||
Unrealized gain on marketable securities
|
$ | 12 | $ | 101 | $ | 78 | ||||||
Acquisition and development of oil and gas
|
||||||||||||
properties through accounts payable
|
$ | 142 | $ | 6,202 | $ | 2,092 | ||||||
Additions to oil and gas properties
|
||||||||||||
through asset retirement obligations
|
$ | 131 | $ | 142 | $ | 186 | ||||||
Marketable Securities
|
Accounts Receivable
|
Restricted Investments
|
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Oil & Gas properties
|
||||||||
Unproved
|
$ | 7,478 | $ | 9,169 | ||||
Proved
|
136,521 | 119,919 | ||||||
143,999 | 129,088 | |||||||
Less accumulated depreciation
|
||||||||
depletion and amortization
|
(57,077 | ) | (43,454 | ) | ||||
Net book value
|
86,922 | 85,634 | ||||||
Mineral properties
|
20,739 | 20,739 | ||||||
Building, land and equipment
|
8,334 | 8,469 | ||||||
Less accumulated depreciation
|
(4,135 | ) | (4,034 | ) | ||||
Net book value
|
4,199 | 4,435 | ||||||
Totals
|
$ | 111,860 | $ | 110,808 | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Costs associated with Mount Emmons
|
||||||||
beginning of year
|
$ | 20,739 | $ | 20,739 | ||||
Development costs
|
-- | -- | ||||||
Costs at the end of the period
|
$ | 20,739 | $ | 20,739 | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Assets held for sale
|
||||||||
Remington Village
|
$ | -- | $ | 15,167 | ||||
Corporate aircraft and facilities
|
-- | 1,884 | ||||||
$ | -- | $ | 17,051 | |||||
Liabilities held for sale
|
||||||||
Remington Village
|
$ | -- | $ | 10,022 | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Beginning asset retirement obligation
|
$ | 686 | $ | 510 | ||||
Accretion of discount
|
38 | 34 | ||||||
Liabilities incurred
|
131 | 142 | ||||||
Liabilities settled
|
(43 | ) | -- | |||||
Ending asset retirement obligation
|
$ | 812 | $ | 686 | ||||
Mineral properties
|
$ | 175 | $ | 162 | ||||
Oil & Gas wells
|
637 | 524 | ||||||
Ending asset retirement obligation
|
$ | 812 | $ | 686 | ||||
Year Ended December 31,
|
||||||
2013
|
2012
|
2011
|
||||
Risk-free interest rate
|
1.66%
|
0.82% to 1.41%
|
1.77%
|
|||
Expected lives (years)
|
6.0
|
5.0 to 6.0
|
6.0
|
|||
Expected volatility
|
62.59%
|
61.87% to 63.59%
|
59.64%
|
|||
Expected dividend yield
|
--
|
--
|
--
|
Income Taxes
|
(In thousands)
|
||||||||||||||||
Fair Value Measurements at December 31, 2013 Using
|
||||||||||||||||
December 31,
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
|||||||||||||
Description
|
2013
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
Commodity risk management assets
|
$ | 14 | $ | -- | $ | 14 | $ | -- | ||||||||
Available for sale securities
|
69 | 69 | -- | -- | ||||||||||||
Total assets
|
$ | 83 | $ | 69 | $ | 14 | $ | -- | ||||||||
Commodity risk management liability
|
$ | 280 | $ | -- | $ | 280 | $ | -- | ||||||||
Other accrued liabilities
1
|
741 | -- | -- | 741 | ||||||||||||
Total liabilities
|
$ | 1,021 | $ | -- | $ | 280 | $ | 741 | ||||||||
1
Other accrued liabilities is the company's liability for its executive retirement program
|
Change in Level 3 Fair Value Measurements
|
||||||||||||||||
(In thousands)
|
||||||||||||||||
December 31,
|
Sale of
|
December 31,
|
||||||||||||||
Description
|
2012
|
Assets
|
Revision of Value
|
2013
|
||||||||||||
Assets held for sale
|
||||||||||||||||
Remington Village
|
$ | 15,167 | $ | (15,167 | ) | $ | -- | $ | -- | |||||||
Corporate aircraft and facilities
|
1,884 | (1,884 | ) | -- | -- | |||||||||||
Total
|
$ | 17,051 | $ | (17,051 | ) | $ | -- | $ | -- | |||||||
December 31,
|
Additions and
|
December 31,
|
||||||||||||||
Description
|
2012 |
Payments
|
Revision of Value
|
2013 | ||||||||||||
Other accrued liabilities
|
$ | 771 | $ | (30 | ) | $ | -- | $ | 741 | |||||||
(In thousands)
|
||||||||||||
December 31, 2013
|
||||||||||||
Unrealized
|
||||||||||||
Description of Securities
|
Cost
|
Gain
|
Fair Value
|
|||||||||
Available for sale securities
|
$ | 24 | $ | 45 | $ | 69 | ||||||
Total
|
$ | 24 | $ | 45 | $ | 69 | ||||||
December 31, 2012
|
||||||||||||
Unrealized
|
||||||||||||
Description of Securities
|
Cost
|
Gain
|
Fair Value
|
|||||||||
Available for sale securities
|
$ | 24 | $ | 159 | $ | 183 | ||||||
Total
|
$ | 24 | $ | 159 | $ | 183 | ||||||
Quantity
|
|||||||||||||
Settlement Period
|
Counterparty
|
Basis
|
(Bbls/day)
|
Strike Price
|
|||||||||
Crude Oil Costless Collar
|
|||||||||||||
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
Call:
|
$ | 95.00 | |||||||||||
Crude Oil Costless Collar
|
|||||||||||||
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
Call:
|
$ | 97.25 | |||||||||||
Crude Oil Costless Collar
|
|||||||||||||
07/01/14 - 12/31/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
Call:
|
$ | 98.40 |
As of December 31, 2013
|
||||||||||
(in thousands)
|
||||||||||
Derivative Assets
|
Derivative Liabilities
|
|||||||||
Balance Sheet
|
Fair
|
Balance Sheet
|
Fair
|
|||||||
Classification
|
Value
|
Classification
|
Value
|
|||||||
Crude oil costless collars
|
Current Asset
|
$ | 14 |
Current Liability
|
$ | 280 | ||||
As of December 31, 2012
|
||||||||||
(in thousands)
|
||||||||||
Balance Sheet
|
Fair
|
Balance Sheet
|
Fair
|
|||||||
Classification
|
Value
|
Classification
|
Value
|
|||||||
Crude oil costless collars
|
Current Asset
|
$ | 472 |
Current Liability
|
$ | -- | ||||
(In thousands)
|
||||||||||||
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Realized derivative gain (loss)
|
$ | (338 | ) | $ | 21 | $ | (1,974 | ) | ||||
Unrealized derivative gain (loss)
|
$ | (737 | ) | $ | 1,070 | $ | 1,126 | |||||
Total realized and unrealized derivative gain (loss)
|
$ | (1,075 | ) | $ | 1,091 | $ | (848 | ) | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Unproved oil and gas properties
|
$ | 7,478 | $ | 9,169 | ||||
Proved oil and gas properties
|
136,521 | 119,919 | ||||||
$ | 143,999 | $ | 129,088 | |||||
(In thousands)
|
||||||||||||||||
Acquisitions
|
Exploration
|
Development
|
Total
|
|||||||||||||
2010
|
$ | 134 | $ | -- | $ | -- | $ | 134 | ||||||||
2011
|
5,006 | -- | -- | 5,006 | ||||||||||||
2012
|
271 | -- | -- | 271 | ||||||||||||
2013
|
2,067 | -- | -- | 2,067 | ||||||||||||
Total
|
$ | 7,478 | $ | -- | $ | -- | $ | 7,478 | ||||||||
(In thousands)
|
||||||||||||
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Property acquisition costs:
|
||||||||||||
Proved
|
$ | 445 | $ | 2,987 | $ | 1,288 | ||||||
Unproved
|
1,760 | 1,416 | 10,679 | |||||||||
Exploration costs
|
9,138 | 10,943 | 32,788 | |||||||||
Development costs
|
9,403 | 20,134 | 4,550 | |||||||||
Total costs incurred
|
$ | 20,746 | $ | 35,480 | $ | 49,305 | ||||||
(In thousands)
|
||||||||||||
For the years ending December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Oil and gas revenues
|
$ | 33,647 | $ | 32,534 | $ | 30,958 | ||||||
Operating expenses
|
10,469 | 10,788 | 11,552 | |||||||||
Depreciation, depletion and amortization
|
13,623 | 14,893 | 13,997 | |||||||||
Impairment
|
5,828 | 5,189 | -- | |||||||||
29,920 | 30,870 | 25,549 | ||||||||||
Operating income
|
$ | 3,727 | $ | 1,664 | $ | 5,409 | ||||||
December 31, 2013
|
Oil (BBLS)
|
Natural Gas or NGL (MCFE)
|
||
Beginning of year
|
2,613,643
|
1,798,088
|
||
Revisions of previous quantity estimates
|
(162,957)
|
382,690
|
||
Extensions, discoveries and improved recoveries
|
1,352,746
|
678,412
|
||
Purchase of reserves in place
|
--
|
--
|
||
Sales of reserves in place
|
--
|
--
|
||
Production
|
(343,719)
|
(487,282)
|
||
End of year
|
3,459,713
|
2,371,908
|
||
Proved developed reserves at end of year
|
1,875,528
|
1,701,282
|
||
December 31, 2012
|
Oil (BBLS)
|
Natural Gas or NGL (MCFE)
|
||
Beginning of year
|
2,737,969
|
2,744,128
|
||
Revisions of previous quantity estimates
|
(145,596)
|
(481,583)
|
||
Extensions, discoveries and improved recoveries
|
763,125
|
369,169
|
||
Purchase of reserves in place
|
75,948
|
30,457
|
||
Sales of reserves in place
|
(444,272)
|
(437,057)
|
||
Production
|
(373,531)
|
(427,026)
|
||
End of year
|
2,613,643
|
1,798,088
|
||
Proved developed reserves at end of year
|
1,770,659
|
1,420,295
|
||
(In thousands)
|
||||||||||||
December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Future cash inflows
|
$ | 330,245 | $ | 237,148 | $ | 259,533 | ||||||
Future costs:
|
||||||||||||
Production
|
(129,392 | ) | (96,616 | ) | (77,813 | ) | ||||||
Development
|
(37,739 | ) | (21,461 | ) | (42,972 | ) | ||||||
Future income tax expense
|
(14,500 | ) | (8,483 | ) | (19,790 | ) | ||||||
Future net cash flows
|
148,614 | 110,588 | 118,958 | |||||||||
10% discount factor
|
(43,761 | ) | (39,571 | ) | (56,767 | ) | ||||||
Standardized measure of discounted future net cash flows
|
$ | 104,853 | $ | 71,017 | $ | 62,191 | ||||||
(In thousands)
|
||||||||||||
Year ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Balance at beginning of year
|
$ | 71,017 | $ | 62,191 | $ | 44,653 | ||||||
Sales of oil and gas, net of production costs
|
(23,179 | ) | (21,747 | ) | (19,406 | ) | ||||||
Net change in prices and production costs
|
2,543 | (4,548 | ) | 1,401 | ||||||||
Net change in future development costs
|
-- | -- | -- | |||||||||
Extensions and discoveries
|
54,360 | 23,297 | 26,574 | |||||||||
Purchase of reserves in place
|
-- | 2,573 | 3,082 | |||||||||
Sale of reserves in place
|
-- | (13,573 | ) | (1,947 | ) | |||||||
Revisions of previous quantity estimates
|
(2,961 | ) | (5,927 | ) | (3,158 | ) | ||||||
Development costs incurred during year
|
8,344 | 22,808 | 14,930 | |||||||||
Previously estimated development costs incurred
|
(6,414 | ) | (9,706 | ) | (2,719 | ) | ||||||
Net change in income taxes
|
(4,245 | ) | 7,261 | (4,270 | ) | |||||||
Accretion of discount
|
7,647 | 7,254 | 5,207 | |||||||||
Changes in production rates, timing and other
|
(2,259 | ) | 1,134 | (2,156 | ) | |||||||
Balance at end of year
|
$ | 104,853 | $ | 71,017 | $ | 62,191 | ||||||
(In thousands)
|
||||||||||||
For the years ending December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Revenues
|
$ | 1,271 | $ | 2,037 | $ | 2,147 | ||||||
Operating expenses
|
844 | 1,885 | 1,468 | |||||||||
Impairment
|
-- | 2,955 | 3,063 | |||||||||
844 | 4,840 | 4,531 | ||||||||||
Income (loss) before income taxes
|
427 | (2,803 | ) | (2,384 | ) | |||||||
Income tax benefit from (provision for)
|
-- | 1,009 | (245 | ) | ||||||||
Net income (loss) from discontinued operations
|
$ | 427 | $ | (1,794 | ) | $ | (2,629 | ) | ||||
(In thousands)
|
||||||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Other liabilities and debt:
|
||||||||
Other liabilities
|
||||||||
Deferred rent
|
$ | 11 | $ | 12 | ||||
Remington Escrow
|
95 | -- | ||||||
Employee health insurance self funding
|
58 | 32 | ||||||
$ | 164 | $ | 44 | |||||
Other long term liabilities:
|
||||||||
Accrued executive retirement costs
|
$ | 741 | $ | 771 | ||||
Debt:
|
||||||||
Credit Facility - collateralized by
|
||||||||
oil and gas reserves, at 2.46%
|
$ | 9,000 | $ | 10,000 | ||||
Long term Debt
|
||||||||
Real estate note - collateralized by
|
||||||||
property, interest at 5.5%
|
-- | 9,621 | ||||||
Real estate note - collateralized by
|
||||||||
property, interest at 6%
|
-- | 200 | ||||||
9,000 | 19,821 | |||||||
Less current portion
|
-- | (526 | ) | |||||
Totals
|
$ | 9,000 | $ | 19,295 | ||||
The provision for income tax expense (benefit) for the years ended December 31, 2013,
2012, and 2011 consists of the following:
|
||||||||||||
(in thousands)
|
||||||||||||
Years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Current income tax expense (benefit)
|
||||||||||||
Federal
|
$ | -- | $ | -- | $ | -- | ||||||
State
|
-- | -- | -- | |||||||||
$ | -- | $ | -- | $ | -- | |||||||
Deferred income tax expense (benefit)
|
||||||||||||
Federal
|
$ | -- | $ | (1,093 | ) | $ | (3,316 | ) | ||||
State
|
-- | (64 | ) | (195 | ) | |||||||
$ | -- | $ | (1,157 | ) | $ | (3,511 | ) | |||||
(in thousands)
|
||||||||||||
Years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Federal statutory income tax rate
|
$ | (2,509 | ) | $ | (4,164 | ) | $ | (2,828 | ) | |||
State income taxes, net of federal benefit
|
(158 | ) | (245 | ) | (166 | ) | ||||||
Incentive stock options
|
43 | 12 | 246 | |||||||||
Percent depletion carryover
|
(174 | ) | (177 | ) | (807 | ) | ||||||
Valuation analysis
|
2,717 | 3,512 | -- | |||||||||
Other
|
81 | (95 | ) | 44 | ||||||||
$ | -- | $ | (1,157 | ) | $ | (3,511 | ) | |||||
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
Deferred tax assets:
|
||||||||
Net operating loss
|
$ | 6,930 | $ | 2,899 | ||||
Derivative instruments
|
96 | (170 | ) | |||||
Asset retirement obligation
|
294 | 247 | ||||||
Stock based compensation
|
228 | 313 | ||||||
Deferred compensation
|
385 | 382 | ||||||
Alternative minimum tax credit
|
706 | 706 | ||||||
Contribution carryover
|
37 | 37 | ||||||
Equity investments
|
643 | (91 | ) | |||||
Percentage depletion carryover
|
2,421 | 2,100 | ||||||
$ | 11,740 | $ | 6,423 | |||||
Deferred tax liabilities:
|
||||||||
Property and equipment
|
(5,446 | ) | (2,854 | ) | ||||
State tax
|
(9 | ) | -- | |||||
Marketable securities
|
(16 | ) | (57 | ) | ||||
$ | (5,471 | ) | $ | (2,911 | ) | |||
Net deferred tax assets (liabilities)
|
6,269 | 3,512 | ||||||
Less: Valuation Allowance
|
(6,269 | ) | (3,512 | ) | ||||
Deferred tax liability
|
$ | -- | $ | -- | ||||
(In thousands)
|
||||||||||||
For the years ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Revenues:
|
||||||||||||
Oil and gas
|
$ | 33,647 | $ | 32,534 | $ | 30,958 | ||||||
Total revenues
|
33,647 | 32,534 | 30,958 | |||||||||
Operating expenses:
|
||||||||||||
Oil and gas
|
29,920 | 30,870 | 25,549 | |||||||||
Mineral properties
|
3,045 | 2,899 | 2,364 | |||||||||
Total operating expenses
|
32,965 | 33,769 | 27,913 | |||||||||
Interest expense:
|
||||||||||||
Oil and gas
|
264 | 169 | 268 | |||||||||
Mineral properties
|
12 | 24 | 36 | |||||||||
Total interest expense
|
276 | 193 | 304 | |||||||||
Operating income (loss)
|
||||||||||||
Oil and gas
|
$ | 3,463 | $ | 1,495 | $ | 5,141 | ||||||
Mineral properties
|
(3,057 | ) | (2,923 | ) | (2,400 | ) | ||||||
Operating income (loss)
|
||||||||||||
from identified segments
|
406 | (1,428 | ) | 2,741 | ||||||||
General and administrative expenses
|
(5,673 | ) | (9,109 | ) | (8,261 | ) | ||||||
Add back interest expense
|
276 | 193 | 304 | |||||||||
Other revenues and expenses
|
(2,695 | ) | 849 | (717 | ) | |||||||
Income (loss) before income taxes
|
||||||||||||
and discontinued operations
|
$ | (7,686 | ) | $ | (9,495 | ) | $ | (5,933 | ) | |||
Depreciation, depletion and amortization expense:
|
||||||||||||
Oil and gas
|
$ | 13,623 | $ | 14,893 | $ | 13,997 | ||||||
Mineral properties
|
126 | 127 | 102 | |||||||||
Corporate
|
149 | 437 | 494 | |||||||||
Total Depreciation, depletion
|
||||||||||||
and amortization expense
|
$ | 13,898 | $ | 15,457 | $ | 14,593 | ||||||
(In thousands)
|
||||||||||||
December 31,
|
December 31,
|
December 31,
|
||||||||||
2013
|
2012
|
2011
|
||||||||||
Assets by segment
|
||||||||||||
Oil and gas
|
$ | 97,418 | $ | 93,839 | $ | 109,141 | ||||||
Mineral
|
20,739 | 20,747 | 20,755 | |||||||||
Corporate
|
8,644 | 26,241 | 32,543 | |||||||||
Total assets
|
$ | 126,801 | $ | 140,827 | $ | 162,439 | ||||||
For the years ended December 31, | ||||||||||||||||||||||||
2013
|
2012
|
2011
|
||||||||||||||||||||||
Employee Options
|
Weighted Average Exercise Price
|
Employee Options
|
Weighted Average Exercise Price
|
Employee Options
|
Weighted Average Exercise Price
|
|||||||||||||||||||
Outstanding at beginning
|
||||||||||||||||||||||||
of the year
|
2,259,282 | $ | 3.80 | 2,318,399 | $ | 3.94 | 3,011,647 | $ | 3.87 | |||||||||||||||
Granted
|
270,000 | $ | 2.08 | 150,000 | $ | 2.32 | -- | $ | -- | |||||||||||||||
Forfeited
|
-- | $ | -- | (10,000 | ) | $ | 2.32 | -- | $ | -- | ||||||||||||||
Expired
|
(28,333 | ) | $ | 4.68 | (194,950 | ) | $ | 4.47 | (200,000 | ) | $ | 3.90 | ||||||||||||
Exercised
|
-- | $ | -- | (4,167 | ) | $ | 2.52 | (493,248 | ) | $ | 3.51 | |||||||||||||
Outstanding at year end
|
2,500,949 | $ | 3.60 | 2,259,282 | $ | 3.80 | 2,318,399 | $ | 3.94 | |||||||||||||||
Exercisable at year end
|
2,137,619 | $ | 3.85 | 2,119,282 | $ | 3.90 | 2,108,399 | $ | 3.84 | |||||||||||||||
Weighted average fair
|
||||||||||||||||||||||||
value of options
|
||||||||||||||||||||||||
granted during
|
||||||||||||||||||||||||
the year
|
$ | 1.20 | $ | 1.30 | $ | -- | ||||||||||||||||||
Grant Price Range
|
Employee Options Outstanding at December 31, 2013
|
Weighted average remaining contractual life in years
|
Weighted average exercise price
|
Employee Options exercisable at December 31, 2013
|
Weighted average exercise price
|
|||||||||||||||||
$ | 2.08 | 270,000 | 9.50 | $ | 2.08 | -- | $ | -- | ||||||||||||||
$ | 2.09 - $2.32 | 140,000 | 8.53 | $ | 2.32 | 46,670 | $ | 2.32 | ||||||||||||||
$ | 2.33 - $2.46 | 386,869 | 0.50 | $ | 2.46 | 386,869 | $ | 2.46 | ||||||||||||||
$ | 2.47 - $2.52 | 405,312 | 4.73 | $ | 2.52 | 405,312 | $ | 2.52 | ||||||||||||||
$ | 2.53 - $3.86 | 273,768 | 1.79 | $ | 3.86 | 273,768 | $ | 3.86 | ||||||||||||||
$ | 3.87 - $4.97 | 1,025,000 | 3.57 | $ | 4.97 | 1,025,000 | $ | 4.97 | ||||||||||||||
2,500,949 | 4.00 | $ | 3.60 | 2,137,619 | $ | 3.85 | ||||||||||||||||
At December 31, | ||||||||||||
2013
|
2012
|
2011
|
||||||||||
Available for future grant
|
790,000 | 1,060,000 | -- | |||||||||
Intrinsic value of options exercised
|
$ | -- | $ | 4,000 | $ | 888,000 | ||||||
Aggregate intrinsic value of options outstanding
|
$ | 1,661,000 | $ | -- | $ | 351,000 | ||||||
Aggregate intrinsic value of options exercisable
|
$ | 1,073,000 | $ | -- | $ | 351,000 | ||||||
For the years ended December 31, | ||||||||||||||||||||||||
2013
|
2012
|
2011
|
||||||||||||||||||||||
Director Options
|
Weighted Average Exercise Price
|
Director Options
|
Weighted Average Exercise Price
|
Director Options
|
Weighted Average Exercise Price
|
|||||||||||||||||||
Outstanding at beginning
|
||||||||||||||||||||||||
of the period
|
150,000 | $ | 3.05 | 210,000 | $ | 3.10 | 320,000 | $ | 2.95 | |||||||||||||||
Granted
|
36,000 | $ | 2.08 | 80,000 | $ | 2.78 | 20,000 | $ | 4.19 | |||||||||||||||
Forfeited
|
-- | $ | -- | -- | $ | -- | (20,000 | ) | $ | 2.52 | ||||||||||||||
Expired
|
(40,000 | ) | $ | 2.60 | (120,000 | ) | $ | 3.05 | (5,000 | ) | $ | 3.90 | ||||||||||||
Exercised
|
-- | $ | -- | (20,000 | ) | $ | 2.52 | (105,000 | ) | $ | 2.92 | |||||||||||||
Outstanding at period end
|
146,000 | $ | 2.93 | 150,000 | $ | 3.05 | 210,000 | $ | 3.10 | |||||||||||||||
Exercisable at period end
|
56,668 | $ | 3.46 | 63,335 | $ | 3.01 | 183,334 | $ | 2.91 | |||||||||||||||
Weighted average fair
|
||||||||||||||||||||||||
value of options
|
||||||||||||||||||||||||
granted during
|
||||||||||||||||||||||||
the period
|
$ | 1.20 | $ | 1.59 | $ | 2.34 | ||||||||||||||||||
Grant Price Range
|
Director Options Outstanding at December 31, 2013
|
Weighted average remaining contractual life in years
|
Weighted average exercise price
|
Director Options exercisable at December 31, 2013
|
Weighted average exercise price
|
|||||||||||||||||
$ | 2.08 | 36,000 | 9.50 | $ | 2.08 | -- | $ | -- | ||||||||||||||
$ | 2.09 - $2.32 | 10,000 | 8.53 | $ | 2.32 | 3,334 | $ | 2.32 | ||||||||||||||
$ | 2.33 - $2.52 | 10,000 | 4.73 | $ | 2.52 | 10,000 | $ | 2.52 | ||||||||||||||
$ | 2.53 - $2.85 | 60,000 | 8.22 | $ | 2.85 | 20,000 | $ | 2.85 | ||||||||||||||
$ | 2.86 - $4.19 | 20,000 | 7.48 | $ | 4.19 | 13,334 | $ | 4.19 | ||||||||||||||
$ | 4.20 - $5.04 | 10,000 | 6.48 | $ | 5.04 | 10,000 | $ | 5.04 | ||||||||||||||
146,000 | 8.10 | $ | 2.93 | 56,668 | $ | 3.46 | ||||||||||||||||
At December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Available for future grant
|
131,359 | 126,526 | 164,099 | |||||||||
Intrinsic value of options exercised
|
$ | -- | $ | 17,000 | $ | 14,000 | ||||||
Aggregate intrinsic value of options outstanding
|
$ | 142,000 | $ | -- | $ | 31,000 | ||||||
Aggregate intrinsic value of options exercisable
|
$ | 35,000 | $ | -- | $ | 31,000 |
For the years ended December 31,
|
|||||
2013
|
2012
|
2011
|
|||
Risk-free interest rate
|
1.66%
|
0.82% to 1.41%
|
1.77%
|
||
Expected lives (years)
|
6.0
|
5.0 to 6.0
|
6.0
|
||
Expected volatility
|
62.59%
|
61.87% to 63.59%
|
59.64%
|
||
Expected dividend yield
|
--
|
--
|
--
|
(In thousands except per share data)
|
||||||||||||||||
Three Months Ended
|
||||||||||||||||
December 31,
|
September 30,
|
June 30,
|
March 31,
|
|||||||||||||
2013
|
2013
|
2013
|
2013
|
|||||||||||||
Operating revenues
|
$ | 9,271 | $ | 8,582 | $ | 7,915 | $ | 7,879 | ||||||||
Operating income (loss)
|
$ | 692 | $ | 359 | $ | 118 | $ | (6,160 | ) | |||||||
Income (loss) before income tax and discontinued operations
|
$ | (1,217 | ) | $ | (706 | ) | $ | 367 | $ | (6,130 | ) | |||||
Benefit from (provision for) income taxes
|
$ | -- | $ | -- | $ | -- | $ | -- | ||||||||
Discontinued operations, net of tax
|
$ | (3 | ) | $ | (128 | ) | $ | 206 | $ | 232 | ||||||
Net income (loss)
|
$ | (1,220 | ) | $ | (834 | ) | $ | 573 | $ | (5,898 | ) | |||||
Loss per share, basic
|
||||||||||||||||
Continuing operations
|
$ | (0.04 | ) | $ | (0.03 | ) | $ | 0.01 | $ | (0.22 | ) | |||||
Discontinued operations
|
-- | -- | 0.01 | 0.01 | ||||||||||||
$ | (0.04 | ) | $ | (0.03 | ) | $ | 0.02 | $ | (0.21 | ) | ||||||
Basic weighted average shares outstanding
|
27,682,602 | 27,682,602 | 27,682,272 | 27,667,102 | ||||||||||||
Loss per share, diluted
|
||||||||||||||||
Continuing operations
|
$ | (0.04 | ) | $ | (0.03 | ) | $ | 0.01 | $ | (0.22 | ) | |||||
Discontinued operations
|
-- | -- | 0.01 | 0.01 | ||||||||||||
$ | (0.04 | ) | $ | (0.03 | ) | $ | 0.02 | $ | (0.21 | ) | ||||||
Diluted weighted average shares outstanding
|
27,682,602 | 27,682,602 | 27,682,272 | 27,667,102 |
(In thousands except per share data)
|
||||||||||||||||
Three Months Ended
|
||||||||||||||||
December 31,
|
September 30,
|
June 30,
|
March 31,
|
|||||||||||||
2012
|
2012
|
2012
|
2012
|
|||||||||||||
Operating revenues
|
$ | 8,038 | $ | 7,639 | $ | 8,522 | $ | 8,335 | ||||||||
Operating (loss)
|
$ | (5,880 | ) | $ | (2,709 | ) | $ | (991 | ) | $ | (712 | ) | ||||
Income (loss) before income tax and discontinued operations
|
$ | (6,079 | ) | $ | (3,155 | ) | $ | 624 | $ | (833 | ) | |||||
Benefit from (provision for) income taxes
|
$ | (1,302 | ) | $ | 1,285 | $ | (379 | ) | $ | 388 | ||||||
Discontinued operations, net of tax
|
$ | (548 | ) | $ | (75 | ) | $ | (1,235 | ) | $ | 64 | |||||
Net income (loss)
|
$ | (7,929 | ) | $ | (1,945 | ) | $ | (990 | ) | $ | (381 | ) | ||||
Loss per share, basic
|
||||||||||||||||
Continuing operations
|
$ | (0.27 | ) | $ | (0.07 | ) | $ | 0.01 | $ | (0.01 | ) | |||||
Discontinued operations
|
(0.02 | ) | -- | (0.05 | ) | -- | ||||||||||
$ | (0.29 | ) | $ | (0.07 | ) | $ | (0.04 | ) | $ | (0.01 | ) | |||||
Basic weighted average shares outstanding
|
27,475,813 | 27,468,355 | 27,460,483 | 27,438,584 | ||||||||||||
Loss per share, diluted
|
||||||||||||||||
Continuing operations
|
$ | (0.27 | ) | $ | (0.07 | ) | $ | 0.01 | $ | (0.01 | ) | |||||
Discontinued operations
|
(0.02 | ) | -- | (0.05 | ) | -- | ||||||||||
$ | (0.29 | ) | $ | (0.07 | ) | $ | (0.04 | ) | $ | (0.01 | ) | |||||
Diluted weighted average shares outstanding
|
27,475,813 | 27,468,355 | 27,460,483 | 27,438,584 |
(In thousands except per share data)
|
||||||||||||||||
Three Months Ended
|
||||||||||||||||
December 31,
|
September 30,
|
June 30,
|
March 31,
|
|||||||||||||
2011
|
2011
|
2011
|
2011
|
|||||||||||||
Operating revenues
|
$ | 8,846 | $ | 8,408 | $ | 7,025 | $ | 6,679 | ||||||||
Operating income (loss)
|
$ | (736 | ) | $ | (689 | ) | $ | (723 | ) | $ | (3,068 | ) | ||||
Income (loss) before income tax and discontinued operations
|
$ | (2,443 | ) | $ | 1,022 | $ | 420 | $ | (4,932 | ) | ||||||
Benefit from (provision for) income taxes
|
$ | 2,671 | $ | (892 | ) | $ | (618 | ) | $ | 2,594 | ||||||
Discontinued operations, net of tax
|
$ | (3,019 | ) | $ | 138 | $ | 123 | $ | 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 |
(a)(1) and (a)(2)
|
Page
|
Report of Independent Registered Public Accounting Firm
|
75
|
Financial Statements
|
|
Consolidated Balance Sheets as of December 31, 2012 and 2011
|
76
|
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010
|
78
|
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2012, 2011 and 2010
|
80
|
Statement of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010
|
81
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010
|
84
|
Notes to Consolidated Financial Statements
|
86
|
10.5**
|
2012 Equity Plan (incorporated by reference from Appendix A to the Company’s Proxy Statement Form DEF14A filed April 30, 2012)
|
10.5.1**
|
Form of Grant to the 2012 Equity Plan (incorporated by reference from Exhibit 10.5.1 to the Form 10-K filed March 18, 2013)
|
10.6**
|
Form of Production Payment Royalty Agreement (Exhibit A to the Asset Purchase Agreement with sxr Uranium One, Inc.) (incorporated by reference from Exhibit 10.2 to the Company’s Report on Form 8-K filed February 23, 2007)
|
10.7(a)**†
|
Executive Employment Agreement – Keith G. Larsen (effective 4-20-12) (incorporated by reference from Exhibit 10.1 to the Form 8-K filed January 17, 2012)
|
10.7(b)**†
|
Executive Employment Agreement – Mark J. Larsen (effective 4-20-12) (incorporated by reference from Exhibit 10.2 to the Form 8-K filed January 17, 2012)
|
10.7(c)**†
|
Executive Employment Agreement – Steven R. Youngbauer (effective 4-20-12) (incorporated by reference from Exhibit 10.3 to the Form 8-K filed January 17, 2012)
|
10.7(d)**†
|
Form of Executive Severance and Non-Compete Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Quarterly Report on From 10-Q filed on May 10, 2013)
|
10.8**
|
Agreement for Purchase of Leasehold Interests in McKenzie and Williams Counties, North Dakota (Brigham Oil & Gas, L.P.) (incorporated by reference from Exhibit 10.6 to the Company’s Annual Report on Form 10-K filed March14, 2012)
|
10.9(a)**
|
Agreement for Purchase of Leasehold Interests in McKenzie County, North Dakota (Geo Resources, Inc.) (incorporated by reference from Exhibit 10.7(a) to the Company’s Annual Report on Form 10-K filed March14, 2012)
|
10.9(b)**
|
Amendments (5) to Agreement for Purchase of Leasehold Interest in McKenzie County, North Dakota (Geo Resources, Inc.) (incorporated by reference from Exhibit 10.7(b) to the Company’s Annual Report on Form 10-K filed March14, 2012)
|
10.10(a)*
|
Participation Agreement between Energy One, LLC and Contango/Crimson effective February18, 2011 for the Leona River Project
|
10.10(b)*
|
Participation Agreement between Energy One, LLC and Contango/Crimson effective April 1, 2011 for the Booth/Tortuga Project
|
14.0**
|
Code of Ethics (incorporated by reference from Exhibit 14 to the Company’s Annual Report on Form 10-K filed March 30, 2004)
|
21.1*
|
Subsidiaries of Registrant
|
23.0*
|
Consent of Ryder Scott Company L.P.
|
23.1*
|
Consent of Cawley, Gillespie & Associates, Inc.
|
23.2*
|
Consent of Netherland, Sewell & Associates, Inc.
|
23.3*
|
Consent of Independent Registered Accounting Firm (Hein & Associates LLP)
|
31.1*
|
Certification under Rule 13a-14(a) Keith G. Larsen
|
|
U.S. ENERGY CORP. (Registrant)
|
|||
Date: March 12, 2014
|
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 12, 2014
|
By:
|
/s/ Keith G. Larsen
|
||
KEITH G. LARSEN, Director, Chairman and CEO (Principal Executive Officer)
|
||||
Date: March 12, 2014
|
By:
|
/s/ Steven D. Richmond
|
||
STEVEN D. RICHMOND
|
||||
Chief Financial Officer (Principal Financial Officer)
|
||||
Date: March 12, 2014
|
By:
|
/s/ Bryon G. Mowry
|
||
BRYON G. MOWRY
|
||||
Principal Accounting Officer
|
||||
Date: March 12, 2014
|
By:
|
/s/ Mark J. Larsen
|
||
MARK J. LARSEN, President and Director
|
||||
Date: March 12, 2014
|
By:
|
/s/ Robert Scott Lorimer
|
||
ROBERT SCOTT LORIMER, Director
|
||||
Date: March 12, 2014
|
By:
|
/s/ Stephen V. Conrad
|
||
STEPHEN V. CONRAD, Director
|
||||
Date: March 12, 2014
|
By:
|
/s/ Jerry W. Danni
|
||
JERRY W. DANNI, Director
|
||||
Date: March 12, 2014
|
By:
|
/s/ Leo A. Heath
|
||
LEO A. HEATH, Director
|
||||
Date: March 12, 2014
|
By:
|
/s/ Thomas R. Bandy
|
||
THOMAS R. BANDY, Director
|
|
a.
|
Upon execution of this Agreement (“Closing”), EOne shall pay Crimson an initial cash consideration of $2,908,750.
|
|
b.
|
EOne shall pay Crimson the remaining $2,000,000 cash consideration upon cash call from Crimson not earlier than thirty (30) days prior to the expected spud date of the KM Ranch #1H well (the “Initial Well”) described in No. A.2 below.
|
|
a.
|
Crimson shall deliver to EOne an undivided 30.00% of 8/8
ths
working interest in and to the Oil & Gas Lease.
|
|
b.
|
Crimson shall deliver a proportionately reduced 75% of 8/8ths net revenue interest in the Oil & Gas Lease (i.e. 22.50% net revenue interest to the 30.00% working interest being acquired by EOne).
|
|
c.
|
The assignment of the Oil and Gas Lease shall cover all depths owned by Crimson in the Oil & Gas Lease.
|
|
d.
|
The assignment of the Oil and Gas Lease shall be made subject to the terms, covenants and conditions of the Oil and Gas Lease; this Agreement; and the JOA, and Crimson shall warrant and defend title to the Oil and Gas Lease by, through and under Crimson only against every person lawfully claiming title to said property.
|
|
A.
|
Paragraph Headings
:
|
|
C.
|
Entire Agreement
:
|
|
D.
|
Execution
:
|
|
E.
|
Binding Agreement
:
|
|
F.
|
News Releases
:
|
|
G.
|
Information Distribution List/Geological Well Requirements
:
|
H.
|
Notices/Information
:
|
M.
|
Governing Law
:
|
|
(a)
|
Any and all claims, counterclaims, demands, cause of action, disputes, controversies, and other matters in question arising out of or relating to this Agreement, any provision hereof or thereof, the alleged breach of any such provision, or in any way relating to the subject matter of this Agreement or the relationship between the Parties or their Affiliates created by this Agreement,
|
|
(b)
|
It is the intention of the Parties that the arbitration shall be conducted pursuant to the Federal Arbitration Act, as such Act is modified by this Agreement. The validity, construction, and interpretation of this agreement to arbitrate, and all procedural aspects of the arbitration conducted pursuant to this agreement to arbitrate, including but not limited to, the determination of the issues that are subject to arbitration (i.e., arbitrability), the scope of the arbitrable issues, allegations of "fraud in the inducement" to enter into this Agreement or this arbitration provision, allegations of waiver, laches, delay or other defenses to arbitrability, and the rules governing the conduct of the arbitration (including the time for filing an answer, the time for the filing of counterclaims, the times for amending the pleadings, the specificity of the pleadings, the extent and scope of discovery, the issuance of subpoenas, the times for the designation of experts, whether the arbitration is to be stayed pending resolution of related litigation involving third parties not bound by this Agreement, the receipt of evidence, and the like), shall be decided by the arbitrators. Failing agreement upon the rules governing the conduct of the arbitration within thirty days after appointment of the third arbitrator (as provided below), the arbitrators shall adopt the Commercial Arbitration Rules of the American Arbitration Association. but the arbitration shall not be under the supervision of, and no fee shall be paid to, the American Arbitration Association. In deciding the substance of the Parties' Claims, the arbitrators shall refer to the substantive laws of the State of Texas for guidance (excluding Texas choice-of-law principles that might call for the application of some other State's law). Notwithstanding any other provision in this arbitration agreement to the contrary, the Parties expressly agree that the arbitrators shall have absolutely no authority to award treble, exemplary or punitive damages of any type under any circumstances regardless of whether such damages may be available under Texas law, the law of any other State, or federal law, or under the Federal Arbitration Act, or under the Commercial Arbitration Rules of the American Arbitration Association, the Parties hereby waiving their right, if any, to recover treble, exemplary or punitive damages in connection with any such Claims.
|
|
(c)
|
The arbitration proceeding shall be conducted in Houston, Texas. Within thirty days of the notice of initiation of the arbitration procedure, each Party shall select one arbitrator. The two arbitrators shall select a third arbitrator, failing agreement on which within ninety days of the original notice, the Parties (or either of them) shall apply to any United States District Judge for the Southern District of Texas, Houston Division, who shall appoint the third arbitrator. While the third arbitrator shall be neutral, the two party-appointed arbitrators are not required to be neutral and it shall not be grounds for removal of either of the two party-appointed arbitrators or for vacating the arbitrators' award that either of such arbitrators has past or present minimal relationships with the Party that appointed such arbitrator.
|
|
(d)
|
All fees of the arbitrators shall be borne equally by the Parties.
|
|
(e)
|
To the fullest extent permitted by law, the arbitration proceeding and the arbitrators' award shall be maintained in confidence by the Parties.
|
|
(f)
|
The award of the arbitrators shall be final and binding on the Parties, and judgment thereon may be entered in a court of competent jurisdiction.
|
|
1.
|
In consideration for EOne’s participation in the Leona River Project above, EOne will have the right to participate with Crimson on a ground floor basis in any offer Crimson may make to Sage for the purchase of Sage’s working interest in the Booth/Tortuga Area as shown on Exhibit “E” attached hereto. This offer may include the purchase of Sage’s working interest in existing producing wells in addition to the purchase of Sage’s Eagle Ford and deeper rights. If EOne elects to participate in any offer made to Sage, EOne will be required to acquire sufficient interest such that EOne shall have a 30% of 8/8’s working interest in the Booth/Tortuga Area and cost sharing of the acquired properties will be allocated accordingly, based on the value assigned to the producing wells and Eagle Ford rights and deeper rights. If EOne elects not to participate in any offer made to Sage or fails to close on the Leona River Project for any reason, EOne’s rights to participate in the Booth/Tortuga Area shall terminate.
|
|
2.
|
Crimson and EOne shall agree to form an Area of Mutual Interest (“AMI” or “Contract Area”) around the Booth/Tortuga Area as shown in blue on Exhibit “E” and enter into a Participation Agreement and AAPL Model Form 610-1989 Joint Operating Agreement naming Crimson as operator. The Joint Operating Agreement for the Booth/Tortuga Area shall be in substantially the same form as the JOA described in Article II of this Agreement.
|
|
3.
|
After the acquisition of the Sage Interest, all leasehold and capital expenditure will be on a ground floor basis.
|
|
4.
|
EOne shall have the right to review Crimson’s land and technical data regarding the Booth/Tortuga Area upon execution of a Confidentiality and Non-Compete Agreement covering the Booth/Tortuga Area.
|
B.
|
Assignment of the Combined Booth/Tortuga Interests:
|
1.
|
Crimson shall deliver to EOne an undivided 30.00% of 8/8
ths
working interest in and to the Combined Booth/Tortuga Interests consisting of no less than 2,156 net acres.
|
2.
|
Crimson shall deliver to Liberty an undivided 20.00% of 8/8
ths
working interest in and to the Combined Booth/Tortuga Interests consisting of no less than 1,437 net acres.
|
3.
|
Crimson shall deliver to EOne the proportionately reduced net revenue interest in the Combined Booth/Tortuga Interests as set forth in Exhibit “E” and attached hereto, without any additional burdens reserved to Crimson; provided that such proportionately reduced net revenue interests shall never be less than 75%.
|
4.
|
Crimson shall deliver to Liberty the proportionately reduced net revenue interest in the Combined Booth/Tortuga Interests as set forth in Exhibit “E” and attached hereto, without any additional burdens reserved to Crimson; provided that such proportionately reduced net revenue interests shall never be less than 75%.
|
5.
|
The Crimson-Assignees Assignment shall cover all depths owned or acquired by Crimson in the oil and gas leases underlying the Combined Booth/Tortuga Interests.
|
6.
|
The portion of the Combined Booth/Tortuga Interests assigned to Assignees shall not be burdened by any lien, mortgage or other material encumbrance other than the oil and gas leases underlying the Combined Booth/Tortuga Interests and the JOA.
|
7.
|
The Crimson-Assignees Assignment shall be made subject to the terms, covenants and conditions of the oil and gas leases underlying the Combined Booth/Tortuga Interests and the JOA.
|
8.
|
The Crimson-Assignees Assignment shall be made without warranty of any kind, express or implied, except for claims arising by, through and under Crimson.
|
|
A.
|
Paragraph Headings
:
|
|
C.
|
Entire Agreement
:
|
|
D.
|
Execution
:
|
|
E.
|
Binding Agreement
:
|
|
F.
|
News Releases
:
|
|
G.
|
Information Distribution List/Geological Well Requirements
:
|
H.
|
Notices/Information
:
|
K.
|
Term of Agreement
:
|
L.
|
Governing Law
:
|
|
(a)
|
Any and all claims, counterclaims, demands, cause of action, disputes, controversies, and other matters in question arising out of or relating to this Agreement, any provision hereof or thereof, the alleged breach of any such provision, or in any way relating to the subject matter of this Agreement or the relationship between the parties or their Affiliates created by this Agreement, involving the parties and/or their respective representatives (all of which are referred to herein as "Claims'), even though some or all of such Claims allegedly are extra-contractual in nature, whether such Claims sound in contract, tort, or otherwise, at law or in equity, under State or federal law, whether provided by statute or the common law, for damages or any other relief, shall be resolved by binding arbitration.
|
|
(b)
|
It is the intention of the parties that the arbitration shall be conducted pursuant to the Federal Arbitration Act, as such Act is modified by this Agreement. The validity, construction, and interpretation of this agreement to arbitrate, and all procedural aspects of the arbitration conducted pursuant to this agreement to arbitrate, including but not limited to, the determination of the issues that are subject to arbitration (i.e., arbitrability), the scope of the arbitrable issues, allegations of "fraud in the inducement" to enter into this Agreement or this arbitration provision, allegations of waiver, laches, delay or other defenses to arbitrability, and the rules governing the conduct of the arbitration (including the time for filing an answer, the time for the filing of counterclaims, the times for amending the pleadings, the specificity of the pleadings, the extent and scope of discovery, the issuance of subpoenas, the times for the designation of experts, whether the arbitration is to be stayed pending resolution of related litigation involving third parties not bound by this Agreement, the receipt of evidence, and the like), shall be decided by the arbitrators. Failing agreement upon the rules governing the conduct of the arbitration within thirty days after appointment of the third arbitrator (as provided below), the arbitrators shall adopt the Commercial Arbitration Rules of the American Arbitration Association. but the arbitration shall not be under the supervision of, and no fee shall be paid to, the American Arbitration Association. In deciding the substance of the parties' Claims, the arbitrators shall refer to the substantive laws of the State of Texas for guidance (excluding Texas choice-of-law principles that might call for the application of some other State's law). Notwithstanding any other provision in this arbitration agreement to the contrary, the parties expressly agree that the arbitrators shall have absolutely no authority to award treble, exemplary or punitive damages of any type under any circumstances regardless of whether such damages may be available under Texas law, the law of any other State, or federal law, or under the Federal Arbitration Act, or under the Commercial Arbitration Rules of the
|
|
(c)
|
The arbitration proceeding shall be conducted in Houston, Texas. Within thirty days of the notice of initiation of the arbitration procedure, each party shall select one arbitrator. The two arbitrators shall select a third arbitrator, failing agreement on which within ninety days of the original notice, the parties (or either of them) shall apply to any United States District Judge for the Southern District of Texas, Houston Division, who shall appoint the third arbitrator. While the third arbitrator shall be neutral, the two party-appointed arbitrators are not required to be neutral and it shall not be grounds for removal of either of the two party-appointed arbitrators or for vacating the arbitrators' award that either of such arbitrators has past or present minimal relationships with the party that appointed such arbitrator.
|
|
(d)
|
All fees of the arbitrators shall be borne equally by the parties. All other fees and costs associated with the arbitration will be borne by the party incurring such fees and costs.
|
|
(e)
|
To the fullest extent permitted by law, the arbitration proceeding and the arbitrators’ award shall be maintained in confidence by the parties.
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
FAX (713) 651-0849
|
|
1100 LOUISIANA SUITE 4600
|
HOUSTON, TEXAS 77002-5294
|
TELEPHONE (713) 651-9191
|
SUITE 600, 1015 4TH STREET, S.W.
|
CALGARY, ALBERTA T2R 1J4
|
TEL (403) 262-2799
|
FAX (403) 262-2790
|
621 17TH STREET, SUITE 1550
|
DENVER, COLORADO 80293-1501
|
TEL (303) 623-9147
|
FAX (303) 623-4258
|
13640 BRIARWICK DR., SUITE100
|
306 WEST SEVENTH STREET, SUITE 302
|
1000 LOUISIANA STREET, SUITE 625
|
AUSTIN, TEXAS 78729-1107
|
FORT WORTH, TEXAS 76102-4987
|
HOUSTON, TEXAS 77002-5008
|
512-249-7000
|
817- 336-2461
|
713-651-9944
|
www.cgaus.com
|
|
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.
|
Proved
|
||||||||||||||||||
Total
|
Developed
|
Undeveloped
|
||||||||||||||||
Net Reserves
|
||||||||||||||||||
Oil
|
— bbl
|
3,459,715 | 1,875,528 | 1,584,187 | ||||||||||||||
Gas
|
— Mcf
|
2,371,910 | 1,701,282 | 670,628 | ||||||||||||||
Net Revenue
|
||||||||||||||||||
Oil
|
— $ | 315,042,562 | 167,324,609 | 147,717,969 | ||||||||||||||
Gas
|
— $ | 15,202,712 | 10,576,320 | 4,626,393 | ||||||||||||||
Net BOE Production
|
— |
BOE
|
3,855,033 | 2,159,075 | 1,695,958 | |||||||||||||
Ad Valorem Tax
|
— | $ | 2,761,331 | 754,971 | 2,006,359 | |||||||||||||
Operating Expense
|
— | $ | 97,183,742 | 69,621,547 | 27,562,213 | |||||||||||||
Production Severance Tax
|
— | $ | 29,447,176 | 17,912,430 | 11,534,748 | |||||||||||||
Investments
|
— | $ | 37,739,480 | 42,900 | 37,696,586 | |||||||||||||
Future Net Cash Flow
|
— | $ | 163,113,531 | 89,569,078 | 73,544,438 | |||||||||||||
Discounted @ 10%
|
— | $ | 115,082,672 | 65,424,863 | 49,657,863 | |||||||||||||
(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.
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(20)
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Cumulative Future Net Cash Flow
.
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(21)
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Cumulative Cash Flow Discounted @ 10%
is calculated by discounting monthly cash flows at the specified annual rates.
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DCF Profile
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The cash flow discounted at six different rates are shown at the bottom of columns (20-21). Interest has been compounded monthly.
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Life
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The economic life of the appraised property is noted in the lower right-hand corner of the table.
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Footnotes
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Comments regarding the evaluation may be shown in the lower left-hand footnotes.
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Price Deck
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A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.
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