SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
Annual Report Pursuant to section 13 or 15(d)
of the Securities Exchange Act of 1934
(Mark One)
[ ] Annual report pursuant to section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended ______________ or
[X] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from June 1, 2002 to
December 31, 2002
Commission file number 0-6814
U.S. ENERGY CORP.
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(Exact Name of Registrant as Specified in its Charter)
Wyoming 83-0205516
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
877 North 8th West
Riverton, WY 82501
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(Address of principal executive offices) (Zip Code)
Registrant's Telephone Number, including area code: (307) 856-9271
Securities registered pursuant to Section 12(b) of the Act:
NONE
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Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $0.01 PAR VALUE
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(Title of Class)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO
The aggregate market value of the shares of voting stock held by
non-affiliates of the Registrant as of March 21, 2003, computed by reference to
the average of the bid and asked prices of the Registrant's common stock as
reported by the National Market System of NASDAQ on that date, was approximately
$30,284,400.
Class Outstanding at March 21, 2003
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Common Stock, $0.01 par value 12,209,776 shares
Documents incorporated by reference: Portions of the documents listed below have
been incorporated by reference into the indicated parts of this report as
specified in the responses to the referenced sections of this filing.
Proxy Statement for the Meeting of Shareholders to be held June 2003, into
Part III of the filing.
Indicate by check mark if disclosure of delinquent filers, pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of the Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K includes "forward-looking statements"
within the meaning of Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of historical
fact included in this Report, are forward-looking statements, including without
limitation the statements under Management's Discussion and Analysis of
Financial Condition and Results of Operations and the disclosures about Rocky
Mountain Gas, Inc. and plans for developing its coalbed methane acreage. In
addition, whenever words like "expect," "anticipate" or "believe" are used, we
are making forward-looking statements.
Although we believe that our forward-looking statements are reasonable, we
don't know if our expectations will prove to be correct. Important future
factors that could cause actual results to differ materially from expectations
include: domestic consumption rates for natural gas; domestic market prices for
natural gas, uranium, gold, and molybdenum; the amounts of gas we will be able
to produce from our coalbed methane properties; the availability of permits to
drill and operate coalbed methane wells; whether and when gas transmission lines
will be built in reasonable proximity to our coalbed methane properties and
whether and on what terms the capital necessary to develop our properties can be
obtained. The forward-looking statements should be carefully considered in the
context of all the information set forth in this Annual Report.
The Company has changed its fiscal year from May 31 to December 31.
Therefore, this is a "transition" Annual Report, presenting information as of
December 31, 2002 and for the seven months then ended. PART I
ITEM 1 AND ITEM 2. BUSINESS AND PROPERTIES.
(A) GENERAL.
U.S. Energy Corp. is a Wyoming corporation (formed in 1966) in the business
of acquiring, exploring, developing and/or selling or leasing mineral
properties. In this Annual Report, "we", "Company" or "USE" refers to U.S.
Energy Corp. including subsidiaries unless otherwise specifically noted. Our new
year ends December 31.
During the seven months ended December 31, 2002, most of our business
activity was devoted to the coalbed methane ("CBM") area , i.e., acquiring
acreage, drilling exploratory wells, testing the wells, and closing the purchase
of the Bobcat Field (a CBM producing field) in Wyoming. CBM activities are
conducted through Rocky Mountain Gas, Inc ("RMG"), a Wyoming corporation owned
51.1% by USE and 40.4% by Crested Corp. ("Crested"). At December 31, 2002,
Crested was a 70.5% majority-owned subsidiary of USE, see below. Properties of
RMG are held in Wyoming and southeastern Montana. As of the filing date of this
Annual Report, RMG holds approximately 281,886 gross mineral acres of CBM
properties.
We also hold commercial properties, most of which are located in Utah that
were acquired as part of a uranium property and mill acquisition. In the new
fiscal year ended December 31, 2002 (i.e., the seven months then ended),
revenues were generated from CBM sales and commercial operations.
For financial statement presentation purposes, the Company has two segments
of business; minerals and commercial operations (motel, real estate and
airport), see note I to the financial statements. However, presently the
Company's business priority is focused mainly on CBM.
2
Ryder Scott Company, independent petroleum consultants of Houston, Texas,
have estimated the net proved gas reserves and the discounted 10% present value
of the reserves, in our Bobcat Field in Wyoming. See "Gas Reserves" below. We
have been selling CBM from the Bobcat field since June 2002.
We have conducted exploratory drilling and testing on other CBM properties,
but in general, additional work (dewatering of completed wells, and drilling and
dewatering more wells) is needed before we can determine if we have proved
reserves on those properties. Specifically, we expect to make a determination
whether there are proved reserves on the Clearmont property (not now in
production) in the third or fourth quarter 2003. Such determinations on the
other properties are not expected to be made until 2004 or later.
For detailed information about our coalbed methane properties and business
strategy, please see "Minerals - Coalbed Methane" below.
Except for in the Bobcat field, only a limited number of exploratory wells
have been drilled, and there is not yet enough information from these wells to
determine if they contain proved reserves. Gas prices during the seven months
ended December 31, 2002 were lower in the Powder River Basin (our area of
activity) relative to national prices, and continued low prices will affect not
only the economics of the producing Bobcat property, but also the economics of
the exploration projects as they move into production in the future. In
addition, we could encounter delays in obtaining permits for continued
exploration, and more funding may be needed but may not be available.
USE and Crested originally were independent companies, with two common
affiliates (John L. Larsen and Max T. Evans; Mr. Evans died in February 2002).
In 1980, USE and Crested formed a joint venture ("USECC") to do business
together (unless one or the other elected not to pursue an individual project).
As a result of USE funding certain of Crested's obligations from time to time
(due to Crested's lack of cash on hand), and Crested subsequently paying a
portion of this debt by issuing common stock to USE, Crested became a
majority-owned subsidiary of USE in fiscal 1993. In fiscal 2001, Crested issued
another 6,666,666 shares of its common stock to reduce Crested's debt owed to
USE by $3.0 million, which increased USE's ownership of Crested to 70.5%. All
the operations of USE (and Crested) are in the United States. Principal
executive offices of USE are located in the Glen L. Larsen building at 877 North
8th Street West, Riverton, Wyoming 82501, telephone 307.856.9271.
Most of the USE's operations are conducted through subsidiaries, the USECC
Joint Venture with Crested, and jointly-owned subsidiaries of USE and Crested.
The Company's subsidiaries are:
Percent Primary
Subsidiary Owned by USE* Business Conducted
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Plateau Resources Ltd. 100.0% Uranium (Utah) - Inactive - shut down;
Motel/real estate - Active
Northwest Gold, Inc. 96.0% Gold (Montana) - Inactive - shut down
Rocky Mountain Gas, Inc. 91.5% Coalbed methane exploration - active
Energx, Ltd. 90.0% Gas - Inactive - shut down
Crested Corp. 70.5% Uranium, gold and molybdenum properties
(all inactive and shut down), and exploration
activities on coalbed methane properties
Sutter Gold Mining Company 66.3% Gold (California) - Inactive - shut down
Four Nines Gold, Inc. 50.9% Contract Drilling/Construction - Inactive
(since 2001)
3
USECC Joint Venture 50.0% Uranium (Wyoming, Utah), gold and
molybdenum,** all inactive and shut down;
real estate management and coalbed methane
exploration
Yellowstone Fuels Corp. 35.9% Uranium (Wyoming) - Inactive - shut down
*Includes ownership of Crested Corp. in RMG and Sutter.
**There are no plans to put the molybdenum property into production in the
foreseeable future. See "Inactive Mining Properties - Molybdenum.
Until September 11, 2000, USE, USECC and Kennecott Uranium Company
("Kennecott") owned the Green Mountain Mining Venture ("GMMV"), which held a
large uranium deposit and uranium mill in Wyoming. On September 11, 2000, USE
and Crested settled litigation with Kennecott involving the GMMV by selling
their interest in the GMMV and its properties back to Kennecott for $3,250,000,
receiving a royalty interest in the uranium properties and miscellaneous
equipment . The GMMV properties are shut down. Kennecott also assumed all
reclamation obligations on the GMMV properties; reclamation obligations for an
ion exchange facility located on properties outside the GMMV were not assumed by
Kennecott, see "Sheep Mountain Partners - Properties" below. Other uranium
properties and a uranium mill in southeast Utah are held by Plateau Resources
Ltd., a wholly-owned subsidiary of USE. The Utah uranium properties are shut
down.
The mineral properties held by Sutter Gold Mining Company ("SGMC", a
majority-owned subsidiary of USE), are shut down because the historical market
price of gold has not permitted raising the capital necessary to put the
properties into production. During the first quarter of 2003, gold prices
increased to a level which allowed the Company to begin marketing the SGMC
property.
In coalbed methane, we compete against many companies, some of which are
much larger and better financed than the Company. The principal area of
competition is encountered in the financial ability to acquire good acreage
positions and drill wells to explore coalbed methane potential, then, if
warranted, drill production wells and install production equipment (gathering
systems, compressors, etc.).
We own a royalty interest in a molybdenum property in Colorado; the
property is owned by Phelps Dodge Corporation, a worldwide integrated minerals
company with inventories of exploration, development stage, and producing
properties, involving numerous metals and other minerals. We believe, at the
present time, Phelps Dodge does not have a plan to place the molybdenum property
into production.
In the motel, real estate and airport operations area (significant in terms
of revenues for fiscal 2002 and the seven months ended December 31, 2002, but
not our primary business focus), we own and manage an office building (where our
headquarters are located), and small parcels of land, all in Riverton, Wyoming,
and a small amount of additional acreage elsewhere in Wyoming and Colorado. We
also own a townsite, a motel and convenience store, and other commercial
facilities in Utah. There is no significant competition in this area; although
parcels are sold from time to time, we are not in the land development business.
(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS.
During the seven months ended December 31, 2002 and the two former fiscal
years ended May 31, 2002 and 2001, for technical financial presentation
purposes, we operated in three business segments: (i) coalbed methane gas
exploration (and holding shut down mines and mineral properties), (ii) motel,
real estate, and airport operations, and (iii) contract drilling/ construction
(the first quarter of former fiscal year 2001). Contract drilling/construction
operations were shut down as an operating segment in fiscal 2001. While we
4
technically had three segments in this 31 month period, most activities in
minerals, motel/real estate/airport, and contract drilling/construction have
ceased or have been severely curtailed. The only current activities of a
material and recurring nature are in coalbed methane, and motel operations and
management services.
The principal products of the operating units within each of the reportable
industry segments for the seven months ended December 31, 2002 and the two
former fiscal years ended May 31, 2002 are shown in the narrative table below.
For more information, see note I to the financial statements.
INDUSTRY SEGMENTS PRINCIPAL PRODUCTS
Coalbed Methane Gas Exploration Acquisition of coalbed methane
and Production (and holding of properties, production of coalbed
mineral properties which are methane, and exploration and
shut development of properties for coalbed
methane. This activity is down)
materialand recurring, and is our
principal business focus. Sales and
leases of mineral-bearing properties and,
from time to time, the production and/or
marketing of uranium, gold and receipt of
advance royalties on molybdenum.
Activities in uranium, gold and
molybdenum are shut down as recurring
activities.
Motel and Real Estate Operation of a motel and rental of real
estate, operation of an aircraft fixed
base operation (fuel sales, flight
instruction and aircraft maintenance,
which was shut down in the former fiscal
year 2002), and various contract
services, including managerial services
for subsidiary companies. Only the motel
and real estate, and management services
activities remain active now. Though
significant in terms of contributions to
revenues on a historical basis, these
operations are auxiliary to the principal
business focus of the company (coalbed
methane).
Contract Drilling/Construction Contract drilling of coalbed methane
wells, construction of drill sites, gas
pipe lines, reservoirs and reclamation of
locations. This activity has been shut
down.
(C) NARRATIVE DESCRIPTION OF BUSINESS (INCLUDING ITEM 2 - PROPERTIES).
COALBED METHANE (AND INACTIVE MINING PROPERTIES)
ROCKY MOUNTAIN GAS, INC. ("RMG") was incorporated in Wyoming on November 1,
1999 for business in the coalbed methane industry in Wyoming and Montana. RMG is
a subsidiary of the Company (owned 51.1% by the Company and 40.4% by Crested as
of December 31, 2002).
As of the filing date of this Annual Report, RMG holds leases and options
on approximately 281,886 gross mineral acres of federal, state and private (fee)
land in the Powder River Basin ("PRB") of Wyoming and Montana and the Green
River Basin of Wyoming. As of the filing date of this Annual Report, there are
24 producing CBM wells on the acreage, all located in the Bobcat Field (1,940
gross acres in the Bobcat Field which was acquired in June 2002). RMG holds a
27.6% working (22% net revenue) interest in the Bobcat Field.
5
Through December 31, 2002, 70 CBM wells have been drilled, almost all with
funds provided by industry partner CCBM, Inc. ("CCBM") ( a wholly owned
subsidiary of Carrizo Oil and Gas, Inc. of Houston, Texas) and former industry
partner SENGAI (see below). Seven of these wells were drilled in the Bobcat
Field. Except for the wells in the Bobcat Field, reserves have not been
established for any of the properties on which these wells were drilled.
Subject to production of coalbed methane gas by July 2003, an independent
reserve evaluation for the Clearmont prospect is expected to be completed in the
third or fourth quarter 2003. This prospect was acquired as unexplored acreage
in former fiscal year 2001; drilling started there in former fiscal year 2002.
The dewatering process at Clearmont is underway. See "Acquisition and
Exploration Capital Expenditures" below.
RMG's Castle Rock and Kirby properties in southeast Montana contain large
acreage prospects will require the drilling of numerous exploratory wells and
extended dewatering periods for each group or "pod" of wells (from 6 to 18
months after drilling and completion) before an assessment of reserves can be
made. In areas where no other wells on adjacent properties are dewatering the
coal seam, the dewatering process could take as long as 24 months.
Among the uncertainties we face in determining if our coalbed methane
investments will yield value are the following: Prices for gas sold in the
Powder River Basin are currently the lowest in the United States due to the
current lack of take-away capacity in the Basin, and may not improve enough,
over a sustained time period, to make many properties economic. To continue
exploration efforts, additional capital (in addition to RMG's one half of
remaining balance under the CCBM $5.0 million drilling commitment which was
$893,300 at December 31, 2002) may be needed. Permitting issues for new wells
may further delay work. An unfavorable confluence of these uncertainties, if
realized, could result in a write-down of the carrying value of those properties
which don't produce enough gas at low prices to be economic. This could result
in the write-down of the carrying value of other properties which need more
wells drilled and dewatered to improve the economics of production; and/or the
delay (whether from lack of capital or permitting problems) in establishing
reserves for the larger prospects where many wells will have to be drilled to
assess their value.
GAS RESERVES
The following table sets forth estimated net proved gas reserves for RMG's
producing properties and the present value (discounted 10%, referred to as the
"PV10") of such reserves as of December 31, 2002. The reserve data and the
present value as of that date were prepared by Ryder Scott Company, independent
petroleum engineers. For further information, see Ryder Scott's reserve report
included as an exhibit to this Annual Report.
The PV10 value was prepared using constant prices as of the calculation
date, discounted at 10% per annum on a pre-income tax basis, and is not intended
to represent the current market value of the estimated gas reserves owned by the
Company. Note that the PV10 discount factor has been calculated net of ad
valorem and production taxes, but before income taxes. The PV10 discount factor
is not the same as the standardized measure of present value calculations which
are determined on an after-income tax basis.
Proved Reserves Proved Reserves
Developed Undeveloped Total
--------- ----------- -----
Coalbed methane gas (Mmcf)* 489.7 95.9 585.6
PV10 Value $ 793,482 $ 94,947 $ 888,429
*Million cubic feet
6
For further information concerning the present value of future net revenue
from these proved reserves, see Note M to the financial statements in this
Annual Report.
These estimates of proved reserves have been filed with the Securities and
Exchange Commission, and have not been included in reports to other federal
agencies.
Note that there are numerous uncertainties inherent in estimating gas
reserves and their estimated values, including many factors beyond the control
of the Company. The reserve data in this Annual Report are only estimates.
Reservoir engineering is a subjective process of estimating underground
accumulations of gas that cannot be measured exactly. Estimates of economically
recoverable gas, and the future net cash flows which may be realized from the
reserves, necessarily depend on a number of variable factors and assumptions,
such as historical production from the area compared with production from other
areas, the assumed effects of regulations by government agencies, assumptions
about future gas prices and operating costs, severance and excise taxes,
development costs, and work-over and remedial costs. The outcomes in fact may
vary considerably from the assumptions.
Estimates of the economically recoverable quantities of gas attributable to
any particular property, the classification of reserves as to proved developed
and proved undeveloped based on risk of recovery, and estimates of the future
net cash flows expected from the properties, as prepared by different engineers
or by the same engineers but at different times, may vary substantially, and the
estimates may be revised up or down as assumptions change.
It is likely that actual production volumes, revenues from production, and
the amount of money spent on the properties, will vary from the estimates. These
variances could be material.
The PV10 discount factor, which is required by the Securities and Exchange
Commission for use in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor, based on
interest rates in effect in the financial markets, and risks associated with the
gas business.
Generally, the volume of gas production declines as reserves are depleted,
with the rate of decline depending on reservoir characteristics. Except to the
extent we conduct successful exploration and development activities, or acquire
properties with proved reserves, or both, our proved reserves will decline with
production. Therefore, our future production depends on finding or acquiring
more reserves.
The business of exploring for, developing, or acquiring reserves is capital
intensive. To the extent operating cash flow is reduced and external capital
becomes unavailable or limited, our ability to make the necessary capital
investment to maintain or expand our gas reserves asset base would be impaired.
There is no assurance future exploration, development, and acquisition
activities will result in additional proved reserves. Even if revenues increase
because of higher gas prices, increased exploration and development costs could
neutralize cash flows from the increased revenues.
VOLUMES, PRICES AND GAS OPERATING EXPENSE
This table shows RMG's 27.6% working (22% net revenue) sales volumes of gas
produced, average sales prices received for gas sold, and average production
costs associated with the Company's gas sales for the seven months ended
December 31, 2002, all from the Bobcat Field.
7
Seven Months Ended
December 31, 2002
-----------------
Sales volumes (Mcf) 64,314
Average sales price per Mcf(1) $1.86
Average cost (per Mcf)(2) $1.91
(1) The Bobcat Field gas (the only property in production at the filing date of
this Annual Report) has an energy content of .96 to .98 MMBtu per 1 Mcf.
From time to time, we have sold some of the production at a set price and
the balance at daily market prices. During the seven months ended December
31, 2002, we sold 22.6% of our share of production at contract prices and
77.4% of our share at the market.
(2) Includes direct lifting costs (labor, repairs and maintenance, materials
and supplies, workover costs, insurance and property, gathering,
compression, marketing and severance taxes).
ACQUISITION AND EXPLORATION CAPITAL EXPENDITURES
From inception on November 1, 1999 through December 31, 2002, RMG incurred
net acquisition (purchase price and holding costs) and exploration costs
(drilling and completion) on CBM properties of approximately $4,904,000, which
does not include approximately $1,606,700 funded by CCBM on RMG's behalf for
lease hold, drilling and completion costs. Unproved CBM properties on the
balance sheet have been reduced by $2,500,000 to reflect the reduction of the
full cost price as a result of principal payments made by CCBM under its
agreement with RMG and by payments from other industry partners.
The following table shows certain information regarding the gross costs
incurred by RMG.
Seven Months Ended Year Ended May 31,
December 31, -------------------------------
2002 2002 2001
------------ ----------- ------------
Acquisition costs $ 936,200 $ 192,600 $ 870,600
Exploration 97,200 87,400 283,900
------------ ----------- ------------
$ 1,033,400 $ 280,000 $ 1,154,500
============ =========== ============
The acquisition costs included amounts paid for properties, delay rentals,
lease option payments, and general and administrative costs directly
attributable to the acquisitions.
The recorded amounts for acquisition and exploration of $1,033,400,
$280,000 and $1,154,500 represent 3.0%, 1.5% and 3.8% of total assets at
December 31, 2002, and May 31, 2002 and 2001, respectively.
We use the full-cost method of accounting for gas properties. Under this
method, all acquisition and exploration costs are capitalized in a "full-cost
pool" as incurred. Depletion of the pool will be recorded using the
unit-of-production method. To the extent capitalized costs in the full-cost pool
(net of depreciation, depletion and amortization and related deferred taxes)
exceed the present value (using a 10% discount rate) of estimated future net
pre-tax cash flows from proved gas reserves as established by reserve reports,
the excess costs will be charged to operations.
If it is determined that there are no reserves on the Clearmont or other
CBM properties, all acquisition and exploration costs previously capitalized for
those properties will be written-down and charged to operations. To the extent
reserves are established to be less than such costs, the costs will be
written-down
8
to the amount of present value of the reserves. In this event, assets would
decrease and expenses would increase. Once incurred, a write-down of gas
properties can't later be reversed.
In addition, if future exploration work (in particular the larger
prospects) is delayed because of lack of capital or permitting delays, or both,
with the result that it cannot be established whether or not proved reserves
exist on the properties, the exploration costs for those properties would be
written-off.
When updated reserve reports are obtained on our properties, any resulting
impact on the financial statements will be reported in the next periodic filing
with the SEC.
As of the filing of this Annual Report, we hold leases and options to
develop approximately 281,886 gross mineral acres (including 43,711 acres we
have options on - see "Oyster Ridge below) under leases from the United States
Bureau of Land Management, the states of Wyoming and Montana, and private
landowners. Table 1 shows the total gross and net lease acres held in each
prospect, and the amount of such acreage held by RMG and by companies with which
RMG has agreements (CCBM, Inc. and Quaneco, L.L.C.). These agreements are
summarized under "Carrizo - Purchase and Sale Agreement" and "Quaneco -
Agreement." Acreage data assumes CCBM completes its obligations; CCBM will own
its 50% working interest in wells drilled under CCBM's drilling fund commitment,
but if CCBM does not complete its purchase obligations, CCBM would be entitled
to a reduced working interest in the remaining undrilled acreage.
The 281,886 gross acres does not include approximately 50,600 acres RMG has
options to purchase. See "New Options Acreage."
CCBM currently has purchase rights to acquire a 6.25% working interest in
the Castle Rock prospect, and owns a 6.25% working interest in eight wells in
Castle Rock, which were drilled by Suncor Energy Natural Gas America, Inc.
("SENGAI"). RMG's and CCBM's interests in the Castle Rock prospect, as shown in
Table 1, reflect the completion of SENGAI's drilling program in late calendar
2001. SENGAI elected not to exercise its option under an Option and Farmin
Agreement on February 8, 2002.
Prospects are evaluated for coal potential using available public and
industry data, taking into account proximity to other positions held by RMG and
existing or planned gas transmission lines, and whether drilling and production
permits can be obtained and the costs thereof. The final decision to acquire a
prospect is made by the president of RMG. Well drilling and testing is done by
outside contract drilling companies. Drilling results (cores, gas and water flow
rates, and other data) are evaluated by RMG staff, using customary technical
methods, to determine if any coal zones encountered in the well should be
completed for production. Completion requires setting casing pipe down to the
zone(s), installing pumps, and installing and setting up the necessary surface
equipment (for example, water disposal lines and water holding tanks for
evaluation wells in Montana, pending production permitting approval and water
holding ponds in Wyoming), and dewatering the well sufficiently so production
can start. The decision whether to complete the well is made by RMG's president.
Table 1 reflects RMG's, Quaneco's and CCBM's acreage position as of the
filing of this Report. Table 1 does not reflect the reduction in net acreage
held by RMG if Anadarko Petroleum, Inc. exercises its option to back-in for a
25% working interest on 43,711 gross acres within the Oyster Ridge prospect.
Also, 43,711 of the acres shown as held in Oyster Ridge assume we continue to
earn acreage under the drill-to-earn-acreage provisions of the option agreement
with Anadarko. See "Description of Prospects - Oyster Ridge" below.
9
TABLE 1
- ---------------------------------------------------------------------------------------------------------
Project
and Date Gross Lease Net Lease RMG Net Quaneco Net CCBM Net
Acquired Acres Acres Acres Acres Acres
- ---------------------------------------------------------------------------------------------------------
Castle Rock 123,840 111,567 48,811 55,784 6,973
Jan. 2000
Kirby 81,494 75,122 18,933 37,256 18,933
Jan. 2000
Bobcat June 1,940 1,940 530 0 530
2002
Oyster Ridge 65,247 65,247 25,729 0 25,729
Dec. 1999
Clearmont 6,465 3,905 1,953 0 1,953
Jan. 2000
Sussex 640 640 320 0 320
Jan. 2000
Finley 160 160 80 0 80
Jan. 2000
Baggs North 120 120 60 0 60
Jan. 2000
Gillette North 80 80 40 0 40
Jan. 2000
Arvada 1,900 1,700 850 0 850
Jan. 2000
- ---------------------------------------------------------------------------------------------------------
TOTAL 281,886 260,481 97,306 93,040 55,468
- ---------------------------------------------------------------------------------------------------------
We own a 25% working interest (20% net revenue interest) in 81,494 gross
and 75,122 net acres in the Kirby prospect (southeast Montana) and a 50% working
interest (from 30% to 50% net revenue interest) in 73,792 net acres in other
prospects (all in Wyoming), and a 27.6% working (22% net revenue) interest in
Bobcat Field. We own a 43.75% working interest (35% net revenue interest) in the
Castle Rock prospect on 123,840 gross and 111,567 net acres in southeast
Montana. CCBM can purchase a 6.25% working interest in our acreage (6,973 net
acres) of the Castle Rock prospect if they meet certain payment obligations. In
July 2001, we sold a 50% working interest in all our coalbed methane leases,
except at Castle Rock, to CCBM for $7,500,000, plus other considerations, and
CCBM purchased a 27.6% working (22% net revenue) interest in Bobcat at the same
time we purchased our interest in Bobcat. The acreage data above reflects these
transactions.
CCBM agreed to pay up to $5,000,000 for drilling and completing CBM wells
on the properties owned by RMG and CCBM. Drilling started on the Clearmont
prospect in Wyoming in August 2001. This drilling program should be sufficient
to drill a total of approximately 60 coalbed methane wells to completion or
abandonment stage. We have a carried working interest in all of the wells
drilled in these programs.
As of the filing of this Report, we have set casing on 33 wells (80 acre
spacing units) and have plugged and abandoned one of those wells at the
Clearmont prospect. No reserves have been established to date on the Clearmont
property. Drilling permits for 61 additional wells have been issued for
Clearmont.
A total of 70 wells have been drilled on RMG acreage through December 31,
2002: 5 in former fiscal year 2001 and 53 in former fiscal year 2002 and 12 in
the seven months ended December 31, 2002. Nineteen of the wells were drilled by
SENGAI in Castle Rock under the terms of a option and farmin agreement. Eleven
of those 19 wells were stratigraphic wells and will be reclaimed by SENGAI; 8 of
those 19 wells were completed and are owned by RMG (93.75% working interest) and
CCBM (6.25% working interest), as
10
Quaneco opted out of maintaining a working interest in the 8 wells. Other than
the Castle Rock and Bobcat wells, RMG and CCBM both have a 50% working interest
in all of these wells (see Table 2 below). For information on the 19 wells
drilled by SENGAI in Castle Rock, see "SENGAI - Option and Farmin Agreement"
below.
As of December 31, 2002, CCBM and RMG have spent approximately $3,171,900
of the $5,000,000 drilling fund. We are relying on the $1,828,100 balance to pay
for continued drilling and completion work on the RMG properties. Like previous
wells drilled with the CCBM drilling fund, RMG will have a 50% carried working
interest with no financial obligation of RMG for drilling and completion costs
until after CCBM has spent $5,000,000. Work would be delayed if CCBM were not
able to fund these costs. Presently, we do not have the capital resources to
fund these costs, and would have to obtain the necessary capital from other
industry partners or from sale of equity in RMG.
Future annual financial obligations for our coalbed methane properties
consist of approximately $323,200 gross in rental fees to the lessors for the
new calendar fiscal year 2003 ($109,600 net to RMG).
Table 2 shows the wells drilled on RMG's prospects from June 1, 2000
through December 31, 2002. Under the agreement with CCBM, RMG has a carried
working interest in all these wells (with the exception of a $156,600 payment
that was made by RMG to cover 50% of a non-consent cost for 12 wells). CCBM also
paid $156,600 to cover 50% of their cost in acquiring a non-consent working
interest in those 12 wells. RMG had a carried working interest in the 8 Castle
Rock wells which were completed (out of the 19 drilled in that prospect), as
SENGAI paid all costs under their drilling program completed in December 2001.
RMG owns a 93.75% working interest and CCBM owns a 6.25% working interest in the
8 Castle Rock wells.
With the exceptions noted above, RMG has had a carried interest in all the
wells on the Oyster Ridge, Clearmont and Arvada prospects. Table 2 lists the
number of wells drilled, the total exploration costs and the remaining number of
wells currently permitted for drilling as of December 31, 2002.
TABLE 2
ROCKY MOUNTAIN GAS, INC.
Prospect FY 2001 FY 2002 New Year 2002 TOTAL Remaining
(6/1/00-5/31/01) (6/1/01-5/31/02) (6/1/02-12/31/02) Permits
Wells $ Wells $ Wells $ Wells $
- --------------------------------------------------------------------------------------------------------------------------
Castle Rock 3 $ 283,900 19 $ 2,500,000 0 $ 4,300 22 $ 2,788,200 16
- --------------------------------------------------------------------------------------------------------------------------
Kirby 0 -0- 0 -0- 0 -0- 0 -0- 8
- --------------------------------------------------------------------------------------------------------------------------
Oyster Ridge 2 150,500 5 464,200 0 3,400 7 618,100 0
- --------------------------------------------------------------------------------------------------------------------------
Clearmont 0 -0- 28 1,470,400 5 474,700 33*** 1,945,100 61
- --------------------------------------------------------------------------------------------------------------------------
Arvada 0 -0- 1 64,800 0 -0- 1 64,800 6
- --------------------------------------------------------------------------------------------------------------------------
Bobcat 0 -0- ** 7 528,500 7 528,500 14
- --------------------------------------------------------------------------------------------------------------------------
TOTAL 5 $ 434,400 53 $ 4,499,400 12 $ 1,010,900 70 $ 5,944,700 105
- --------------------------------------------------------------------------------------------------------------------------
* 19 of these wells were drilled by SENGAI
** 18 wells had been drilled by previous owner
*** one well plugged and abandoned
11
CARRIZO - PURCHASE AND SALE AGREEMENT. On July 10, 2001, RMG closed a
Purchase and Sale Agreement with CCBM, Inc., a Delaware corporation which is
wholly-owned by Carrizo Oil & Gas, Inc., Houston, Texas (NMS "CRZO"). The
agreement between CCBM and RMG is intended to finance the further exploration of
the acreage prospective for coalbed methane currently owned by RMG in Montana
and Wyoming, and to acquire and develop more acreage in Wyoming and the Powder
River Basin of Montana.
RMG has assigned CCBM an undivided 50% interest in all of RMG's existing
coalbed methane properties (with the exception of Castle Rock of which only a
6.25% working interest was assigned) for a purchase price of $7,500,000 by a
promissory note payable in principal amounts of $125,000 per month plus interest
at an annual rate of 8%, over 41 months (starting July 31, 2001) with a balloon
payment due on the forty-second month. These properties consisted of the Kirby,
Oyster Ridge, Clearmont, Sussex, Finley, Baggs North, and Gillette North
properties. The 50% undivided interest is pledged back to RMG to secure the
purchase price, and will be released 25% when 33.3% of the principal amount
($2,500,000) of the purchase price is paid, another 25% when total principal
payments reach 66.6% of the principal amount ($5,000,000) of the purchase price,
and the balance of the total 50% undivided interest when all of the principal
amount ($7,500,000) of the purchase price, has been paid.
CCBM has the right to participate in other properties RMG may acquire (like
the Bobcat property) under the area of mutual interest ("AMI"), see "Agreement
for Purchase of the Bobcat Property" above, and "Carrizo - Purchase and Sale
Agreement" in the Annual Report (Form 10-K/A1) for the former fiscal year ended
May 31, 2002.
In addition to its one-half share of revenues in proportion to its one-half
share of the working interest, CCBM will be entitled to a credit (applied as a
prepayment of the purchase price for the undivided 50% interest in RMG's
acreage), equal to 20% of RMG's net revenue interest from wells drilled with the
$5,000,000 drilling budget, until the amount of that credit in favor of CCBM
equals $1,250,000.
RMG is the designated operator under a Joint Operating Agreement between
RMG and CCBM, which governs all operations on the properties subject to the
Purchase and Sale Agreement between RMG and CCBM subject to pre-existing JOA's
with other entities, and operations or properties in the area of mutual interest
("AMI"). The AMI four-year term ends June 30, 2005. It covers the entire state
of Wyoming, and the Powder River Basin of Montana, but will be reduced if CCBM
does not obtain at least $20 million for future property acquisitions (see
below).
Under the Purchase and Sale agreement with CCBM, CCBM will use its best
efforts to obtain financing to raise no less than $20,000,000 to be used by RMG
to acquire more properties in the AMI. CCBM would have a 50% working interest in
properties so acquired. If CCBM's efforts were not successful by June 30, 2002,
the AMI was to be reduced to a 6-mile radius from all existing properties held
jointly by RMG and CCBM. As of December 31, 2002, CCBM has not been successful
in its efforts to raise the $20,000,000 land acquisition fund. RMG has agreed
verbally not to invoke this provision of the contract, which CCBM has agreed to
continue to pursue sources of capital to fund the $20,000,000 commitment.
A management committee oversees all operations subject to the Purchase and
Sale Agreement, with two members each from CCBM and RMG, however, RMG shall have
a tie-breaking vote until the $5,000,000 drilling commitment has been expended
and until the purchase price has been paid. Once the $5,000,000 drilling
commitment has been expended and the full purchase price is paid, RMG will
allocate (with Quaneco's consent) to CCBM one of RMG's managing member positions
with Powder River Gas LLC, which is the operative entity for the Montana acreage
RMG holds with Quaneco L.L.C.
12
QUANECO - AGREEMENT. On January 3, 2000, RMG purchased a 50% working
interest and 40% net revenue interest in the Castle Rock and Kirby prospects in
the Powder River Basin of southeast Montana consisting of approximately 185,000
net mineral acres from Quaneco, L.L.C. (formerly Quantum Energy, L.L.C.,
Cleveland, Ohio and Oklahoma City, Oklahoma). The acreage includes 88,409 net
acres of Bureau of Land Management ("BLM") land, 14,916 net acres of state land
(Montana), and 82,775 net acres of fee land. In fiscal 2000 and 2001, RMG paid
Quaneco the cash purchase price of $5,500,000 for the acreage plus a drilling
commitment of $2,500,000.
For information on the Quaneco agreement, see "Quaneco Agreement" in the
Annual Report (Form 10-K/A1) for the former fiscal year ended May 31, 2002.
SENGAI - OPTION AND FARMIN AGREEMENT.
For information on the Quaneco agreement, see "SENGAI Option and Farmin
Agreement" in the Annual Report (Form 10-K/A1) for the former fiscal year ended
May 31, 2002.
NEW OPTIONS ACREAGE
In December 2002, we signed an option to acquire producing, proven and
undeveloped CBM properties from an undisclosed party. The optioned properties
are reported to be producing CBM from 184 wells producing from various coal
seams ranging in depth from 400 to 500 feet. Working interest in these wells
range from 27% to 100% and net revenue interest ranges from 21% to 98%. Deeper
coals could be prospective for development, and operational and infrastructure
improvements. Drilling more wells could enhance current production. The
properties include various gas gathering contracts, gas purchasing contracts and
additional drilling permits. This option expires April 15, 2003.
In February 2003, we signed a separate option with the same party to
acquire additional gross acres of undeveloped acreage. There are reported to be
10 completed shut-in wells on the properties. A portion of the acreage under
option, offsets production from adjoining properties belonging to other parties.
Pipelines traverse a portion of the acreage. This option expires May 1, 2003.
As of the filing of this Annual Report, RMG is conducting due diligence
review of the acreage under the options. Ryder Scott Company, independent
petroleum engineers, is preparing reserve evaluations of the producing
properties under option. Results of the reserve reports will determine whether,
and at what price, RMG will negotiate the purchase of one or both properties.
Closing is subject to RMG raising sufficient capital. CCBM will have the right
to purchase one-half the interests RMG purchases in the acreage.
DESCRIPTION OF PROSPECTS
Leases of federal mineral rights are obtained from the United States Bureau
of Land Management and expire from 2004 to 2009, unless RMG establishes
production on the lease, in which event the lease is held so long as coalbed
methane or other gas or oil is produced. A royalty interest of 12.5% on the
production is paid to the BLM. State leases expire from 2003 to 2004 in Wyoming
and Montana, unless RMG establishes production on the lease, in which event the
lease is held so long as coalbed methane or other gas or oil is produced. The
royalty paid to the State of Wyoming is from 12.5 % to 16.67%, and 12.5% to the
State of Montana. Annual renewal fees for non-producing Federal leases is $1.50
to $2.00 per acre, and $1.00 and $1.50 for non-producing Wyoming and Montana
leases.
13
An environmental group has filed a lawsuit against the BLM, RMG and others,
challenging the validity of numerous BLM leases in the Powder River Basin of
Montana. See Item 3, Legal Proceedings ("Rocky Mountain Gas Litigation").
Leases on private (fee) land for coalbed methane and conventional gas
expire at various times from 2003 to 2011, unless production is established, in
which event the lease is held so long as there is production. The landowner is
paid a royalty from production of 12.5% to 20.0% , depending on the lease terms.
Table 3 presents total acreage, both developed and undeveloped held by RMG
at December 31, 2002.
TABLE 3
ROCKY MOUNTAIN GAS, INC.
- ------------------------------------------------------------------------------------------------------------------------
Gross Leased Net Leased Net Leased Net Leased Net Leased from Net Leased
Prospect Acres Acres from BLM from State of State of from Private
Wyoming Montana Owners
- ------------------------------------------------------------------------------------------------------------------------
Castle Rock 123,840 111,567 55,104 0 10,860 45,603
- ------------------------------------------------------------------------------------------------------------------------
Kirby 81,494 75,122 33,305 0 4,056 37,761
- ------------------------------------------------------------------------------------------------------------------------
Oyster Ridge* 21,536 21,536 17,107 1,229 0 3,200
- ------------------------------------------------------------------------------------------------------------------------
Clearmont 6,465 3,905 0 640 0 3,265
- ------------------------------------------------------------------------------------------------------------------------
Sussex 640 640 0 640 0 0
- ------------------------------------------------------------------------------------------------------------------------
Finley 160 160 0 160 0 0
- ------------------------------------------------------------------------------------------------------------------------
Baggs North 120 120 0 120 0 0
- ------------------------------------------------------------------------------------------------------------------------
Gillette North 80 80 0 80 0 0
- ------------------------------------------------------------------------------------------------------------------------
Arvada 1,900 1,700 1,200 0 0 500
- ------------------------------------------------------------------------------------------------------------------------
Bobcat - Undeveloped 180 180 0 0 0 180
- ------------------------------------------------------------------------------------------------------------------------
Total Undeveloped Acres 236,415 215,010 106,716 2,869 14,916 90,509
- ------------------------------------------------------------------------------------------------------------------------
Bobcat - Developed 1,760 1,760 0 0 0 1,760
- ------------------------------------------------------------------------------------------------------------------------
Total Acres 238,175 216,770 106,716 2,869 14,916 92,269
- ------------------------------------------------------------------------------------------------------------------------
*Does not include 43,711 acres under option from Anadarko Petroleum. See
"Description of Properties - Oyster Ridge."
BOBCAT FIELD. On April 12, 2002, the Company and RMG signed an agreement to
purchase working interests in approximately 1,940 gross acres of coalbed methane
properties in the Powder River Basin of Wyoming. The contract closed on June 4,
2002. The Company paid the seller $500,000 cash and another $150,000 by issuing
37,500 shares of its restricted common stock to the seller; CCBM paid $500,000
cash to the seller and Carrizo Oil & Gas, Inc. issued its restricted shares of
common stock valued at $150,000. The properties are located approximately 25
miles north of Gillette, Wyoming, in Campbell County.
As of the filing of this Annual Report, 24 CBM wells have been drilled (22
completed in the Cook coal at 650 feet, 2 completed in the Canyon coal at 450
feet), and are producing. Produced and sold gas (net of gas used as fuel for the
compressors) averaged approximately 1,829 Mcf or 1,796 MMBtu per day in
14
January 2003 (422 Mcf or 414 MMBtu per day net to RMG). All gas sales during
January 2003 were sold at market prices, which averaged $3.03 per MMBtu.
In February 2003, RMG received a guaranteed contract price of $3.07 per
MMBtu for its share of the first 1,000 MMBtu of gas sold each day, with the
balance at market prices (an average of $4.25/MMBtu). 500 MMBtu per day will be
sold at a guaranteed contract price of $3.52 per MMBtu from March 1, 2003 to
October 31, 2003. Reserves have been established for the Bobcat Field, see "Gas
Reserves" above.
CASTLE ROCK: The Castle Rock project consists of 123,840 gross and 111,567
net acres located in the northeastern portion of the Powder River Basin of
Montana, west of Broadus, Montana. Coals present are in the Tongue River member
of the Fort Union formation and appear comparable to coals currently being
developed by other operators south of the Castle Rock acreage near the
Montana/Wyoming border. Currently, there are no pipelines in this area.
KIRBY: The Kirby project consists of 81,494 gross and 75,122 net acres
located in the northwestern portion of the Powder River Basin in Montana located
in Big Horn and Rosebud Counties, Montana, north of Sheridan, Wyoming. Coals are
in the lower portion of the tertiary Fort Union formation and are similar to
productive coals in the Wyoming portion of the Powder River Basin to the south.
Redstone (recently acquired by Montana Dakota Utilities) has established
significant coalbed methane production 12 miles south of Kirby at the CX field.
At least two other operators are currently planning to drill and develop nearby
acreage. CMS's Bighorn Gas Gathering recently extended a new 20" pipeline to
within 10 miles of the Kirby project.
In the seven months ended December 31, 2002, a 3 well exploration program
was started; 2 wells have been drilled and were completed in January 2003 at the
southern end of the acreage, with encouraging initial gas shows and an
individual coal thickness of over 50 feet. Complete results from the exploration
program will dictate the extent of follow-up pilot programs tentatively
scheduled for later in 2003.
OYSTER RIDGE: The Oyster Ridge project consists of 65,247 gross and net
acres located in southwestern Wyoming in the Ham's Fork Coal Field adjacent to
the Green River Basin. RMG and CCBM have a 100% working interest (50% each) in
21,536 acres within Oyster Ridge.
Anadarko Petroleum, Inc. is successor to Union Pacific Land Resources
Corporation, which sold the acreage subject to UPLRC's back-in option to third
parties, from whom RMG acquired the acreage in December 1999.
The agreement with Anadarko is a drill-to-earn-acreage agreement: we must
drill at least four wells each year, each on a new section (640 acres), to earn
a lease on each drilled section , and also to keep in force previously earned
leases in the 43,711 acres areas. Wells drilled by our seller, and by us (with
CCBM), have earned 3,200 acres, which are included in the 21,536 acres leased
presently. Under the terms of the agreement, we must drill 4 additional wells by
March 31, 2003 to keep our agreement in force. As a result of a 60 day extension
of time granted by Anadarko, RMG expects to meet this drilling commitment.
Within this prospect, 43,711 gross acres are subject to an option held by
Anadarko Petroleum, Inc. to participate as a 25% working interest owner on all
wells drilled each year. Anadarko has not yet elected to participate, and has no
working interest in the seven wells drilled to date on this prospect. If
Anadarko elects to participate in the future, working interest ownership in
affected wells would be 37.5% RMG, 37.5% CCBM, and 25% Anadarko.
15
The area is prospective for coalbed methane production from two primary
Cretaceous age coals, the Frontier and the Adaville. The Kern River pipeline,
which services southern California, crosses the property. Exploratory drilling
and completion operations on previously drilled wells resumed at Oyster Ridge in
June, 2001. Through December 31, 2002, $618,100 has been spent on drilling and
completion at Oyster Ridge.
CLEARMONT: The Clearmont project consists of approximately 6,465 gross and
3,905 net acres located in the western Powder River Basin of Wyoming. RMG (and
now CCBM jointly) owns working interests ranging from 25% to 100%. The area is
characterized by several shallow Fort Union coalbeds (most notable the Roland
and Anderson coals) as well as several deeper coals that hold significant
exploration potential. Substantial coalbed methane production and development is
ongoing in the immediate area including Federated's Box Elder Creek project 12
miles to the west and the Penneco/CMS Wild Horse Creek project 15 miles to the
east. The Clearmont project is located at the convergence of the WBI Bitter
Creek and the Bighorn Sheridan Lateral pipelines. An exploration drilling
program began at Clearmont in August 2001 and could be in production fourth
quarter 2003 depending on drilling results and gas prices. Through December 31,
2002, $1,945,100 has been spent on drilling and completion at Clearmont.
Nineteen of the existing 32 wells at Clearmont have been on full-scale
dewatering since June 2002. These 19 wells are hooked up to a gas gathering
system but as of December 31, 2002, no gas production had occurred. The other 13
wells were not being dewatered as of December 31, 2002. Dewatering of these
wells will commence once the gathering system is installed. During 2003, RMG
expects to begin selling gas produced from the Clearmont wells to CMS Field
Services, Inc. pursuant to a gas contract. However, production could be delayed
if dewatering hasn't progressed sufficiently to allow production of commercial
amounts of gas. In the third calendar quarter 2002, RMG completed construction
of a field gathering system (for delivery and initial compression of the gas) to
Bighorn Gas Gathering, LLC. Bighorn has signed a gas gathering agreement with
RMG to deliver gas collected from RMG's system to CMS.
SUSSEX: RMG and CCBM hold 640 gross and net acres in this project area
located in Johnson County, Wyoming. This State lease lies 3 miles south of
Sussex, Wyoming. RMG has a 50% working interest. To date, RMG has not conducted
any significant exploration on the property.
FINLEY: RMG and CCBM hold 160 gross and net acres in this project area
located in Converse County, Wyoming. This prospect is a State lease 12 miles
east of Edgerton, Wyoming. To date, RMG has not conducted any significant
exploration on the property.
BAGGS NORTH: This prospect contains 120 gross and net acres located in
Carbon County, Wyoming. This State lease is located 7 miles north of Baggs,
Wyoming. RMG holds a 50% working interest in this prospect. To date, RMG has not
conducted any significant exploration on the property.
GILLETTE NORTH: RMG holds a 50% working interest in 80 gross and net acres
in this project area located in Campbell County, Wyoming. This State lease lies
at the north end of the City of Gillette. Existing coalbed methane wells lay in
the section immediately north. To date, RMG has not conducted any significant
exploration on the property.
ARVADA: This prospect contains 1,900 gross acres, 1,700 net acres, located
in Sheridan County, Wyoming adjacent to the Clearmont prospect. RMG holds a 50%
working interest, and a 31% to 40.75% net revenue interest. To date, RMG and
CCBM have spent $64,800 on the drilling of one 1,471' deep test well and are
analyzing the drilling results. Gas gathering and production sales are covered
by agreements with Bighorn Gas Gathering, LLC and CMS Field Services, Inc.
16
GENERAL INFORMATION ABOUT COALBED METHANE.
Methane is the primary commercial component of natural gas produced from
conventional gas wells. Methane also exists in its natural state in coal seams.
Natural gas produced from conventional wells generally contains other
hydrocarbons in varying amounts which require the natural gas to be processed.
Methane gas produced from coalbeds generally contains only methane and is
pipeline-quality gas after simple water dehydration.
Coalbed methane ("CBM")production is similar to conventional natural gas
production in terms of the physical producing facilities. However, the
subsurface mechanisms that allow gas movement to the wellbore are very
different. Conventional natural gas wells require a porous and permeable
reservoir, hydrocarbon migration and a natural structural or stratigraphic trap.
Coalbed methane gas is trapped (adsorbed) in the coal itself and in the water
contained in the pore space, until released by pressure changes when the water
in the coal is removed. In contrast to conventional gas wells, new coalbed
methane wells initially produce water for several months. As the formation water
pressure decreases, methane gas is released from the structure.
Methane production is a direct result of reducing the hydrostatic (water)
pressure in the coal formation. Three principal stages are involved:
o Drill wells (typically eight or more in a 'pod') down to the same coal
formation, in contiguous 80 acre spacing per well; test the water in
the formation and test coal samples taken from the formation. Water
testing determines if the geochemical environment of the coal seam is
conducive to the formation of CBM.
o Install gathering lines to hook up and put wells on pump to 'dewater'
the coal formation. Hydrostatic pressure must be reduced to about 50%
of initial pressure before enough data is obtained (water flow rates,
CBM gas flows) to determine how much CBM the wells may produce. This
dewatering stage may take 6 to 18 months, and in some instances 24
months (where there is no dewatering of the coal seam occurring from
wells drilled by others on adjacent properties).
o Installing (or have a transmission company install) a compressor and
transport line to carry produced gas to a gas transmission line for
sale to end users. Gas production starts gradually then continues to
grow in volume as hydrostatic pressure is reduced; optimal production
won't occur until hydrostatic pressure is reduced approximately 90%
from initial levels.
COALBED METHANE WELL PERMITTING
Operators drilling for coalbed methane are subject to many rules and
regulations and must obtain drilling, water discharge and other permits from
various governmental agencies depending on the type of mineral ownership and
location of the property. Intermittent delays in the permitting process can
reasonably be expected throughout the development of all RMG projects. For
example, there is currently a temporary moratorium for drilling coalbed methane
wells on fee and state lands in Montana (although, RMG negotiated the right to
receive 116 drilling permits to drill in Montana during the moratorium). We may
shift our exploration and development strategy as needed to accommodate the
permitting process. As with all governmental permit processes, there is no
assurance that permits will be issued in a timely fashion or in a form
consistent with the plan of operations.
Drilling and production operations on our Powder River Basin leases in
Wyoming and Montana are subject to environmental rules, requirements and permits
issued by various federal authorities for drilling and
17
operating on all land, regardless of ownership, and state and local regulatory
agencies for land owned by the state or in fee by private interests. The primary
U.S. federal agency with related responsibilities is the Bureau of Land
Management of the U.S. Department of the Interior ("BLM") which has imposed
environmental limitations and conditions on coalbed methane drilling, production
and related construction activities on federal leases in the PRB. These
conditions and requirements are imposed through Records of Decision ("ROD")
issued pursuant to Environmental Impact Statements ("EIS"). The BLM may also
impose site- specific conditions on development activities, such as drilling and
the construction of rights-of-way, before it approves required applications for
permits to drill and plans of development. The BLM is currently developing an
updated Supplemental EIS ("SEIS") for 51,000 CBM wells in the Powder River Basin
of Wyoming. Additionally, the BLM is conducting a SEIS for 39,000 CBM wells in
Montana. Both of these PRB SEISs are expected to be completed, with RODs issued,
by mid 2003. While the BLM SEIS has been underway, there has been a moratorium
on the issuing of new drilling permits on federal leases in both Wyoming and
Montana; however, RMG currently holds previously issued BLM permits and Montana
state permits to drill 16 wells on the Castle Rock project and 8 wells on the
Kirby project and can therefore drill these wells prior to completion of the
SEISs and issuance of additional permits.
The state-based environmental agencies primarily concern themselves with
the issuance of permits related to drilling, land, air quality and water
discharge. The primary state-based agencies for which coalbed methane operators
are subject to include:
o Wyoming Department of Environmental Quality ("WDEQ")
o Wyoming Oil and Gas Conservation Commission ("WOGCC")
o Montana Department of Environmental Quality ("MDEQ")
o Montana Board of Oil and Gas Conservation ("MBOGC")
While the BLM is primarily responsible for issuing broadly based EISs for
each state, its jurisdiction over related matters and the actual issuance of
drilling permits is primarily reserved for federal leases. Permits for drilling
on state or fee owned land are issued by the WOGCC and MBOGC following their
review of the BLM EIS and the formulation of their own local EIS's.
The WOGCC has historically undertaken environmental studies and its history
in issuing drilling permits for the Powder River Basin is as follows:
o 90 wells approved on three small pilot projects from 1992 to 1995.
o 250 wells approved in areas north of Gillette in 1996.
o 640 wells approved in areas south of Gillette in 1997.
o 5,890 wells approved in 1999, (in conjunction with the 1998 Wyoming EIS)
in the Wyodak area. (The Wyodak area of the Powder River Basin runs
south of Gillette and was the initial development area of the Basin).
o 2,500 wells approved in early 2001 in the Wyodak area, primarily on
federal lands.
To date, a total of 28,000 CBM drilling permits have been issued statewide,
(including permits for other coalbed methane basins) on federal, state and fee
leases, although 6,700 were unused and are now expired.
In conjunction with the BLM EIS, WOGCC has also been formulating its own
updated SEIS since June 2000 related to future permits for 51,000 CBM wells in
the PRB of Wyoming covering 8,000,000 acres in Campbell, Sheridan, Johnson and
Converse counties. The related minerals are on land which is 54% federal, 37%
fee and 9% state. Surface rights are on land which is 14% federal, 77% fee and
9% state. The related ROD is expected by mid 2003, which should lead to a large
number of new drilling permits being
18
issued in 2003. The WOGCC has estimated that approximately 5,000 new CBM wells
will be drilled annually for at least the next five years.
In contrast to Wyoming, Montana authorities have been very slow in
undertaking CBM environmental studies and granting permits to drill wells. In
fact, to date, only the Redstone (Fidelity) project just south of RMG's Kirby
project is producing CBM gas in Montana. With the exception of a relatively
small number of drilling permits available from earlier issuance (including
those held by RMG which have allowed some recent drilling on the Kirby and
Castle Rock projects), a drilling moratorium has been in effect during the last
two years. In recent months, however, the MBOGC has drafted a SEIS, as an
amendment to the Powder River and Billings Resources Management Plans, for
coalbed methane gas development in Montana. This new SEIS, in conjunction with
the similar EIS carried out by the BLM, is expected to address a comprehensive
statewide CBM development program to allow permitting for 39,000 wells. A draft
of the SEIS has been completed and a ROD is expected by mid 2003. Additionally,
despite the current moratorium on CBM drilling permits in Montana, RMG received
one of only two Environmental Assessments and a Finding of No Significant Impact
("FONSI")which will allow it to drill 56 wells on federal leases held in
Montana. These wells would evaluate potential CBM production as well as
conventional gas. The ROD in Montana is expected by mid 2003 and drilling
permits should then be issued on federal, state and fee leases.
The DEQs are primarily responsible for issuing air quality and water
discharge permits, among other things. Water disposal has been and is expected
to continue to be a significant issue, particularly with respect to coalbed
methane gas production, which typically entails substantial water production at
least during the dewatering phase of completion of a new well. The primary issue
of concern is the salinity content in the produced water, which is measured by
the sodium absorption ratio ("SAR"), which, depending upon a location, can range
from slightly less than that in surface water to a substantially greater amount.
Due to the discrepancies of the SAR content found in water from coalbed methane
wells, the disposal of this water is tightly regulated. If the SAR content is
low, the water can be used for irrigation, livestock drinking water or even as a
water supply for cities. If the SAR content is higher, the water quality does
not merit use for drinking water or irrigation and, under these measures, the
DEQ has outlined various other methods of water disposal. Man-made ponds may
also be built right beside the wells, enabling the wells to drain their water
into the ponds (called surface discharge). Additionally, there might be
drainages which the produced water can flow into. Finally, the water might be
reinjected through wells into the ground below levels from which the water was
produced. Thus far, the vast majority of associated water produced has been
discharged on the surface, primarily captured in reservoirs and ponds and
allowed to evaporate.
Overall, RMG has not experienced any difficulty in obtaining air quality
and water discharge permits from the WDEQ and has yet to apply for such permits
in Montana. It has two WDEQ National Point Discharge Elimination System
("NPDES") Program permits to dispose of all anticipated water production into
reservoirs at the Bobcat and Clearmont projects. The State of Wyoming recently
streamlined the process and time required to obtain these permits and RMG
anticipates that it will be able to obtain the necessary permits for its other
properties in Wyoming and Montana.
The following summarizes permits now in place.
19
Table 4
Expiration
Prospect Remaining Permits or Renewal Date
- --------------------------------------------------------------------------------
Castle Rock 16 05/13/03 and 07/03/03
- --------------------------------------------------------------------------------
Kirby 8 07/03/03 and 07/15/03
- --------------------------------------------------------------------------------
07/15/03; 08/01/03; 08/02/03; 08/09/03;
Clearmont 61 09/11/03; 10/28/03; 11/20/03;
12/19/03; 12/20/03 and 02/17/04
- --------------------------------------------------------------------------------
Arvada 6 10/28/03 and 12/05/03
- --------------------------------------------------------------------------------
Bobcat 14 09/11/03; 09/18/03 and 12/19/03
- --------------------------------------------------------------------------------
Total 105
- --------------------------------------------------------------------------------
Drilling permits issued by the State of Wyoming allow one year for drilling
completion; permits issued by the State of Montana allow six months. Expired
permits for undrilled locations are usually renewed by the agencies without
difficulty.
Once drilled, all wells in Wyoming are subject to a National Pollution
Discharge Elimination System ("NPDES") permit relating to water testing and
discharge. All wells in the Castle Rock and Kirby prospects remain subject to
the Montana Board of Oil and Gas Commission approval. Upon completion of
drilling, wells are subject to monthly reporting regarding status and production
to the respective state agencies in which they are located.
GATHERING AND TRANSMISSION OF CBM GAS
Due to the low pressure characteristics of the coalbeds, the production of
coalbed methane is dependent on the installation of multi-stage compression
facilities. Gas gathering will be similar among RMG's fields. Components include
the wellhead and two pipelines. One pipeline transports gas to a low level
compression station, then on to a high level compression station and finally to
the transmission pipeline. The water is commonly collected through another
pipeline from each of the wells and pumped into a surface reservoir.
Companies involved in coalbed methane production generally outsource gas
gathering, compression and transmission. RMG and industry partners have and will
likely continue to outsource their compression and gathering to third parties at
fixed charges per Mcf transported.
GAS MARKETS
Current production from the PRB, having grown from virtually nothing in the
early 1990s, is now approximately 900 Mmcfd. Since this area is sparsely
populated, most of this gas must be exported from Montana and Wyoming to distant
markets. The existing Wyoming pipeline infrastructure is already substantial and
continues to expand with gathering systems and intrastate lines, yet is
ultimately dependent on large interstate pipelines. With the exception of a
portion of the gathering systems, this pipeline system is typically owned and
operated by independent mid-stream energy companies, rather than oil and gas
operators. The pipelines generally will not be financed and constructed until
appropriate amounts of gas have been proven and committed for transport on the
new lines. While the total current take away capacity from the PRB is
approximately 1.25 billion cubic feet per day (Bcfd), excess capacity over
current production rates does not exist in all locations and not all producers
have a ready market for the sale of their gas at all times. Some major producers
in the region reserve portions of pipeline capacity beyond their current
requirements, resulting in less than stated maximum capacity being available for
other producers. In addition, total stated
20
capacity is unavailable at times, as was the case during this past summer when
two major pipelines were curtailed or shut down for maintenance or construction
activities.
Based on the existing pipeline systems and the gas sales markets in its
area of operations in Wyoming, RMG expects that, at least for the next few
years, the markets in which it sells its gas, and the spot prices to which it
will be subject, will be dependent upon three major sales points:
o The Colorado Interstate Gas ("CIG") station near Cheyenne in
southeastern Wyoming, which primarily feeds regional markets or
markets in the Midwest.
o The Ventura market ("Ventura") located in Ventura, Iowa, which
prices gas on the Northern Border pipeline where it interconnects
with Northern Natural Gas and feeds markets in the Northern
Plains and Midwest.
o The Opal market ("Opal") in southwestern Wyoming, which delivers
to the Kern River pipeline for delivery to Utah, Nevada, Arizona
and California.
PIPELINES THAT SERVE THE CIG MARKET
Following early PRB development, two large diameter intrastate pipelines,
the Fort Union and the Thunder Creek, were constructed in the Basin in 1999, and
gathering system infrastructure has continued to grow significantly since that
time. These two major intrastate pipelines currently provide almost 1.1 Bcfd
capacity, flowing south out of the Basin to the CIG Hub in Southeast Wyoming.
Descriptions are as follows:
o Fort Union. The Fort Union Gas Gathering pipeline consists of a
106 mile, 24 inch, 434 Mmcfd capacity line completed in August
1999 and a 20" pipeline with a capacity of 200 Mmcfd completed in
September 2001. It is believed that capacity could be increased
by another 200 Mmcfd by adding additional compression to this
line.
o Thunder Creek. Thunder Creek Gas Services pipeline is a 126-mile,
24 inch pipeline which commenced operations on September 1, 1999
with a capacity of 450 Mmcfd.
The RMG Bobcat Field currently delivers its gas to the Thunder Creek
pipeline where it is carried south and delivered to the CIG market. As an
alternative, the Bobcat gas could be sold in the Ventura market through an
interconnection of the Thunder Creek pipeline to other lines flowing north out
of the Basin.
The Clearmont and Arvada projects will utilize the Big Horn pipeline, a 110
mile gathering line originating on the Montana/Wyoming border north of Sheridan,
flowing generally east and bisecting the Clearmont and Arvada projects before
connecting with the Fort Union pipeline. The Big Horn pipeline was completed in
December 2000 with an initial capacity of 250 Mmcfd and is readily up-gradable
through additional compression to 500 Mmcfd. While the Big Horn pipeline can
currently deliver gas only to the south into the CIG market, anticipated future
pipeline construction may enable this gas to be delivered to the Ventura market
at a later date.
When the Kirby project is prepared to commence gas sales in the future, it
is expected that this property will be hooked up with an approximate 10 mile
extension of the Big Horn pipeline. However, Kirby is still largely unexplored,
so any production from this acreage may be several years into the future.
21
PIPELINES THAT SERVE THE VENTURA MARKET
There is currently only a single significant pipeline capable of
transporting gas out of the Basin to the north, the Bitter Creek pipeline, which
connects with the Northern Border interstate pipeline. However, two additional
lines that are well along in their planning stages, would also deliver gas to
the Northern Border pipeline. Descriptions are as follows:
o Bitter Creek. The Bitter Creek pipeline is owned by Williston
Basin Interstate Pipeline Company ("WBI"), a subsidiary of MDU
Resources Group, Inc. It was completed in 2001 with initial
capacity of 150 Mmcfd.
o Grasslands. In response to the need for expandable access to the
Ventura market, the Grasslands pipeline, also owned by WBI, is
expected to be completed and in service by November 2003. It is
anticipated to be a 245 mile, 16 inch line with an initial
capacity of 80 Mmcfd and expandable to 200 Mmcfd.
o Bison. Northern Border Partners, L.P. is currently holding an
open season to solicit interest in firm transportation on the
proposed Bison 20 inch interstate pipeline project which would
connect PRB gas supplies to a proposed interconnection to its own
Northern Border pipeline. Currently, the project is anticipated
to be in service in November 2005 with a capacity of 240 Mmcfd.
The pipeline is proposed to start near Gillette, Wyoming and
extend north into Montana. Interconnections for receipt of gas
are proposed with Big Horn, Fort Union, Thunder Creek and other
lines through the eastern corridor of the Castle Rock project.
THE OPAL MARKET
The Opal market, in southwestern Wyoming, is a major pipeline connection
point, with several intrastate and interstate lines connecting to the major
interstate line, Kern River, which transports gas to the southwest and is
described as follows:
o Kern River. The Opal market is served by the Kern River pipeline
which has a capacity of 824 Mmcfd, and delivers to markets in
Utah, Nevada, Arizona and California. Kern River Gas Transmission
has started construction of a $1.2 billion expansion project to
more than double the capacity of its 926 mile interstate
pipeline. When completed in May 2003, this line will have
capacity of 1.73 Bcfd.
GAS PRICES
Historically, spot gas prices received by producers at the Ventura, CIG and
Opal markets have generally been at discounts to the NYMEX front month contract
and Henry Hub spot cash prices, although with lesser discounts during the winter
months. Prices at CIG almost always trade at a further discount to the Ventura
prices, and again with an even higher discount during the second and third
quarters, because CIG is partially based on local demand which drops
approximately 50% outside the heating season, whereas Ventura serves larger
national markets and is highly correlated to Chicago market prices.
Opal has generally traded in price ranges close to those at CIG. This
larger than normal negative spread has resulted from a combination of (i)
rapidly growing CBM and conventional gas production volumes in this region, (ii)
the curtailment of both of the primary lines taking gas south out of the PRB due
to maintenance and/or construction (Fort Union and Thunder Creek), (iii) weak
western U.S. demand during most of 2002, (iv) large amounts of current pipeline
capacity controlled by the larger producers, and (v)
22
restraint in new pipeline construction from both regulatory delays and hesitancy
to construct new lines by the pipeline companies. RMG management believes that
this situation is temporary and that new pipelines currently under construction
should bring the price differentials back to normal historic levels in 2003 and
2004. Furthermore, commencing with cooler weather in late October 2002, realized
prices in the CIG market have returned to differentials more in line with the
historical norm. However, there is no guarantee that the increased capacity will
eliminate the negative price differential or even significantly reduce it.
INACTIVE MINING PROPERTIES - URANIUM
GENERAL. We have interests in several uranium-bearing properties in Wyoming
and Utah and in a uranium processing mill in southeastern Utah (the "Shootaring
Mill" in Garfield County). All the uranium- bearing properties are in areas
which produced significant amounts of uranium in the 1970s and 1980s. At some
future date, we could sell or develop and operate these properties (directly or
through a subsidiary company or a joint venture) with companies having the
necessary capital to mine and mill the uranium bearing material to produce
uranium concentrates ("U3O8") for sale to public utilities that operate nuclear
powered electricity generating plants. Currently there is no uranium mill
available in Wyoming and it would take a substantial increase in the market
price of uranium concentrate over a period of time before a company with the
financial wherewithal would build a mill and place the deposits in production.
Therefore, until uranium oxide prices improve significantly, the uranium
properties will remain shut down.
At the dates of the consolidated balance sheets in this report, there are
no values carried on the balance sheets for uranium properties.
SHEEP MOUNTAIN - WYOMING
Unpatented lode mining claims, underground and open pit uranium mines and
mining equipment in the Crooks Gap area are located on Sheep Mountain in Fremont
County, Wyoming. From December 21, 1988 to June 1, 1998, these properties were
held by Sheep Mountain Partners ("SMP"). On June 1, 1998, the Company received
back from SMP all of the Sheep Mountain mineral properties and equipment, in
partial settlement of disputes with Nukem, Inc. ("Nukem") and its subsidiary
Cycle Resource Investment Corp. ("CRIC"). The judgment against Nukem impressing
the CIS uranium supply contracts in constructive trust with SMP remains
unresolved. See "Legal Proceedings." The Sheep Mountain Mines 1 and 2 were first
operated by Western Nuclear, Inc., a subsidiary of Phelps Dodge Corporation, in
the late 1970s.
We have recorded reclamation liabilities for the SMP properties (see note K
to the consolidated financial statements in this report). All historical costs
in the SMP properties were offset against a monetary award which was received
from Nukem during fiscal 1999.
THE PROPERTY INTERESTS OF USE IN UTAH THROUGH PLATEAU RESOURCES LIMITED
("PLATEAU") ARE:
Plateau Resources Limited is a wholly-owned subsidiary of USE. See "Plateau
Shootaring Canyon Mill" below.
The Tony M property contains underground uranium deposits in San Juan
County, Utah.
Plateau is the lessee of the Tony M property and has posted a bond securing
Plateau's obligations to reclaim these properties. The Tony M property was
originally developed by Plateau at the time Plateau was owned by Consumers Power
Company ("CPC"), a Michigan public utility. Significant areas of uranium
mineralization have been accessed and delineated by the prior owner's
underground workings. When the Tony M property was in production (while Plateau
was owned by CPC), it produced ore containing from three to
23
eight pounds of uranium concentrates per ton. Some of this ore was processed at
the Shootaring Mill. In addition, low grade uranium mineralization was
stockpiled at the Tony M property and at the Shootaring Mill.
Plateau also acquired the Velvet property and the nearby Woods Complex in
the Lisbon Valley area in southeastern Utah. The Velvet Mine was developed and
permitted by its prior owner and is located approximately 178 miles by road from
the Shootaring Mill. The prior owner drove several miles of access tunnels
(adits) and drifts (access tunnels) and mined material from the workings.
However, we cannot ascertain the amount or grade of material previously mined,
nor have we ascertained by our own drilling the location and grade of remaining
mineralized material in the mine. The Woods Complex was formerly an operating
uranium mine with a remaining undeveloped resource. Access to this resource
would be by extending a drift approximately 2,500 feet from the former Woods
Mine. The Woods Mine property is not permitted, but we do not expect difficulty
in obtaining a new permit, should we seek one, because the surface facilities
would occupy the site that has been disturbed from previous operations.
PLATEAU'S SHOOTARING CANYON MILL AND PROPERTIES
ACQUISITION OF PLATEAU RESOURCES LIMITED ("PLATEAU"). In August 1993, USE
purchased from Consumers Power Company ("CPC"), all of the outstanding stock of
Plateau which owns the Shootaring Canyon uranium processing mill and support
facilities in southeastern Utah (the "Shootaring Mill") for a nominal cash
consideration. The Shootaring Mill holds a source materials license from the
NRC. In the purchase of the stock from CPC, we agreed to various obligations, as
disclosed in USE's 1998 Form 10-K at pages 15 and 16.
SHOOTARING MILL AND FACILITIES. The Shootaring Mill is located in
southeastern Utah and occupies 19 acres of a 265 acre plant site. The mill was
designed to process 750 tpd, but only operated on a trial basis for two months
in mid-summer of 1982. In 1984, Plateau placed the mill on standby because CPC
had canceled the construction of an additional nuclear energy plant.
For information on the Shootaring mill facility and related real estate
property at Ticaboo, please see "Plateau's Shootaring Canyon Mill and
Properties" in the annual report (Form 10-K/A1) for the former fiscal year ended
May 31, 2002.
THE GREEN MOUNTAIN MINING VENTURE ("GMMV") PROJECT
For information on the GMMV agreement, see "Green Mountain Mining Venture"
in the annual report (Form 10-K/A1) for the former fiscal year ended May 31,
2002.
SHEEP MOUNTAIN PARTNERS ("SMP")
SMP PARTNERSHIP. In February 1988, USE acquired uranium mines, mining
equipment and mineralized properties (Sheep Mountain Mines) at Crooks Gap in
south-central Fremont County, Wyoming, from Western Nuclear, Inc. These Crooks
Gap mining properties are adjacent to the Green Mountain uranium properties.
USECC mined and milled uranium ore from one of the underground Sheep Mines
during fiscal 1988 and 1989. In December 1988, USECC sold 50 percent of the
interests in the Crooks Gap properties to Nukem's subsidiary Cycle Resource
Investment Corporation ("CRIC") for cash. The parties thereafter contributed the
properties to and formed Sheep Mountain Partners ("SMP"), in which USECC
received an undivided 50 percent interest. SMP is a Colorado general partnership
formed on December 21, 1988, between USECC and Nukem, Inc. then of Stamford, CT
("Nukem") through its wholly-owned subsidiary CRIC.
24
SMP was directed by a management committee, with three members appointed by
USECC and three members appointed by Nukem/CRIC. The committee has not met since
1991 as a result of the SMP arbitration/litigation. During fiscal 1991, disputes
arose between the SMP partners which resulted in litigation. See Item 3, Legal
Proceedings.
PROPERTIES. USE, Crested and/or USECC own 98 unpatented lode mining claims
and a 644 acre Wyoming State Mineral Lease in the Crooks Gap area.
An ion exchange plant located on the properties (to remove natural soluble
uranium from mine water) was reclaimed and the plant disposed of at the
Sweetwater Mill impoundment facility in fiscal 2002.
Permits to operate existing mines (now shut down) on the Crooks Gap
properties have been issued by the State of Wyoming. Amendments are needed to
open new mines within the permit area. As a condition to issuance of the
permits, a NPDES water discharge permit under the Clean Water Act has been
obtained. Monitoring and treatment of water removed from the mines and
discharged in nearby Crooks Creek is generally required. During the past two
years, USECC did not discharge wastewater into Crooks Creek, and the mine water
is presently being discharged into the USECC McIntosh Pit.
INACTIVE MINING PROPERTIES - GOLD
SUTTER GOLD MINING COMPANY. In fiscal 1991, USE acquired an interest in
Sutter properties located in the Mother Lode Mining District of Amador County,
California. The entire Lincoln Project (which is the name we use for the
properties) is owned by Sutter Gold Mining Company, a Wyoming corporation
("SGMC"), and a majority-owned subsidiary of USE.
This property has never been in production. Persistent low prices for gold
have made financing difficult, and in fiscal 1999 resulted in a substantial
write down of the SGMC properties.
Due to the depressed gold prices in the past, litigation that has been
resolved and lack of available funding, SGMC has deferred the start of
construction of a gold mill complex and extension of existing underground
workings. A tourist visitors center has been set up (see below) and leased to a
third party for $1,500 per month plus a 4% gross royalty on revenues. There is
one caretaker employee at the Sutter operation. The exploration permits are
being kept current as necessary to allow for possible mining activities on the
properties in the future. With the increase in the gold spot market price, we
are currently marketing the SGMC properties.
In 1998 and 1999, the Company took impairments (write-downs) in the amounts
of $1,500,000 and $10,718,800, respectively, of the carrying value of the gold
properties. These two impairments wrote off almost 85% of our investment in
these properties. As a result of low market prices for gold, we determined that
we could not produce gold from these properties at a profit. The impairments
taken in 1998 and 1999 resulted in no value for mine exploration, and the
remaining assets relating to this property include raw land which is no longer
needed for mining activity, and buildings and equipment. A significant portion
of the raw land has been sold.
We have not obtained a final feasibility study to support a determination
that the Sutter property contains proven or probable reserves of gold.
PROPERTIES. SGMC holds approximately 216 acres of surface and mineral
rights (owned), 54 acres of surface rights (owned), 55 acres of surface rights
(leased), 154 acres of mineral rights (leased), and 366 acres of mineral rights
(owned), all on patented mining claims near Sutter Creek, Amador County,
California.
25
The properties are located in the western Sierra Nevada Mountains at from 1,000
to 1,500 feet in elevation; year round climate is temperate. Access is by
California State Highway 16 from Sacramento to California State Highway 49, then
by paved county road approximately .4 mile outside of Sutter Creek.
Surface and mineral rights holding costs will be approximately $113,000
from January 1, 2003 through December 31, 2003. Property taxes for fiscal 2003
are estimated to be $20,000.
The leases are for varying terms, and require rental fees, advance
production royalties, real property taxes and insurance.
PERMITS. The Amador County Board of Supervisors has issued a Conditional
Use Permit ("CUP") allowing mining of the SGM and milling of production, subject
to conditions relating to land use, environmental and public safety issues, road
construction and improvement, and site reclamation.
VISITORS CENTER. In fiscal 2000, SGMC spent approximately $298,000 for
surface infrastructure related to improving access to the mine site, and to a
lesser extent tourist related improvements. The visitors center is being
operated by a third party. The visitors center is an exhibit of the pictures and
memorabilia from mining operations on other properties in the Sutter district in
the nineteenth century, and a guided tour of the underground workings at the
Lincoln Project. Revenues from this tourist operation were $49,200 for the seven
months ended December 31, 2002 and $41,200 and $105,400 in former fiscal years
2002 and 2001, respectively, and are included in "motel, real estate and airport
operations" in the consolidated statements of operations included in this
report. These revenues offset a majority of costs for holding the Sutter
properties.
MOLYBDENUM
As a holder of royalty, reversionary and certain other interests in
properties located at Mt. Emmons near Crested Butte, Colorado, USE and Crested
are entitled to receive annual advance royalties of 50,000 pounds of molybdenum,
or cash equivalent. AMAX Inc. (which was acquired by Cyprus Minerals Company and
was renamed Cyprus Amax Minerals Company in November 1993 and was acquired later
by Phelps Dodge) delineated a deposit of molybdenum containing approximately
146,000,000 tons of mineralization averaging 0.43% molybdenum disulfide on the
properties of USE and Crested.
Advance royalties are paid in equal quarterly installments until: (i)
commencement of production; (ii) failure to obtain certain licenses, permits,
etc., that are required for production; or (iii) AMAX's return of the properties
to USE and Crested. The advance royalty payments reduce the operating royalties
(6% of gross production proceeds) which would otherwise be due out of
production. There is no obligation to repay the advance royalties if the
property is not placed in production. USE recognized $108,500 and $132,600 of
revenues in fiscal 2001 and 2000 related to this royalty interest. Phelps Dodge
ceased making the quarterly installments in July 2001.
The Agreement with AMAX also provides that USE and Crested receive
$2,000,000 if the Mt. Emmons properties are put into production and, in the
event AMAX sells its subsidiary, Mt. Emmons Mining Company, or its interest in
the molybdenum properties, USE and Crested are to receive 15% of the first
$25,000,000 received by AMAX.
AMAX Inc. and its successor companies have sought to put the Mt. Emmons
molybdenum property into production for 20 years. Due to local opposition to
mining (the property is close to the Crested Butte, Colorado recreational resort
area) and AMAX's successors' failure to diligently pursue obtaining the permits
needed to start mining, we know of no plans at this time to put the property
into production.
26
USE and Crested are in litigation with Phelps Dodge concerning the
Agreement and the properties, see "Item 3 - Legal Proceedings."
OIL AND GAS
FORT PECK LUSTRE FIELD (MONTANA). We operate a small oil production
facility (three wells) at the Lustre Oil Field on the Ft. Peck Indian
Reservation in northeastern Montana. We receive a fee based on oil produced.
This fee and other assets of the Company collateralize a $750,000 line of credit
from a bank.
MOTEL, REAL ESTATE AND AIRPORT OPERATIONS
WYOMING. We own varying interests, alone and with Crested, in affiliated
companies engaged in real estate, and other commercial businesses. Activities of
these and other subsidiaries include ownership and management of a commercial
office building, townsite, motel, convenience store and other commercial
facilities in Ticaboo, Utah.
The Company and Crested own a 14-acre tract in Riverton, Wyoming, with a
two-story 30,400 square foot office building (including underground parking).
The first floor is rented to nonaffiliates and government agencies; the second
floor is occupied by the Company and Crested. The property is mortgaged to the
WDEQ as security for future reclamation work on the Sheep Mountain Crooks Gap
uranium properties.
The Company and Crested also own a fixed base aircraft facility at the
Riverton Regional Airport, including a 10,000 square foot aircraft hangar and
7,000 square feet of associated offices and facilities. This facility is on land
leased from the City of Riverton for a term ending December 16, 2005, with an
option to renew on mutually agreeable terms for five years. The operation for
services to the public was shut down late in fiscal 2002.
The Company owns three mountain sites covering 16 acres in Fremont County,
Wyoming. In Riverton, Wyoming, the Company owns four city lots and improvements
including two smaller office buildings.
COLORADO. USECC owns 182 acres of undeveloped land in and near Gunnison,
Colorado.
UTAH. Canyon Homesteads, Inc. (a Plateau subsidiary) owns a majority
interest in a joint venture which holds the Ticaboo Townsite in Ticaboo, Utah
(see "Minerals - Uranium-Shootaring Canyon Mill - Ticaboo Townsite" above). In
fiscal 1995, USE acquired the minority interest in the joint venture from a
nonaffiliate.
The motel and real estate operations are not dependent upon a single
customer, or a few customers, the loss of which would have a materially adverse
effect on the Company.
RESEARCH AND DEVELOPMENT
No research and development expenditures have been incurred, either on the
Company's account or sponsored by customers, during the past three fiscal years.
ENVIRONMENTAL
GENERAL. Operations are subject to various federal, state and local laws
and regulations regarding the discharge of materials into the environment or
otherwise relating to the protection of the environment,
27
including the Clean Air Act, the Clean Water Act, the Resource Conservation and
Recovery Act ("RCRA"), and the Comprehensive Environmental Response Compensation
Liability Act ("CERCLA"). With respect to mining operations conducted in
Wyoming, Wyoming's mine permitting statutes, Abandoned Mine Reclamation Act and
industrial development and siting laws and regulations also impact us. Similar
laws and regulations in California affect SGMC operations and Utah laws and
regulations effect Plateau's operations.
Management believes the Company complies in all material respects with
existing environmental regulations.
As of December 31, 2002, we have recorded estimated reclamation obligations
of $8,906,800. We anticipate that the reclamation efforts may not be required to
be started for many years, and that when started, paying for those reclamation
efforts will occur over several years. For further information on the
approximate reclamation costs (decommissioning, decontamination and other
reclamation efforts for which we are primarily responsible or potentially
responsible), see note K to the consolidated financial statements included with
this report.
OTHER ENVIRONMENTAL COSTS. Actual costs for compliance with environmental
laws may vary considerably from estimates, depending upon such factors as
changes in environmental laws and regulation (e.g., the new Clean Air Act), and
conditions encountered in minerals exploration and mining. USE does not
anticipate that expenditures to comply with laws regulating the discharge of
materials into the environment, or which are otherwise designed to protect the
environment, will have any substantial adverse impact on the competitive
position of the Company.
EMPLOYEES
As of March 24, 2003, USE had 33 full-time employees. Crested uses
approximately 50 percent of the time of USE employees, and reimburses USE on a
cost reimbursement basis.
MINING CLAIM HOLDINGS
TITLE. Nearly all the uranium mining properties held by the Company, are on
federal unpatented claims. Unpatented claims are located upon federal public
land pursuant to procedure established by the General Mining Law. Requirements
for the location of a valid mining claim on public land depend on the type of
claim being staked, but generally include discovery of valuable minerals,
erecting a discovery monument and posting thereon a location notice, marking the
boundaries of the claim with monuments, and filing a certificate of location
with the county in which the claim is located and with the BLM. If the statutes
and regulations for the location of a mining claim are complied with, the
locator obtains a valid possessory right to the contained minerals. To preserve
an otherwise valid claim, a claimant must also pay certain rental fees annually
to the federal government (currently $100 per claim) and make certain additional
filings with the county and the BLM. Failure to pay such fees or make the
required filings may render the mining claim void or voidable. Because mining
claims are self-initiated and self-maintained, they possess some unique
vulnerabilities not associated with other types of property interests. It is
impossible to ascertain the validity of unpatented mining claims solely from
public real estate records and it can be difficult or impossible to confirm that
all of the requisite steps have been followed for location and maintenance of a
claim. If the validity of an unpatented mining claim is challenged by the
government, the claimant has the burden of proving the present economic
feasibility of mining minerals located thereon. Thus, it is conceivable that
during times of falling metal prices, claims which were valid when located could
become invalid if challenged.
28
RMG's properties and mineral leases of BLM, state and fee lands require
annual cash payments of approximately $323,200 during fiscal 2003. RMG is
obligated for $109,600 of this amount to keep the leases in effect.
PROPOSED FEDERAL LEGISLATION. The U.S. Congress has, in legislative
sessions in recent years, actively considered several proposals for major
revision of the General Mining Law, which governs mining claims and related
activities on federal public lands. If any of the recent proposals become law,
it could result in the imposition of a royalty upon production of minerals from
federal lands and new requirements for mined land reclamation and other
environmental control measures. It remains unclear whether the current Congress
will pass such legislation and, if passed, the extent such new legislation will
affect existing mining claims and operations. The effect of any revision of the
General Mining Law on operations cannot be determined conclusively until such
revision is enacted; however, such legislation could materially increase the
carrying costs of mineral properties which are located on federal unpatented
mining claims, and could increase both the capital and operating costs for such
projects and impair the ability to hold or develop such properties.
ITEM 3. LEGAL PROCEEDINGS
Material pending proceedings are summarized below. Other proceedings which
were pending in fiscal 2002 have been settled or otherwise finally resolved.
SHEEP MOUNTAIN PARTNERS ARBITRATION/LITIGATION
In 1991, disputes arose between USE/Crested, and Nukem, Inc. and its
subsidiary Cycle Resource Investment Corp. ("CRIC"), concerning the formation
and operation of the Sheep Mountain Partners partnership for uranium mining and
marketing, and activities of the parties outside SMP. Arbitration proceedings
were initiated by CRIC in June 1991 and in July 1991, USECC filed a lawsuit
against Nukem, CRIC and others in the U.S. District Court (District of Colorado)
in Civil No. 91B1153. Later, USECC filed another suit for the standby costs at
the SMP mines against SMP in the Colorado State Court. The Federal Court stayed
both the arbitration proceedings and the State Court case. In February 1994, all
of the parties agreed to exclusive and binding arbitration of the disputes
before the American Arbitration Association ("AAA"), for which the legal claims
made by both sides included fraud and misrepresentation, breach of contract,
breach of duties owed to the SMP partnership, and other claims.
The AAA panel (the "Panel") entered an Order and Award (the "Order") in
April 1996 and clarified the Order on July 3, 1996, finding generally in favor
of USE and Crested on certain of their claims (including the claims for
reimbursement for standby maintenance expenses and profits denied SMP in Nukem's
trading of uranium), and in favor of Nukem/CRIC and against USE and Crested on
certain other claims, and imposing a constructive trust in favor of Sheep
Mountain Partners on uranium contracts Nukem entered into to purchase uranium
from CIS republics. USECC filed a petition for confirmation of the Order and on
June 30, 1997, and the U.S. District Court confirmed the Order in its Second
Amended Judgment (the "Judgment"). Thereafter, Nukem/CRIC appealed the Judgment
to the 10th Circuit Court of Appeals ("CCA").
A three judge panel of the 10th CCA issued an Order and Judgment on October
22, 1998, which unanimously affirmed the Federal District Court's Second Amended
Judgment without modification. The ruling affirmed (i) the imposition of a
constructive trust in favor of SMP on Nukem's rights to purchase CIS uranium,
the uranium acquired pursuant to those rights, and the profits therefrom; and
(ii) the damage award against Nukem/CRIC. As a result of the ruling of the 10th
CCA, USE and Crested received an additional $6,077,264 (including interest and
court costs) from Nukem in February 1999 for a total net monetary award of
$15,468,625 in the arbitration/litigation, and equitable relief in the form of
USE's and Crested's interest in SMP, which holds the constructive trust over the
CIS contracts. Nukem/CRIC filed two motions for entry of final satisfaction of
Judgment. The U.S. District Court denied both motions, Nukem again appealed to
the 10th CCA, which again affirmed the District Court's ruling, and held that
Nukem/CRIC had not demonstrated that the Judgment had been satisfied because
they had not provided USECC with an accounting of the partnerships assets.
29
In February 2001, the U.S. District Court appointed a Special Master to
determine the amounts, if any, owed by Nukem to SMP pursuant to the constructive
trust. The Special Master has ordered an accounting to identify all deliveries
of CIS uranium made directly or indirectly to Nukem and any Nukem affiliates; to
identify the ultimate disposition of all uranium purchased under the CIS
contracts; to identify the location, number of pounds, and associated cost of
uranium purchased under the CIS contracts at December 31, 2001, and to calculate
the profits realized from the sale of CIS uranium. At a status hearing held
before the U.S. District Court on August 23, 2002, the Court ordered the Special
Master to file his report on or before December 6, 2002 and a further hearing to
schedule arguments on December 13, 2002. Because Nukem and its affiliates failed
to furnish certain documentation and information, the Special Master filed a
motion for extension of time to file his report. The Court granted the motion
and ordered the Special Master to file the report by March 3, 2003. On February
9, 2003, the U.S. District Court granted a second motion of the Special Master
for an extension of time and ordered the report to be filed by April 4, 2003
with a hearing on the report to be held on April 11, 2003.
CONTOUR DEVELOPMENT LITIGATION
On July 28, 1998, USE filed a lawsuit in the United States District Court,
Denver, Colorado, Case No. 98WM1630, against Contour Development Company, L.L.C.
and entities and persons associated with Contour Development Company, L.L.C.
(together, "Contour") seeking compensatory and consequential damages of more
than $1.3 million from the defendants for dealings in real estate owned by USE
and Crested in Gunnison, Colorado. The Contour defendants asserted a
counterclaim asking for payment of attorneys fee and costs. The parties agreed
to settle the litigation, with the Company receiving $25,000 cash and
unencumbered title to two commercial real estate lots covering seven acres in
Gunnison, Colorado, and unencumbered title to five development lots covering 175
acres north of Gunnison, Colorado. There is a dispute as to the settlement terms
and the parties have submitted the issues for resolution by the Court.
See "Business - Commercial Operations - Real Estate and Other Commercial
Operations - Colorado Properties" above.
PHELPS DODGE LITIGATION
The Company and Crested, were served with a lawsuit on June 19, 2002, filed
in the U.S. District Court of Colorado (Case No. 02-B-0796(PAC)) by Phelps Dodge
Corporation and its subsidiary, Mt. Emmons Mining Company (MEMCO), over
contractual obligations from USECC's agreement with Phelps Dodge's predecessor
companies, concerning a mining property in Colorado.
The litigation stems from agreements that date back to 1974 when the
Company and Crested leased mining claims on Mt. Emmons near Crested Butte,
Colorado to AMAX Inc., Phelps Dodge's predecessor company. The claims cover one
of the world's largest and richest deposits of molybdenum. AMAX reportedly spent
over $200 million on the acquisition, exploration and mine planning activities
on the Mt. Emmons properties. In counter and cross-claims filed in the U.S.
District Court of Colorado, USECC contends that Phelps Dodge and its
subsidiaries committed several breaches of contracts related to the agreements,
including breach of fiduciary obligations and covenants of good faith and fair
dealing. USECC also contends Phelps Dodge is guilty of violating federal and
state antitrust laws when it purchased Cyprus Amax Minerals Company (Cyprus
Amax).
The complaint filed by Phelps Dodge and MEMCO seeks a determination that
Phelps Dodge's acquisition of Cyprus Amax was not a sale. Under a 1986 agreement
between USECC and AMAX, if AMAX sold MEMCO or its interest in the mining
properties, the Company and Crested would receive 15% (7.5% each) of the first
$25 million of the purchase price ($3.75 million). In November 1993, Cyprus
Minerals Company acquired AMAX to form Cyprus Amax Minerals Co. ("Cyprus Amax").
USECC's counter and cross-claims allege that in 1999, Phelps Dodge formed a
wholly-owned subsidiary CAV Corporation, for the purpose of purchasing the
controlling interest of Cyprus Amax and its subsidiaries (including MEMCO) at an
estimated value in cash and Phelps Dodge stock exceeding $1 billion and making
Cyprus Amax a subsidiary of Phelps Dodge. Therefore, USECC asserts the
acquisition of Cyprus Amax by Phelps Dodge
30
was a sale of MEMCO and the properties that triggers the obligation of Cyprus
Amax to pay USECC the $3.75 million plus interest.
A second counterclaim by the Company and Crested rejects the claim by
Phelps Dodge that it and its predecessors, Cyprus Amax and AMAX Inc., had
mistakenly paid royalties to the Company and Crested since January 1991. In
1984, AMAX began paying the cash equivalent (half each to the Company and
Crested) of 700,000 pounds of molybdenum per year as an advance royalty prior to
the mine beginning production. In 1986, USECC agreed to assist financially
troubled AMAX and substantially reduced the annual advance royalty to 50,000
pounds of molybdenum, so that AMAX could continue to hold the properties and
eventually bring them into production. AMAX, Cyprus Amax and Phelps Dodge
continued paying the annual advance royalties to the Company and Crested until
the payment due in July 2001, when Phelps Dodge unilaterally ceased making the
payments. Phelps Dodge and MEMCO seek a declaratory judgment that the advance
royalty payment obligation has terminated, and further, that USECC should repay
$948,109 of royalties paid to USECC from 1993 through 2000, because those
payments were made by mistake.
The third issue in the litigation is whether USECC must, under terms of a
1987 royalty deed, accept Phelps Dodge's and MEMCO's forth-coming conveyance of
the Mt. Emmons properties back to USECC, which properties now include a plant to
treat mine water, costing in excess of $1 million a year to operate in
compliance with State of Colorado regulations. Phelps Dodge's and MEMCO's
threatened reconveyance would require USECC to assume the operating costs of the
water treatment plant. USECC refuses to have the water treatment plant included
in the return of the properties because, the USECC counterclaim argues, the
properties must be in the same condition as when they were acquired by AMAX
before the water treatment plant was constructed by AMAX.
The properties are comprised of 10 unpatented lode mining claims (for which
patents are expected to be issued by the BLM in the near future), and 770
unpatented lode mining claims, for a total of 15,600 acres.
As added counterclaims, USECC seeks (i) damages for defendants' breach of
covenants of good faith and fair dealing; (ii) damages for defendants' failure
to develop the Mt. Emmons properties and not protecting USECC's rights as
revisionary owner of the mining rights to the properties, (iii) damages for
unjust enrichment of defendants; (iv) damages for breach of the defendants'
fiduciary duties owed to USECC as revisionary owner of the property, and for
neglecting to maintain the mining rights and interests in the properties; and
(v) damages relating to defendants' actions in violation of federal and Colorado
anti-trust and constraint of trade laws.
USECC also seeks a declaratory judgment of its rights and liabilities under
the agreements affecting the Mt. Emmons properties; an injunction against
defendants prohibiting the conveyance of the properties to USECC with the water
treatment plan; an injunction against further waste of the properties by the
defendants; an injunction requiring defendants to divest their molybdenum
holdings (including the Mt. Emmons properties); and an injunction requiring
defendants to assist USECC in mining molybdenum from the Mt. Emmons properties.
On August 2, 2002, Phelps Dodge and MEMCO filed a reply to the
counterclaims of USECC and Cyprus Amax filed an answer to the counterclaims and
third party complaint of USECC, generally denying the allegations of USECC. CAV
Corporation filed a motion for summary judgment seeking dismissal of USECC's
cross complaint and is pending. A Scheduling/Planning Conference in the case was
held on September 12, 2002 and since then, Phelps Dodge dismissed its claim that
USECC repay the advance royalty of $948,109 to Phelps Dodge. Discovery is
underway and certain motions are pending, including Phelps Dodge's motion for
Partial Summary Judgment asking the court to order USECC to accept a conveyance
of the subject mining claims with the water treatment plant.
Except for the parties' claims regarding payment of the $3.75 million due
on the sale of MEMCO, payments of royalties, and responsibility going forward
for payment of the operating costs of the water treatment plan, the financial
impact to the Company. and Crested of favorable or unfavorable outcomes in the
litigation presently is not determinable.
31
SUTTER PROPERTY LITIGATION
On or about March 13, 2002, the Company's subsidiary, Sutter Gold Mining
Company ("SGMC"), was served with a complaint filed by Edward A. Swift et al in
the Superior Court of Amador County, California, Case Number 02CU2051. The
litigation involved a mining lease entered into in 1989. The claim was settled
by issuing the plaintiffs 20,000 shares of restricted common stock, in USE.
ROCKY MOUNTAIN GAS LITIGATION
On or about April 1, 2002, the Company's subsidiary, Rocky Mountain Gas,
Inc. ("RMG") was served with a Second Amended Complaint wherein the Northern
Plains Resource Council had filed suit in the U.S. District Court of Montana,
Billings Division in Case No. CV-01-96-BLG-RWA, against the United States Bureau
of Land Management ("BLM"), RMG and certain of its affiliates (including the
Company and Crested), and joined some 20 other defendants. The plaintiff is
seeking to cancel oil and gas leases issued to RMG et al by the BLM in the
Powder River Basin of Montana and for other relief.
The basis for the complaint appears to be that the BLM's regulations
require the BLM to respond to objections filed by persons owning land or lease
rights adjacent to the coalbed properties which the BLM is offering to lease to
the public. The argument of plaintiff appears to be that if objections are not
responded to by the BLM prior to issuing CBM leases, the leases are invalid.
Based on this argument, the plaintiff appears to have been successful in forcing
cancellation of some CBM leases granted to others in the Powder River Basin of
Montana, because the BLM did not respond to some objecting adjacent landowners.
However, all of the BLM leases in Montana held by RMG (none are held by the
Company and Crested in their own corporate names) are at least four years old,
and there is no record of any objections being made to the issue of those
leases.
Based on filings in the case to date, it appears that the BLM is taking the
initiative in responding to the plaintiff. We believe RMG's leases were validly
issued in compliance with BLM procedures, and do not believe the plaintiff's
lawsuit will adversely affect any of RMG's Montana BLM leases. However, RMG
holds BLM leases on 88,409 gross acres in Montana (in the Castle Rock and Kirby
prospects), which equals 31.5% of RMG's total coalbed methane leases. An adverse
court ruling to the effect that all or a substantial portion of the BLM leases
in Montana are invalid could materially and adversely impact RMG. No trial date
has been set.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On December 16, 2002, the annual meeting of shareholders was held and the
only issue considered was the re-election of three directors: Don C. Anderson,
Nick Bebout and H. Russell Fraser. These directors were re-elected for a term
expiring on the third succeeding Annual Meeting of Shareholders and until their
successors are duly elected or appointed and qualified. With respect to the
re-election of these three directors, the votes cast were as follows:
Name of Director For Abstain
---------------- --- -------
Don C. Anderson 8,834,230 114,860
Nick Bebout 8,740,690 114,860
H. Russell Fraser 8,740,250 114,970
32
PART II
ITEM 5. MARKET FOR COMMON SHARES AND RELATED STOCKHOLDER MATTERS
(a) Market Information
Shares of USE common stock are traded on the over-the-counter market, and
prices are reported on a "last sale" basis by the National Market System ("NMS")
of the National Association of Securities Dealers Automated Quotation System
("Nasdaq"). The range by quarter of high and low sales prices is set forth below
for fiscal 2002 and 2001.
High Low
---- ---
Transition period ended December 31, 2002
-----------------------------------------
First quarter 8/31/02 $ 3.95 $ 2.00
Second quarter ended 11/30/02 4.20 3.38
Month ended 12/31/02 3.98 3.08
Fiscal year ended May 31, 2002
------------------------------
First quarter ended 8/31/01 $ 6.05 $ 3.56
Second quarter ended 11/30/01 4.15 3.09
Third quarter ended 2/29/02 5.27 3.50
Fourth quarter ended 5/31/02 4.30 3.29
Fiscal year to ended May 31, 2001
---------------------------------
First quarter ended 8/31/00 $ 3.00 $ 1.75
Second quarter ended 11/30/00 3.38 1.75
Third quarter ended 2/28/01 4.00 2.00
Fourth quarter ended 5/31/01 6.25 3.56
(b) Holders
(1) At March 24, 2003 the closing market price was $3.21 per share and there
were approximately 691 shareholders of record. As of March 21, 2003, we had
12,209,776 shares of common stock issued and outstanding, including shares owned
by our subsidiaries and shares in officers' and directors' names that are
subject to forfeiture.
(2) Not applicable.
(c) We have not paid any cash dividends with respect to common stock. There are
no contractual restrictions on our present or future ability to pay cash
dividends, however, we intend to retain any earnings in the near future for
operations.
ITEM 6. SELECTED FINANCIAL DATA.
The following tables show certain selected historical financial data for
USE for the five former fiscal years ended May 31, 2002, and as of the seven
months ended December 31, 2002 and 2001. The selected financial data is derived
from and should be read with the financial statements for USE included in this
Report.
33
December 31, May 31,
--------------------------- -----------------------------------------------------------------------
2002 2001 2002 2001 2000 1999 1998
---- ---- ---- ---- ---- ---- ----
Current assets $ 4,755,300 $ 4,597,900 $ 4,892,600 $ 3,330,000 $ 3,456,800 $12,718,900 $14,301,000
Current liabilities 2,044,400 2,563,800 1,406,400 2,396,700 6,617,900 5,355,600 6,062,100
Working capital
(deficit) 2,710,900 2,034,100 3,486,200 933,300 (3,161,100) 7,363,300 8,238,900
Total assets 28,190,600 30,991,700 30,537,900 30,465,200 30,876,100 33,391,000 45,019,100
Long-term
obligations(1) 15,192,100 14,741,200 14,949,100 14,981,500 14,025,200 14,526,900 14,468,600
Shareholders' equity 7,356,800 6,873,900 10,597,200 7,320,600 4,683,800 10,180,300 14,453,500
(1)Includes $8,906,800, of accrued reclamation costs on mining properties at
December 31, 2002, 2001 and May 31, 2002, 2001, 2000, 1999 and 1998,
respectively. See Note K of Notes to Consolidated Financial Statements.
Seven Months Ended
December 31, For Former Fiscal Years Ended May 31,
-------------------------- -------------------------------------------------------------------------
2002 2001 2002 2001 2000 1999 1998
Operating revenues $ 1,027,600 $ 1,073,300 $ 2,004,100 $ 3,263,000 $ 3,303,900 $ 3,788,600 $ 6,132,600
Loss from
continuing operations (3,507,800) (3,570,800) (7,454,200) (7,517,800) (11,356,100) (22,713,300) (4,984,900)
Other income & expenses (387,100) 1,005,000 1,319,500 8,730,800 802,200 6,655,500 5,349,900
(Loss) income before
minority interests,
equity in (loss)
income of affiliates,
discontinued
operations, and
income taxes (3,894,900) (2,745,200) (6,134,700) 1,213,000 (10,553,900) (16,057,800) (365,000)
Minority interest in
loss (income) of
consolidated
subsidiaries 54,800 24,500 39,500 220,100 509,300 4,468,400 (772,500)
Equity in loss of
affiliates -- -- -- -- (2,900) (59,100) (575,700)
Income taxes -- -- -- -- -- -- --
Discontinued operations
net of tax -- -- (85,900) 488,100 (594,300) -- --
Preferred stock dividends -- (75,000) (86,500) (150,000) (20,800) -- --
----------- ----------- ----------- ----------- ------------ ------------ -----------
Net (loss) income
to common shareholders $(3,840,100) $(2,785,400) $(6,267,600) $ 1,771,200 $(10,662,600) $(11,648,500) $ (983,200)
=========== =========== =========== =========== ============ ============ ===========
34
Seven Months Ended
December 31, For Former Fiscal Years Ended May 31,
-------------------- -------------------------------------------------
2002 2001 2002 2001 2000 1999 1998
---- ---- ---- ---- ---- ---- ----
Per share financial data
Operating revenues $ 0.10 $ 0.13 $ 0.22 $ 0.42 $ 0.43 $ 0.53 $ 0.92
Loss from
continuing operations (0.32) (0.45) (0.80) (0.96) (1.39) (3.18) (0.75)
Other income & expenses (0.04) 0.12 0.14 1.11 0.01 0.93 0.80
(Loss) income before
minority interests,
equity in income
(loss) of affiliates,
discontinued operations,
and income taxes (0.36) (0.33) (0.66) 0.15 $ (1.38) $ (2.25) $ 0.05
Minority interest in loss (income)
of consolidated subsidiaries -- -- 0.01 0.03 0.07 0.63 (0.12)
Equity in loss of affiliates -- -- -- -- -- (0.01) (0.08)
Discontinued operations -- -- (0.01) 0.06 (0.08) -- --
Income taxes -- -- -- -- -- -- --
Preferred stock dividends -- (0.01) (0.01) (0.01) -- -- --
-------- -------- -------- -------- ------- -------- --------
Net income (loss)
per share, basic $ (0.36) $ (0.34) $ (0.67) $ 0.23 $ (1.39) $ (1.63) $ (0.15)
======== ======== ======== ======== ======== ======== ========
Net income (loss)
per share diluted $ (0.36) $ (0.34) $ (0.67) $ 0.21 $ (1.39) $ (1.63) $ (0.15)
======== ======== ======== ======== ======== ======== ========
35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following is Management's Discussion and Analysis of significant
factors which have affected our liquidity, capital resources and results of
operations during the periods included in the accompanying financial statements.
The discussion contains forward-looking statements that involve risks and
uncertainties. Due to uncertainties in our business, actual results may differ
materially from the discussion below.
During its regular meeting on December 16, 2002, the Board of Directors
unanimously voted to change the Company's year end from May 31 to December 31
beginning December 31, 2002. This decision was made primarily as a result of the
Company expanding activities in the coalbed methane/natural gas industry. Many
business relationships in the natural gas industry are based upon partnerships
which by statute have December 31 year ends. Changing the Company's year end to
December 31 will simplify accounting and reporting responsibilities of the
Company. Additionally, many indexes and valuations in the natural gas industry
are calculated as of December 31. As a result of the decision to change the year
end to December 31, the Company has presented Balance Sheets as of December 31,
2002, May 31, 2002 and May 31, 2001, along with Statements of Operations and
Statements of Cash Flows for the seven months ended December 31, 2002 and the
fiscal years ended May 31, 2002, 2001 and 2000. Additionally, Footnote N to the
consolidated financial statements presents transitional period comparative data
for the seven month periods ended December 31, 2002 and 2001.
CRITICAL ACCOUNTING POLICIES
OIL AND GAS PRODUCING ACTIVITIES - We follow the full cost method of
accounting for oil and gas properties. Accordingly, all costs associated with
acquisition, exploration, and development of oil and gas reserves, including
directly related overhead costs, are capitalized.
All capitalized costs of oil and gas properties subject to amortization and
the estimated future costs to develop proved reserves, are amortized on the
unit-of-production method using estimates of proved reserves. Investments in
unproved properties and major exploration and development projects are not
amortized until proved reserves associated with the projects can be determined.
Unproved properties are assessed periodically to ascertain whether impairment
has occurred. Such assessments could cause the Company to reduce the carrying
values of the properties.
In addition, the capitalized costs are subject to a "ceiling test," which
basically limits such costs to the aggregate of the "estimated present
value,"discounted at a 10-percent interest rate of future net revenues from
proved reserves, based on current economic and operating conditions, plus the
lower of cost or fair market value of unproved properties.
Our discounted present value of our proved natural gas reserves is a major
component of the ceiling calculation and requires many subjective judgments.
Estimates of reserves are forecasts based on engineering and geological
analyses. Different reserve engineers may reach different conclusions as to
estimated quantities of natural gas reserves based on the same information. Our
reserve estimates are prepared by independent consultants. The passage of time
provides more qualitative information regarding reserve estimates, and revisions
are made to prior estimates based on updated information. However, there can be
no assurance that more significant revisions will not be necessary in the
future. Significant downward revisions could result in a full cost write-down.
In addition to the impact on calculation of the ceiling test, estimates of
proved reserves are also a major component of the calculation of depletion.
While the quantities of proved reserves require substantial judgment, the
associated price of natural gas reserves that are included in the discounted
present value of our reserves are objectively determined. The ceiling
calculation requires prices and costs in effect as of the last day of the
accounting period are generally
36
held constant for the life of the properties. As a result, the present value is
not necessarily an indication of the fair value of the reserves. Natural gas
prices have historically been volatile and the prevailing prices at any given
time may not reflect our Company's or the industry's forecast of future prices.
RECLAMATION LIABILITIES - The Company's policy is to accrue the liability
for future reclamation costs of its mineral properties based on the current
estimate of the future reclamation costs as determined by internal and external
experts.
RECENT ACCOUNTING PRONOUNCEMENTS
SFAS NO. 143 - In July 2001, the Financial Accounting Standards Board
issued SFAS No. 143 "Accounting for Asset Retirement Obligations." The statement
requires entities to record the fair value of a liability for legal obligations
associated with the retirement of obligations of tangible long-lived assets in
the period in which it is incurred. When the liability is initially recorded,
the entity increases the carrying amount of the related long-lived asset.
Accretion of the liability is recognized each period, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The standard is effective for fiscal
years beginning after June 15, 2002, with earlier application encouraged. The
Company is evaluating the impact of SFAS No. 143 and has implemented the
pronouncement effective January 1, 2003.
SFAS NO. 148 - In December 2002, the Company adopted the supplemental
disclosure requirements of SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure", which amended SFAS No. 123,
"Accounting for Stock-Based Compensation." The Company continues to record
compensation related to employee stock options based on the intrinsic value
method per APB Opinion No. 25, "Accounting for Stock Issued to Employees." SFAS
No. 148 encourages companies to voluntarily elect to record the compensation
based on market value either prospectively, as defined in SFAS No. 123, or
retroactively or in a modified prospective method. Among other things, the
Company is concerned about the reasonableness of the values of its stock options
determined using the Black Scholes method. Therefore, the Company has delayed
the potential transition to recording stock compensation based on fair market
value until there is more clarity regarding the measurement of stock option
values.
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, including indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 expands the information
disclosures required by guarantors for obligations under certain types of
guarantees. It also requires initial recognition at fair value of a liability
for such guarantees. The initial recognition and initial measurement provisions
of this Interpretation are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002, irrespective of the guarantor's
fiscal year-end. The disclosure requirements in the Interpretation are effective
for financial statements of interim or annual periods ending after December 15,
2002. The Company believes that the adoption of this statements will not have a
material impact on its financial condition or results of operation.
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"), which addresses consolidation by
business enterprises where equity investors do not bear the residual economic
risks and rewards. These entities have been commonly referred to as
"special-purpose entities". Companies are required to apply the provision of FIN
46 prospectively for all variable interest entities created after January 31,
2003. For public companies, all interest acquired before February 1, 2003 must
follow the new rules in accounting periods beginning after June 15, 2003. The
Company is currently evaluating the impact FIN 46 is expected to have on the
Company's financial condition or results of operations.
37
The Company has reviewed other current outstanding statements from the
Financial Accounting Standards Board and does not believe that any of those
statements will have a material adverse affect on the financial statements of
the Company when adopted.
LIQUIDITY AND CAPITAL RESOURCES
During the seven months ended December 31, 2002, our cash position
decreased by $823,300 to $1,741,000 from a cash position of $2,564,300 at May
31, 2002, our previous year end. This reduction of cash was as a result of
$2,857,800 being consumed in operations during the seven months ended December
31, 2002. This was offset by cash which was provided from investing and
financing activities during the same period of $1,567,100 and $467,500,
respectively.
Operations during the seven months ended December 31, 2002 resulted in a
loss of $3,840,100. The major non cash components of this loss were depreciation
and amortization of $360,100; amortization of debt discounts of $211,200; loss
on the sale of assets of $342,600, and non cash compensation of $314,800. These
non cash expenses along with the net decrease in current assets and liabilities
of $246,400, resulted in net cash consumed by operations of $2,857,800.
Operations during the seven months ended December 31, 2002 consisted primarily
of administrative costs associated with the expansion of the RMG coalbed methane
gas business, holding costs associated with mineral properties that are in shut
down status and the management of the Plateau properties in southern Utah.
Through December 31, 2002, the coalbed methane properties were being developed
and produced very little revenue.
Investment activities provided cash of $1,567,100 primarily as a result of
the sale of a portion of the SGMC raw land that was no longer needed for the
operations of its mineral property, sale of certain business development real
estate in Wyoming and the sale of various pieces of equipment that are no longer
needed. These activities provided $1,566,000 in cash. Additionally, RMG received
$1,125,000 from CCBM as principal payments on the $7,500,000 promissory note for
the purchase of a 50% interest in certain of the RMG properties. As these
payments are received, they reduce RMG's cost basis in its full cost pool of
coalbed methane properties. Investing activities also consumed cash through the
purchase and exploration of coalbed methane properties of $883,400 and the
purchase of various pieces of equipment and the replacement of major component
parts of others, for $411,200.
Financing activities during the seven months ended December 31, 2002,
provided $467,500 as a result of an increase in long term debt of $892,800,
which was offset by payments on long term debt and the line of credit of
$225,300 and $200,000, respectively. Long term debt increased as a result of the
purchase and long term maintenance on pieces of equipment of $198,500, financing
of liability insurance premiums of $194,300 and new convertible debt from a
third party company in the amount of $500,000.
This new convertible debt was entered into in November 2002. The
convertible debt is due in two years and accrues interest at 8% per annum
payable quarterly. At the option of the holder of the debt, the note can be
fully paid by the issuance of either 166,666 shares of the Company's common
stock or 250,000 shares of RMG common stock. The Company and RMG also issued
warrants to purchase 60,000 shares of their common stock at $3.00 and $2.00 per
share, respectively. A discount of $240,000 was recorded against the debt as a
result of the beneficial conversion feature of the debt. The amortization of
this discount along with a discount taken on previously entered into convertible
debt, reduced the overall increase in long term debt by $211,200.
38
CAPITAL RESOURCES
- -----------------
GENERAL - The primary sources of our capital resources are cash on hand;
collection of receivables; receipt of monthly payments from CCBM for the
purchase of an interest in RMG's coalbed methane properties; CCBM funding of
drilling and development programs; production from RMG's coalbed methane
properties; sale of excess mine, construction and drilling equipment; sale of
real estate properties which are no longer needed in the core business of the
Company; sale of mineral properties; the line of credit with a commercial bank;
equity financing of the Company's subsidiaries; and the final determination of
the Sheep Mountain Partners ("SMP") arbitration/litigation. We will also
continue to receive revenues from our motel and real estate operations in
southern Utah.
RMG COALBED METHANE - Drilling and development capital requirements will be
satisfied for the majority of 2003 from the CCBM work commitment of which there
is $1,828,100 remaining as of December 31, 2002. Approximately one-half of this
amount, $893,300, will be paid by CCBM on behalf of RMG for its obligations for
drilling and property development of coalbed methane properties. There is also a
balance of $5,250,000 due from CCBM under its purchase agreement. CCBM pays
$125,000 per month plus interest until November 2004 at which time a balloon
payment of $2,375,000 is due on this promissory note. CCBM's interest in RMG's
coalbed methane properties is pledged as security for the note to RMG. After
CCBM has paid $2,500,000 (33%) of the principal amount of the promissory note,
RMG will release 25% of the undivided interest in the coalbed methane properties
purchased by CCBM; another 25% when $5,000,000 (66.6%) of the principal is paid,
and the balance of the total 50% undivided interest when all of the principal
amount of $7,500,000 of the purchase price has been paid. CCBM may elect at any
time to discontinue making the monthly payments subject to not obtaining a full
50% undivided interest in the properties.
Under the CCBM agreement, CCBM also agreed to use its best efforts to
obtain financing to raise no less than $20 million to be used by RMG to acquire
more coalbed methane properties. CCBM has not been successful in raising these
funds within the terms of the agreement due to market conditions for coalbed
methane gas. RMG has verbally extended the time for CCBM to raise the funds to
June 30, 2003. RMG and CCBM continue to pursue various sources of financing to
expand the coalbed methane business.
SHUT DOWN MINING PROPERTIES - The Company has shut down it mines and
discontinued its mining and construction operations. As a result the Company has
surplus equipment and buildings from these operations.
To assist in financing the holding costs of the SGMC properties (which are
shut down), the Company developed a mine tour business. After operating the mine
tour business for approximately one year, it was determined to lease the tour
business to a third party. Proceeds under the lease agreement partially defray
the holding costs of the mine properties. The Company is currently discussing
the potential of either a sale of the properties to an industry partner or a
possible joint venture agreement to operate the properties.
We have been involved in litigation with Nukem, Inc. involving SMP for the
past twelve years. The U.S. District Court of Colorado has appointed a Special
Master to determine the value of the purchase rights, the pounds of uranium and
the profits under certain contracts Nukem entered into with three CIS Republics,
which contracts have been impressed in a constructive trust in favor of SMP. The
Special Master is currently performing the accounting. The Federal Court has
ordered that the accounting be completed and filed with the Court by April 4,
2003 with a further status hearing to be held on April 11, 2003. The ultimate
outcome of this litigation cannot be determined but management of the Company
believes that it will be beneficial to the Company.
39
REAL ESTATE - The Company continues to market home and mobile home lots in
southern Utah. These fully developed properties are not important to the
operations of the Company. The lots were a portion of the assets that the
Company acquired when it purchased the Shootaring uranium mill and Ticaboo
Townsite. The Company has also listed the commercial operations at Ticaboo for
sale. It is the intention of management of the Company to sell this commercial
property. The Company is also selling components of the Shootaring Mill.
LINES OF CREDIT - We currently have a $750,000 line of credit with a
commercial bank. As of December 31, 2003 the full amount of the line of credit
was available to the Company. This line of credit is up for renewal in June
2003.
We also have a $300,000 credit facility through our subsidiary Plateau
Resources. This line of credit is for the development of the Ticaboo Townsite in
southern Utah. Plateau has drawn down the entire amount of this financing
facility which is repayable over 10 years. All payments on this debt is current
as of December 31, 2003.
We believe that these cash resources will be sufficient to sustain
operations during 2003.
CAPITAL REQUIREMENTS
- --------------------
The primary capital requirements during 2003 are expected to be exploration
and development of coalbed methane properties; the cost of maintaining our
uranium and gold properties that are shut down and general and administrative
costs.
EXPLORATION OF COALBED METHANE PROPERTIES - The majority of the 2003
exploration costs associated with the coalbed methane properties of RMG will be
funded by CCBM from the remaining balance of $1,828,100 under the $5.0 million
work commitment. If properties are drilled that are owned only 50% or less by
RMG, we may be required to fund the drilling costs for the interest ownership of
the remaining non- participating parties. Should we be required to fund any
non-participating entities' portion of the exploration programs, there is a
back-in provision on each property which gives RMG a disproportionate amount of
the production revenues until our cost and additional amounts are recovered
before the non-participating parties begin to receive production funds.
During 2003, it is projected that various drilling, completion and
gathering programs will be completed on RMG properties. In addition, it is the
intent of the management of the Company and RMG to purchase additional
exploratory production acreage. All of these programs are subject to financing
and will be limited if financing is not available through CCBM or through
financing arranged by RMG and the Company. Due to the uncertainty of raising the
necessary capital to complete these projects, it is not possible to project what
if any capital requirements the Company and RMG will be required to fund during
2003. However, a total of $323,200 gross rental fees are due to lessors on CBM
leases during 2003, of which RMG is responsible for $109,600. These fees will
have to be paid to keep the acreage positions.
HOLDING COSTS OF SHUT-DOWN MINERAL PROPERTIES - The holding costs
associated with the uranium mineral properties formerly owned by Sheep Mountain
Partners ("SMP"), are approximately $28,000 per month. We continue to implement
cost cutting measures to reduce the holding costs. We have begun the process of
reclamation on certain of these mine properties and will continue to do work
during 2003. It is estimated that $50,000 in reclamation work will be completed
on the SMP properties during 2003.
40
Plateau owns the Ticaboo Townsite, which includes a motel, convenience
store, boat storage, restaurant and lounge. The operation and lease of these
facilities cover their operating costs and return a profit to the Company.
Additionally, Plateau owns and maintains the Tony M uranium property and
Shootaring Canyon uranium mill. The uranium property and mill are both shut down
and the holding cost of these properties is minimal.
We have one employee at the SGMC properties to preserve the core assets and
properties. In addition to the cost of this employee, we have lease payments
that are due to various land owners. The net average monthly cash cost of the
Sutter properties is expected to be $10,000 during 2003.
DEBT PAYMENTS - Debt to non-related parties at December 31, 2002 was
$3,137,800 as compared with $2,559,000 and $2,294,500 at May 31, 2002 and May
31, 2001, respectively. The increase in debt to non-related parties of $578,800,
consists of debt incurred to finance annual insurance premiums of $194,300;
purchase of equipment of $198,500 and convertible debt in the amount of $500,000
from an independent company. This debt was discounted by $299,800 for detached
warrants and a beneficial conversion provision, which will be amortized over the
life of the debt. The payment requirements on long term debt during 2003 is
$120,000 of interest on convertible loans and principal payments of $317,200.
(See Note G to the Financial Statements for more detail) At December 31, 2002,
the Company had not borrowed any money from its available $750,000 line of
credit with a commercial bank.
RECLAMATION COSTS - The reclamation obligations are long term and are
either bonded through the use of cash bonds or the pledge of assets. It is
anticipated that $50,000 of reclamation work will be performed on the SMP
properties during 2003. There is no reclamation requirement on the SGMC
properties during 2003.
The Company may begin reclamation work at the Shootaring uranium mill in
southern Utah. If such projects are initiated management of the Company will
seek to have the projects funded through the cash bonds that have been posted
for that purpose. At December 31, 2003 the Company had $9.8 million in cash
deposit accounts for the funding of the reclamation of the Shootaring mill.
As the coalbed methane properties are just coming into production there is
no reclamation cost anticipated during 2003. If an exploratory well were to be
abandoned, it is anticipated that the reclamation cost for the well would range
from $3,500 to $5,000. RMG will only be obligated to the extent of its working
interest in such reclamation costs.
FEDERAL INCOME TAX ISSUES - The Internal Revenue Service ("IRS") has
audited our books and records through the fiscal years ended May 31, 2000. There
were no changes in the amount of taxes due as a result of these audits and the
audits are closed.
RESULTS OF OPERATIONS
---------------------
SEVEN MONTHS ENDED DECEMBER 31, 2002 COMPARED TO
THE SEVEN MONTHS ENDED DECEMBER 31, 2001
Revenues:
- ---------
During the seven months ended December 31, 2002, the Company recognized
$1,027,600 in revenues as compared to $1,073,300 in revenues during the seven
months ended December 31, 2001. This decrease of $45,700 in revenues is primarly
as a result of decreased revenues from motel, real estate and airport operations
of $149,100 and decreased management fees of $16,000. These decreases in
revenues was offset by revenues from the production of coalbed methane gas
during the seven months ended December 31, 2002
41
of $119,400 while no revenues from coalbed methane produciton were recognized
during the same period of the previous year.
Revenues from motel, real estate and airport operations decreased due
primarly as a result of decreased tourist travel to the Company's southern Utah
operations near Lake Powell. This decrease in tourist business is directly
related to the fear of terrorist activity which has been felt in the United
States since the attack on the World Trade Centers and the lack of moisture in
Utah which has caused Lake Powell to be at a very low level for water sports and
recreation.
Through the purchase of the Bobcat Field, RMG began selling coalbed methane
gas during the seven months ended December 31, 2002. As anticipated, production
from these newly developed wells was lower than it will be in the future.
Additionally the market price for natural gas was very low during the summer and
fall months of 2002. These reasons along with high start up and operating costs
of $355,200 resulted in a loss from operations for coalbed methane of $235,800.
Management believes with increased production volumes, reduced ongoing operating
costs and increased market prices that the coalbed methane properties will show
profits and cash flows during 2003.
Costs and Expenses:
- -------------------
Costs and expenses during the seven months ended December 2002 were
$4,535,400 as compared to costs and expenses of $4,823,500 during the seven
months ended December 31, 2001. This reduction of $288,100 was as a result of
reduced motel operating costs of $221,600 as a result of the reduced amount of
tourists at the Company's operations in southern Utah as discussed above and a
reduction of $466,300 in the holding costs of shut down mineral properties due
to an ongoing cost cutting program. These reductions in operating costs were
offset primarly by the operating costs associated with coalbed methane.
Other Income and Expenses:
- --------------------------
During the seven months ended December 31, 2002 the Company recognized a
loss on the sale of assets of $342,600 while it recognized a gain on the sale of
assets during the seven months ended December 31, 2001 of $592,600. The Company
also had an increase in interest expense of $234,500 during the seven months
ended December 31, 2002 over the same period of the previous year as a result of
the interest on the Company's convertible debt.
Operations for the seven months ended December 31, 2002 resulted in a loss
of $3,840,100 or $0.36 per share as compared to a loss of $2,785,400 or $0.45
per share for the seven months ended December 31, 2001.
FISCAL 2002 COMPARED TO FISCAL 2001
- -----------------------------------
Revenues:
- ---------
Revenues from operations decreased by $1,258,900 to $2,004,100 during
fiscal 2002 from the $3,263,000 recognized during fiscal 2001. Components of
this decrease are reductions of $426,500 in motel, real estate and airport
operations; mineral sales of $334,300; mineral royalties of $108,500; and
management fees of $389,600. Mineral sales during fiscal 2001 resulted from
purchase of uranium oxide on the open market to fill uranium sales contracts and
the sale of a uranium contract to a third party. We did not supply any of the
uranium sold under the contracts from production out of our mines. We have not
produced any minerals from mines for several years. The uranium contracts
expired and no molybdenum advance royalties have been received since 2001.
42
The reduction of motel, real estate and airport operations of $426,500 was
primarily as a result of reduced revenues at our Ticaboo motel in southern Utah.
The reduction in revenues in the tourism business is attributed to the general
decline in the economy as well as the negative effect that the terrorist attacks
have had on people's desire to travel.
There were no mineral sales during fiscal 2002 while there was one delivery
under a uranium contract as well as the sale of one of the Company's uranium
contracts to a third party during fiscal 2001. Currently the Company does not
have any delivery contracts for uranium or any other mineral. Depending on the
outcome of the SMP litigation, the Company may well have CIS pounds of uranium
for which it will need to obtain delivery contracts.
The Company holds a 6% gross royalty on the Mt. Emmons molybdenum deposit
near Crested Butte, CO. Under the provisions of the royalty agreement, the
Company and Crested are to receive 50,000 pounds of molybdenum or its cash
equivalent annually as an advance royalty. The royalty agreement was originally
made with AMAX Inc., which was purchased by Cyprus Minerals Company in 1993 and
changed its name to Cyprus Amax Minerals Company ("Cyprus Amax"). In 1999,
Cyprus Amax was purchased by Phelps Dodge Corporation. AMAX and Cyprus had made
the advance royalty payments to USECC on a timely basis. Phelps Dodge made one
advance royalty payment and ceased making payments in fiscal 2001. Phelps Dodge
suspended payments under the advance royalty agreement and has sued the Company.
The Company has filed counter claims against Phelps Dodge requesting that the
advance royalty and other issues be reinstated. It is not known what the outcome
of this litigation will be.
Management fees were reduced by $389,600 in fiscal 2002 from the prior
period due to reduced activity in the entities from which management fees are
collected.
Costs and Expenses:
- -------------------
During fiscal 2002, costs and expenses were reduced by $1,322,500. This
reduction was as a result of reduced activity in our commercial operations in
southern Utah because some of the operations were leased to third parties, and
the general economy turned down as a result of terrorist attacks. This reduced
both revenues as discussed above and costs and expenses of $1,307,300. The
holding costs of mineral properties were reduced by $1,661,500 as a result of
the Company reducing costs associated with mineral properties that are shut
down. The general and administrative costs were reduced by $104,700. In addition
to these reductions in costs and expenses, the Company recognized an expense of
$123,800 in abandonment of mining equipment during fiscal 2001. There was no
abandonment expense in fiscal 2002.
These reductions in costs and expenses were offset by increases in
impairment of goodwill of $1,622,700; provision for doubtful accounts of
$171,200, and other expenses of $80,900. The impairment of goodwill came as a
result of the Company purchasing an additional 8.7% of RMG equity or 1,105,499
shares of RMG stock by issuing 912,233 shares of the Company's common stock. The
shares of the Company's common stock were valued at $3.92 per share. An
impairment of $1,622,700 was taken on this investment in RMG as RMG had no gas
production and the impairment brought the total investment in RMG in line with
the fair market value of the RMG assets.
A provision for doubtful accounts was provided on the balance of a note
receivable that the Company held for the sale of Ruby Mining Company to
Admiralty Corporation. The note was in the original amount of $225,000 and had
been reduced to $171,200. The note went in default during fiscal 2002 at which
time the Company began negotiations with Admiralty to resolve the issue of the
outstanding balance. Terms were reached which required Admiralty to pay interest
on the note, plus accrued interest, through August 2003, at which time the
entire note balance would come due. Because of the financial condition of
Admiralty, it is not
43
known if that company will be able to pay the balance of the note when due. The
entire amount of the note was therefore reserved.
Other Income and Expenses:
- --------------------------
Gain on sale of assets income decreased by $350,900 during fiscal 2002 to
$812,700. This decrease was as a result of the sale of a majority of the surplus
mining equipment that the Company had for sale during the prior year. During
fiscal 2002, there was no income from litigation settlements while during fiscal
2001 there was $7,132,800 in litigation settlement as a result of the Company
settling all issues appertaining to the Kennecott litigation. Interest income
increased by $152,400 during fiscal 2002 over fiscal 2001 as did interest
expense which increased by $80,000 for the same period. These increases were as
a result of larger amounts of cash invested in interest bearing accounts and
increased debt.
Operations for the twelve months ended May 31, 2002, resulted in a net loss
of $6,267,600 or $0.67 per share as compared to net income of $1,771,200 or
$0.23 per share for the previous year.
FISCAL 2001 COMPARED TO FISCAL 2000
- -----------------------------------
Revenues:
- ---------
Operating revenues during fiscal 2001 decreased $40,900 from revenues for
the previous year to $3,263,000. This decrease was primarily as a result of a
decrease in revenues from motel, real estate and airport operations. This
decrease was offset by increases in mineral sales and management fees.
During fiscal 2001, we recorded $334,300 in revenues from mineral sales
compared with no mineral sales revenue during the previous year. The increase
was the result of the sale of a uranium delivery contract to a non-affiliated
company, and a delivery of uranium made under that market related contract
before the sale of the contract. There were no similar sales of uranium
contracts or uranium during the same period of the prior year. The Company
purchased the uranium necessary to deliver to its contract.
Revenues from motel, real estate and airport operations decreased from
$2,734,800 at May 31, 2000 to $2,222,400 at May 31, 2001. This decrease is as
result of the mine tour at SGMC and the boat storage, restaurant and convenience
store operations being leased to third parties by Plateau during fiscal 2001.
Management fees increased $161,300 to $597,800 during fiscal 2001. This
increase was due to RMG operations on which we receive a management fee.
Costs and Expenses:
- -------------------
Costs and expenses decreased by $3,879,200 during fiscal 2001 to
$10,780,800 from $14,660,000 during the previous year. This reduction in costs
and expenses came as a result of reduced motel, real estate and airport
operations expense of $151,100, and general and administrative costs and
expenses of $3,805,900. These reductions in costs and expenses were offset by
increases in mineral holding costs and expenses of $662,600; and abandonment of
mining equipment of $123,800.
General and administrative costs during fiscal 2000 were significantly
higher than those experienced during fiscal 2001 due to a noncash charge to
operations of $3,139,100 as a result of the issuance of common shares of RMG
stock below the market. Other reductions in general and administrative costs and
expenses during fiscal 2001 were related to a reduction of staff.
44
Other Income and Expenses:
- --------------------------
As a result of the settlement of the Kennecott litigation, $7,132,800 was
recorded as revenue during fiscal 2001. This revenue has two components: (1)
Noncash revenues as a result of the recognition of $4,000,000 of a deferred GMMV
purchase option payment that was received in 1997 and (2) the receipt of cash
from Kennecott as a result of the settlement, $3,132,800 - net of accounts
receivable from GMMV.
During the fiscal 2001, we recognized a gain of $1,163,600 from the sale of
equipment that was determined to be surplus. One component of this amount was
the sale of certain GMMV assets that were distributed to the Company from the
GMMV upon the resolution of the Kennecott litigation. The other main components
of this increase are the final royalty payment received from the sale of The
Brunton Company of $233,000, and the sale of real estate in Colorado of
$264,600.
Operations for the fiscal year ended May 31, 2001, resulted in earnings of
$1,771,200 or $0.21 per share fully diluted as compared to a loss of $10,621,000
or $1.33 per share fully diluted for the fiscal year ended May 31, 2000.
FUTURE OPERATIONS
-----------------
We have generated operating losses as of the seven months ended December
31, 2002 and in each of the three fiscal years ended May 31, 2002 as a result of
costs associated with shut down mineral properties. We have discontinued our
focus on these properties and at December 31, 2002, we are committed to be in
the coalbed methane business well into the future.
EFFECTS OF CHANGES IN PRICES
----------------------------
Mineral operations are significantly affected by changes in commodity
prices. As prices for a particular mineral increase, prices for prospects for
that mineral also increase, making acquisitions of such properties costly, and
sales advantageous. Conversely, a price decline facilitates acquisitions of
properties containing that mineral, but makes sales of such properties more
difficult. Operational impacts of changes in mineral commodity prices are common
in the mining industry.
NATURAL GAS. Our decision to expand into the coalbed methane gas industry
were predicated on the projections for natural gas demand and prices. The
Company is confident that it can maintain its costs at industry coalbed methane
industry standards but cannot predict what will happen to the price of coalbed
methane gas.
URANIUM AND GOLD. Changes in the prices of uranium and gold are not
expected to materially affect our operations during 2003.
MOLYBDENUM AND OIL. Changes in prices of molybdenum and petroleum are not
expected to materially affect our operations during 2003.
ITEM 8. FINANCIAL STATEMENTS
Financial statements meeting the requirements of Regulation S-X for the
Company follow immediately. Please note that the financial information contained
in these financial statements for the year ended May 31, 2000 was audited by
Arthur Andersen LLP who has ceased operations. A copy of Arthur Andersen's
previously issued audit report, dated September 11, 2000 is included in this
filing. This report has not been revised. This report refers to financial
information for the two years ended May 31, 2000. However, only the information
for the year ended May 31, 2000 is included in the financial statements filed
with this report.
45
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To U.S. Energy Corp.:
We have audited the accompanying consolidated balance sheets of U.S. ENERGY
CORP. (a Wyoming corporation) AND SUBSIDIARIES as of December 31, 2002, May 31,
2002 and May 31, 2001, and the related consolidated statements of operations,
shareholders' equity and cash flows for the seven months ended December 31, 2002
and each of the two years in the period ended May 31, 2002. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. The financial statements of U.S. ENERGY CORP. AND SUBSIDIARIES as of
and for the year ended May 31, 2000, were audited by other auditors who have
ceased operations. Those auditors expressed an unqualified opinion on those
financial statements before the reclassifications described in Notes B and L in
their report dated September 11, 2000.
As described in Notes B and L, the financial statements include certain
reclassifications. We have audited the reclassifications that were applied to
the 2000 financial statements. In our opinion, such reclassification adjustments
are appropriate and have been properly applied. However, we were not engaged to
audit, review, or apply any procedures to the 2000 financial statements of the
Company other than with respect to such reclassification adjustments and
accordingly, we do not express an opinion or any form of assurance on the 2000
financial statements taken as a whole.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements as of December 31, 2002,
May 31, 2002 and May 31, 2001 present fairly, in all material respects, the
financial position of U.S. Energy Corp. and subsidiaries as of December 31,
2002, May 31, 2002 and May 31, 2001, and the results of their operations and
their cash flows for the seven months ended December 31, 2002 and each of the
two years ended May 31, 2002 and May 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming the Company
will continue as a going concern. As discussed in Note A to the financial
statements, the Company has experienced recurring losses from operations and has
a substantial accumulated deficit. These factors raise substantial doubt about
the ability of the Company to continue as a going concern. Management's plans in
regards to these matters are also described in Note A. The financial statements
do not include any adjustments that might result from the outcome of this
uncertainty.
GRANT THORNTON LLP
Denver, Colorado,
February 28, 2003
46
The report that appears below is a copy of the report issued by the
Company's previous independent auditor, Arthur Andersen, LLP. That firm has
discontinued performing auditing and accounting services.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To U.S. Energy Corp.:
We have audited the accompanying balance sheet of U.S. Energy Corp. (a Wyoming
corporation) as of May 31, 2000, and the related consolidated statements of
operations, shareholders' equity and cash flows for the year ended May 31, 2000.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of U.S. Energy Corp. as of May 31,
2000, and the results of operations and cash flows for the year ended May 31,
2000, in conformity with accounting principles generally accepted in the United
States.
ARTHUR ANDERSEN LLP
Denver, Colorado
September 11, 2000
47
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
Seven Months Ended Year Ended
December 31, May 31,
------------ ------------------------------
2002 2002 2001
------------ ------------ ------------
CURRENT ASSETS:
Cash and cash equivalents $ 1,741,000 $ 2,564,300 $ 685,500
Accounts receivable:
Trade, net of allowance of $27,800 1,655,700 768,800 1,319,300
Affiliates 117,600 132,800 74,200
Current portion of long-term notes 165,900 229,000 225,000
Assets held for resale 532,800 532,800 532,800
Prepaid expenses 528,300 578,300 451,000
Inventory 14,000 86,600 42,200
------------ ------------ ------------
Total current assets 4,755,300 4,892,600 3,330,000
INVESTMENTS:
Restricted investments 9,911,700 10,015,500 9,794,900
PROPERTIES AND EQUIPMENT:
Land 576,300 1,764,100 1,771,800
Buildings and improvements 7,811,300 8,501,300 8,425,400
Machinery and equipment 4,737,100 5,107,700 5,536,900
Proved oil and gas properties, full cost method 2,423,600 1,773,600 1,773,600
Unproved coalbed methane properties,
excluded from amortization 4,254,000 4,995,600 5,881,700
------------ ------------ ------------
Total property and equipment 19,802,300 22,142,300 23,389,400
Less-accumulated depreciation,
depletion and amortization (7,214,800) (7,584,200) (7,285,100)
------------ ------------ ------------
Net property and equipment 12,587,500 14,558,100 16,104,300
OTHER ASSETS:
Accounts and notes receivable:
Real estate and equipment sales -- 36,800 42,400
Employees 48,800 65,000 180,300
Deposits and other 887,300 969,900 1,013,300
------------ ------------ ------------
Total other assets 936,100 1,071,700 1,236,000
------------ ------------ ------------
Total assets $ 28,190,600 $ 30,537,900 $ 30,465,200
============ ============ ============
The accompanying notes to consolidated financial statements
are and integral part of these statements.
48
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
Seven Months Ended Year Ended
December 31, May 31,
------------- -------------------------------
2002 2002 2001
------------ ------------ ------------
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 1,592,800 $ 758,600 $ 1,404,300
Prepaid drilling costs 134,400 242,100 --
Current portion of long-term debt 317,200 205,700 142,400
Line of credit -- 200,000 850,000
------------ ------------ ------------
Total current liabilities 2,044,400 1,406,400 2,396,700
LONG-TERM DEBT 2,820,600 2,353,300 2,152,100
RECLAMATION LIABILITY 8,906,800 8,906,800 8,906,800
OTHER ACCRUED LIABILITIES 2,319,900 2,544,200 2,777,800
DEFERRED TAX LIABILITY 1,144,800 1,144,800 1,144,800
MINORITY INTERESTS 587,400 575,300 1,177,800
COMMITMENTS AND CONTINGENCIES
FORFEITABLE COMMON STOCK,
$.01 par value; 500,788, 500,788 and 433,788
shares issued, respectively, forfeitable until earned 3,009,900 3,009,900 2,748,600
PREFERRED STOCK,
$.01 par value; 1,000 shares authorized,
200 shares issued and outstanding in 2001 -- -- 1,840,000
SHAREHOLDERS' EQUITY:
Common stock, $.01 par value; unlimited shares
authorized; 11,826,396, 11,720,818 and 8,989,047
shares issued, respectively 118,300 117,200 90,000
Additional paid-in capital 48,877,100 48,278,500 38,681,600
Accumulated deficit (38,407,700) (34,567,600) (28,300,000)
Treasury stock at cost, 959,725, 959,725 and
949,725 shares, respectively (2,740,400) (2,740,400) (2,660,500)
Unallocated ESOP contribution (490,500) (490,500) (490,500)
------------ ------------ ------------
Total shareholders' equity 7,356,800 10,597,200 7,320,600
------------ ------------ ------------
Total liabilities and shareholders' equity $ 28,190,600 $ 30,537,900 $ 30,465,200
============ ============ ============
The accompanying notes to consolidated financial statements
are and integral part of these statements.
49
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Seven Months Ended
December 31, Year Ended May 31,
------------------------------------------------------------------
2002 2002 2001 2000
------------ ------------ ------------ ------------
OPERATING REVENUES:
Motel, real estate and airport operations $ 749,100 $ 1,795,900 $ 2,222,400 $ 2,734,800
Methane gas sales 119,400 -- -- --
Mineral sales -- -- 334,300 --
Mineral royalties -- -- 108,500 132,600
Management fees 159,100 208,200 597,800 436,500
------------ ------------ ------------ ------------
1,027,600 2,004,100 3,263,000 3,303,900
OPERATING COSTS AND EXPENSES:
Motel, real estate and airport operations 527,200 1,928,900 3,236,200 3,387,300
Gas operations 355,200 -- -- --
Mineral holding costs 737,200 1,707,800 3,369,300 2,706,700
General and administrative 2,915,800 3,946,800 4,051,500 7,857,400
Abandonment of mining equipment -- -- 123,800 --
Provision for doubtful accounts -- 171,200 -- 708,600
Other -- 80,900 -- --
Impairment of goodwill -- 1,622,700 -- --
------------ ------------ ------------ ------------
4,535,400 9,458,300 10,780,800 14,660,000
------------ ------------ ------------ ------------
OPERATING LOSS (3,507,800) (7,454,200) (7,517,800) (11,356,100)
OTHER INCOME & EXPENSES
Gain (Loss) on sales of assets (342,600) 812,700 1,163,600 71,400
Litigation settlements, net -- -- 7,132,800 --
Interest income 524,500 852,100 699,700 813,600
Interest expense (361,200) (345,300) (265,300) (82,800)
Other (207,800) -- -- --
------------ ------------ ------------ ------------
(387,100) 1,319,500 8,730,800 802,200
------------ ------------ ------------ ------------
(LOSS) INCOME BEFORE MINORITY
INTEREST AND EQUITY IN LOSS
OF AFFILIATES (3,894,900) (6,134,700) 1,213,000 (10,553,900)
MINORITY INTEREST IN LOSS
OF CONSOLIDATED SUBSIDIARIES 54,800 39,500 220,100 509,300
EQUITY IN LOSS OF AFFILIATES -- -- -- (2,900)
------------ ------------ ------------ ------------
(Continued)
The accompanying notes to consolidated financial statements
are and integral part of these statements.
50
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(CONTINUED)
Seven Months Ended
December 31, Year Ended May 31,
------------ ------------------------------------------------
2002 2002 2001 2000
------------ ------------ ------------ ------------
(LOSS) INCOME BEFORE
INCOME TAXES (3,840,100) (6,095,200) 1,433,100 (10,047,500)
PROVISION FOR INCOME TAXES -- -- -- --
------------ ------------ ------------ ------------
NET (LOSS) INCOME FROM
CONTINUING OPERATIONS (3,840,100) (6,095,200) 1,433,100 (10,047,500)
DISCONTINUED OPERATIONS,
NET OF TAX -- (85,900) 488,100 (594,300)
------------ ------------ ------------ ------------
NET (LOSS) INCOME (3,840,100) (6,181,100) 1,921,200 (10,641,800)
PREFERRED STOCK DIVIDENDS -- (86,500) (150,000) (20,800)
------------ ------------ ------------ ------------
NET (LOSS) INCOME TO
COMMON SHAREHOLDERS $ (3,840,100) $ (6,267,600) $ 1,771,200 $(10,662,600)
============ ============ ============ ============
NET (LOSS) INCOME PER SHARE BASIC
FROM CONTINUED OPERATIONS $ (0.36) $ (0.66) $ 0.17 $ (1.31)
FROM DISCONTINUED OPERATIONS -- (0.01) 0.06 (0.08)
------------ ------------ ------------ ------------
$ (0.36) $ (0.67) $ 0.23 $ (1.39)
============ ============ ============ ============
NET (LOSS) INCOME
PER SHARE DILUTED
FROM CONTINUED OPERATIONS $ (0.36) $ (0.66) $ 0.15 $ (1.31)
FROM DISCONTINUED OPERATIONS -- (0.01) .06 (0.08)
------------ ------------ ------------ ------------
$ (0.36) $ (0.67) $ 0.21 $ (1.39)
============ ============ ============ ============
BASIC WEIGHTED AVERAGE
SHARES OUTSTANDING 10,770,658 9,299,359 7,826,001 7,673,475
============ ============ ============ ============
DILUTED WEIGHTED AVERAGE
SHARES OUTSTANDING 10,770,658 9,299,359 8,487,680 7,673,475
============ ============ ============ ============
The accompanying notes to consolidated financial statements
are and integral part of these statements.
51
Additional
Common Stock Paid-In Accumulated
Shares Amount Capital Deficit
------ ------ ---------- -----------
Balance May 31, 1999 8,550,624 $ 85,600 $ 33,014,900 $(19,408,600)
Funding of ESOP 123,802 1,200 370,200 --
Issuance of common stock
to outside directors 6,020 100 21,000 --
Issuance of common stock for
purchase of subsidiary stock 73,109 700 259,900 --
Forfeitable shares earned 9,600 100 88,000 --
Treasury stock from consolidation
of subsidiaries Ruby Mining Co.
and Northwest Gold, Inc. -- -- -- --
Unrealized gain on sale of
subsidiary stock -- -- 1,053,700 --
Noncash compensation
paid by subsidiary -- -- 2,990,000 --
Writedown of unallocated
ESOP contribution -- -- -- --
Net Loss -- -- -- (10,662,600)
--------- ------------ ------------ ------------
Balance May 31, 2000 8,763,155 $ 87,700 $ 37,797,700 $(30,071,200)
========= ============ ============ ============
52a
Unallocated Total
Treasury Stock ESOP Shareholders'
Shares Amount Contribution Equity
------ ------ ------------ -------------
Balance May 31, 1999 930,532 $ (2,584,600) $ (927,000) $ 10,180,300
Funding of ESOP -- -- -- 371,400
Issuance of common stock
to outside directors -- -- -- 21,100
Issuance of common stock for
purchase of subsidiary stock -- -- -- 260,600
Forfeitable shares earned -- -- -- 88,100
Treasury stock from consolidation
of subsidiaries Ruby Mining Co.
and Northwest Gold, Inc. 14,193 (55,300) -- (55,300)
Unrealized gain on sale of
subsidiary stock -- -- -- 1,053,700
Noncash compensation
paid by subsidiary -- -- -- 2,990,000
Writedown of unallocated
ESOP contribution -- -- 436,500 436,500
Net Loss -- -- -- (10,662,600)
------- ------------ ------------ ------------
Balance May 31, 2000 944,725 $ (2,639,900) $ (490,500) $ 4,683,800
======= ============ ============ ============
Total Shareholders' Equity at May 31, 2000 does not include 396,608 shares
currently issued but forfeitable if certain conditions are not met by the
recipients. "Basic and Diluted Weighted Average Shares Outstanding" also
includes the 827,108 shares of U.S. Energy common stock held by majority-owned
subsidiaries, which, in consolidation, are treated as treasury shares.
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
52b
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(CONTINUED)
Additional
Common Stock Paid-In Accumulated
Shares Amount Capital Deficit
------ ------ ---------- -----------
Balance May 31, 2000 8,763,155 $ 87,700 $ 37,797,700 $(30,071,200)
Funding of ESOP 53,837 500 287,500 --
Issuance of common stock
to outside directors 8,532 100 19,100 --
Forfeitable shares earned 29,820 300 193,900 --
Issuance of common stock
for services rendered 15,000 200 70,400 --
Treasury stock from payment
on balance of note receivable -- -- -- --
Sale of Ruby Mining -- -- 25,800 --
Issuance of common stock
for exercised options 118,703 1,200 287,200 --
Net income -- -- -- 1,771,200
--------- ------------ ------------ -----------
Balance May 31, 2001 8,989,047 $ 90,000 $ 38,681,600 $(28,300,000)
========= ============ ============ ============
53a
Unallocated Total
Treasury Stock ESOP Shareholders'
Shares Amount Contribution Equity
------ ------ ------------ -------------
Balance May 31, 2000 944,725 $ (2,639,900) $ (490,500) $ 4,683,800
Funding of ESOP -- -- -- 288,000
Issuance of common stock
to outside directors -- -- -- 19,200
Forfeitable shares earned -- -- -- 194,200
Issuance of common stock
for services rendered -- -- -- 70,600
Treasury stock from payment
on balance of note receivable 5,000 (20,600) -- (20,600)
Sale of Ruby Mining -- -- -- 25,800
Issuance of common stock
for exercised options -- -- -- 288,400
Net income -- -- -- 1,771,200
------- ------------ ------------ ------------
Balance May 31, 2001 949,725 $ (2,660,500) $ (490,500) $ 7,320,600
======= ============ ============ ============
Total Shareholders' Equity at May 31, 2001 does not include 433,788 shares
currently issued but forfeitable if certain conditions are not met by the
recipients. "Basic and Diluted Weighted Average Shares Outstanding" also
includes 814,496 shares of common stock held by majority-owned subsidiaries,
which, in consolidation, are treated as treasury shares.
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
53b
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(CONTINUED)
Additional Unallocated
Common Stock Paid-In Accumulated
Shares Amount Capital Deficit
------ ------ ---------- -----------
Balance May 31, 2001 8,989,047 $ 90,000 $ 38,681,600 $(28,300,000)
Funding of ESOP 70,075 700 236,200 --
Issuance of common stock
to outside directors 3,429 -- 14,400 --
Issuance of common stock
for services rendered 45,000 500 147,600 --
Issuance of common stock warrants
for services rendered -- -- 592,900 --
Treasury stock from payment
on balance of note receivable -- -- -- --
Issuance of common stock
in exchange for preferred stock 513,140 5,100 1,846,400 --
Issuance of common stock
in exchange for subsidiary stock 912,233 9,100 3,566,900 --
Issuance of common stock
to purchase property 61,760 600 246,200 --
Issuance of common stock
through private placement 871,592 8,700 2,341,800 --
Issuance of common stock
for exercised stock warrants 1,205 -- 4,500 --
Issuance of common stock
for exercised options 253,337 2,500 600,000 --
Net loss -- -- -- (6,267,600)
---------- ------------ ------------ -----------
Balance May 31, 2002 11,720,818 $ 117,200 $ 48,278,500 $(34,567,600)
========== ============ ============ ============
54a
Total
Treasury Stock ESOP Shareholders'
Shares Amount Contribution Equity
------ ------ ------------ -------------
Balance May 31, 2001 949,725 $ (2,660,500) $ (490,500) $ 7,320,600
Funding of ESOP -- -- -- 236,900
Issuance of common stock
to outside directors -- -- -- 14,400
Issuance of common stock
for services rendered -- -- -- 148,100
Issuance of common stock warrants
for services rendered -- -- -- 592,900
Treasury stock from payment
on balance of note receivable 10,000 (79,900) -- (79,900)
Issuance of common stock
in exchange for preferred stock -- -- -- 1,851,500
Issuance of common stock
in exchange for subsidiary stock -- -- -- 3,576,000
Issuance of common stock
to purchase property -- -- -- 246,800
Issuance of common stock
through private placement -- -- -- 2,350,500
Issuance of common stock
for exercised stock warrants -- -- -- 4,500
Issuance of common stock
for exercised options -- -- -- 602,500
Net loss -- -- -- (6,267,600)
------- ------------ ------------ ------------
Balance May 31, 2002 959,725 $ (2,740,400) $ (490,500) $ 10,597,200
======= ============ ============ ============
Total Shareholders' Equity at May 31, 2002 does not include 500,788 shares
currently issued but forfeitable if certain conditions are not met by the
recipients. "Basic and Diluted Weighted Average Shares Outstanding" also
includes 814,496 shares of common stock held by majority-owned subsidiaries,
which, in consolidation, are treated as treasury shares.
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
54b
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(CONTINUED)
Additional Unallocated
Common Stock Paid-In Accumulated
Shares Amount Capital Deficit
------ ------ ---------- -----------
Balance May 31, 2002 11,720,818 $ 117,200 $ 48,278,500 $(34,567,600)
Funding of ESOP 43,867 400 134,700 --
Issuance of common stock
to outside consltants 15,000 200 60,700 --
Issuance of common
stock warrants 325,900 -- -- --
Issuance of common stock
for settlement of law suit 20,000 200 77,600 --
Issuance of common stock
for exercised options 26,711 300 (300) --
Net loss -- -- -- (3,840,100)
---------- ------------ ------------ ------------
Balance December 31, 2002 11,826,396 $ 118,300 $ 48,877,100 $(38,407,700)
========== ============ ============ ============
55a
Total
Treasury Stock ESOP Shareholders'
Shares Amount Contribution Equity
------ ------ ------------ -------------
Balance May 31, 2002 959,725 $ (2,740,400) $ (490,500) $ 10,597,200
Funding of ESOP -- -- -- 135,100
Issuance of common stock
to outside consltants -- -- -- 60,900
Issuance of common
stock warrants -- 325,900
Issuance of common stock
for settlement of law suit -- -- -- 77,800
Issuance of common stock
for exercised options -- -- -- --
Net loss -- -- -- (3,840,100)
------- ------------ ------------ ------------
Balance December 31, 2002 959,725 $ (2,740,400) $ (490,500) $ 7,356,800
======= ============ ============ ============
Total Shareholders' Equity at December 31, 2002 does not include 500,788 shares
currently issued but forfeitable if certain conditions are not met by the
recipients. "Basic and Diluted Weighted Average Shares Outstanding" also
includes 814,496 shares of common stock held by majority-owned subsidiaries,
which, in consolidation, are treated as treasury shares.
The accompanying notes to consolidated financial statements are an integral
part of these financial statements.
55b
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Seven Months Ended
December 31, Year Ended May 31,
------------ -----------------------------------------------
2002 2002 2001 2000
------------ ------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (3,840,100) $ (6,267,600) $ 1,771,200 $(10,662,600)
Adjustments to reconcile net income (loss)
to net cash used in operating activities:
Minority interest in loss of
consolidated subsidiaries (54,800) (39,500) (220,100) (509,300)
Depreciation and amortization 360,100 541,500 1,254,000 1,273,000
Amortization of debt discount 211,200 -- -- --
Impairment of goodwill -- 1,622,700 -- --
Impairment of mineral interests -- -- 123,800 --
Noncash services 31,500 787,700 19,100 21,100
Noncash dividend -- 11,500 -- --
Equity in loss from affiliates -- -- -- 2,900
(Gain) loss on sale of assets 342,600 (812,700) (1,163,600) (71,400)
Write off of properties 21,500 -- -- --
Provision for doubtful accounts -- 171,200 -- 708,600
Noncash compensation 314,800 535,200 501,700 3,361,400
Deferred income -- -- (4,000,000) --
Net changes in assets and liabilities:
Accounts and notes receivable (755,600) 799,900 1,241,000 (536,500)
Other assets 8,800 (47,500) (112,700) 92,200
Prepaid drilling costs (107,700) 242,100 -- --
Accounts payable and accrued expenses 609,900 (879,300) (887,300) (217,200)
Reclamation and other -- -- -- 45,900
------------ ------------ ------------ ------------
NET CASH USED IN OPERATING ACTIVITIES (2,857,800) (3,334,800) (1,472,900) (6,491,900)
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration of coalbed
methane gas properties (883,400) (142,100) (1,187,800) (4,727,200)
Proceeds from sale of property and equipment 1,566,000 752,000 2,608,000 78,300
Proceeds from sale of gas interests 1,125,000 1,125,000 -- --
Increase (decrease) in restricted investments 66,100 (236,800) (417,700) (200,600)
Purchase of property and equipment (411,200) (82,300) (311,400) (2,240,000)
Net change in investments in affiliates 104,600 406,500 292,400 (12,500)
------------ ------------ ------------ ------------
NET CASH PROVIDED BY (USED IN)
INVESTING ACTIVITIES 1,567,100 1,822,300 983,500 (7,102,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock -- 2,957,400 288,400 --
Proceeds from issuance of preferred stock -- -- -- 1,840,000
Proceeds from sale of stock by subsidiary -- 1,000,000 -- 2,160,000
Proceeds from long-term debt 892,800 631,700 619,100 886,400
Net activity from lines of credit (200,000) (650,000) 200,000 650,000
Purchase of treasury stock -- -- (20,600) --
Repayments of long-term debt (225,300) (547,800) (828,400) (1,246,300)
Cash acquired in purchase of subsidiary -- -- -- 47,200
------------ ------------ ------------ ------------
NET CASH PROVIDED BY
FINANCING ACTIVITIES 467,500 3,391,300 258,500 4,337,300
------------ ------------ ------------ ------------
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
56
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Seven Months Ended
December 31, Year Ended May 31,
------------ ---------------------------------------------
2002 2002 2001 2000
------------ ------------ ------------ ------------
NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS (823,300) 1,878,800 (230,900) (9,256,600)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 2,564,300 685,500 916,400 10,173,000
------------ ------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 1,741,000 $ 2,564,300 $ 685,500 $ 916,400
============ ============ ============ ============
SUPPLEMENTAL DISCLOSURE
Income tax paid $ -- $ -- $ -- $ --
============ ============ ============ ============
Interest paid $ 361,200 $ 345,300 $ 265,300 $ 35,800
============ ============ ============ ============
NONCASH INVESTING AND
FINANCING ACTIVITIES:
Methane gas property purchase $ 150,000 $ -- $ -- $ --
============ ============ ============ ============
Issuance of stock to invest in subsidiary $ -- $ 3,568,500 $ -- $ --
============ ============ ============ ============
Issuance of stock to retire preferred stock $ -- $ 1,840,000 $ -- $ --
============ ============ ============ ============
Sale of assets through notes and
accounts receivable $ -- $ 442,200 $ 1,164,500 $ --
============ ============ ============ ============
Issuance of stock as deferred compensation $ -- $ 261,300 $ 358,400 $ 201,000
============ ============ ============ ============
Issuance of stock warrants for services $ 26,100 $ -- $ -- $ --
============ ============ ============ ============
Acquisition of assets through issuance of debt $ -- $ 180,600 $ 1,631,700 $ 506,000
============ ============ ============ ============
Acquisition of assets through issuance of stock $ -- $ 96,800 $ -- $ --
============ ============ ============ ============
Satisfaction of receivable - employee
with stock in company $ -- $ 79,900 $ -- $ --
============ ============ ============ ============
Issuance of stock for services $ 60,900 $ 14,400 $ 70,500 $ --
============ ============ ============ ============
Issuance of stock for retired employees $ -- $ -- $ 194,400 $ 88,100
============ ============ ============ ============
Satisfaction of receivable - affiliate
with stock in affiliate $ -- $ -- $ 3,000,000 $ 196,700
============ ============ ============ ============
Issuance of stock warrants in conjunction
with notes payable $ 299,800 $ 592,900 $ -- $ --
============ ============ ============ ============
The accompanying notes to consolidated financial statements
are and integral part of these statements.
57
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
A. BUSINESS ORGANIZATION AND OPERATIONS:
U.S. Energy Corp. and subsidiaries (the "Company" or "USE") was
incorporated in the State of Wyoming on January 26, 1966. The Company engages in
the acquisition, exploration, holding, sale and/or development of mineral and
coalbed methane gas properties, the production of petroleum properties and
marketing of minerals and methane gas. Principal mineral interests are in
coalbed methane, uranium, gold and molybdenum. The Company's uranium and gold
properties are currently all in a shut down status. The Company holds various
real and personal properties used in commercial activities. Most of the
Company's activities are conducted and through the joint venture discussed below
and in Note D.
The Company was engaged in the maintenance of two uranium properties, one
in southern Utah, and the second in Wyoming known as Sheep Mountain Partners
("SMP"). Both of these ventures have been involved in significant litigation
(see Note K). Sutter Gold Mining Company ("SGMC"), a Wyoming corporation owned
66.3% by the Company at December 31, 2002, manages the Company's interest in
gold properties. The Company also owns 100% of the outstanding stock of Plateau
Resources Limited ("Plateau"), which owns a nonoperating uranium mill and
commercial properties in southeastern Utah. Currently, the mill is nonoperating
but has been granted a license to operate subject to certain conditions. Rocky
Mountain Gas, Inc. ("RMG") was formed in November 1999 to consolidate all
methane gas operations of the Company. The Company owns and controls 91.5% of
RMG as of December 31, 2002.
During its regular meeting on December 16, 2002, the Company's Board of
Directors voted on a unanimous basis to change the Company's year end to
December 31 effective December 31, 2002.
MANAGEMENT'S PLAN
-----------------
The Company has generated significant net losses during the seven months
ended December 31, 2002 and two of the past three fiscal years ending May 31,
2002 and has an accumulated deficit of approximately $38,407,700 at December 31,
2002. The Company has working capital of approximately $2,710,900 at December
31, 2002 and its cash balance has decreased from $2,564,300 at May 31, 2002 to
$1,741,000 at December 31, 2002. During the seven months ended December 31,
2002, and the fiscal year ended May 31, 2001 and 2000, the Company experienced
negative cash flow of $823,300, $230,900 and $9,256,600 respectively. The
Company experienced positive cash flow of $1,878,800 for the fiscal year ended
May 31, 2002.
After the CCBM work commitment has been fully funded, the Company does not
have sufficient capital available to fund its portion of the anticipated
exploration and development activities on its coalbed methane properties.
Additionally, the Company's known cash flows through December 31, 2003 from
current operations and associated overhead are negative based on current
projections. In order to improve liquidity of the Company, management intends to
do the following:
o Maintain production from the Bobcat coalbed methane property at about
2,000 Mcf per day and bring the Clearmont property on line. Management
also believes that additional production can be obtained as the coals
continue to be de-watered and more gas wells are drilled. The Company
is working to reduce the price differential that affects Wyoming gas
production by hedging a portion of its production and securing
pipeline capacity. These two
58
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
factors along with anticipated higher demand primarily as a result of
new proposed pipelines which will increase methane gas prices should
have a significant impact on the Company's cash flows.
o Continue to reduce its mining activities.
o Sell home and mobile home lots at its commercial operations in
southern Utah. These lots are no longer needed for current operations
and will provide cash flows to the Company.
o Sell the Ticaboo Townsite in southern Utah. Included in the Townsite
is a motel, C store, restaurant/lounge, boat storage and repair
facility and undeveloped land. The sale of this property would
increase the cash position of the Company significantly and would
allow the employees of the Company to concentrate on the Company's
core business of coalbed methane.
o Sell raw land in Riverton, Wyoming and Gunnison, Colorado. Management
intends to sell this land at its fair market value. The land is not
needed for the operations of the Company now or into the future.
o Seek equity funding or a joint venture partner to place the SGMC
property into production or sell the entire property to an industry
partner.
o Raise additional capital through a private placement and a public
offering of its subsidiary Rocky Mountain Gas, Inc. The timing of such
a public offering will depend on the market prices for methane gas.
o Reduce overhead expenses and concentrate on its primary business -
coalbed methane.
Additionally, management of the Company believes that funds will be
received as a result of the accounting that is currently being conducted by the
Special Master under the direction of the U.S. District Court, District of
Colorado in the litigation with Nukem, Inc. The Court ordered that the final
accounting be delivered to the Court no later than December 6, 2002. The Special
Master filed a motion with the Court requesting additional time to complete the
accounting. On February 19, 2003, the U.S. District Court granted a second
motion of the Special Master for the extension of time and ordered the report be
filed by April 4, 2003 with a hearing on the report to be held on April 11,
2003. Management cannot predict the ultimate outcome of the litigation, however,
management of the Company believes it will be beneficial to the Company.
As a result of these plans, management believes that they will generate
sufficient cash flows to meet its current obligations in calendar 2003.
59
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of USE and subsidiaries include the
accounts of the Company, the accounts of its majority-owned or controlled
subsidiaries Plateau (100%), Energx, Ltd ("Energx") (90%), Four Nines Gold, Inc.
("FNG") (50.9%), SGMC (66.3%), Crested Corp. ("Crested") (70.5%), Yellowstone
Fuels Corp. ("YSFC") (35.9%) Rocky Mountain Gas ("RMG") (91.5%), Northwest Gold,
Inc. ("NWG") (96%) and the USECC Joint Venture ("USECC"), a consolidated joint
venture which is equally owned by U.S. Energy Corp. and Crested, through which
the bulk of their operations are conducted.
Investments in joint ventures and all 20% to 50% owned companies are
accounted for using the equity method. Investments of less than 20% are
accounted for by the cost method. All material intercompany profits,
transactions and balances have been eliminated.
CASH EQUIVALENTS
The Company considers all highly liquid investments with original
maturities of three months or less to be cash equivalents.
RESTRICTED INVESTMENTS
Based on the provisions of Statement of Financial Accounting Standards No.
115 ("SFAS 115"), the Company accounts for its restricted investment in certain
securities as held-to-maturity. Held-to-maturity securities are measured at
amortized cost. If a decline in fair value of such investments is determined to
be other than temporary, the investment is written down to fair value.
ACCOUNTS RECEIVABLE
The majority of the Company's accounts receivable are due from industry
partners for drilling and operating expenses associated with coalbed methane gas
wells for which RMG acts as operator and from sales of land. The Company
determines any required allowance by considering a number of factors including
length of time trade accounts receivable are past due and the Company's previous
loss history. The Company writes off accounts receivable when they become
uncollectable, and payments subsequently received on such receivables are
credited to the allowance for doubtful accounts.
In addition, the Company is due $5,250,000 from CCBM under a non-recourse
promissory note receivable which arose as part of the sale of a portion of RMG's
coalbed methane properties to CCBM. The note receivable is fully reserved due to
its non-recourse nature with payments received credited against the full-cost
pool.
60
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
INVENTORIES
Inventories consist of aviation fuel and well casing and tubing.
Inventories are stated at lower of cost or market using the average cost method.
PROPERTIES AND EQUIPMENT
Land, buildings, improvements, machinery and equipment are carried at cost.
Depreciation of buildings, improvements, machinery and equipment is provided
principally by the straight-line method over estimated useful lives ranging from
3 to 45 years. Following is a breakdown of the lives over which assets are
depreciated.
Office Equipment 3 to 5 years
Field Tools and Hand Equipment 5 to 7 years
Vehicles and Trucks 3 to 7 years
Heavy Equipment 7 to 10 years
Service Buildings 20 years
Corporate Headquarter's Building 45 years
The Company capitalizes all costs incidental to the acquisition and
exploration of mineral properties as incurred. Costs are charged to operations
if the Company determines that the property is not economical. Costs and
expenses related to general corporate overhead are expensed as incurred.
The Company has acquired substantial mining properties and associated
facilities at minimal cash cost, primarily through the assumption of reclamation
and environmental liabilities. Certain of these properties are owned by various
ventures in which the Company is either a partner or venturer. (See Note K.)
OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with acquisition, exploration, and
development of oil and gas reserves, including directly related overhead costs,
are capitalized.
All capitalized costs of oil and gas properties subject to amortization and
the estimated future costs to develop proved reserves, are amortized on the
unit-of-production method using estimates of proved reserves. Investments in
unproved properties and major exploration and development projects are not
amortized until proved reserves associated with the projects can be determined
or until impairment occurs. If the results of an assessment indicate that the
properties are impaired, the capitalized cost of the property will be written
off.
61
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
After there are proven reserves, the capitalized costs associated with
those reserves are subject to a "ceiling test," which basically limits such
costs to the aggregate of the "estimated present value," discounted at a
10-percent interest rate of future net revenues from proved reserves, based on
current economic and operating conditions, plus the lower of cost or fair market
value of unproved properties.
As of December 31, 2002, the Company had proven reserves on its Bobcat
property of 585.6 million cubic feet (MMcf).
Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas, in which case the gain or loss is recognized in income.
Abandonments of properties are accounted for as adjustments of capitalized costs
with no loss recognized.
LONG-LIVED ASSETS
The Company evaluates its long-lived assets (other than oil and gas
properties which are discussed above) for impairment when events or changes in
circumstances indicate that the related carrying amount may not be recoverable.
If the sum of estimated future cash flows on an undiscounted basis is less than
the carrying amount of the related asset, an asset impairment is considered to
exist. The related impairment loss is measured by comparing estimated future
cash flows on a discounted basis to the carrying amount of the asset. Changes in
significant assumptions underlying future cash flow estimates may have a
material effect on the Company's financial position and results of operations.
An uneconomic commodity market price, if sustained for an extended period of
time, or an inability to obtain financing necessary to develop mineral
interests, may result in asset impairment.
During the year ended May 31, 2002, the Company recorded a $1,622,700
impairment of goodwill that arose as part of the purchase of an additional
1,105,499 shares of RMG common stock. These shares of stock were purchased by
issuing 910,320 shares of the Company's common stock pursuant to conversion
rights granted RMG private placement investors.
During fiscal 2001, the Company recorded an impairment on its mineral
properties of $123,800 in YSFC. As of December 31, 2002, management believes no
further impairment is necessary and that the fair market of remaining assets
exceeds the carrying value. See Note F for further discussion.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amount of cash equivalents, receivables, other current assets,
accounts payable and accrued expenses approximates fair value because of the
short-term nature of those instruments. The recorded amounts for short-term and
long-term debt, approximate fair market value due to the variable nature of the
interest rates on the short term debt, and the fact that interest rates remain
general unchanged from issuance of the long term debt.
62
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
REVENUE RECOGNITION
Revenues from motel, real estate and airport operations are from the rental
of motel rooms, boat storage facilities and mobile home lots at the Company's
operations in southern Utah as well as the rental of office space in office
buildings in Riverton, Wyoming. Airport operations consist of the sale of
aviation fuel, repair and maintenance of aircraft and rental of hanger space.
All these revenues are reported on a gross revenue basis and are recorded at the
time the service is provided.
The Company, through its subsidiary, RMG, utilizes the accrual method of
accounting for natural gas revenues whereby revenues are recognized as the
Company's entitlement share of the gas is produced based upon its working
interest in the properties. The Company will record a receivable (payable) to
the extent that it receives less (more) than its proportionate share of the gas
revenues.
Revenues from mineral sales consist of the sale of uranium to a delivery
contract and the sale of that contract to a third party supplier. The sale of
uranium is reported on a net basis. The Company has not produced any uranium
from its properties during the period covered by the enclosed financial
statements and has purchased all uranium delivered under its supply contracts
from the open market as all the Company's uranium operations are shut down.
Mineral royalties which are non-refundable are recognized as revenue when
received (see Note F).
Management fees are recorded as a percentage of actual costs for services
provided for subsidiaries and partnerships for which the Company provides
management services. The Company is also paid a management fee for overseeing
oil production on the Fort Peck Reservation in Montana. Management fees are
recorded when the service is provided.
STOCK BASED COMPENSATION
SFAS 123, "Accounting for Stock-Based Compensation," defines a fair value
based method of accounting for employee stock options or similar equity
instruments. However, SFAS 123 allows the continued measurement of compensation
cost for such plans using the intrinsic value based method prescribed by APB
Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"), provided
that pro forma disclosures are made of net income or loss and net income or loss
per share, assuming the fair value based method of SFAS 123 had been applied.
The Company has elected to account for its stock-based compensation plans under
APB 25; accordingly, for purposes of the pro forma disclosures presented below,
the Company has computed the fair values of all options granted using the
Black-Scholes pricing model and the following weighted average assumptions (no
options were granted during 2000):
63
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Seven Months ended Year ended May 31,
December 31, --------------------------------
2002 2002 2001 2000
---- ---- ---- ----
Risk-free interest rate 4.4% 5.6% 4.29% --
Expected lives 8.5 years 10 years 10 years --
Expected volatility 50.38% 62.65% 73.1% --
Expected dividend yield -- -- -- --
To estimate expected lives of options for this valuation, it was assumed
options will be exercised at the end of their expected lives. All options are
initially assumed to vest. Cumulative compensation cost recognized in pro forma
net income or loss with respect to options that are forfeited prior to vesting
is adjusted as a reduction of pro forma compensation expense in the period of
forfeiture. Pro forma stock-based compensation, net of the effect of
forfeitures, was $1,410,850 for the seven months ended December 31, 2002 and
$3,079,700, $2,746,600 and $0 for the fiscal years ended May 31, 2002, 2001 and
2000, respectively.
If the Company had accounted for its stock-based compensation plans in
accordance with SFAS 123, the Company's net loss and pro forma net loss per
common share would have been reported as follows:
Seven Months Ended
December 31, Year Ended May 31,
------------- -------------------------------------------------
2002 2002 2001 2000
------------- ------------- ------------- ---------------
Net loss to common shareholders
As reported $ (3,840,100) $ (6,267,600) $ 1,771,200 $ (10,662,600)
Pro forma $ (5,250,950) $ (9,347,300) $ (975,400) $ (10,662,600)
Net loss per common share
As reported, Basic $ (.36) $ (.67) $ .23 $ (1.39)
As reported, Diluted $ (.36) $ (.67) $ .21 $ (1.39)
Pro forma, Basic $ (.49) $ (1.01) $ (.12) $ (1.39)
Pro forma, Diluted $ (.49) $ (1.01) $ (.12) $ (1.39)
Weighted average shares used to calculate pro forma net loss per share were
determined as described in Note B, except in applying the treasury stock method
to outstanding options, net proceeds assumed received upon exercise were
increased by the amount of compensation cost attributable to future service
periods and not yet recognized as pro forma expense.
INCOME TAXES
The Company accounts for income taxes under the provisions of Statement of
Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income
Taxes". This statement requires recognition of deferred income tax assets and
liabilities for the expected future income tax consequences, based on enacted
tax laws, of temporary differences between the financial reporting and tax bases
of assets, liabilities and carryforwards.
64
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
SFAS 109 requires recognition of deferred tax assets for the expected
future effects of all deductible temporary differences, loss carryforwards and
tax credit carryforwards. Deferred tax assets are reduced, if deemed necessary,
by a valuation allowance for any tax benefits which, based on current
circumstances, are not expected to be realized.
NET (LOSS) INCOME PER SHARE
The Company reports net (loss) income per share pursuant to Statement of
Financial Accounting Standards No. 128 ("SFAS 128"). SFAS 128 specifies the
computation, presentation and disclosure requirements for earnings per share.
Basic earnings per share is computed based on the weighted average number of
common shares outstanding. Diluted earnings per share is computed based on the
weighted average number of common shares outstanding adjusted for the
incremental shares attributed to outstanding options to purchase common stock,
if dilutive. Potential common shares relating to options and warrants are
excluded from the computation of diluted earnings (loss) per share, because they
were antidilutive, totaled 4,910,900, 3,999,468, 3,316,011 and 1,797,655 at
December 31, 2002, May 31, 2002, 2001 and 2000, respectively.
COMPREHENSIVE INCOME
There are no components of comprehensive income which have been excluded
from net income and, therefore, no separate statement of comprehensive income
has been presented.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
RECLASSIFICATIONS
Certain reclassifications have been made in the prior years financial
statements in order to conform with the presentation for the current year.
RECENT ACCOUNTING PRONOUNCEMENTS
- --------------------------------
SFAS NO. 143 - In July 2001, the Financial Accounting Standards Board
issued SFAS No. 143 "Accounting for Asset Retirement Obligations." The statement
requires entities to record the fair value of a liability for legal obligations
associated with the retirement of obligations of tangible long-lived assets in
the period in which it is incurred. When the liability is initially recorded,
the entity increases the carrying amount of the related long-lived asset.
Accretion of the liability is recognized each period, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The standard is effective for
65
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
fiscal years beginning after June 15, 2002, with earlier application encouraged.
The Company is evaluating the impact of SFAS No. 143 and has implemented the
pronouncement effective January 1, 2003.
SFAS NO. 148 - In December 2002, the Company adopted the supplemental
disclosure requirements of SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure", which amended SFAS No. 123,
"Accounting for Stock-Based Compensation." The Company continues to record
compensation related to employee stock options based on the intrinsic value
method per APB Opinion No. 25, "Accounting for Stock Issued to Employees." SFAS
No. 148 encourages companies to voluntarily elect to record the compensation
based on market value either prospectively, as defined in SFAS No. 123, or
retroactively or in a modified prospective method. Among other things, the
Company is concerned about the reasonableness of the values of its stock options
determined using the Black Scholes method. Therefore, the Company has delayed
the potential transition to recording stock compensation based on fair market
value until there is more clarity regarding the measurement of stock option
values.
FIN 45 - In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, including
indirect Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 expands the
information disclosures required by guarantors for obligations under certain
types of guarantees. It also requires initial recognition at fair value of a
liability for such guarantees. The initial recognition and initial measurement
provisions of this Interpretation are applicable on a prospective basis to
guarantees issued or modified after December 31, 2002, irrespective of the
guarantor's fiscal year-end. The disclosure requirements in the Interpretation
are effective for financial statements of interim or annual periods ending after
December 15, 2002. The Company believes that the adoption of this statements
will not have a material impact on its financial condition or results of
operation.
FIN 46 - In January 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities" ("FIN 46"), which addresses
consolidation by business enterprises where equity investors do not bear the
residual economic risks and rewards. These entities have been commonly referred
to as "special-purpose entities". Companies are required to apply the provision
of FIN 46 prospectively for all variable interest entities created after January
31, 2003. For public companies, all interest acquired before February 1, 2003
must follow the new rules in account periods beginning after June 15, 2003. The
Company has not yet evaluated the impact FIN 46 is expected to have on the
Company's financial condition or results of operations.
The Company has reviewed other current outstanding statements from the
Financial Accounting Standards Board and does not believe that any of those
statements will have a material adverse affect on the financial statements of
the Company when adopted.
C. RELATED-PARTY TRANSACTIONS:
The Company provides management and administrative services for affiliates
under the terms of various management agreements. Revenues from services
provided by the Company to unconsolidated affiliates were $55,900 during the
seven months ended December 31, 2002, and $78,800, $132,500, and
66
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
$39,900 in fiscal 2002, 2001, and 2000, respectively. The Company has $117,600
of receivables from unconsolidated subsidiaries as of December 31, 2002.
As of December 31, 2002, the Company had notes receivable due from certain
directors and employees of the Company totaling $48,800 due December 31, 2003.
This indebtedness is secured by 144,000 shares of the Company's common stock.
During the seven months ended December 31, 2002, this debt was reduced by
$16,200.
D. USECC JOINT VENTURE:
The Company operates the Glen L. Larsen office complex; holds interests in
various mineral operations; conducts oil and gas operations; and transacts all
operating and payroll expenses through a joint venture with Crested, the USECC
joint venture.
E. INVESTMENTS IN AND ADVANCES TO AFFILIATES:
The Company's restricted investments secure various decommissioning,
reclamation and holding costs. Investments are comprised of debt securities
issued by the U.S. Treasury that mature at varying times from three months to
one year from the original purchase date. As of December 31, 2002, May 31, 2002
and May 31, 2001, the cost of debt securities was a reasonable approximation of
fair market value. These investments are classified as held-to-maturity under
SFAS 115 and are measured at amortized cost.
F. MINERAL CLAIMS TRANSACTIONS:
GMMV
- ----
During fiscal 1990, the Company entered into an agreement with Kennecott, a
wholly-owned, indirect subsidiary of The RTZ Corporation plc, for Kennecott to
acquire a 50% interest in certain uranium mineral properties in Wyoming known as
the Green Mountain Properties. During the life of the venture, the parties
entered into various amendments to the GMMV agreement.
As a result of sustained depressed uranium prices, the GMMV properties were
maintained on a shut down basis. During fiscal 2000, certain disputes arose in
the GMMV venture and Kennecott sued the Company. On September 11, 2000, the
parties settled all disputes by Kennecott paying the Company $3.25 million and
Kennecott assuming all reclamation liabilities of the GMMV Properties.
67
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
SMP
- ---
During fiscal 1989, the Company, through USECC, entered into an agreement
to sell a 50% interest in their Sheep Mountain properties to Nukem's subsidiary
CRIC. USECC and CRIC immediately contributed their 50% interests in the
properties to a newly-formed partnership, Sheep Mountain Partners ("SMP"). SMP
was established to further explore uranium mineralization on the claims on Sheep
Mountain, acquire uranium supply contracts and market uranium. Certain disputes
arose among USECC, CRIC and its parent Nukem, Inc. over the operation of SMP.
These disputes have been in litigation/arbitration for the past ten years. See
Note K for a description of the investment and a discussion of the related
litigation/arbitration.
Due to the litigation and arbitration proceedings involving SMP for the
past 12 years, the Company has expensed all of its costs related to SMP and has
no carrying value of its investment in SMP as proceeds from litigation and
arbitration proceedings were accounted for under the cost recovery method of
accounting as discussed in Note K. The Company's direct loss generated from its
investment in SMP, which represents mine holding costs incurred directly by the
Company, was $83,000, $508,600, $399,300, and $711,300 for the seven months
ended December 31, 2002 and years ended May 31, 2002, 2001 and 2000,
respectively.
As part of a partial settlement agreement dated June 1, 1998, the Company
was awarded the return of its Sheep Mountain uranium mines and certain other
properties. Accordingly, all mine holding costs since that date have been
expensed by the Company.
PHELPS DODGE
- ------------
During prior years, the Company conveyed interests in mining claims to AMAX
Inc. ("AMAX") in exchange for cash, royalties, and other consideration. There
are no remaining values on the balance sheets of the Company relating to these
claims. AMAX merged with Cyprus Minerals Company forming Cyprus Amax Minerals
Company ("Cyprus Amax") which was purchased by Phelps Dodge Corporation ("Phelps
Dodge") in December of 1999. The properties have not been placed into production
as of December 31, 2002.
AMAX and later Cyprus Amax, paid the Company an annual advance in royalty
of 50,000 pounds of molybdenum (or its cash equivalent). During fiscal 2000,
Phelps Dodge assumed this obligation and made payments to the Company during
fiscal 2001. Phelps Dodge is entitled to a partial credit against future
royalties for any advance royalty payments made, but such royalties are not
refundable if the properties are not placed into production. The Company
recognized $108,500, and $132,600 of revenue from the advance royalty payments
during the years ended May 31, 2001, and 2000, respectively. Phelps Dodge did
not make the payment of the advance royalty since the year ended May 31, 2001.
The Company considers this a breach of Phelps Dodge's contractual obligations
and has filed a counter claim against Phelps Dodge in this issue. See Note K for
further discussion.
Should Phelps Dodge be successful in returning the properties to the
Company, it may cancel future obligations under the advance royalty obligation.
If Phelps Dodge formally decides to place the properties into production, it is
obligated to pay $2,000,000 to the Company. Also, per the contract with AMAX,
the
68
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Company is to receive 15% of the first $25,000,000, or $3,750,000, if the
molybdenum properties are sold, which the Company believes has occurred when
Phelps Dodge Purchased Cyprus Amax. See Note K.
SUTTER GOLD MINE COMPANY ("SGMC")
- ---------------------------------
SGMC was established in 1990 to conduct operations on mining leases and to
produce gold from the Lincoln properties in California. SGMC has not generated
any significant revenue and has no assurance of future revenue. All acquisition
and mine exploration costs since inception were initially capitalized. Due to
the decline in the spot price for gold and the lack of adequate financing, SGMC
has the mine on a shut down status and written down the associated properties.
Primarily as a result of the sustained decline in gold prices and the
uncertainty of when prices might recover, the Company evaluated the carrying
value of its SGMC properties for impairment, and in fiscal 1999 and 1998, the
Company recorded an impairment in the amount of $10,718,300 and $1,500,000
respectively.
This impairment, which was taken as required under the provisions of SFAS #
121, resulted in a write- off of nearly 85% of the cost of these properties to
values that were estimated to be fair market values at that time based on the
salvage values of equipment and the local tax assessor's assessed values of the
land, buildings and improvements.
Since the date of the last impairment in 1999, the Company has annually
determined whether or not events or changes in circumstances had occurred
suggesting that additional impairment of the assets of Sutter under SFAS # 121
was necessary. The Company has not deemed it necessary to further impair the
assets based on the assessed valuations of the property.
The Company will continue to evaluate the carrying value of its long-lived
assets and long-lived assets to be disposed of under the provisions of SFAS #
144.
PLATEAU RESOURCES LIMITED ("PLATEAU")
- -------------------------------------
During fiscal 1994, the Company entered into an agreement with Consumers
Power Company to acquire all the issued and outstanding common stock of Plateau,
a Utah corporation. Plateau owns a uranium processing mill and support
facilities and certain other real estate assets through its wholly-owned
subsidiary Canyon Homesteads, Inc. in southeastern Utah. The Company paid
nominal cash consideration for the Plateau stock and agreed to assume all
environmental liabilities and reclamation bonding obligations. At December 31,
2002, Plateau had a cash security in the amount of $9.8 million to cover
reclamation of the properties (see Note K).
The Company is currently evaluating the best utilization of Plateau's
properties. Revenues are being generated from the Townsite assets which include
a motel, C-store, lounge, restaurant, boat storage facility and housing. The
convenience store, lounge and restaurant, and boat storage facility are leased
to third party companies. The Company receives rent on these facilities and a
percentage of the revenues of each operation. The Company is also considering
the possibility of selling the mill facility or various parts of the mill.
69
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
ROCKY MOUNTAIN GAS, INC.("RMG")
- -------------------------------
In November 1999, the Company organized RMG to enter into the coalbed
methane gas business. RMG is engaged in the acquisition of coalbed methane gas
leases and the exploration for methane gas on those properties. The Company owns
and controls 91.5% of RMG. RMG sold 333,333, 53,000 and 1,203,333 shares,
respectively, of its common stock in private placements during the fiscal years
ended May 31, 2002, 2001 and 2000, respectively, for total proceeds of
approximately $4,669,000.
On January 3, 2000, RMG entered into an agreement with Quantum Energy,
L.L.C. (Quantum formed a subsidiary "Quaneco" to conduct its business with RMG))
to purchase a 50% working interest and 40% net revenue interest in approximately
185,000 acres of unproven leasehold interests in the Powder River Basin of
southeastern Montana.
RMG and Quaneco then entered into an Option and Farmin Agreement with
Suncor (Natural Gas) America, Inc. ("SENGAI") on 112,000 acres in southeast
Montana. SENGAI paid $1,705,000 for the right to exercise the option, of which
$1,278,800 was due to RMG. These funds were applied to the final payment due
under the Quaneco agreement.
SENGAI also committed to assume $2,000,000 of the remaining $2,250,000
drilling commitment that RMG had under its drilling commitment to Quaneco.
SENGAI made the decision not to exercises its option on the acreage.
RMG also acquired a 100% working interest (82% revenue interest) in 65,247
net mineral acres in southwest Wyoming.
In July, 2001, RMG closed a Purchase and Sale Agreement with CCBM, Inc.
("CCBM"), a wholly- owned subsidiary of Carrizo Oil & Gas, Inc. of Houston,
Texas. CCBM purchased an undivided 50% interest in all of RMG's existing coalbed
properties. CCBM signed a $7,500,000 Promissory Note payable in principal
amounts of $125,000 per month plus interest at annual rate of 8% over 41 months
(starting July 31, 2001) with a balloon payment due on the forty-second month.
The 50% undivided interest is pledged back to RMG to secure the purchase price,
and will be released 25% when 33.3% of the principal amount of the purchase
price is paid, another 25% when the total principal payments reach 66.6% of the
principal amount of the purchase price and the balance when the total principal
amount is paid.
CCBM has also agreed to fund $5,000,000 for an initial drilling program. If
CCBM fails to expend $5,000,000 in the drilling program or $2,500,000 for RMG's
benefit, CCBM will be obligated to pay any remaining unspent portions of the
$2,500,000 directly to RMG. If CCBM defaults on its purchase obligation CCBM
will still earn a 50% working interest in each well location (80 acres) and
production therefrom. CCBM's ownership will be earned on these wells regardless
of the status of the payments on the promissory note.
70
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
CCBM will be entitled to a credit (applied as a prepayment of the purchase
price for the undivided 50% interest in RMG's acreage), equal to 20% of RMG's
net revenue interest from wells drilled with the $5,000,000 until CCBM equals
$1,250,000 from production proceeds.
BOBCAT
- ------
On April 12, 2002, RMG signed an agreement to purchase working interests in
approximately 1,940 gross acres of coalbed methane properties in the Powder
River Basin of Wyoming known as the Bobcat Field. The contract closed on June 4,
2002. The Company paid the seller $500,000 cash and another $150,000 by issuing
37,500 shares of its restricted common stock to the seller; CCBM paid $500,000
cash to the seller and Carrizo Oil & Gas, Inc. issued its restricted shares of
common stock valued at $150,000. The properties are located approximately 25
miles north of Gillette, in Campbell County, Wyoming. To date, 25 coalbed
methane wells have been drilled; 24 wells are currently hooked up and produced
in December 2002 at a combined rate of approximately 1,400,000 cubic feet of gas
per day (1,400 Mcf) from the two primary coals on the property: the Cook coal
(22 wells) at 650 feet, and the Canyon coal (2 wells) at 450 feet.
The seller kept, as an overriding royalty interest, all net revenue
interest in the properties in excess of 80%. RMG and CCBM each hold an average
of 27.6% working interest and an average of 22% net revenue interest, in the
drilled wells.
Permits have been issued for drilling 14 more wells on 80 acre spacing.
OIL AND GAS PROPERTIES AND EQUIPMENT INCLUDED THE FOLLOWING:
- ------------------------------------------------------------
December 31, May 31,
------------ -------------------------------------------
2002 2002 2001 2000
Oil and gas properties:
Subject to amortization $ 2,423,600 $ 1,773,600 $ 1,773,600 $ 1,773,600
Not subject to amortization:
Seven months ended 12-31-02 508,400
Acquired in fiscal 2002 363,900 363,900 -- --
Acquired in fiscal 2001 1,154,500 1,154,500 1,154,500 --
Acquired in fiscal 2000 4,727,200 4,727,200 4,727,200 4,727,200
----------- ----------- ----------- -----------
6,754,000 6,245,600 5,881,700 4,727,200
Sale of gas interests (2,500,000) (1,250,000) -- --
----------- ----------- ----------- -----------
4,254,000 4,995,600 5,881,700 4,727,200
----------- ----------- ----------- -----------
Total oil and gas properties 6,677,600 6,769,200 7,655,300 6,500,800
Accumulated depreciation, depletion
and amortization (1,834,100) (1,773,600) (1,773,600) (1,773,600)
----------- ----------- ----------- -----------
Net oil and gas properties $ 4,843,500 $ 4,995,600 $ 5,881,700 $ 4,727,200
=========== =========== =========== ===========
71
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
The Company began drilling of its coalbed methane properties during 2001
and acquired producing properties in June of 2002.
The following sets forth costs incurred for oil and gas property
acquisition and development activities, whether capitalized or expensed:
December 31, May 31,
------------ --------------------------------------------
2002 2002 2001 2000
------------ ----------- ----------- ------------
Acquisition of properties/facilities $ 936,200 $ 192,600 $ 870,600 $ 4,727,200
Development 97,200 87,400 283,900 --
----------- ----------- ----------- -----------
$ 1,033,400 $ 280,000 $ 1,154,500 $ 4,727,200
=========== =========== =========== ===========
As of December 31, 2002, the Company had approximately 214,800 acres for
the potential development of coalbed methane ("CBM") natural gas production in
Wyoming and Montana with a cost basis of $4,254,000. These properties were
mostly acquired in 2000 and drilling projects on these properties are in the
early stage of evaluation and thus no reserves are recorded at year end
associated with these properties. At December 31, 2002 960 acres are being
dewatered. The purchase, exploration and development costs of these acres will
become part of the amortization base in August or September of 2003.
The results from operations of oil and gas activities for the seven months
ended December 31, 2002, the Company's first period of oil and gas operations,
are as follows:
Sales to third parties $ 119,400
Production costs (355,200)
Depreciation, depletion and amortization (65,200)
----------
$ (301,000)
==========
Depreciation, depletion and amortization was $0.98 per equivalent MCF of
production for the period ended December 31, 2002.
G. DEBT:
LINES OF CREDIT
- ---------------
The Company has a $750,000 line of credit from a commercial bank. The line
of credit has a variable interest rate (5.25% as of December 31, 2002). The
weighted average interest rate for the seven months ended December 31, 2002 was
5.62%. As of December 31, 2002, none of the line of credit had been borrowed.
The line of credit is collateralized by certain real property and a share of the
net proceeds of fees from production from certain oil wells.
72
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
LONG-TERM DEBT
- --------------
The components of long-term debt as of December 31, 2002 and May 31, 2002
are as follows:
December 31, May 31,
------------ --------------------------
2002 2002 2001
------------ ----------- -----------
USECB installment notes - collateralized by
equipment; interest at 5.0 to 11.0%,
matures in 2002 - 2015 $ 1,839,400 $ 1,611,600 $ 1,670,200
SGMC installment notes - secured by certain
properties, interest at 7.5% to 8.0%
maturity from 2002 - 2007 531,100 579,500 624,300
USE convertible notes - net of discount of
$758,700 at December 31, 2002 and
$620,100 at May 31, 2002 collateralized by
equipment and real estate, interest at 8.0%; 741,300 329,900 --
PLATEAU installment note - collateralized by
equipment, interest at 8.0% matures in 2004 26,000 38,000 --
------------ ----------- -----------
3,137,800 2,559,000 2,294,500
Less current portion (317,200) (205,700) (142,400)
------------ ----------- -----------
$ 2,820,600 $ 2,353,300 $ 2,152,100
============ =========== ===========
Principal requirements on long-term debt are $317,200, $726,300; $197,600;
$206,600; $1,219,600 and $260,300 for the years ended December 31, 2003 through
2007, and thereafter, respectively.
H. INCOME TAXES:
The components of deferred taxes as of December 31, 2002, May 31, 2002 and
2001 are as follows:
December 31, May 31,
------------ -----------------------------
2002 2002 2001
------------ ------------ -------------
Deferred tax assets:
Deferred compensation $ 345,500 $ 273,400 $ 279,000
Net operating loss carryforwards 9,560,000 9,028,600 8,180,000
Tax Credits -- -- 15,000
Non-deductible reserves and other 622,800 622,800 840,000
Tax basis in excess of book basis 250,000 250,000 2,850,400
------------ ------------ -------------
Total deferred tax assets 10,778,300 10,174,800 12,164,400
------------ ------------ -------------
Deferred tax liabilities:
Development and exploration costs 2,963,900 2,753,800 2,157,200
------------ ------------ -------------
Total deferred tax liabilities 2,963,900 2,753,800 2,157,200
------------ ------------ -------------
8,084,400 7,421,000 10,007,200
Valuation allowance (9,229,200) (8,565,800) (11,152,000)
------------ ------------ -------------
Net deferred tax liability $ (1,144,800) $ (1,444,800) $ (1,144,800)
============ ============ =============
73
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
A valuation allowance for deferred tax assets is required when it is more
likely than not that some portion or all of the deferred tax assets will not be
realized. The ultimate realization of this deferred tax asset depends on the
Company's ability to generate sufficient taxable income in the future.
Management believes it is more likely than not that the net deferred tax asset
will not be realized by future operating results.
The Company has established a valuation allowance of $9,229,200,
$8,565,800, and $11,152,000 at December 31, 2002, May 31, 2002, and May 31,
2001, against deferred tax assets due to the losses incurred by the Company in
past fiscal years. The Company's ability to generate future taxable income to
utilize the NOL carryforwards is uncertain.
The income tax provision (benefit) is different from the amounts computed
by applying the statutory federal income tax rate to income before taxes. The
reasons for these differences are as follows:
December 31, Year Ended May 31,
------------ ---------------------------------------------
2002 2002 2001 2000
------------ ------------ ------------ -----------
Expected federal income tax $ (1,305,600) $ (2,131,000) $ 602,200 $(3,618,200)
Net operating losses not previously
benefitted and other 1,969,000 4,717,200 2,213,300 (10,600)
Valuation allowance (663,400) (2,586,200) (2,815,500) 3,628,800
------------ ------------ ------------ -----------
Income tax provision $ -- $ -- $ -- $ --
============ ============ ============ ===========
There were no taxes currently payable as of December 31, 2002, May 31,
2002, May 31, 2001 or May 31,2000 related to continuing operations.
At December 31, 2002, the Company and its subsidiaries had available, for
federal income tax purposes, net operating loss carryforwards of approximately
$27,300,000 which will expire from 2006 to 2022. The Internal Revenue Code
contains provisions which limit the NOL carryforwards available which can be
used in a given year when significant changes in Company ownership interests
occur. In addition, the NOL amounts are subject to examination by the tax
authorities.
The Internal Revenue Service has audited the Company's and subsidiaries tax
returns through the year ended May 31, 2000. The Company's income tax
liabilities are settled through fiscal 2000.
I. SEGMENTS AND MAJOR CUSTOMERS:
The Company's primary business activity is coalbed methane gas property
acquisition and exploration and production (and holding shut down mining
properties). The Company has no producing mines. The other reportable industry
segment is commercial activities through motel, real estate and airport
operations. The Company discontinued its drilling/construction segment in the
third quarter of fiscal 2002. The following is information related to these
industry segments:
74
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Seven Months Ended December 31, 2002
---------------------------------------------------------------
Coalbed
Methane Motel/
(and holding Real Estate/
costs for inactive Airport
mining properties) Operations Consolidated
------------------ ---------- ------------
Revenues $ 119,400 $ 749,100 $ 868,500
=============== ==============
Other revenues 159,100
-------------
Total revenues $ 1,027,600
=============
Operating (loss) income $ (973,000) $ 221,900 $ (751,100)
Other revenue 159,100
General corporate and other expenses (2,915,800)
Other income and expenses (387,100)
Discontinued operations, net of tax --
Equity in loss of affiliates and
minority interest in subsidiaries 54,800
-------------
Loss before income taxes $ (3,840,100)
=============
Identifiable net assets at
December 31, 2002 $ 16,022,800 $ 4,564,700 $ 20,587,500
=============== ==============
Investments in affiliates --
Corporate assets 7,603,100
-------------
Total assets at December 31, 2002 $ 28,190,600
=============
Capital expenditures $ 1,033,400 $ 37,800
=============== ==============
Depreciation, depletion and
amortization $ 94,800 $ 78,200
=============== ==============
75
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Year Ended May 31, 2002
----------------------------------------------------------------
Coalbed
Methane Motel/
(and holding Real Estate/
costs for inactive Airport
mining properties) Operations Consolidated
------------------ ---------- ------------
Revenues $ -- $ 1,795,900 $ 1,795,900
=============== =============
Other revenues 208,200
-------------
Total revenues $ 2,004,100
=============
Operating loss $ (1,707,800) $ (133,000) $ (1,840,800)
=============== =============
Other revenue 208,200
General corporate and other expenses (5,821,600)
Other income and expenses 1,319,500
Discontinued operations, net of tax (85,900)
Equity in loss of affiliates and
minority interest in subsidiaries 39,500
-------------
Loss before income taxes $ (6,181,100)
=============
Identifiable net assets at
May 31, 2002 $ 18,138,500 $ 4,351,600 $ 22,490,100
=============== =============
Investments in affiliates - -
Corporate assets 8,047,800
Total assets at May 31, 2002 $ 30,537,900
=== ==== =============
Capital expenditures $ 151,300 $ 101,500
=============== =============
Depreciation, depletion and
amortization $ 167,600 $ 254,300
=============== =============
76
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Year Ended May 31, 2001
----------------------------------------------------------------------
Coalbed
Methane Motel Contract
(and holding Real Estate/ Drilling/
costs for inactive Airport Construction
mining properties) Operations Operations Consolidated
------------------ ---------- ---------- ------------
Revenues $ 442,800 $ 2,222,400 $ 2,238,600 $ 4,903,800
=============== ============= =============
Other revenues 597,800
-------------
Total revenues $ 5,501,600
=============
Operating (loss) profit $ (2,866,400) $ (1,013,800) $ 488,100 $ (3,392,100)
=============== ============= =============
Other revenue, income and expenses 9,328,600
General corporate and other expenses (4,235,400)
Equity in loss of affiliates and
minority interest in subsidiaries 220,100
-------------
Income before income taxes $ 1,921,200
=============
Identifiable net assets at May 31, 2001 $ 18,424,900 $ 5,616,400 $ 1,050,500 $ 25,091,800
=============== ============= =============
Investments in affiliates 16,200
Corporate assets 5,357,200
-------------
Total assets at May 31, 2001 $ 30,465,200
=== ==== =============
Capital expenditures $ 1,280,200 $ 1,326,800 $ 256,000
=============== ============= =============
Depreciation, depletion and
amortization $ 129,700 $ 271,100 $ 324,700
=============== ============= =============
77
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Year Ended May 31, 2000
----------------------------------------------------------------------
Coalbed
Methane Motel Contract
(and holding Real Estate/ Drilling/
costs for inactive Airport Construction
mining properties) Operations Operations Consolidated
------------------ ---------- ---------- ------------
Revenues $ 132,600 $ 2,734,800 $ 3,584,900 $ 6,452,300
=============== ============= =============
Other revenues 436,500
--------------
Total revenues $ 6,888,800
==============
Operating (loss) profit $ (2,518,600) $ (652,500) $ (594,300) $ (3,765,400)
=============== ============= =============
Other revenue, income and expenses 530,100
General corporate and other expenses (7,912,900)
Equity in loss of affiliates and
minority interest in subsidiaries 506,400
--------------
Loss before income taxes $ (10,641,800)
==============
Identifiable net assets at May 31, 2000 $ 17,543,700 $ 4,880,900 $ 2,163,300 $ 24,587,900
=============== ============= =============
Investments in affiliates 9,600
Corporate assets 6,278,600
--------------
Total assets at May 31, 2000 $ 30,876,100
==============
Capital expenditures $ 4,749,300 $ 944,600 $ 1,551,800
=============== ============= =============
Depreciation, depletion and
amortization $ 72,600 $ 148,100 $ 155,400
=============== ============= =============
78
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
J. SHAREHOLDERS' EQUITY:
STOCK OPTION PLANS
The Board of Directors adopted the U.S. Energy Corp. 1989 Stock Option Plan
for the benefit of USE's key employees. The Option Plan, as amended and renamed
the 1998 Incentive Stock Option Plan ("1998 ISOP"), reserved 2,750,000 shares of
the Company's $.01 par value common stock for issuance under the 1998 ISOP.
Options which expired without exercise were available for reissue. During fiscal
1992, the Company issued 371,200 non-qualified options to certain of its
executive officers, Board members and others at prices ranging from $2.75 to
$2.90 per share. Unexercised options expired on April 14, 2002 and April 30,
2002. During fiscal 1996, the Company issued options to purchase 360,000 common
shares at $4.00 per share. Unexercised options expired on December 31, 2000.
During fiscal 1999, the Company issued 837,500 options under the 1998 ISOP,
including 299,462 non-qualified and 538,038 qualified options. The non-
qualified options were issued at a price below fair market value, resulting in
the recognition of $262,000 in compensation expense at the time of issuance.
During fiscal 2001, the Company issued 1,499,000 options under the 1998 ISOP,
including 918,763 non-qualified and 580,237 qualified options. Various employees
exercised 118,703 of the outstanding options raising $288,400 of capital. During
the year ended May 31, 2002, various employees exercised 253,337 of the
outstanding options raising $602,500 of capital. During the period ended
December 31, 2002 various employees exercised 26,711 of the outstanding options.
In December 2001, the Board of Directors adopted (and the shareholders
approved) the U.S. Energy Corp. 2001 Incentive Stock Option Plan (the "2001
ISOP") for the benefit of USE's key employees. The 2001 ISOP reserves 3,000,000
shares of the Company's $.01 par value common stock for issuance for a period of
10 years. During fiscal 2002, the Company granted 1,030,000 options to certain
of its employees, executive officers, and board members at $3.90 per share.
These options will expire in December, 2011. During the seven months ended
December 31, 2002, the Company granted 973,000 options to various employees and
board members at $2.25 per share. These options will expire in December 2011.
The 2001 ISOP replaces the 1998 ISOP, however, options granted under the
1998 ISOP remain exercisable until their expiration date under the terms of that
Plan.
79
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
A summary of the Employee Stock Option Plan activity for the seven months
ended December 31, 2002 and the years ended May 31, 2002 and 2001 is as follows:
Seven Months
Ended December 31, Year Ended May 31,
-------------------- -----------------------------------------------------------
2002 2002 2001 2000
-------------------- ------------------ -------------------- -----------------
Weighted Weighted Weighted Weighted
Average Average Average Average
Exercise Exercise Exercise Exercise
Options Price Options Price Options Price Options Price
------- ----- ------- ----- ------- ----- ------- -----
Outstanding at beginning
of the period 2,896,830 $2.96 2,449,000 $2.49 1,300,200 $2.79 1,300,200 $2.79
Granted 973,000 2.25 1,030,000 3.90 1,499,000 2.69 -- --
Forfeited (107,718) 2.33 (75,000) 2.49 (82,500) 2.88 -- --
Expired -- -- (253,833) 2.89 (149,000) -- -- --
Exercised (71,167) 2.40 (253,337) 2.48 (118,700) -- -- --
--------- --------- --------- ---------
Outstanding at period end 3,690,945 2.77 2,896,830 2.96 2,449,000 2.49 1,300,200 $2.79
========= ========= ========= =========
Exercisable at period end 3,690,945 2.77 2,896,830 2.96 2,449,000 2.49 1,300,200 $2.79
========= ========= ========= =========
Weighted average fair
value of options
granted during the period $2.25 $1.83 -- --
The following table summarized information about employee stock options
outstanding and exercisable at December 31, 2002:
Weighted
Weighted Number of Average Number
Average Options Remaining of Options
Exercise Outstanding at Contractual Exercisable at
Price December 31, 2002 Life in years December 31, 2002
----- ----------------- ------------- -----------------
$2.00 276,090 5.73 276,090
2.25 968,000 8.95 968,000
2.40 1,130,381 8.02 1,130,381
2.88 336,474 5.73 336,474
3.90 980,000 8.95 980,000
--------- ---------
3,690,495 3,690,495
========= =========
80
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
EMPLOYEE STOCK OWNERSHIP PLAN
The Board of Directors of USE adopted the U.S. Energy Corp. 1989 Employee
Stock Ownership Plan ("ESOP") in 1989, for the benefit of USE employees. During
the seven months ending December 31, 2002 the Board of Directors of USE
contributed 43,867 shares to the ESOP at the price of $3.08 for a total expense
of $135,100. This compares to contributions to the ESOP during the fiscal years
ended May 31, 2002, 2001 and 2000 of 70,075, 53,837, and 123,802 shares to the
ESOP at prices of $3.29, $5.35, and $3.00 per share, respectively. The Company
has expensed $135,100, $236,900, $288,000, and $371,400 during the seven months
ended December 31, 2002 and the fiscal years ended May 31, 2002, 2001, and 2000,
respectively related to these contributions. USE has loaned the ESOP $1,014,300
to purchase 125,000 shares from the Company and 38,550 shares on the open
market. These loans, which are secured by pledges of the stock purchased, bear
interest at the rate of 10% per annum. The loans are reflected as unallocated
ESOP contribution in the equity section of the accompanying Consolidated Balance
Sheets.
EXECUTIVE OFFICER COMPENSATION
In May 1996, the Board of Directors of USE approved an annual incentive
compensation arrangement ("1996 Stock Award Program") for its CEO and four other
officers of the Company payable in shares of the Company's common stock. The
1996 Stock Award Program was subsequently modified to reflect the intent of the
directors which was to provide incentive to the officers of the Company to
remain with USE. The shares are to be issued annually pursuant to the
recommendation of the Compensation Committee on or before January 15 of each
year, beginning January 15, 1997, as long as each officer is employed by the
Company. The officers will receive up to an aggregate total of 67,000 shares per
year for the years 1997 through 2002. The shares under the plan are forfeitable
until retirement, death or disability of the officer. The shares are held in
trust by the Company's treasurer and are voted by the Company's non-employee
directors. As of December 31, 2002, 349,158 total shares have been issued to the
five officers of the Company under the 1996 Stock Award Plan.
In December 2001, the Board of Directors adopted (and the shareholders
approved) the 2001 Stock Award Plan to compensate five of its executive officers
and the president of RMG. Under the Plan, an aggregate of 60,000 shares may be
issued each year from 2002 through 2006. No shares were issued under this Plan
during the seven month ended December 31, 2002 and the fiscal year ended May 31,
2002.
OPTIONS AND WARRANTS TO OTHERS
As of the date of this report, there are 719,167 options and warrants
outstanding to purchase shares of the Company's common stock. These options and
warrants are held by persons or entities other than employees, officers and
directors of the Company.
In February of 1999, the Company entered into a warrant purchase agreement
with a consulting firm to purchase 20,000 shares of the Company's common stock
at an exercise price of $2.62 expiring January 31, 2002 (extended to March 15,
2003). The warrants were issued in exchange for services to be provided during
the period from February 1999 to February 2000. The Company determined the fair
value associated with
81
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
these warrants to be $36,000, which is recognized ratably over the term of the
consulting agreement. Accordingly, $9,000 was recognized as an expense in fiscal
1999 and $27,000 in fiscal 2000.
Also, during fiscal 1999, the Company issued warrants in exchange for
outstanding YSFC warrants, which were originally issued for services provided by
outside consultants in connection with the agreement discussed above. The
Company issued 74,564 warrants at an exercise price of $3.64 expiring September
19, 2002. The Company determined the fair value associated with these warrants
to be $167,000, which was recorded as an additional investment in YSFC during
fiscal 1999. During fiscal 2002, a warrant for 6,703 shares was canceled and
20,000 shares were issued to its holder in exchange for services provided during
fiscal 2002.
In February 1999, the Company entered into a consulting agreement with an
individual to provide consulting and other services for a period of 24 months,
commencing on February 8, 1999 and ending on January 31, 2001. As consideration
for services to be performed, the Company granted the individual 25,000 shares
of the Company's common stock at a grant price of $2.75 per share and entered
into a 5 year warrant purchase agreement to purchase up to 75,000 shares of the
Company's common stock at an exercise price of $2.25 per share, expiring
February 8, 2004. The Company determined the fair value associated with the
stock grant to be $68,750 and the warrants to be $140,000, which were recognized
ratably over the term of the consulting agreement. Accordingly, $69,550;
$104,400; and $34,800 were recognized as an expense in fiscal 2001, 2000 and
1999, respectively related to this agreement.
During fiscal 2001, the Company entered into a consulting agreement with a
company to provide consulting services for a period of two years, commencing on
April 11, 2001. In addition to a monthly cash payment of $2,000, the Company
issued the consultant an option to purchase up to 20,000 shares of the Company's
common stock at $3.98 per share. The option expires on April 10, 2006. The fair
value of the grant was $65,180.
Also during fiscal 2001, the Company entered into a consulting agreement
with a company to provide consulting and other services for a period of 18
months, commencing on May 14, 2001 and ending on November 14, 2002. As
consideration for services to be performed, the Company issued the consultant
15,000 shares of the Company's common stock at a grant price of $4.70 per share
and entered into two stock option agreements to purchase up to 30,000 shares of
the Company's common stock at an exercise price of $4.70, expiring May 14, 2003.
The first option for 10,000 shares, is exercisable upon the condition that the
Company's common stock market price closes at or above $6.50 per share for
ninety (90) consecutive days prior to the expiration date of May 14, 2003. The
exercise price of this option equaled or exceeded market price of the stock at
the date of grant. The second option for 20,000 shares is exercisable if and
when the Company's common stock market price closes at or above $10.00 per share
for ninety (90) consecutive days prior to its expiration date on May 14, 2003.
During fiscal 2002, the Company raised $2,350,500 by issuing 871,592 shares
of common stock with 250,272 detached warrants in two separate private
placements.
82
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
In May 2002, the Company issued warrants to purchase 120,000 shares of the
Company's common stock at $3.00 per share, and warrants to purchase 120,000
shares of the Company's subsidiary, RMG at $1.50 per share in connection with a
$1 million convertible debt issue. The warrants expire on May 30, 2005. The fair
value of the warrants was $271,700 which has been recorded as a discount on the
debt which will be amortized over the term of the convertible debt.
Additionally, a discount of $398,400 has been recorded against the convertible
debt resulting from allocation of proceeds to the beneficial conversion feature
of the debt instrument. The Company issued warrants to purchase 30,000 shares at
$3.00 held by 31 persons who own equity interests in the firm which served as a
financial advisor in connection with this financing. The warrants were issued as
of May 3, 2002, expiring March 30, 2005. The fair value of these warrants was
$54,600. The fair value of the warrants was estimated on the date of the grant
using the Black-Scholes Options Pricing Model with the following weighted
average assumptions: No expected dividends; expected volatility 51.3%; risk
factor interest rate of 5%, and expected life of three years. Accordingly,
$195,400 was recognized as an expense during the seven months ended December 31,
2002.
In November 2002, the Company issued warrants to purchase 60,000 shares of
the Company's common stock at $3.00 per share and warrants to purchase 60,000
shares of the Company's subsidiary, RMG, at $2.00 per share in connection with a
$500,000 secured convertible note. The warrants expire on November 19, 2005. The
fair value of the warrants was $59,400 which was recorded as a discount on the
debt. A discount of $240,400 was also recorded against the debt as a result of
the beneficial conversion feature of the debt. These two discounts are being
amortized over the life of the debt instrument. The Company issued warrants to
purchase 15,000 shares of the Company's common stock at $3.00 held by 34 persons
who own equity interests in the firm which served as a financial advisor in
connection with this financing. The Warrants were issued as of November 19, 2002
and expire on November 19, 2005. The fair value of theses warrants was $16,900.
The fair value of the warrants was established using the Black-Scholes Option
Pricing Model using a volatility rate of 1.54%; an annual interest rate of 2%;
and a expected life of 550 days. Accordingly, $15,800 was recognized as an
expense during the seven months ended December 31, 2002.
The Company issued warrants to purchase 11,034 shares of its common stock a
$3.75 held by individuals who own a company which acts as financial advisor to
the Company. The warrants were issued as of November 2, 2001 and expire November
2, 2006. The fair value of the grant was $35,600. The fair value of the warrants
was established using the Black-Scholes Option Pricing Model using a volatility
rate of 1.54%; an annual interest rate of 2%; and a expected life of 5 years.
Options to purchase 20,000 shares at $3.90 were granted to a consulting oil
and gas engineer on January 10, 2002 and will expire on January 9, 2005. The
fair value of the grant was $71,400. The fair value of the grant was $35,600.
The fair value of the warrants was established using the Black-Scholes Option
Pricing Model using a volatility rate of 1.54%; an annual interest rate of 2%;
and a expected life of 4 years.
FORFEITABLE SHARES
Certain of the shares issued to officers, directors, employees and third
parties are forfeitable if certain conditions are not met. Therefore, these
shares have been reflected outside of the Shareholders' Equity section in the
accompanying Consolidated Balance Sheets until earned. During fiscal 1993, the
Company's Board
83
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
of Directors amended the stock bonus plan. As a result, the earn-out dates of
certain individuals were extended until retirement. The Company recorded
$178,300 of compensation expense for the seven months ended December 31, 2002
compared to $298,300; $201,000; and $173,300 for the years ended May 31, 2002,
2001 and 2000, respectively. A schedule of total forfeitable shares for the
Company is set forth in the following table:
Issue Number Issue Total
Date of Shares Price Compensation
-------------- --------- ----- ------------
May 1990 40,300 $ 9.75 $ 392,900
June 1990 66,300 11.00 729,300
November 1992 10,660 N/A N/A
May 1993 20,000 3.375 67,500
November 1993 18,520 3.00 55,600
January 1994 18,520 4.00 74,100
January 1995 13,520 3.75 50,700
February 1996 7,700 15.125 116,500
December 1996 28,380 10.875 308,600
December 1996 8,452 11.50 97,200
August 1997 7,320 10.875 79,600
August 1997 5,706 10.875 62,100
May 1998 67,000 6.56 439,500
------- ---------
Balance at
May 31, 1998 312,378 2,473,600
May 1999 67,000 $ 4.00 268,000
Shares earned (40,170) -- (269,900)
------- ---------
Balance at
May 31, 1999 339,208 2,471,700
May 2000 67,000 $ 3.00 201,000
Shares earned (9,600) -- (88,100)
------- ---------
Balance at
May 31, 2000 396,608 2,584,600
May 2001 67,000 $ 5.35 358,400
Shares earned (29,820) -- (194,400)
------- ---------
Balance at
May 31, 2001 433,788 2,748,600
May 2002 67,000 $ 3.90 261,300
------- ---------
Balance at
May 31, 2002 and
December 31, 2002 500,788 $ 3,009,900
======= ===========
84
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
K. COMMITMENTS, CONTINGENCIES AND OTHER:
LEGAL PROCEEDINGS
Material pending proceedings are summarized below. Certain of the Company's
affiliates are involved in ordinary routine litigation incidental to their
business. Other proceedings which were pending during the seven months ended
December 31, 2002 have been settled or otherwise finally resolved.
SHEEP MOUNTAIN PARTNERS ARBITRATION/LITIGATION
In 1991, disputes arose between the Company, Crested, Nukem, Inc. and its
subsidiary Cycle Resource Investment Corp. ("CRIC"), concerning the formation
and operation of the Sheep Mountain Partners partnership. Arbitration
proceedings were initiated by CRIC in June 1991 and in July 1991, USECC filed a
lawsuit against Nukem, CRIC and others in the U.S. District Court (District of
Colorado) in Civil No. 91B1153. Later, USECC filed another suit for the standby
costs at the SMP mines against SMP in the Colorado State Court. The Federal
Court stayed both the arbitration proceedings and the State Court case. In
February 1994, all of the parties agreed to consensual and binding arbitration
of the disputes before the American Arbitration Association ("AAA"), for which
the legal claims made by both sides included fraud and misrepresentation, breach
of contract, breach of duties owed to the SMP partnership, and other claims.
The AAA panel (the "Panel") entered an Order and Award (the "Order") in
April 1996 and clarified the Order on July 3, 1996, finding generally in favor
of USE and Crested on certain of their claims (including the claims for
reimbursement for standby maintenance expenses and profits denied SMP in Nukem's
trading of uranium), and in favor of Nukem/CRIC and against USE and Crested on
certain other claims, and imposing a constructive trust in favor of Sheep
Mountain Partners on uranium contracts Nukem entered into to purchase uranium
from CIS republics. USECC filed a petition for confirmation of the Order and on
June 30, 1997, and the U.S. District Court confirmed the Order in its Second
Amended Judgment (the "Judgment"). Thereafter, Nukem/CRIC appealed the Judgment
to the 10th Circuit Court of Appeals ("CCA").
A three judge panel of the 10th CCA issued an Order and Judgment on October
22, 1998, which unanimously affirmed the Federal District Court's Second Amended
Judgment without modification. The ruling affirmed (i) the imposition of a
constructive trust in favor of SMP on Nukem's rights to purchase CIS uranium,
the uranium acquired pursuant to those rights, and the profits therefrom; and
(ii) the damage award against Nukem/CRIC. As a result of the ruling of the 10th
CCA, USE and Crested received an additional $6,077,264 (including interest and
court costs) from Nukem in February 1999 for a total net monetary award of
$15,468,625 in the arbitration/litigation, and equitable relief in the form of
USE's and Crested's interest in SMP, which holds the constructive trust over the
CIS contracts. Nukem/CRIC filed two motions for entry of final satisfaction of
Judgment. The U.S. District Court denied both motions, Nukem again appealed to
the 10th CCA, which again affirmed the District Court's ruling, and held that
Nukem/CRIC had not demonstrated that the Judgment had been satisfied because
they had not provided USECC with an accounting of the partnerships assets.
85
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
In February 2001, the U.S. District Court appointed a Special Master to
determine the amounts, if any, owed by Nukem to SMP pursuant to the constructive
trust. The Special Master has ordered an accounting to identify all deliveries
of CIS uranium made directly or indirectly to Nukem and any Nukem affiliates; to
identify the ultimate disposition of all uranium purchased under the CIS
contracts; to identify the location, number of pounds, and associated cost of
uranium purchased under the CIS contracts at December 31, 2001, and to calculate
the profits realized from the sale of CIS uranium. At a status hearing held
before the U.S. District Court on August 23, 2002, the Court ordered the Special
Master to file his report on or before December 6, 2002 and a further hearing to
schedule arguments will be held before the Court on December 13, 2002. Because
Nukem and its affiliates failed to furnish certain documentation and
information, the Special Master filed a motion for extension of time to file his
report. The Court granted the motion and ordered the Special Master to file the
report by March 3, 2003. On February 9, 2003, the U.S. District Court granted a
second motion of the Special Master for extension of time and ordered the report
to be filed by April 4, 2003 with a hearing on the report to be held on April
11, 2003.
CONTOUR DEVELOPMENT LITIGATION
On July 28, 1998, USE filed a lawsuit in the United States District Court,
Denver, Colorado, Case No. 98WM1630, against Contour Development Company, L.L.C.
and entities and persons associated with Contour Development Company, L.L.C.
(together, "Contour") seeking compensatory and consequential damages of more
than $1.3 million from the defendants for dealings in real estate owned by USE
and Crested in Gunnison, Colorado. The Contour defendants asserted a
counterclaim asking for payment of attorneys fee and costs. The parties entered
into an agreement to settle the litigation, with USE receiving $25,000 cash and
unencumbered title to two commercial real estate lots covering seven acres in
Gunnison, Colorado, and unencumbered title to five development lots covering 175
acres north of Gunnison, Colorado. There was a claimed misunderstanding on
certain of the terms of the settlement and it has been referred to the Court to
resolve the differences.
See "Business - Commercial Operations - Real Estate and Other Commercial
Operations - Colorado Properties" above.
PHELPS DODGE LITIGATION
U.S. Energy Corp. and its majority-owned subsidiary, Crested Corp., d/b/a
USECC, were served with a lawsuit on June 19, 2002, filed in the U.S. District
Court of Colorado (Case No. 02-B-0796(PAC)) by Phelps Dodge Corporation and its
subsidiary, Mt. Emmons Mining Company (MEMCO), over contractual obligations from
USECC's agreement with Phelps Dodge's predecessor companies, concerning a mining
property in Colorado.
The litigation stems from agreements that date back to 1974 when U.S.
Energy and Crested Corp. leased mining claims on Mt. Emmons near Crested Butte,
Colorado to AMAX Inc., Phelps Dodge's predecessor company. The claims cover one
of the world's largest and richest deposits of molybdenum. AMAX reportedly spent
over $200 million on the acquisition, exploration and mine planning activities
on the Mt. Emmons properties. In counter and cross-claims filed in the U.S.
District Court of Colorado, USECC
86
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
contends that Phelps Dodge and its subsidiaries committed several breaches of
contracts related to the agreements, including breach of fiduciary obligations
and covenants of good faith and fair dealing. USECC also contends Phelps Dodge
is guilty of violating federal and state antitrust laws when it purchased Cyprus
Amax Minerals Company (Cyprus Amax).
The complaint filed by Phelps Dodge and MEMCO seeks a determination that
Phelps Dodge's acquisition of Cyprus Amax was not a sale. Under a 1986 agreement
between USECC and AMAX, if AMAX sold MEMCO or its interest in the mining
properties, U.S. Energy and Crested would receive 15% (7.5% each) of the first
$25 million of the purchase price ($3.75 million). In 1991, Cyprus Minerals
Company acquired AMAX to form Cyprus Amax Minerals Co. USECC's counter and
cross-claims allege that in 1999, Phelps Dodge formed a wholly-owned subsidiary
CAV Corporation, for the purpose of purchasing the controlling interest of
Cyprus Amax and its subsidiaries (including MEMCO) at an estimated value in cash
and Phelps Dodge stock exceeding $1 billion and making Cyprus Amax a subsidiary
of Phelps Dodge. Therefore, USECC asserts the acquisition of Cyprus Amax by
Phelps Dodge was a sale of MEMCO and the properties that triggers the obligation
of Cyprus Amax to pay USECC the $3.75 million plus interest.
A second counterclaim by USECC rejects the claim by Phelps Dodge that it
and its predecessors, Cyprus Amax and AMAX Inc., had mistakenly paid royalties
to USECC since January 1991. In 1984, AMAX began paying the cash equivalent
(half each to U.S. Energy and Crested Corp.) of 700,000 pounds of molybdenum per
year as an advance royalty prior to the mine beginning production. In 1986,
USECC agreed to assist financially troubled AMAX and substantially reduced the
annual advance royalty to 50,000 pounds of molybdenum, so that AMAX could
continue to hold the properties and eventually bring them into production. AMAX,
Cyprus Amax and Phelps Dodge continued paying the annual advance royalties to
U.S. Energy and Crested Corp. until the payment due in July 2001, when Phelps
Dodge unilaterally ceased making the payments. Phelps Dodge and MEMCO seek a
declaratory judgment that the advance royalty payment obligation has terminated.
The third issue in the litigation is whether USECC must, under terms of a
1987 royalty deed, accept Phelps Dodge's and MEMCO's forth-coming conveyance of
the Mt. Emmons properties back to USECC, which properties now include a plant to
treat mine water, costing in excess of $1 million a year to operate in
compliance with State of Colorado regulations. Phelps Dodge's and MEMCO's
threatened reconveyance would require USECC to assume the operating costs of the
water treatment plant. USECC refuses to have the water treatment plant included
in the return of the properties because, the USECC counterclaim argues, the
properties must be in the same condition as when they were acquired by AMAX
before the water treatment plant was constructed by AMAX.
The properties are comprised of 16 patented lode mining claims covered in
part by 10 unpatended lode mining claims (for which patents are expected to be
issued by the BLM in the near future), and 778 unpatented lode mining claim and
mill site claims, for a total of about 15,600 acres.
As added counterclaims, USECC seeks (i) damages for defendants' breach of
covenants of good faith and fair dealing; (ii) damages for defendants' failure
to develop the Mt. Emmons properties and not protecting USECC's rights as
revisionary owner of the mining rights to the properties, (iii) damages for
unjust enrichment
87
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
of defendants; (iv) damages for breach of the defendants' fiduciary duties owed
to USECC as revisionary owner of the property, and for neglecting to maintain
the mining rights and interests in the properties; and (v) damages relating to
defendants' actions in violation of federal and Colorado anti-trust and
constraint of trade laws.
USECC also seeks a declaratory judgment of its rights and liabilities under
the agreements affecting the Mt. Emmons properties; an injunction against
defendants prohibiting the conveyance of the properties to USECC with the water
treatment plan; an injunction against further waste of the properties by the
defendants; an injunction requiring defendants to divest their molybdenum
holdings (including the Mt. Emmons properties); and an injunction requiring
defendants to assist USECC in mining molybdenum from the Mt. Emmons properties.
On August 2, 2002, Phelps Dodge and MEMCO filed a reply to the
counterclaims of USECC and Cyprus Amax filed an answer to the counterclaims and
third party complaint of USECC, generally denying the allegations of USECC. CAV
Corporation filed a motion for summary judgment seeking dismissal of USECC's
cross complaint and is pending. A Scheduling/Planning Conference in the case was
held and thereafter, Phelps Dodge dismissed its claim for reimbursement of
advance royalties from USECC. On March 17, 2003, Phelps Dodge filed a motion for
partial summary judgment on the first claim to return the properties to USECC
with the obligation of operating the water treatment plant. USECC are filing a
response and discovery is underway.
Except for the parties' claims regarding payment of the $3.75 million due
on the sale of MEMCO, payments of royalties, and responsibility going forward
for payment of the operating costs of the water treatment plan, the financial
impact to U.S. Energy Corp. and Crested Corp. of favorable or unfavorable
outcomes in the litigation presently is not determinable.
LITIGATION INVOLVING LEASES ON COALBED METHANE PROPERTIES IN MONTANA
On or about April 1, 2001, the Company's subsidiary, Rocky Mountain Gas,
Inc. (RMG) was served with a Second Amended Complaint wherein the Northern
Plains Resource Council had filed suit in the U.S. District Court of Montana,
Billings Division in Case No. CV-01-96-BLG-RWA against the United States Bureau
of Land Management ("BLM"), RMG, certain of its affiliates (including U.S.
Energy Corp. and Crested Corp.) some 20 other defendants. The plaintiff is
seeking to cancel oil and gas leases issued to RMG et. al. by the BLM in the
Powder River Basin of Montana and for other relief.
The basis for the complaint appears to be that the BLM's regulations
require the BLM to respond to objections filed by persons owning land or lease
rights adjacent to the coalbed properties which the BLM is offering to lease to
the public. The argument of plaintiff appears to be that if objections are not
responded to by the BLM prior to issuing CBM leases, the leases are invalid.
Based on this argument, the plaintiff appears to have been successful in forcing
cancellation of some CBM leases granted to others in the Powder River Basin of
Montana, because the BLM did not respond to some objecting adjacent landowners.
However, all of the BLM leases in Montana held by RMG (none are held by U.S.
Energy Corp. or Crested Corp. in their
88
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
own corporate names) are at least four years old, and there is no record of any
objections being made to the issue of those leases.
Based on filings in the case to date, it appears that the BLM is taking the
initiative in responding to the plaintiff. We believe RMG's leases were validly
issued in compliance with BLM procedures, and do not believe the plaintiff's
lawsuit will adversely affect any of RMG's Montana BLM leases.
RECLAMATION AND ENVIRONMENTAL LIABILITIES
Most of the Company's and Crested's exploration activities are subject to
federal and state regulations that require the Company and Crested to protect
the environment. The Company and Crested conduct their operations in accordance
with these regulations. The Company's and Crested's current estimates of their
reclamation obligations and their current level of expenditures to perform
ongoing reclamation may change in the future. At the present time, however, the
Company and Crested cannot predict the outcome of future regulation or impact on
costs. Nonetheless, the Company and Crested have recorded their best estimate of
future reclamation and closure costs based on currently available facts,
technology and enacted laws and regulations. Certain regulatory agencies, such
as the Nuclear Regulatory Commission ("NRC"), the Bureau of Land Management
("BLM") and the Wyoming Department of Environmental Quality ("WDEQ") review the
Company's and Crested's reclamation, environmental and decommissioning
liabilities, and the Company and Crested believe the recorded amounts are
consistent with those reviews and related bonding requirements. To the extent
that planned production on their properties is delayed, interrupted or
discontinued because of regulation or the economics of the properties, the
future earnings of the Company and Crested would be adversely affected. The
Company and Crested believe they have accrued all necessary reclamation costs
and there are no additional contingent losses or unasserted claims to be
disclosed or recorded.
The majority of the Company's and Crested's environmental obligations
relate to former mining properties acquired by the Company and Crested. Since
the Company and Crested currently do not have properties in production, the
Company's and Crested's policy of providing for future reclamation and mine
closure costs on a unit-of-production basis has not resulted in any significant
annual expenditures or costs. For the obligations recorded on acquired
properties, including site-restoration, closure and monitoring costs, actual
expenditures for reclamation will occur over several years, and since these
properties are all considered future production properties, those expenditures,
particularly the closure costs, may not be incurred for many years. The Company
and Crested also do not believe that any significant capital expenditures to
monitor or reduce hazardous substances or other environmental impacts are
currently required. As a result, the near term reclamation obligations are not
expected to have a significant impact on the Company's liquidity.
As of December 31, 2002, estimated reclamation obligations related to the
above mentioned mining properties total $8,906,800. Crested's portion of this
obligation is $748,400, which is reflected on the balance sheet of the Company.
The remaining balance of $7,614,700 is an obligation of USE and its other
affiliates, (excluding Crested). The Company is obligated for 50% of any
reclamation costs in excess of current estimated reclamation obligations. The
Company, however, does not expect that estimated reclamation costs will be
exceeded.
89
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
The Company and Crested currently have three mineral properties or
investments that account for most of their environmental obligations, SMP,
Plateau and SGMC. The environmental obligations and the nature and extent of
cost sharing arrangements with other potentially responsible parties, as well as
any uncertainties with respect to joint and several liability of each are
discussed in the following paragraphs:
SMP
---
The Company and Crested are equally responsible for the reclamation
obligations, environmental liabilities and liabilities for injuries to employees
in mining operations with respect to the Sheep Mountain properties. The
reclamation obligations, which are established by regulatory authorities, were
reviewed by the Company, Crested and the regulatory authorities during fiscal
2002 and they jointly determined that the reclamation liability was $1,496,800.
The Company and Crested are self bonded for this obligation by mortgaging
certain of their real estate assets, including the Glen L. Larsen building, and
by posting cash bonds.
GMMV
----
During fiscal 1991, the Company and Crested acquired mineral properties on
Green Mountain known as the Big Eagle Property. The GMMV also acquired a uranium
mill known as the Sweetwater Mill. As part of the settlement of the GMMV
litigation with Kennecott in September 2000, the Company was released from any
and all reclamation and environmental obligations related to the GMMV except the
Ion Exchange Plant. During fiscal 2002, the Company and Crested completed the
required reclamation on the Ion Exchange Plant. The reclamation work has been
completed and a final report has been submitted to and is being reviewed by the
regulatory agencies. No further monitoring of the site is required and no
additional reclamation work is anticipated.
SUTTER GOLD MINING COMPANY
--------------------------
SGMC's mineral properties are currently on shut down status and have never
been in production. There has been minimal surface disturbance on the Sutter
properties. Reclamation obligations consist of closing the mine entry and
removal of a mine shop. The reclamation obligation to close the property has
been set by the State of California at $27,800 which is covered by a cash
reclamation bond. This amount was recorded by SGMC as a reclamation liability as
of December 31, 2002.
PLATEAU RESOURCES LIMITED
-------------------------
The environmental and reclamation obligations acquired with the acquisition
of Plateau include obligations relating to the Shootaring Mill. Based on the
bonding requirements, Plateau transferred $2,500,000 to a trust account as
financial surety to pay future costs of mill decommissioning, site reclamation
and long-term site surveillance. In fiscal 1997, Plateau requested that the mill
be place on operational status. The NRC increased the reclamation liability to
$6,784,000 as a result of this request. As of December 31, 2002, a cash deposit
for reclamation in the amount of $8,818,600 was held by Plateau's escrow agent
to satisfy the obligation of reclamation.
90
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
EXECUTIVE COMPENSATION
- ----------------------
The Company is committed to pay the estates of certain of their officers
one years' salary and an amount to be determined by the Boards of Directors, for
a period of up to five years thereafter. This commitment applies only in the
event of the death or total disability of those officers who are full-time
employees of the Company at the time of total disability or death. Certain
officers and employees have employment agreements with the Company.
L. DISCONTINUED OPERATIONS.
During the third quarter of the fiscal year ended May 31, 2002, the Company
made the decision to discontinue its drilling/construction segment. The assets
associated with this business segment are being sold and or converted for use
elsewhere in the Company. The financial statements for the fiscal years ended
May 31, 2001 and 2000 have been revised to present the effect of discontinued
operations. There is no material income or loss from discontinued operations
from the measurement date to December 31, 2002.
M. SUPPLEMENTAL NATURAL GAS RESERVE INFORMATION (UNAUDITED):
The following estimates of proved gas reserves, both developed and
undeveloped, represent interests owned by the Company located solely within the
United States. Proved reserves represent estimated quantities of natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed gas reserves are the quantities expected
to be recovered through existing wells with existing equipment and operating
methods. Proved undeveloped gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells for which
relatively major expenditures are required for completion.
The Company began natural gas production in June, 2002. Disclosures of gas
reserves which follow are based on estimates prepared by independent engineering
consultants as of December 31, 2002. Such estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. These estimates do not include probable or possible reserves. The
information provided does not represent Management's estimate of the Company's
expected future cash flows or value of proved oil and gas reserves.
91
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Changes in estimated reserve quantities
The net interest in estimated quantities of proved developed and
undeveloped reserves of crude oil and natural gas at December 31, 2002 and
changes in such quantities and discounted future net cash flow during the period
ended December 31, 2002 were as follows:
(Unaudited) - Unescalated
----------------------------------------
MMCF Discounted
Million Future Net Cash Flow
Cubic Feet (10% Discount)
------------- --------------------
Proved developed and undeveloped reserves:
Beginning of year --
Purchase of reserves in place 649.918
Production (64.315)
-------
End of year 585.603
=======
Proved developed producing 489.684 $ 793,481
Proved undeveloped 95.919 94,947
------- ------------
Total proved reserves 585.603 $ 888,428
======= ============
The standardized measure has been prepared assuming year end sales prices
adjusted for fixed and determinable contractual price changes, current costs. No
provision has been made for income taxes due to available operating loss
carryforwards. No deduction has been made for depletion, depreciation or any
indirect costs such as general corporate overhead or interest expense.
Standardized measure of discounted future net cash flows from estimated
production of proved gas reserved:
Future cash inflows $ 1,756,809
Future production and development costs (705,505)
-----------
Future net cash flows 1,051,304
10% annual discount for estimated timing of cash flows (162,876)
-----------
Standardized measure of discounted future net cash flows $ 888,428
===========
Changes in standard measure of discounted future net cash flows from
proved gas reserves:
Standardized measure - beginning of year $ --
Purchase of reserves in place 652,628
Sales of gas produced, net of production costs 235,800
-----------
Standardized measure - end of year $ 888,428
===========
92
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
N. TRANSITION PERIOD COMPARATIVE DATA
The following table presents certain financial information for the seven
months ended December 31, 2002 and 2001, respectively:
Seven Months Ended
December 31,
------------------------------
2002 2001
------------ ------------
(Unaudited)
Revenues $ 1,027,600 $ 1,073,300
Costs and expenses 4,535,400 4,823,500
------------ ------------
Operating loss (3,507,800) (3,750,200)
Other income and expenses (387,100) 1,005,000
------------ ------------
Loss before minority interest (3,894,900) (2,745,200)
Minority interest in loss of subsidiaries 54,800 24,500
Loss before income taxes (3,840,100) (2,720,700)
Provision for income taxes -- --
------------ ------------
Net loss from continuing operations (3,840,100) (2,720,700)
Discontinued operations, net of tax -- 10,300
Net loss (3,840,100) (2,710,400)
Preferred stock dividends -- (75,000)
------------ ------------
Net loss available to common stock shareholders $ (3,840,100) $ (2,785,400)
============ ============
PER SHARE DATA:
Revenues $ 0.11 $ 0.13
Operating loss (0.32) (0.45)
Loss from continuing operations (0.36) (0.33)
Net loss (0.36) (0.33)
Preferred Stock dividends -- (0.01)
------------ ------------
Net loss available to common stock
shareholders $ (0.36) $ (0.34)
============ ============
Weighted average common shares outstanding
Basic 10,770,658 8,386,672
============ ============
Diluted 10,770,658 8,386,672
============ ============
93
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
O. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Three Months Ended
Month Ended ------------------------------
December 31, November 30, August 31,
2002 2002 2002
------------ ------------ ------------
Operating Revenues $ 92,400 $ 442,400 $ 492,800
Operating (loss) $ (691,200) $ (1,556,600) $ (1,260,000)
Loss from continuing operations $ (1,453,600) $ (1,264,700) $ (1,121,800)
Discontinued operations, net of tax $ -- $ -- $ --
------------ ------------ ------------
Net loss $ (1,453,600) $ (1,264,700) $ (1,121,800)
============ ============ ============
Loss per Share, basic
Continuing operations $ (0.14) $ (0.12) $ (0.10)
Discontinued operations $ -- $ -- $ --
------------ ------------ ------------
$ (0.14) $ (0.12) $ (0.10)
============ ============ ============
Basic weighted average
shares outstanding 10,766,672 10,765,889 10,761,093
Loss per share, diluted
Continued operations $ (0.14) $ (0.12) $ (0.10)
Discontinued operations $ -- $ -- $ --
------------ ------------ ------------
$ (0.14) $ (0.12) $ (0.10)
============ ============ ============
Diluted weighted average
shares outstanding 10,766,672 10,765,889 10,761,093
94
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, MAY 31, 2002 AND MAY 31, 2001
(CONTINUED)
Three Months Ended
-------------------------------------------------------------------
May 31, February 28, November 30, August 31,
2002 2002 2001 2001
------------ ------------ ------------ ------------
Operating Revenues $ 408,800 $ 238,700 $ 724,200 $ 632,400
Operating (loss) $ (1,588,300) $ (3,066,700) $ (1,197,600) $ (1,601,600)
Loss from continuing operations $ (1,109,700) $ (3,172,000) $ (550,900) $ (1,349,100)
Discontinued operations, net of tax $ (22,200) $ (9,600) $ (37,300) $ (16,800)
------------ ------------ ------------ ------------
Net loss $ (1,131,900) $ (3,181,600) $ (588,200) $ (1,365,900)
============ ============ ============ ============
Loss per Share, basic
Continuing operations $ (0.10) $ (0.32) $ (0.07) $ (0.17)
Discontinued operations $ (0.01) $ -- $ -- $ --
------------ ------------ ------------ ------------
$ (0.11) $ (0.32) $ (0.07) $ (0.17)
============ ============ ============ ============
Basic weighted average
shares outstanding 10,579,828 9,837,494 8,580,904 8,192,316
Loss per share, diluted
Continued operations $ (0.11) $ (0.32) $ (0.07) $ (0.17)
Discontinued operations $ (0.01) $ -- $ -- $ --
------------ ------------ ------------ ------------
$ (0.11) $ (0.32) $ (0.07) $ (0.17)
============ ============ ============ ============
Diluted weighted average
shares outstanding 10,579,828 9,837,494 8,580,904 8,192,316
95
REPORT OF INDEPENDENT CERTIFIED
PUBLIC ACCOUNTANTS ON SCHEDULE
To U.S. Energy Corp:
In connection with our audit of the consolidated financial statements of U.S.
ENERGY CORP. (a Wyoming Corporation) AND SUBSIDIARIES referred to in our report
dated July 18, 2002, which is included in the Company's annual report on Form
10-K, we have also audited Schedule II for each of the years in the period ended
May 31, 2002. In our opinion, this schedule presents fairly, in all material
respects, the information to be set forth therein.
GRANT THORNTON LLP
Denver, Colorado
February 28, 2003
96
U.S. ENERGY CORP.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Balance Additions
beginning charged to Balance end
of period expenses Deductions of period
--------- ---------- ---------- -----------
May 31, 2000 $ 27,800 $ 708,600 $ 708,600 $ 27,800
=========
May 31, 2001 $ 27,800 -- -- $ 27,800
=========
May 31, 2002 $ 27,800 171,200 171,200 $ 27,800
=========
December 31, 2002 $ 27,800 -- -- $ 27,800
=========
97
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
Not applicable.
PART III
In the event a definitive proxy statement containing the information being
incorporated by reference into this Part III is not filed within 120 days of
December 31, 2002, we will file such information under cover of a Form 10-K/A.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by Item 10 with respect to directors and certain
executive officers is incorporated herein by reference to our Proxy Statement
for the Meeting of Shareholders to be held in June 2003, under the captions
"Proposal 1: Election of Directors," Filing of Reports Under Section 16(a),"
and"Business Experience and Other Directorships of Directors and Nominees." The
information regarding the remaining executive officers follows:
INFORMATION CONCERNING EXECUTIVE OFFICERS WHO ARE NOT DIRECTORS.
The following are the two executive officers of USE as of the date of this
Form 10-K; these persons devote their full time to the Company's business.
ROBERT SCOTT LORIMER, age 52, has been the Chief Accounting Officer for
both USE and Crested for more than the past five years. Mr. Lorimer also has
been Chief Financial Officer for both these companies since May 25, 1991, their
Treasurer since December 14, 1990, and Vice President Finance since April 1998.
He serves at the will of each board of directors. There are no understandings
between Mr. Lorimer and any other person, pursuant to which he was named as an
officer, and he has no family relationship with any of the other executive
officers or directors of USE or Crested. During the past five years, Mr. Lorimer
has not been involved in any Reg. S-K Item 401(f) listed proceeding.
DANIEL P. SVILAR, age 74, has been General Counsel for USE and Crested for
more than the past five years. He also has served as Secretary and a director of
Crested, and Assistant Secretary of USE. On March 25, 2002, Mr. Svilar was
appointed Secretary of USE. His positions of General Counsel to, and as officers
of the companies, are at the will of each board of directors. There are no
understandings between Mr. Svilar and any other person pursuant to which he was
named as officer or General Counsel. He has no family relationships with any of
the other executive officers or directors of USE or Crested, except his nephew
Nick Bebout is a USE director. During the past five years, Mr. Svilar has not
been involved in any Reg. S-K Item 401(f) proceeding.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by Item 11 is incorporated herein by reference to
the Proxy Statement for the Meeting of Shareholders to be held in June 2003,
under the captions "Executive Compensation" and "Director's Fees and Other
Compensation."
98
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by Item 12 is incorporated herein by reference to
the Proxy Statement for the Meeting of Shareholders to be held in June 2003,
under the caption "Principal Holders of Voting Securities."
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by Item 13 is incorporated herein by reference to
the Proxy Statement for the Meeting of Shareholders to be held in June, under
the caption "Certain Relationships and Related Transactions."
ITEM 14. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this report, the Company carried
out an evaluation of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Rule 13A-14 of the
Securities Exchange Act of 1934. Based upon the evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that the Company's disclosure
controls and procedures are effective in timely identifying material information
potentially required to be included in the Company's SEC filings.
Disclosure controls and procedures include, without limitation, controls
and procedures designed to ensure that information required to be disclosed by
the Company in its reports filed or submitted under the Securities Exchange Act
of 1934 is accumulated and communicated to Company management, including the
chief executive and chief financial officers of the Company, as appropriate to
allow those persons to make timely decisions regarding required disclosure.
There were no significant changes in the Company's internal controls or
other factors that could significantly affect these controls subsequent to the
date of their evaluation and there were no corrective actions required with
regard to significant deficiencies and material weaknesses.
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES, REPORTS AND FORMS 8-K.
(1) The following financial statements are filed as a part of the Report in
Item 8:
Consolidated Financial Statements Page No.
U.S. Energy Corp. and Subsidiaries --------
Report of Independent Public Accountants
Grant Thornton LLP.......................................................46
Report of Independent Public Accountants
Arthur Andersen LLP......................................................47
Consolidated Balance Sheets - Seven Months Ended
December 31, 2002, and May 31, 2002 and 2001..........................48-49
Consolidated Statements of Operations
for the Seven Months Ended December 31, 2002
and the Years Ended May 31, 2002, 2001 and 2000.......................50-51
99
Consolidated Statements of Shareholders'
Equity for the Seven Months Ended December 31, 2002
and the Years Ended May 31, 2002, 2001 and 2000.......................52-55
Consolidated Statements of Cash Flows
for the Seven Months Ended December 31, 2002
and the Years Ended May 31, 2002, 2001 and 2000.......................56-57
Notes to Consolidated Financial Statements............................58-95
Report of Independent Certified
Public Accountants on Schedule...........................................96
Schedule II - Valuation and Qualifying Accounts..........................97
(2) Not applicable.
(3) Exhibits Required to be Filed. Each individual exhibit filed herewith is
sequentially paginated corresponding to the pagination of the entire Form
10-K. As a result of this pagination, the page numbers of documents filed
herewith containing a table of contents will not be the same as the page
number contained in the original hard copy.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE.
SEQUENTIAL
EXHIBIT NO. TITLE OF EXHIBIT PAGE NO.
- ----------- ---------------- ----------
3.1 USE Restated Articles of Incorporation.........................[2]
3.1(a) USE Articles of Amendment to
Restated Articles of Incorporation.............................[4]
3.1(b) USE Articles of Amendment (Second)
to Restated Articles of Incorporation
(Establishing Series A Convertible Preferred Stock.............[9]
3.1(c) Articles of Amendment (Third) to
Restated Articles of Incorporation
(Increasing number of authorized shares)......................[14]
3.2 USE Bylaws, as amended through April 22, 1992..................[4]
4.1 Amendment to USE 1998 Incentive
Stock Option Plan (To include
Family Transferability of Options
Under SEC Rule 16b)...........................................[11]
4.2 USE 1998 Incentive Stock Option Plan
and Form of Stock Option Agreement 1/99........................[8]
4.3 USE Restricted Stock Bonus Plan,
as amended through 2/94........................................[5]
100
4.4 Form of Stock Option Agreement, and Schedule
Options Granted January 1, 1996................................[6]
4.5 Form of Stock Option Agreement and Schedule,
Options Granted January 10, 2001..............................[11]
4.6 Form of Investors' Warrant issued in
February and March 2002, and
List of Holders...............................................[21]
4.7 USE 1996 Officers' Stock Award Program (Plan)..................[7]
4.8 USE Restated 1996 Officers' Stock Award Plan and
Amendment to USE 1990 Restricted Stock Bonus Plan..............[7]
4.9 Warrant held by Caydal LLC....................................[13]
4.10 Warrant held by Kevin P. Daly................................[13]
4.11 Rights Agreement, dated as of September 19, 2001
between U.S. Energy Corp. and Computershare
Trust Company, Inc. as Rights Agent. The Articles of
Amendment to Articles of Incorporation creating the
Series P Preferred Stock is included herewith as an
exhibit to the Rights Agreement.
Form of Right Certificate (as an exhibit to the
Rights Agreement).
Summary of Rights, which will be sent to all holders of
record of the outstanding shares of Common Stock of the
registrant, also included as an exhibit to the
Rights Agreement..............................................[12]
4.12 Form of Advisor Warrant dated October 18, 2001
and List of Holders ..........................................[14]
4.13 Form of Advisor Warrant dated November 2, 2001
and List of Holders...........................................[14]
4.14 Form of Investor Warrant dated October 18, 2001
and List of Holders...........................................[14]
4.15 Stock Option held by R. Jerry Falkner
dated April 11, 2001..........................................[14]
4.16 Warrant held by Riches In Resources
dated May 14, 2001............................................[14]
4.17 Stock Option held by R. Jerry Falkner dated
October 11, 1999 and Amendment thereto........................[15]
101
4.18 Amendment dated April 25, 2002 to
October 11, 1999 Stock Option
Agreement held by R. Jerry Falkner...........................[16]
4.19 USE 2001 Incentive Stock Option Plan
with Form of Option Agreement.................................[18]
4.20 USE Schedule of Options
Issued - 12/7/01 and 5/20/01..................................[18]
4.21 USE 2001 Officers' Stock Compensation Plan....................[18]
4.22 Warrant held by Tsunami Partners, L.P.........................[22]
4.23 Amendment dated December 10, 2002 to
October 11, 1999 Stock Option
Agreement held by R. Jerry Falkner............................[20]
4.24 Stock Option held by Robert Nicholas..........................[22]
4.25 Form of Warrant, Amendment
thereto and List of Holders
(Yellowstone Fuels Corp./USE Exchange)........................[22]
10.1 USECC Joint Venture Agreement - Amended as of 1/20/89..........[1]
10.2 Management Agreement with USECC................................[3]
10.3 Contract - R. J. Falkner & Company
dated April 11, 2001..........................................[11]
10.4 Consulting Agreement - Riches In Resources
dated May 14, 2001............................................[11]
10.5 Agreement for Strategic Services
VentureRound Group LLC........................................[14]
10.6-10.60 [intentionally left blank]
10.61 Closing Agreement - Addendum to Agreement
for Purchase and Sale of Assets (see Exhibit 10.62)...........[11]
10.62 Agreement for Purchase and Sale of Assets
(Rocky Mountain Gas, Inc. and Quantum Energy LLC)..............[9]
10.63 Purchase and Sale Agreement
CCBM, Inc. (subsidiary of Carrizo Oil & Gas, Inc.)
and Rocky Mountain Gas, Inc...................................[16]
10.64 Purchase and Sale Agreement
Bobcat Property...............................................[16]
102
10.65 Convertible Promissory Note and
Security Agreement dated May 30, 2002.........................[17]
10.66 Convertible Promissory Note and
Security Agreement dated November 19, 2002....................[19]
16. Concurrence Letter from Arthur Andersen LLP
on Change of Accounting Firms.................................[10]
21.1 Subsidiaries of Registrant....................................[11]
99.1 Certification Pursuant to 18 U.S.C. Section 1350.................*
99.2 Summary of reserve report of Ryder Scott Company,
as of December 31, 2002, with consent............................*
* Filed herewith.
_____________
Unless otherwise indicated, the SEC File Number for each of the following
documents incorporated by reference is 000-6814.
[1] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
1989, filed August 29, 1989.
[2] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
1990, filed September 14, 1990.
[3] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
1991, filed September 13, 1991.
[4] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
1992, filed September 14, 1991.
[5] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-1 registration statement, initial filing (SEC File
No. 333-1689) filed June 18, 1996).
[6] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
1996, filed September 13, 1996.
[7] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
1997, filed September 15, 1997.
[8] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
1998, filed September 14, 1998.
[9] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
2000, filed September 13, 2000.
[10] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form 8-K, filed February 5, 2001.
103
[11] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended on May 31,
2001, filed August 29, 2001.
[12] Incorporated by reference to exhibit number 4.1 to the Registrant's
Form 8-A12G filed, September 20, 2001.
[13] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-3 registration statement (SEC File No. 333-73546),
filed November 16, 2001.
[14] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-3 registration statement (SEC File No. 333-75864),
filed December 21, 2001.
[15] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-3 registration statement (SEC File No. 333-83040),
filed February 19, 2002.
[16] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-3 registration statement, amendment no. 1 (SEC File
No. 333-83040), filed May 17, 2002.
[17] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form 8-K, filed June 6, 2002.
[18] Incorporated by reference from the like-numbered exhibit to the
Registrant's Annual Report on Form 10-K for the year ended May 31,
2002, filed September 13, 2002.
[19] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form 8-K, filed December 9, 2002.
[20] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-3 registration statement, amendment no. 4 (SEC File
No. 333-83040), filed March 3, 2003.
[21] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-3 registration statement (SEC File No. 333-88584),
filed March 10, 2003.
[22] Incorporated by reference from the like-numbered exhibit to the
Registrant's Form S-3 registration statement (SEC File No. 333-103692),
filed March 10, 2003.
(b) Reports filed on Form 8-K.
During the transition period ended December 31, 2002, the Registrant
filed two reports on Form 8-K dated December 9, 2002 and December 18,
2002.
(c) Required exhibits are attached hereto and listed above under Item 15(a)(3).
(d) Required financial statement schedules are listed and attached hereto in
Item 15(a)(2).
104
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this amended report to be
signed on its behalf by the undersigned, thereunto duly authorized.
U.S. ENERGY CORP.
(Registrant)
Date: March 28, 2003 By: /s/ John L. Larsen
-------------------------------
John L. 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 28, 2003 By: /s/ John L. Larsen
-------------------------------
John L. Larsen, Director
Date: March 28, 2003 By: /s/ Keith G. Larsen
-------------------------------
Keith G. Larsen, Director
Date: March 28, 2003 By: /s/ Harold F. Herron
-------------------------------
Harold F. Herron, Director
Date: March 28, 2003 By: /s/ Don C. Anderson
-------------------------------
Don C. Anderson, Director
Date: March 28, 2003 By: /s/ Nick Bebout
-------------------------------
Nick Bebout, Director
Date: March 28, 2003 By: /s/ H. Russell Fraser
-------------------------------
H. Russell Fraser,
Director
Date: March 28, 2003 By: /s/ R. Scott Lorimer
-------------------------------
Robert Scott Lorimer,
Principal Financial Officer/
Chief Accounting Officer
105
CERTIFICATION
I, Robert Scott Lorimer, certify that:
1. I have reviewed this transition report on Form 10-K of U.S. Energy Corp.;
2. Based on my knowledge, this transition 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 transition
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this transition 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 transition 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-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures 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 transition report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this transition report (the "Evaluation
Date"); and
c. presented in this transition report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
transition report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
DATED this 28th day of March, 2003.
/s/ R. Scott Lorimer
-------------------------------
Robert Scott Lorimer
Chief Financial Officer
106
CERTIFICATION
I, John L. Larsen, certify that:
1. I have reviewed this transition report on Form 10-K of U.S. Energy Corp.;
2. Based on my knowledge, this transition 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 transition
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this transition 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 transition 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-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures 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 transition
report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this transition report (the "Evaluation Date"); and
c. presented in this transition report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
transition report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
DATED this 28th day of March, 2003.
/s/ John L. Larsen
-------------------------------
John L. Larsen,
Chief Executive Officer
107