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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K
(Mark One)
x
Annual report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year Ended December 31, 2004
   
o
Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the
 
transition period from ___________ to ___________

Commission file number 000-6814

U.S. ENERGY CORP.
(Exact Name of Company as Specified in its Charter)

Wyoming
  
83-0205516
(State or other jurisdiction of
  
(I.R.S. Employer
incorporation or organization)
  
Identification No.)
     
877 North 8th West, Riverton, WY
  
82501
(Address of principal executive offices)
  
(Zip Code)
     
Registrant's telephone number, including area code:
  
(307) 856-9271

Securities registered pursuant to Section 12(b) of the Act:
None
 
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.01 par value
(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 Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YES x    NO o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
YES o    NO x

The aggregate market value of the shares of voting stock held by non-affiliates of the Registrant as of March 31, 2005, computed by reference to the average of the bid and asked prices of the Registrant's common stock as reported on Nasdaq Small Cap on that date, was $79,008,500.

Class
  
Outstanding at March 31, 2005
Common stock, $.01 par value
  
16,264,465 Shares

Documents incorporated by reference: Portions of the documents listed below have been incorporated by reference into the indicated parts of this report

Proxy Statement for the Meeting of Shareholders to be held in June 2005, 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 o
 
 
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; the disclosures about Rocky Mountain Gas, Inc. ("RMG") and plans for developing its coalbed methane ("CBM") acreage and its possible acquisition by a Canadian company; the disclosures about possible exploration and other programs for uranium and molybdenum properties; and the disclosures about Sutter Gold Mining Inc., formerly Globemin Resources Inc., and its plans for a gold property in Calif ornia. 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 will depend on:

For CBM gas, whether current plans to merge RMG into (or sell its assets to) a Canadian company will be successfully completed. If those plans are successfully completed, U.S. Energy will hold an equity interest in an oil and gas company with interest in CBM, but USE would not be directly involved in operations. If those plans are not successfully completed and RMG remains in the gas business, results of operations will depend on domestic gas prices; results of exploration drilling; the amounts of gas we will be able to produce; the availability of permits to drill and operate CBM wells; whether and when gas transmission lines will be built in reasonable proximity to the properties being developed; and whether and on what terms the capital necessary to continue holding and developing the properties can be obtai ned.

For the uranium properties, market prices for uranium oxide, whether and on what terms capital can be obtained to develop the properties (and for the uranium mill in Utah, refurbish and put the mill into operation); and the availability of permits to mine the properties, and for the Utah mill obtain an operating license.

For the gold properties held by Sutter Gold Mining Inc., formerly Globemin Resources Inc., whether certain permits can be obtained from the State of California, and whether and on what terms capital can be obtained for further exploration, mining and processing operations.

For the molybdenum property, that the Company expects to receive back from Phelps Dodge Corporation, the Colorado regulatory requirements which we will have to comply with to operate a water treatment plant on the properties, whether adequate water rights for mine development and operation will be obtained from Phelps Dodge or others, and whether permits and bonding for a mine can be obtained, and whether U. S. Energy Corp. and Crested Corp. can raise the necessary capital and/or enter into a joint venture or other arrangement with a third party to put the property into production.

The forward-looking statements should be considered in the context of all the information in this Annual Report.


  
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PART I

Item 1 and Item 2. Business and Properties.

(a) General.

U.S. Energy Corp. ("USE") is a Wyoming corporation (formed in 1966) in the business of acquiring, exploring, developing and/or selling or leasing mineral properties. USE and Crested Corp. ("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). From time to time, USE has funded many of Crested's obligations because Crested did not have the funds to pay its own obligations. Crested has paid a portion of this debt by issuing common stock to USE. At December 31, 2004, Crested owed $9,650,900 to USE.

Historically, our business strategy has been, and will continue to be, acquiring grass roots and/or developed mineral properties when commodity prices are low (such as they have been in natural gas, gold, uranium and molybdenum), then operating, selling, leasing or joint venturing the properties, or selling the companies we set up to hold and explore or develop the properties to other companies in the mineral sector when prices are moving upward.

Typically, projects initially are acquired, financed and operated by USE and Crested in their joint venture (see below). From time to time, some of the projects are then transferred to separate companies organized for that purpose, with the objective of raising capital from an outside source for further development and/or joint venturing with other companies. Examples of this corporate strategy are, for gold properties, Sutter Gold Mining Inc. (formerly Globemin Resources Inc., a publicly traded British Columbia company, which acquired Sutter Gold Mining Company, and then changed its name to Sutter Gold Mining Inc.); and Rocky Mountain Gas, Inc. for CBM. Additional subsidiaries may be organized in the future such as U.S. Uranium Ltd. for uranium and U.S. Moly Corp. for molybdenum. Initial ownership of these sub sidiaries is by USE and Crested, with additional stock (plus options) held by their officers, directors and employees.

In 2002 and 2003, USE's primary business focus was in the CBM business conducted through its subsidiary Rocky Mountain Gas, Inc. ("RMG"). In 2004 and into 2005, commodity prices for the minerals in all our properties (and for molybdenum, the property that we expect to receive back from Phelps Dodge Corporation) increased significantly. Accordingly, in 2004 and continuing into 2005, our business activity has been expanding to include the gold, uranium and molybdenum properties.

Principal executive offices of USE and Crested are located in the Glen L. Larsen building at 877 North 8th West, Riverton, Wyoming 82501, telephone 307-856-9271. RMG has a field office in Gillette, Wyoming. Sutter Gold Mining Inc. has an office in Sutter Creek, California.

In this Annual Report, "we," "Company" or "USE" refer to U.S. Energy Corp. including Crested Corp. ("Crested") and other subsidiaries unless otherwise specifically noted. The Company's fiscal year ends December 31.


  
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Capital Activities in 2004 and First Quarter 2005.

USE

$350,000 Equity - 2004. In the first quarter 2004, we obtained $350,000 of equity funding from an accredited investor (100,000 shares of USE common stock, three year warrants to purchase 50,000 shares of USE common stock, at $3.00 per share; and five year warrants to purchase 200,000 shares at $3.00 per share).

$3,000,000 Loan - 2004. In the third quarter 2004, we borrowed $3,000,000 from Geddes and Company of Phoenix, Arizona. The loan matures on July 30, 2006, bears 10% annual interest, and is secured principally by RMG's CBM properties in the Castle Rock prospect and 4,000,000 shares of RMG stock held by USE. The loan may be prepaid in cash without penalty, but the lender at any time may convert loan principal to RMG common stock at $3.00 per share on the first $1,500,000 converted; and at $3.25, $3.50 and $3.75 per share for each additional $500,000 converted. In connection with the loan, RMG issued to the lender five year warrants to buy 600,000 shares of common stock of RMG: $3.00 per share for 300,000 sha res; and $3.25, $3.50 and $3.75 per share for 100,000 shares at each price.

$4,720,000 Loan - First Quarter 2005. On February 9, 2005, we borrowed $4,000,000 from seven accredited investors, issuing $4,720,000 face amount of debentures (including three years of annual interest at 6%). Net proceeds to USE were $3,700,000 after paying a commission and lenders' legal costs.

The debentures are unsecured; the face amount of the debentures are payable every six months from February 4, 2005, in five installments of 20%, in cash or in restricted common stock of USE. USE may pay this amortization payment in cash or in stock at the lower of $2.43 per share (the “set price”) or 90% of the volume weighted average price of USE’s stock for the 90 trading days prior to the repayment date. The set price was determined on the formula of 90% of the volume weighted average price of the stock over the 90 trading days prior to February 4, 2005. The debentures are convertible to restricted common stock of USE at the set price.

At any time, USE has the right to redeem some or all of the debentures in cash or stock, in an amount equal to 120% of the face amount of the debentures until February 4, 2006; 115% from February 5, 2006 to February 4, 2007; and 110% from February 5, 2007 until maturity. Payment in stock would be at the set price. The holders may convert the debentures to stock even if USE should seek to redeem in cash.

If at any time, after registration for public resale of the conversion shares have been approved, USE’s stock trades at more than 150% of the set price for 20 consecutive trading days, USE may convert the balance of the face amount of the debentures at the set price.

In the event of default, the investors may require payment (i) in cash equal to 130% of the then outstanding face amount; or (ii) in stock equal to 100% of face amount, with the stock priced at the set price, or (iii) in stock equal to 130% of the face amount, with the stock priced at 100% of the volume weighted average price of USE’s stock for the 90 trading days prior to default.

The preceding is a summary of the principal terms of the debentures. The form of debenture is filed as an exhibit to this Annual Report.

USE issued warrants to the investors, expiring February 4, 2008, to purchase 971,195 shares of restricted common stock, at $3.63 per share (equal to 110% of the Nasdaq closing price on February 3, 2005). The number of shares underlying the warrants equals 50% of the shares issuable on full conversion of the debentures at the set price (as if the debentures were so converted on February 4, 2005).

  
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Warrants to purchase 100,000 shares, at the same price and for the same term as the warrants issued to the investors, have been issued to HPC Capital Management (a registered broker-dealer) as compensation (in addition to a 7% cash commission) for its services in connection with the transaction.

If in any period of 20 consecutive trading days (after registration has been approved) USE’s stock price exceeds 200% of the warrants’ exercise price, on each of the trading days, all of the warrants will expire on the 30th day after USE sends a call notice to the warrant holders.

USE has agreed to file with the Securities and Exchange Commission a registration statement to cover the future public sale of shares issuable in payment and/or conversion of the debentures, and the shares issuable on exercise of the warrants. The registration statement also will cover the future sale by HPC Capital Management of the shares issuable on exercise of the warrants issued to HPC.

RMG

Preferred Stock - 2004. In the first quarter 2004, RMG raised $1,800,000 of equity financing from the sale of shares of Series A Preferred Stock in RMG, and warrants to purchase shares of common stock of USE, to institutional investors. Proceeds were used to pay part of the Hi-Pro acquisition price, and for RMG working capital. Terms of the securities:

1.    600,000 shares of Series A Preferred Stock at $3.00 per share, 10% cumulative annual dividend payable at RMG's election in cash or shares of common stock of RMG (at $3.00 per share) or shares of common stock of USE (at 90% of USE's volume weighted average price for the five days, referred to as the "set price"). The Series A Preferred Stock was convertible at the holder's election into shares of common stock of RMG, at $3.00 per share, or shares of common stock of USE at the set price, until February 2006.

2.    Warrants to purchase 150,000 shares of common stock of USE, at the set price.

As of March 3, 2005, all Series A Preferred Stock including dividends has been converted to and paid with USE common stock (894,299 shares), and all warrants have been exercised (150,000 shares of USE common stock).

Purchase of the Hi-Pro Production, LLC ("Hi-Pro") Properties. In 2004, RMG organized a wholly-owned subsidiary RMG I, LLC for the purchase of producing and non-producing CBM properties (the "Hi-Pro properties) near Gillette, Wyoming. RMG and USE participated in raising equity capital and mezzanine financing for this transaction.

Agreement for Acquisition of RMG by with Enterra Energy Trust. As of April 11, 2005, RMG entered into a binding agreement with Enterra Energy Trust ("Enterra," listed on the Toronto Stock Exchange and the Nasdaq National Market), for the acquisition of RMG by Enterra for cash and Enterra units. Enterra would acquire RMG including approximately $3.49 million owed by RMG to its lenders.

Sutter Gold Mining Inc.

In 2004, Sutter Gold Mining Company, a majority-owned subsidiary with gold properties in California, was acquired by Globemin Resources Inc., a British Columbia corporation which is traded on the TSX Venture Exchange (“TSX-V) under its new name, Sutter Gold Mining Inc. A total of Cdn $1,061,800 of equity capital has been raised to continue exploration work on the properties.

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Molybdenum

In February 2005, the United States District Court in Colorado issued an order authorizing Phelps Dodge to return mining claims at Mt. Emmons (near Crested Butte, Colorado) to USE and Crested, including a water treatment plant and the responsibility for operating it. The mining claims contain a world class molybdenum deposit. In 2005, USE and Crested expect to receive back from Phelps Dodge Corporation the patented and unpatented mining claims containing the molybdenum deposit. There are no current plans to put these properties into production but various strategies are being evaluated, including putting the property into production, or selling or leasing the property to (or joint venturing the property with) other entities. These strategies will require resolution of significant permitting issues and substanti al amounts of capital. In 2005, we expect to transfer the properties to a new subsidiary, U.S. Moly Corp.

Uranium

In December 2004, USE and Crested agreed to sell a 50% interest in the Sheep Mountain (Wyoming) uranium properties to Bell Coast Capital Corp., now named Uranium Power Corp. ("UPC"), a British Columbia company trading on the TSX Venture Exchange, for $4,050,000 and 4,000,000 shares of UPC common stock payable by installments through December 2007. The parties signed a Mining Venture Agreement with UPC as of April 11, 2005 for the Sheep Mountain property and other properties to be acquired. UPC may provide up to $10,000,000 for up to 20 different projects.

Plateau Resources Limited (a wholly-owned subsidiary of USE) agreed in December 2004 to lease uranium properties now controlled or owned (and to be acquired) by a third party in reasonable proximity to Plateau’s Shootaring Canyon Mill ("Shootaring Mill") in southeastern Utah. The purpose of this agreement is to obtain uranium properties for future mining to supply the Shootaring Mill, which we plan to put into production.

In 2005, we expect to transfer the uranium claims, and Plateau Resources Limited to a new subsidiary, U.S. Uranium Ltd. We have filed a request with the State of Utah for an operational license to reopen and operate the Shootaring Mill.

Summary Information about the Subsidiaries. Most operations are conducted through subsidiaries, the USECC Joint Venture with Crested, and jointly-owned subsidiaries of USE and Crested.

 
Percent
Primary
Subsidiary
Owned by USE(1)
Business Conducted
Plateau Resources Limited
100%
Uranium (Utah) - inactive mill - shut down, application filed to reopen and operate
Rocky Mountain Gas, Inc.(2)
91.1%
CBM - active
Crested Corp.
70.1%
Uranium and molybdenum (inactive and shut down, with limited reactivation in uranium planned for 2005), gold (being reactivated on a limited basis), and exploration and production activities on CBM properties.
Sutter Gold Mining Inc.(2)
65.5%
Gold (California) - inactive - being reactivated
Four Nines Gold, Inc.
50.9%
Contract Drilling/Construction - inactive
USECC Joint Venture
50.0%
Uranium and molybdenum (inactive and shut down, with limited reactivation in Wyoming uranium planned for 2005), gold (being reactivated), and CBM. Limited real estate and airport operations.
Yellowstone Fuels Corp.
35.9%
Uranium (Wyoming) - inactive - shut down
Pinnacle Gas Resources, Inc.(2)
16.7%
CBM exploration and production - active
 

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      (1)    As of December 31, 2004

(2)    Includes ownership of Crested Corp. in RMG, Sutter Gold Mining Inc., and Pinnacle Gas Resources, Inc.

The foregoing does not include information on ownership of subsidiaries which have been formed but not yet active (U.S. Uranium Ltd. and U.S. Moly Corp.). See Part III of this Report.

Financial information about industry segments.

From June 1, 2002 to December 31, 2003, for technical financial presentation purposes, we operated in two business segments: (i) CBM gas exploration (and holding shut down mines and mineral properties); and (ii) commercial operations (motel, real estate, and airport). By December 31, 2003, all activities in minerals (except CBM) and some of the commercial (motel/real estate/airport) had ceased or were curtailed, and the motel/commercial properties in Utah had been sold.

As of the date of this Annual Report, the primary activities of a material and recurring nature are in CBM. However, in 2004 and continuing in 2005, activities in gold and uranium were initiated, and activities are expected to start up in molybdenum in 2005. If the proposed merger with Enterra is consummated, the investments in CBM (RMG) may be changed from direct involvement in the CBM business to a continuing but passive investment in Enterra, which has conventional producing and non-producing oil and gas properties. Therefore, in 2005 and beyond, we expect to continue to have one active industry segment - exploration and development of mineral properties in gold, molybdenum and uranium.

The principal products of operating units within each of the reportable industry segments for the full years 2004 and 2003, the seven months ended December 31, 2002 and the (former) fiscal year ended May 31, 2002 are shown below. For more information, see note I to the financial statements.

Industry Segments    Principal Products

Minerals:    Acquisition and exploration of CBM properties. This activity is material and recurring, and was our principal business focus in these periods. Sales and leases of other mineral-bearing properties and, from time to time, the production and/or marketing of minerals. Activities in uranium and gold were largely shut down as recurring activities in the periods but uranium and gold are being reactivated at the date of this Report.

Commercial:    Operation of an aircraft fixed based operation (fuel sales, flight instruction and aircraft maintenance) was shut down in the (former) fiscal year 2002. The motel in Utah was sold in 2003. Real estate rental and various contract services continue, including management services for subsidiary companies.

Business and Properties

Coalbed Methane

General.

RMG was incorporated in Wyoming on November 1, 1999 for business in the CBM industry in Wyoming and Montana. RMG is a subsidiary of USE (owned 51.3% by USE and 39.8% by Crested at December 31, 2004). At December 31, 2004, RMG was indebted to the Company in the amount of

  
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$6,059,300. The obligation was incurred by RMG's continuing operating deficits (funded by USE) and for USE issuing common stock on conversion of RMG common stock, as well as preferred stock and payment of dividends on the preferred stock. In addition, a small percentage of RMG stock is held by employees, officers and directors of USE, Crested and RMG (plus options to buy more subsidiary stock) as an equity incentive for those persons to work for the subsidiary in addition to their responsibilities to USE and Crested. The shares and options are forfeitable if service is terminated before retirement.

Please see the Glossary in this Annual Report for definitions of certain terms used in the oil and gas industry, and in this Annual Report.

In 2003, RMG transferred all of its interest in certain CBM properties, including a producing property, to Pinnacle Gas Resources, Inc. ("Pinnacle"). At the same time, Carrizo Oil & Gas, Inc.'s wholly owned subsidiary CCBM, Inc. ("CCBM," with which RMG has an agreement to jointly acquire and explore CBM properties) transferred to Pinnacle all of its interest in the same properties, and affiliates of Credit Suisse First Boston contributed equity financing to Pinnacle.

On January 30, 2004, RMG, through its wholly-owned subsidiary RMG I, LLC ("RMG I"), acquired CBM properties in the Powder River Basin of Wyoming. See "Acquisition of Producing and Non-Producing Properties from Hi-Pro." Part of the purchase price was financed under a $25 million mezzanine credit facility.

As of April 11, 2005, the company and its subsidiary Rocky Mountain Gas, Inc. (“RMG”) has entered into a binding agreement with Enterra Energy Trust (“Enterra”) for the acquisition of RMG by Enterra in consideration of $20,000,000, payable pro rata to the RMG shareholders in the amounts of $6,000,000 in cash and $14,000,000 in exchangeable shares of one of the subsidiary companies of Enterra. The shares will be exchangeable for units of Enterra twelve months after closing of the transaction. The Enterra units are traded on the Toronto Stock Exchange and on Nasdaq; the exchangeable shares will not be traded. RMG will be acquired with approximately $3,500,000 of debt owed to its mezzanine lenders.

Closing of the transaction is subject to approval of the RMG shareholders; U.S. Energy Corp. and Crested Corp., the principal shareholders of RMG, have agreed to vote in favor of the acquisition. Closing is further subject to completion of due diligence by Enterra, and to obtaining regulatory and stock exchange approvals.

RMG’s minority equity ownership of Pinnacle Gas Resources, Inc. will not be included in the transaction with Enterra, which has resulted in a decrease in the consideration to be paid by Enterra from the previously-announced $30,000,000, to the $20,000,000 in the definitive agreement signed as of April 11, 2005. However, Enterra will be entitled to be paid up to (but not more than) $2,000,000 if proceeds from a future disposition of the minority equity interest in Pinnacle exceed $10,000,000.

If the transaction with Enterra is not consummated, additional development of the RMG properties will be contingent upon RMG's ability to raise additional capital. If RMG can obtain the necessary capital, RMG may drill exploratory and development wells on the Castle Rock, Oyster Ridge and Hi-Pro properties, and seek to acquire other producing CBM properties, primarily in Wyoming. Financing may be available under the mezzanine credit facility for more acquisitions, if approved by the lenders. As of the filing date of this Annual Report, RMG does not have any agreements to acquire other producing properties.

As of the filing date of this Annual Report, RMG holds leases and options on approximately 237,200 gross mineral acres (not including acreage held by Pinnacle) of federal, state and private (fee) land in the Powder River Basin of Wyoming and Montana, and adjacent to the Green River Basin of Wyoming.

  
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From RMG's inception, through December 31, 2004, 88 exploratory wells have been drilled primarily with funds provided by our industry partner CCBM (and another oil and gas company under a farmout agreement (completed in 2002) for exploration on our Castle Rock, Montana property). Forty-three of the wells were on properties transferred to Pinnacle in mid-2003. The balance of 45 wells, (15 of which have been plugged and abandoned) are on properties held by RMG. Proven reserves have not been established for any of the properties on which the exploratory wells were drilled.

The Castle Rock property in southeast Montana, and the Oyster Ridge property adjacent to the Green River Basin (southwest Wyoming), are large properties which will require the drilling of numerous exploratory wells and extensive dewatering for each group of wells (possibly as much as 3-12 months after drilling and completion) before an assessment of proven reserves can be made.

Among the uncertainties we face in determining if our CBM investments will yield value are the following: Because prices for gas sold in the Powder River Basin are typically lower than national prices, the economics of Powder River Basin properties can be adversely affected disproportionately by lower gas prices nationwide. The Hi-Pro properties and their cash flows after operation costs are pledged to service acquisition debt. To continue exploration efforts, additional capital will be needed. Permitting new wells on undeveloped acreage may be delayed. An unfavorable confluence of these uncertainties could result in a write-down of the carrying value of those properties which may not produce enough gas at low prices to be economic; in a write-down of the carrying value of other properties which need more wells drilled and dewatered to establish or 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.

Transaction with Pinnacle Gas Resources, Inc.

On June 23, 2003, RMG, CCBM and its parent company Carrizo Oil & Gas, Inc., and seven affiliates of Credit Suisse First Boston Private Equity (the "CSFB Parties") signed and closed agreements for a transaction with Pinnacle. The transaction included: (1) the contribution to Pinnacle by RMG and CCBM of all their ownership of a portion of the CBM properties owned by RMG and CCBM, in exchange for common stock and options to buy common stock in Pinnacle; and (2) $17,640,000 cash to Pinnacle by the CSFB Parties for common stock and series A preferred stock of Pinnacle, and warrants to purchase series A preferred stock of Pinnacle. The CSFB Parties have contributed significant additional capital to Pinnacle since June 2003.

Pinnacle is a private corporation. Only that information about Pinnacle which its board of directors elects to release is available to the public. All other information about Pinnacle is subject to confidentiality agreements between Pinnacle, RMG, and the other Pinnacle shareholders.

At December 31, 2004, RMG's ownership in Pinnacle's common stock was 16.7%. RMG's ownership of Pinnacle on a fully-diluted basis will change if the CSFB Parties fund subsequent capital requests from Pinnacle and/or exercise their warrants to buy equity in Pinnacle (but RMG does not), and/or if RMG and/or CCBM exercise their options to buy equity in Pinnacle, or other events occur.

Prior to and in connection with the Pinnacle transaction, CCBM paid RMG approximately $1.8 million cash to complete its purchase of 50% of RMG's properties, thus enabling CCBM to contribute its interests in the subject properties to Pinnacle as having been fully paid for. See "Continuing Operations of RMG, Continuing Agreement with CCBM, and the AMI Agreement, after the Pinnacle Transaction" below.


  
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Pinnacle is authorized to issue common and preferred stock. Pinnacle has issued series A preferred stock, all held by the CSFB Parties: Liquidation preference of $100.00 per share; 10.5% compounded cumulative annual dividend (12.5% after July 1, 2010); redeemable at Pinnacle's option after July 1, 2004 at a premium declining to par after July 1, 2009 (mandatory redemption if there is a change in control of RMG or CCBM); and with voting rights (a) pari passu with the common stock on regular matters, and (b) as a separate class, to authorize changes in the series A preferred stock, to authorize issuance of stock senior to or in parity with the series A preferred stock, to approve a reorganization or merger of Pinnacle, to approve Pinnacle's sale of substantially all its assets, and similar matters.

Pinnacle's board of directors has eight directors (two each from RMG and CCBM, and four from the CSFB Parties).

In 2003, RMG recorded its equity investment in Pinnacle at the carrying value of its contributed CBM properties (approximately $957,700).

- Continuing Operations of RMG, Continuing Agreement with CCBM, and the AMI Agreement after the Pinnacle Transaction

RMG retained ownership, with CCBM, of the Castle Rock, Oyster Ridge, and Baggs projects, totaling about 189,000 gross acres. The Baggs project was dropped in 2004. RMG and CCBM plan to continue exploration and development activities on Castle Rock and Oyster Ridge.

CCBM paid RMG approximately $1.8 million for CCBM's outstanding purchase obligation (under the July 2001 agreement) on CCBM's interest in those properties it contributed to Pinnacle. The $836,200 balance on the note at December 31, 2003 was paid in 2004.

Also in connection with the transaction, RMG, CCBM, Carrizo, USE and the CSFB Parties signed an area of mutual interest ("AMI") agreement. Pinnacle has the right to acquire from the other parties up to 100% of any interest in oil and gas leases, or interests therein or mineral interests or rights to acquire the same, which the other parties acquire, at the same price paid or payable by the other parties, within the Powder River Basin in Montana and Wyoming (excluding Powder River County, Montana), until the AMI expires on June 23, 2008. The original AMI agreement between CCBM and RMG from July 2001 is superseded by the new AMI agreement, except for areas outside the new AMI agreement territory, wherein the original agreement with CCBM still is in effect. The CCBM AMI expires on June 30, 2005.

Acquisition of Properties from Hi-Pro Production, LLC

On January 30, 2004, RMG I, LLC ("RMG I"), a wholly-owned subsidiary of RMG, purchased CBM properties from Hi-Pro for $6,800,000.

The purchased properties (all located in the Powder River Basin of Wyoming) included 247 completed wells and 18,450 undeveloped fee acres. As of the filing date for this Annual Report, 108 wells now are producing approximately 4.418 million cubic feet (Mmcf) of gas per day (approximately 2.615 Mmcf per day net to RMG I). Sales, net of gas used to run the compressors, are based on Mmbtu (BTU heat content). A portion of Hi - Pro production has low Mmbtu content per Mcf, which has increased overall field operating costs.

RMG I owns an average 58% working (average 46.4% net revenue) interest in the producing wells and proved developed acreage, and a 100% working (average 80% net revenue) interest in all of the undeveloped acreage. The net revenue interest percentage after deduction of the overriding royalty interests held by lenders are 44.66% for the producing and five future wells to the Wyodak coal, and 77%

  
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for production from deeper coals and all of the undeveloped acreage.

The transaction was structured as an asset purchase, with RMG I as the purchaser, in connection with the establishment of a mezzanine credit facility for up to $25,000,000 of secured loans to acquire and develop more proven CBM reserves. RMG may utilize RMG I for future acquisitions (none presently under contract). See "Mezzanine Credit Facility." A substantial portion of the cash consideration paid to Hi-Pro was funded with the initial advance on the credit facility. RMG I replaced Hi-Pro as the contract operator for 89% of the wells that were acquired.

RMG negotiated the purchase based on the $7,113,000 present value, discounted 10%, of gas reserves recoverable (and the estimated future net revenues to be derived) from proved reserves in the Hi-Pro properties, as estimated as of November 1, 2003 by Netherland Sewell and Associates, Inc. See "Reserve Data" below for the estimate as of December 31, 2004.

The $6,800,000 purchase price for the Hi-Pro properties reflects a deduction, negotiated by the parties in January 2004, to account for the decrease in gas production from October 2003 due to the impact on production from deferred maintenance on the properties, and the expected cost of such maintenance work after closing.

- Terms of the Purchase. The purchase price of $6,800,000 was paid:

1.
$
776,700
   cash by RMG
2.
$
588,300
   net revenues from November 1, 2003 to December 31, 2003, which were retained by Hi-Pro. (1)
3.
$
500,000
   by USE's 30 day promissory note (secured by 166,667 restricted shares of USE common stock, valued at $3.00 per share).
4.
$
600,000
   by 200,000 restricted shares of USE common stock (valued at $3.00 per share)
5.
$
700,000
   by 233,333 restricted shares of RMG common stock (valued at $3.00 per shares).(2)
6.
$
3,635,000
   cash, loaned to RMG I under the credit facility agreement.(3)
 
$
6,800,000
  
   
(588,300)
   reverse net revenues from November 1, 2003 to December 31, 2003, which were retained by Hi-Pro.
 
$
6,211,700
  

(1)    RMG paid all January operating costs at closing. Net revenues from the purchased properties for January 2004 were credited to RMG I's obligations under the credit facility agreement. These net revenues were considered by the parties to be a reduction in the purchase price which RMG otherwise would have paid at the January 30, 2004 closing.
(2)    All these RMG shares have been converted to shares of common stock of USE.
(3)    See "Mezzanine Credit Facility."

Reserve Data

Netherland Sewell and Associates, Inc. ("NSAI," Houston, Texas), independent petroleum engineers, have prepared a report on the proved reserves, as of December 31, 2004, estimating recoverable reserves from the Hi-Pro properties, and the present value (discounted 10%) of future cash flow therefrom. NSAI's report takes into account fixed pricing for some production in 2005, reflects the reduction in RMG's net revenue interests due to the overriding royalty interests held by lenders, and (except for fixed pricing in 2005) is based on the CIG Spot market price of $5.515 per Mmbtu, adjusted by lease for energy content, transportation fees and regional price differentials on December 31, 2004, without price escalation. Following is a summary of the December 31, 2004 reserve report:

  
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Net Present
   
Reserves
  
Value
   
(MCF)
  
(discounted at 10%)
Proved Developed Producing
  
1,651,666
  
$3,486,400
Proved Developed Non-Producing
  
889,051
  
$2,304,800
Proved Undeveloped
  
515,224
  
$ 723,400
Total
  
3,055,941
  
$6,514,600

The present value, discounted 10% value ("PV10 value") was prepared after ad valorem and production taxes on a pre-income tax basis, and is not intended to represent the current market value of the estimated gas reserves purchased from Hi-Pro.

There are numerous uncertainties inherent in estimating gas reserves and their estimated values. 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.

The PV10 value takes into account RMG I's contracts to sell 1,000 Mmbtu per day in 2005 at a fixed price of $4.14 per Mmbtu and 500 Mmbtu per day for January 1, 2005 through March 31, 2005 at a fixed price of $8.10 per Mmbtu. From time to time, RMG I may sign fixed price contracts for more production. In addition, gas market prices will vary, possibly by significant amounts, throughout each year, and on an average basis from year to year. For these reasons, the cash flow realized from production likely will vary from the estimates of cash flow used to determine the PV10 value.

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.

The PV10 discount factor, which is required by the SEC 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.

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, RMG's ability to maintain or expand reserves would be impaired. There is no assurance future activities would increase proved reserves. Even if revenues increase because of higher gas prices, increased exploration and development costs could neutralize cash flows from the increased revenues.

Future Plans for the Hi-Pro Properties

In 2004, RMG I drilled one proven undeveloped location to the Wyodak coal, continued a remedial workover program on existing wells, and upgraded gas gathering and pipeline facilities. The workover program cost approximately $250,000 and was funded by the working interest partners. The drilling and gathering upgrade cost approximately $640,000 and was funded with a loan from the mezzanine credit

  
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facility. The programs did not substantially increase production revenues from January 2004 levels (due to declines in BTU content from other wells) but the new well did increase proven reserves for the North Field. There are four more undrilled locations on the currently producing properties available for the Wyodak coal. The first coals of interest under the undeveloped acreage are the Anderson and Canyon coals (for example under the Reno property); the Wyodak coal is not present under the undeveloped acreage.

The Wyodak coal formation is 200 to 600 feet from surface. Existing infrastructure for the Wyodak wells in the North and South Fields (gathering lines, compressors, and water disposal) should significantly reduce gathering costs for new wells to the deeper Dannar and Moyer coals (900 to 1,300 feet). Subject to raising capital, a significant number of wells could be drilled and completed to these deeper coals in 2005 and 2006, all on locations now producing from the Wyodak. This activity is contingent upon obtaining future financing. We do not expect that immediate funding for this activity will be available through the mezzanine credit facility, as proven reserves have not yet been established.

No proven reserves have been established for the Dannar and Moyer coals. Because no other operators are producing gas from or dewatering these coals in the vicinity of the Hi-Pro properties, we expect several pods of wells will have to be drilled and completed to these coals, with an extended dewatering period before significant gas production begins.

The Reno property, part of the Hi - Pro acquisition, consists of 760 gross and net acres, all on fee acreage, located in Campbell County, Wyoming, approximately 50 miles south of Gillette. The target coals on the Reno property are the Anderson, which is about 600-650 feet in depth and approximately 40 feet thick and the Canyon which is about 700-850 feet in depth and 35 feet thick.

Four wells were previously drilled by Hi-Pro at Reno which were completed in both the Anderson and Canyon coals. In 2004, RMG I drilled and completed 4 additional wells at Reno, 2 in the Anderson coal and 2 in the Canyon coal.

- Mezzanine Credit Facility.

RMG I has a credit agreement with Petrobridge Investment Management, LLC (Houston, Texas) as lead arranger, and institutional lenders, for up to $25,000,000 of loans. The loan commitment is through June 30, 2006. All loans will have a three year term from funding date.

Funding to acquire and/or improve any project is subject to the lenders' approval of the transaction and RMG I's development plan.

The first loan ($4,340,000 on January 29, 2004) was applied to the Hi-Pro asset purchase ($3,700,000) including transaction costs and professional fees; and for drilling five development wells and production infrastructure upgrades ($640,000).

Loan balance at December 31, 2004 was $3,214,800 plus a discount of $274,100, which is accreted monthly, for a total of $3,488,900.

A summary of certain terms for all loans follows:

1.    Principal is not amortized, but interest must be paid monthly. All revenues from the properties owned by RMG I (including all current and new wells) are paid to a lock box account controlled by the lenders, from which is paid by the lenders, the lease operating costs, revenue distributions, RMG I operating fees and RMG pumping fees (all approved by the lenders). With the exception of operating

  
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and pumping fees, no revenues will be available for RMG operations until all loans are paid off.

2.    Secured by all of RMG I's properties and by RMG's equity interest in RMG I.

3.    The lenders, in the aggregate, received an overriding royalty interest of 3% of production from the wells producing when the acquisition was closed, and 3% of production from new wells on an 8/8ths working interest basis, proportionately reduced where less than 100% of the working interest is owned by RMG I. For the Hi-Pro properties, the 3% rate applies to all wells (producing and to be drilled) to the Wyodak formation (an aggregate override of 1.74%), and 3% to all wells to deeper formations (aggregate override to be determined based on working interest ownership by well). Override payments to the lenders are not applied to the loan bala nces. The percentage of overrides on future properties may vary.

4.    Negative covenants: RMG I will not permit the ratio of (a total debt to EBITDA to exceed 2.00 to 1.00; (b) EBITDA to interest expense and rents (lease expense) to be less than 3.00 to 1.00; (c) current assets to current liabilities to be less than 1.00 to 1.00; or (d) PV10 proved developed producing reserves) to total debt to be less than 1.00 to 1.00. All these rations are to be determined quarterly. In addition, RMG I shall not permit net sales volume of gas from its properties to be less than 270 Mmcf, 230 Mmcf, 230 Mmcf and 210 Mmcf for each quarter in 2004, or less than 180 Mmcf per quarter in 2005 and the first two quarters of 2006.< /FONT>

At December 31, 2004 and as of the date this Annual Report is filed, RMG I is not in compliance with the negative covenants. As a result, the loan was classified at December 31, 2004 as a current liability. To date, the lenders have granted to RMG I conditional waivers of non-compliance; receipt of future waivers is expected but not assured.

At closing of the Hi-Pro acquisition, USE issued to the participating lenders three year warrants to purchase a total of 318,465 shares of common stock of USE (subject to vesting) at $3.30 cash per share. At closing of the Hi-Pro acquisition, warrants on 63,693 shares vested. The remaining warrants will vest at the rate of the right to buy one USE share for each $157 which RMG I subsequently borrows under the credit facility. Regardless of when vested, all warrants will expire on the earlier of January 30, 2007, or the 180th day after USE notifies the warrant holders that USE stock price has achieved or exceeded $6.60 per share for a consecutive 15 business day period.

The preceding is a summary of some of the terms of the credit agreement, and is qualified by the text of the agreement, filed as an exhibit to the Form 10-K for the year ended December 31, 2003.

Volumes, Prices and Gas Operating Expense - Hi - Pro Property

This table shows the volume of gas sold (net of usage to fuel compressors); and average sales prices for gas sold and average production costs calculated on a per mcf basis, for Hi-Pro production in 2004.

   
Year Ended
December 31,
   
2004
     
Sales volume (mcf)
  
728,051
Average sales price per mcf(1)
  
$4.05
Average cost per mcf(2)
  
$3.19

(1)
Represents the weighted average of selling 92% of production at fixed contract prices and 8% at the market.

  
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(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 - All Properties Through December 31, 2004

From inception on November 1, 1999 through December 31, 2004, RMG incurred net acquisition (purchase price and holding costs) and exploration costs (drilling and completion) on CBM properties of approximately $8,897,300, which does not include approximately $2,500,000 funded by CCBM on RMG's behalf for leasehold, drilling and completion costs. Unproved properties on the balance sheet at December 31, 2004 reflect the reduction (by $5,706,600) 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 foregoing does not include $957,700 spent by RMG on properties transferred to Pinnacle, which we recorded at December 31, 2003 as an investment in Pinnacle.

The following table shows certain information regarding the gross costs incurred by RMG.

   
Year Ended
  
Year Ended
  
Seven Months Ended
  
Year Ended
  
   
December 31,
  
December 31,
  
December 31,
  
May 31,
  
   
2004
  
2003
  
2002
  
2002
  
Acquisition costs
  
$
6,613,900
  
$
107,100
  
$
936,200
  
$
192,600
  
Development
    
1,642,600
    
158,300
    
97,200
    
87,400
  
   
$
8,256,500
  
$
265,400
  
$
1,033,400
  
$
280,000
  

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 $8,256,500, $265,400, $1,033,400 and $280,000 represent 26.9%, 1.1%, 3.6% and 1.0% of total assets at December 31, 2004, 2003 and 2003, and May 31, 2002.

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.

All acquisition and exploration costs for a property are capitalized until such time as proven reserves can be established, or not, for the property. If no proven reserves are established, those capitalized costs will be transferred to the amortization basis and be subject to an impairment test. To the extent proven reserves are established for an exploration property to be less than such costs, the costs will be written-down to the amount of present value of the proven 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.


  
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Coalbed Methane Properties

As of the filing of this Annual Report, we hold leases and options to develop approximately 237,200 gross mineral acres (including 49,493 acres under option - see "Oyster Ridge" below) under leases from the United States Bureau of Land Management, the states of Wyoming and Montana, and private landowners.

Prospects are evaluated for CBM 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. 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 should be completed for production. Completion requires setting casing pipe down to the coal zone(s), installing pumps, and installing and setting up the necessary surface equipment (for example, water disposal lines and water holding tanks and/or holding ponds for evaluation wells, pending production permitting), and d ewatering the well sufficiently so production can start. The decision whether to complete the well is made by the executive officers of RMG.

Productive Wells

At December 31, 2004, gross and net productive wells were as shown in the following table. A “productive well” is a well which is producing (or demonstrated to be capable of production but is shut in).

Project
 
Gross
 
Net
Hi-Pro Field
        
 
North
  
92
  
79
 
South
  
100
  
41
Total
   
192
  
120

Drilling Activity

The following table shows drilling activity for the two fiscal years ended December 31, 2004 and 2003, from RMG’s inception to December 31, 2004, and total wells at March 15, 2005. The data includes wells which have been plugged and abandoned.

 
Prospect
Twelve Months Ended 12/31/04
Twelve Months Ended 12/31/03
Inception to 12/31/04
Total Wells at 2/14/05
Castle Rock (2)
4
0
26
26
Oyster Ridge (3)
8
0
15
15
Hi-Pro(1)
4
0
4
4
Total
16
0
45
45

(1)  Does not include any wells drilled by Hi-Pro Production LLC before November 1, 2003, which wells with associated acreage were purchased by RMG in January 2004.
(2)  Includes 12 wells that have been plugged and abandoned.
(3)  Includes 3 wells that have been plugged and abandoned.


  
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Acreage

Acreage as of March 15, 2005 is:

   
Total
Property
  
Gross
  
Net (RMG)
Castle Rock
  
123,520
  
48,772
Oyster Ridge(1)
  
64,677
 
40,375
Hi-Pro
  
49,009
  
39,521
Total
  
237,206
  
128,668

(1)     Data for Oyster Ridge assumes we will earn some of the acreage under a drill-to-earn agreement with Anadarko and another oil and gas company. See "Description of Prospects - Oyster Ridge" below.

Under a 2001 agreement, CCBM agreed to pay up to $5,000,000 for drilling and completing CBM wells on the properties owned by RMG and CCBM. This drilling commitment was completed by December 31, 2004. Pursuant to the agreement with CCBM, we have a carried working interest in all of the wells drilled with the CCBM drilling fund on properties owned in July 2001 (after the Pinnacle transaction), including the Castle Rock and Oyster Ridge properties. CCBM has the right to participate up to 50% of the working interest in CBM properties we acquire until the AMI expires on June 30, 2005. We will not receive carried interests from CCBM in future wells on any properties. Also pursuant to the 2001 Agreement, CCBM has bought a 25% working interest in the Anadarko Portion of Oyster Ridge and a 6.25% working interest in Castl e Rock.

RMG's leases of United States Bureau of Land Management ("BLM"), state and fee lands will require annual cash payments of approximately $347,500 in 2005 ($206,900 for RMG's portion, to keep undeveloped CBM leases.

Description of Prospects

Leases of federal mineral rights are obtained from the BLM and expire from 2005 to 2009, unless RMG establishes production on the lease, in which event the lease is held so long as CBM 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 2005 to 2009 in Wyoming and Montana, unless RMG establishes production on the lease, in which event the lease is held so long as CBM 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 $2.75 for non-producing Wyoming and Montana state leases.

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."

Leases on private (fee) land for CBM and conventional gas expire at various times from 2005 to 2009, and are held so long as the wells are capable of production on the lease. The landowner is paid a royalty from production of 12.5% to 20.0%, depending on the lease terms.

Castle Rock: The Castle Rock project consists of 123,520 gross and 48,772 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

  
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developed by other operators south of the Castle Rock acreage near the Montana/Wyoming border. Currently, there are no pipelines in this area.

Oyster Ridge: The Oyster Ridge project consists of two acreage positions: (1) 46,896 gross 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 (75% RMG and 25% CCBM) in 15,185 gross acres within this position, and earn-in rights on 31,711 gross acres held by Anadarko Petroleum, Inc.; and (2) 17,781 gross acres held by another oil and gas company (the "Other Party"), which are at the north and south ends of the Anadarko acreage.

The area is prospective for CBM from the Kemmerer and Adaville coals. The Kern River pipeline, which services southern California, crosses the property. Through December 31, 2004, $1,608,400 has been spent on drilling and completion at Oyster Ridge. RMG is the operator for all the acreage.

(1)    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. Wells drilled by us (with CCBM), have earned 3,200 acres. Four of the 2004 wells were drilled to the Frontier coal and four were drilled to the Adaville coal. These wells warrant further testing and the drilling of more exploratory wells.

31,711 gross acres in the Oyster Ridge project 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 wells drilled to date on this prospect. If Anadarko elects to participate in the future, working interest ownership in affected wells would be 56.25% RMG, 18.75% CCBM, and 25% Anadarko.

(2)    In February 2005, RMG signed an exploration and participation agreement to earn a 65% working interest from the Other Party in 17,781 gross mineral acres held by the Other Party under federal and Wyoming state leases. This agreement replaces a 2004 agreement between the parties.

The earn-in agreement is through December 31, 2011 if not terminated sooner. The agreement has two phases:

Commitment wells. On or before August 15, 2005, RMG will commence to drill, case and complete (at its sole expense) four CBM wells (at least one in the Frontier coal), each on a 640 acre drilling block. RMG must spend at least $300,000 on the total of four wells. Upon completion of the four wells, RMG shall have earned 65% of the Other Party's interest in the drilling block and in one additional section offsetting that block. The Other Party's retained 35% interest in each well will be relinquished until RMG attains payout.

Development program. If the four commitment wells have been completed, RMG may elect to commit to an on-going drilling program, by drilling a minimum of five wells per year on unearned Other Party leases or in drilling blocks containing at least 50% of unearned Other Party lands. The development program is extendable in this manner for up to three additional one-year terms. Each development well will earn RMG 65% of the unearned Other Party leasehold in the drilling block, and in the unearned Other Party leasehold in one offsetting section located nearest to the drilling block.


  
-18-
 

At payout to RMG of its drilling and completion costs for each commitment well, the Other Party may then back-in for a 35% working interest in the drilling block or keep only its overriding royalty interest (from 3.5% to 5% depending on the acreage). At payout of the first development well in a drilling block, the Other Party may either back in for a 35% working interest in the well or keep only its overriding royalty interest. These elections would not apply to the extent the Other Party elects to participate for a 35% working interest in any development well.

CCBM decided not to participate with us in the Other Party earn-in agreement.

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.

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. CBM is stored in four ways: 1) as free gas within the micropores (pores with a diameter of less than .0025 inch) and cleats (set of natural fractures in the coal); 2) as dissolved gas in water within the coal; 3) as absorbed gas held by molecular attraction on surfaces macerals (organic constituents that comprise the coal mass), micropores, and cleats in the coal, and 4) as absorbed gas within the molecular structure of the coal molecules. Coals at shallower depths wi th good cleat development contain significant amounts of free and dissolved gas while the percentage of absorbed methane generally increases with increasing pressure (depth) and coal rank. CBM gas is released by pressure changes when the water in the coal is removed. In contrast to conventional gas wells, new CBM 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:

1.    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 conductive to the formation of CBM.
2.    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 3 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).
3.    Installing (or have a transmission company install) a compressor and transport lines 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.

  
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Coalbed Methane Well Permitting

Operators drilling for CBM 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. 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 ("PRB") leases in Wyoming and Montana are subject to environmental rules, requirements and permits issued by various federal authorities for drilling and 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 Federal agency with related responsibilities is the BLM which has imposed environmental limitations and conditions on CBM drilling, production and related construction activities on federal leases in the PRB. These conditions and requirements are imposed through Records of Decision issued pursuant to Environmental Impact Statements ("EIS"). The BLM may also impose site-specific conditions on development activities, such as drilling and rights- of-way for the construction of roads, before it approves required applications for permits to drill and plans of development.

In April 2003, the BLM issued Records of Decision finalizing two impact statements: The Powder River Basin Oil and Gas EIS for the Wyoming portion of the basin, and the Statewide Oil and Gas EIS and Proposed Amendment for the Powder River and Billings Resource Management Plans in Montana. Together, the impact statements authorize the development of some 77,000 CBM gas wells in the Powder River Basin, most of which would be drilled on the Wyoming side of the basin.

With the EIS completed, the BLM will be able to consider drilling or development proposals in the geographic areas studied, however, before any permits are approved, the BLM will conduct an additional round of environmental review to identify site-specific environmental impacts and appropriate mitigation measures. Three lawsuits have been filed challenging the Record of Decisions, however, no stays have been issued. See Item 3, “Legal Proceedings - Rocky Mountain Gas, Inc.”

The state-based environmental agencies have primary jurisdiction over the issuance of permits related to drilling, land, air quality and water discharge. These agencies are:

1.  Wyoming Department of Environmental Quality ("WDEQ")
2.  Wyoming Oil and Gas Conservation Commission ("WOGCC")
3.  Montana Department of Environmental Quality ("MDEQ")
4.  Montana Board of Oil and Gas Conservation ("MBOGC")

While the BLM is primarily responsible for issuing broad-based EIS's 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.

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 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 drilling on the Castle Rock project), a drilling moratorium had been in effect during the last three years, prior to the approval of the two environmental impact statements.

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 CBM gas production, which typically entails substantial water production at least during the

  
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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 CBM wells, the disposal of this water is tightly regulated. If the SAR content is low, the water may 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 reservoirs may also be built near the wells, enabling the wells to d rain 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 to evaporate or permeate into the ground.

Overall, RMG has not experienced any difficulty in obtaining air quality and water discharge permits from the WDEQ, and those permits are in place for the Hi-Pro properties. RMG has not yet applied for such permits in Montana.

The following summarizes permits now in place.

Prospect
Remaining Permits
Castle Rock
0
Hi-Pro
8
Oyster Ridge
7
   
Total
15

Drilling permits issued by the State of Wyoming allow one year for drilling completion; permits issued by the State of Montana allow six months.

Once drilled, all wells producing water 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 project also 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.

Due to the low pressure characteristics of coalbeds, the production of CBM is dependent on the installation of multi-stage compression facilities. Gas is gathered from the wells, and transported 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 either discharged directly into the stream channel or pumped to a surface reservoir.

Companies involved in CBM production generally outsource gas gathering, compression and transmission. RMG will likely continue to outsource most of their compression to third parties at fixed charges based on volume transported.

Gas Markets

Gas production from the Powder River Basin is significant. Since this area is sparsely populated,

  
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most of the gas must be exported 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 way 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 ma rket 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 capacity is unavailable at times as pipelines are 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:

1.  The Colorado Interstate Gas ("CIG") station near Cheyenne in southeastern Wyoming which primarily feeds regional markets or markets in the Midwest.

2.  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.

3.  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

Two large diameter intrastate pipeline, the Fort Union and the Thunder Creek, were constructed in the Basin in 1999, and gathering system infrastructure has continued to grow significantly. 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.

·  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.

·  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 Hi-Pro production is delivered to the Thunder Creek pipeline where it is carried south and delivered to the CIG market.

El Paso Corporation's subsidiary Cheyenne Plains Gas Pipeline Co. received approval from the Federal Energy Regulatory Commission in March 2004 for construction of a new 380 mile pipeline from Cheyenne, Wyoming to Greensburg, Kansas, with a capacity of 560 Mmcf per day. Cheyenne Plains has announced its intent to apply to the FERC for permission to enlarge the line to handle 760 Mmcf per day. This line, with the enlarged capacity, was placed in-service in 2005, and may help further narrow the negative price differential for CIG prices compared to national prices.

  
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Pipelines That Serve the Ventura Market

There are currently only two significant pipelines capable of transporting gas out of the Basin to the north, the Bitter Creek pipeline, which connects with the Northern Border interstate pipeline and the Grasslands pipeline. Descriptions are as follows:

·  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.

·  Grasslands. In response to the need for expandable access to the Ventura market, the Grasslands pipeline, also owned by WBI, went into service in November 2003. It is a 245 mile, 16 inch line
with an initial capacity of 80 Mmcfd and reportably is expandable to 200 Mmcfd.

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 Kern River line with capacity of 1.73 Bcfd, delivering to markets in Utah, Nevada, Arizona and California. If the Oyster Ridge property is put into production, gas could be sold into this market.

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 can 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 can drop outside the heating season, while Ventura serves larger national markets and is highly correlated to Chicago market prices.

The negative price differential in the prices realized by Powder River Basin producers in 2004, as compared to prices realized on the national gas market, ranged from 8% to 23%.

Inactive Mining Properties - Uranium

General. We have interests in several uranium-bearing properties in Wyoming and Utah, and in the Shootaring Mill, in Garfield County, Utah, and properties in proximity to the mill. 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 develop and operate these properties (directly or through a subsidiary company or a joint venture) to produce uranium concentrates ("U3O8") for sale to public utilities with nuclear powered electricity generating plants. Uranium concentrate spot prices have increased substantially to $22 per pound at March 23, 2005, compared to $10 in 2002. However, further increases to sustained higher prices will be needed to warrant putting the properties in production. All of the uranium properties are shut down; work is performed on the mines to prevent flooding and permitting work is done as needed (monitoring and reporting) to keep existing permits in effect.

Over a period of at least 18 months, substantial and expensive work would be required to put the uranium mines into production, including permitting, cleaning rock and other debris from shafts and tunnels, pumping water out of the mines, extending shafts and tunnels, and drill sampling to ascertain whether a commercially viable ore body exists on any of the properties.


  
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A decision to put the uranium properties into production will depend upon uranium prices, mining and milling costs and the ability to raise the necessary funds.

At December 31, 2004, there are no values carried on the balance sheets for uranium properties.

However, we believe the uranium properties we now hold have significant value because uranium prices continue to rise and stabilize at higher prices. Our decision to proceed will be based on our efforts to raise capital through joint ventures or otherwise, to explore the properties further, and put the mines into production and refurbish the Shootaring Mill in Utah. To that end, we have signed an agreement to sell a 50% interest in the Sheep Mountain properties in Wyoming and enter into a joint venture agreement for those properties (and others to be acquired) with Bell Coast Capital Corp., now named Uranium Power Corp. ("UPC") and a separate agreement to lease and acquire more uranium properties in Utah.

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 31, 1988 to June 1, 1998, these properties were held by Sheep Mountain Partners ("SMP") a Colorado general partnership. In February 1988, USE and Crested acquired from Western Nuclear, Inc. unpatented lode uranium mines, mining equipment and mineralized properties (including underground and open pit mines) at Crooks Gap in south-central Fremont County, Wyoming. The mines were first operated by Western Nuclear in the 1970s. USECC mined and milled uranium ore from one of the underground Sheep Mines in 1988 and 1989. In December 1988, USECC sold 50 percent of the interest in the Crooks Gap properties to a subsidiary of Nukem, Inc. and formed Sheep Mountain Partners ("SMP"), in which USECC received an undivided 50 percent interest.

On June 1, 1998, the USE and Crested received back from SMP all of the Sheep Mountain mineral properties and equipment, in partial settlement of certain disputes with Nukem, Inc. Other of those disputes remain in litigation - see Item 3, "Legal Proceedings."

We have recorded reclamation liabilities for the SMP properties (see note K to the consolidated financial statements). All historical costs in the SMP properties were offset against a monetary award which was received from Nukem during fiscal 1999. Permits are in place only for standby maintenance of the mines and discharge of waste water pumped from the mines.

At the filing date of this report, we own 139 unpatented lode mining claims and a 644 acre Wyoming State Mineral Lease on Sheep Mountain in the Crooks Gap area.

- UPC Joint Venture.

Purchase and Sale Agreement. On December 8, 2004, USE and Crested entered into a Purchase and Sale Agreement (the “agreement”) with Bell Coast Capital Corp. now named Uranium Power Corp. (“UPC”), a British Columbia corporation (TSX-V “UCP-V”) for the sale to UPC of an undivided 50% interest in the Sheep Mountain properties. A summary of certain provisions in the agreement follows.

The initial purchase price for the 50% interest in the properties is $4,050,000 and 4,000,000 shares of common stock of UPC, payable by installments.


  
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Initial cash and equity purchase price:

October 29, 2004
$ 175,000
     Paid
     
November 29, 2004
$ 175,000
     Paid
     
June 29, 2005
$ 500,000
     and 1,000,000 common shares of UPC stock
     
June 29, 2006
$ 800,000
     and 750,000 common shares of UPC stock
     
December 29, 2006
$ 800,000
     and 750,000 common shares of UPC stock
     
June 29, 2007
$ 800,000
     and 750,000 common shares of UPC stock
     
December 29, 2007
$ 800,000
     and 750,000 common shares of UPC stock
     
Total
$ 4,050,000
     4,000,000 common shares of UPC stock

The cash portion of the initial purchase price will be increased by $3,000,000 (in two $1,500,000 installments) after the uranium oxide price (long term indicator) is at or exceeds $30.00/lb for four consecutive weeks (the “price benchmark”). If the price benchmark is attained on or before April 29, 2006, the first installment will be due six months after price attainment (but not before April 29, 2006). If the price benchmark is attained after April 29, 2006, the first installment will be due six months after attainment. In either event, the second installment will be due six months after the first installment is due. These payment obligations will survive closing of the purchase of the 50% interest in the properties; if the installments are not timely paid, UPC will forfeit all of its 50% interest i n the properties, and in the joint venture to be formed.

USE and Crested, and UPC, will each be responsible for paying 50% of (i) current and future Sheep Mountain reclamation costs in excess of $1,600,000, and (ii) all costs to maintain and hold the properties.

Closing of the agreement is required on or before December 29, 2007, with UPC’s last payment of the initial purchase price (plus, if applicable, the increase in the cash portion). At the closing, UPC will contribute its 50% interest in the properties, and USE and Crested will contribute their aggregate 50% interest in the properties, to the joint venture (see below), wherein UPC and USE/Crested each hold a 50% interest.

UPC will contribute up to $10,000,000 to the joint venture (at $500,000 for each of 20 exploration projects). USE/Crested, and UPC, each will be responsible for 50% of costs on each project in excess of $500,000.

UPC may terminate the agreement before closing, in which event UPC (i) would forfeit all payments made to termination date, (ii) lose all of its interest in the properties to be contributed by USE/Crested under the agreement and (iii) be relieved of its share of reclamation liabilities existing at December 8, 2004.

- Mining Venture Agreement

As of April 11, 2005, the company and Crested (as the USECC Joint Venture) signed a Mining Venture Agreement with UPC to establish a joint venture, with a term of 30 years, to explore, develop and mine the properties being purchased by UPC under the Purchase and Sale Agreement, and acquire,

  
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explore and develop additional uranium properties. The joint venture generally covers uranium properties in Wyoming and other properties identified in the USECC Joint Venture uranium property data base, but excluding the Green Mountain area and Kennecott’s Sweetwater uranium mill, the Shootaring Canyon uranium mill in southeast Utah (and properties within ten miles of that mill), and properties acquired in connection with a future joint venture involving that mill.

The initial participating interests in the joint venture (profits, losses and capital calls) are 50% for the USECC Joint Venture and 50% for UPC, based on their contributions of the Sheep Mountain properties. Operations will be funded by cash capital contributions of the parties; failure by a party to fund a capital call may result in a reduction or the elimination of its participating interest. In addition, a failure by UPC to pay for its 50% interest in the Sheep Mountain properties may result in a reduction or the elimination of UPC’s participating interest. A budget of $567,842 for the seven months ending December 31, 2005 has been approved, relating to reclamation work at the Sheep Mountain properties, exploration drilling, geological and engineering work, and other costs. A substantial portion of thi s work will be performed by (and be paid to) USECC Joint Venture as manager.

The manager of the joint venture is the USECC Joint Venture; the manager will implement the decisions of the management committee and operate the business of the joint venture. UPC and the USECC Joint Venture each have two representatives on the four person management committee, subject to change if the participating interests of the parties are adjusted. The manager is entitled to a management fee from the joint venture equal to a minimum of 10% of the manager’s costs to provide services and materials to the joint venture (excluding capital costs) for field work and personnel, office overhead and general and administrative expenses, and 2% of capital costs. The manager may be replaced if its participating interest becomes less than 50%.

The preceding is a summary of certain provisions of the Mining Venture Agreement and the Purchase and Sale Agreement, and is qualified by reference to those agreements which are filed as exhibits to this Annual Report.

Utah

In August 1993, USE purchased from Consumers Power Company ("CPC") all of the outstanding stock of Plateau, which owns the Shootaring Mill, a uranium processing mill in southeastern Utah for nominal cash consideration and the assumption of various reclamation obligations. The Shootaring Mill holds a source materials license from the NRC.

The Shootaring Mill, in southeastern Utah, occupies 19 acres of a 265 acre plant site. The Shootaring 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 (now a wholly-owned subsidiary of USE) placed the mill on standby because CPC had canceled the construction of an additional nuclear energy plant. Plateau also owns approximately 90,000 tons of uranium mineralized material stockpiled at the mill site.

In 2003 and 2004, reclamation work on uranium properties (the Tony M, Velvet, and Woods Complex, then held by Plateau in San Juan County, Utah) was completed. Plateau had relinquished these properties in 2003 and 2004, but has subsequently leased the Velvet from a third party who staked unpatented mining claims on the property (see below).

With recent improvements in uranium concentrate prices, Plateau has obtained an extension to January 2007 to commence reclamation work at the mill (reclamation costs are bonded, see Note K to the financial statements). Plateau has filed a request with the State of Utah for a permit and licenses to put the mill in operating status.

  
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The Shootaring Mill is owned by Plateau Resources Limited ("Plateau"), a subsidiary of USE. Crested has a 50% interest in Plateau’s cash flows. The Shootaring Mill was designed to process 750 tons of material per day (tpd) and should be capable of operating at 1,000 tpd, once refurbishing is completed.

When refurbished and the operational license is issued, the Shootaring Mill will have the capacity to produce 1.5 million pounds of uranium concentrates annually depending on the grade of material fed to the Shootaring Mill. It will cost at least $25 million to modify the Shootaring Mill’s tailings cell to Utah standards; post additional reclamation bonding; and complete other Shootaring Mill upgrades befo re production can begin. Additionally, a circuit to process the vanadium which is contained in almost all of the mineralized material is planned to be added to the Shootaring Mill.

Except for the lower grade mineralized material which has been stockpiled at the Shootaring Mill for over ten years, the grades of materials controlled at other properties in the vicinity have not been determined. Until such grades have been established with drilling and testing, and a feasibility study completed on the properties to determine the economics of running the Shootaring Mill to process these materials, we cannot determine if the properties contain any uranium reserves. In any event, the feasibility of the mines, and therefore of operating the Shootaring Mill, will be dependent on sustained high prices for uranium concentrates, and overall, the grades of material available for processing being economic (containing sufficient uranium) at such sustained high prices.

Once required financing is in place, the work is planned to be completed in approximately 18 months after the operating license is granted by the State of Utah, but unforeseen causes may delay the project. Efforts are underway while going through the State of Utah permitting process to raise the necessary financing for the project. However, financing terms have not been finalized, and we cannot predict if and when the financing will be completed.

In addition to the Shootaring Mill site, Plateau holds approximately 200 unpatented lode mining claims which have been acquired through a December 2004 agreement with a third party. Under this agreement, all of the uranium properties currently controlled or owned by the third party have been leased to Plateau (including the Velvet mine, currently shut down), and the third party will assist Plateau in locating additional uranium mineral properties for lease or purchase by Plateau. In return, the third party and Plateau will negotiate a contract mining agreement for the third party to mine and deliver uranium material from those properties to the Shootaring Mill for processing, and pay the third party for that material. In addition to purchasing the material, Plateau will pay the third party a 2.5% gross royalty of the value received by Plateau for uranium concentrates and vanadium recovered at the mill from such material. Plateau has agreed to fund the development of the uranium properties on a project-by-project basis, on terms and in amounts to be agreed upon with the third party.

Included in the properties acquired under the third party agreement is the Velvet Mine, located approximately 178 miles from the Shootaring Mill, which was developed in the 1970s. The prior owner drove several miles of access tunnels (adits) and drifts (access tunnels) and mined material from the workings.

Inactive Mining Properties - Gold

Sutter Gold Mining Inc. In fiscal 1991, USE acquired an interest in gold 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) was owned by Sutter Gold Mining Company, a Wyoming corporation ("SGMC"). SGMC has been acquired by Globemin Resources Inc., a TSX-V listed company, in a reverse takeover stock exchange transaction in 2004. Globemin has changed its name to Sutter Gold Mining, Inc. ("SGMI"). For information on ownership in SGMI by employees and director of USE, see Part III of this report.


  
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This property has never been in production. We do not have a current feasibility study to support a determination that the Lincoln Project contains gold reserves.

SGMC has taken impairments (write-downs), in the 1990s, totaling $13,098,900, of the carrying value of its gold properties. These two impairments wrote off almost 85% of the investment. We determined that we could not produce gold from these properties at a profit as a result of low market price for gold at the time. This resulted in no value allocated to the Lincoln Project; the remaining assets relating to this property include raw land which is no longer needed for mining activity, and buildings and equipment.

Due to the depressed gold prices in the past, litigation (since resolved) and lack of funding, SGMI has deferred the start of construction of a gold mill complex and extension of existing underground workings. A tourist visitor's 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. The conditional use permit is being kept current as necessary to allow for planned mining activities on the properties in the future.

Properties. SGMI holds approximately 535 acres of surface and mineral rights near Sutter Creek, Amador County, California. 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, and property taxes, will be approximately $130,000 and $9,900 respectively, for 2005.

The leases are for varying terms and require rental fees, annual royalty payments and payment of real property taxes and insurance.

The Lincoln Project has been the subject of considerable modern exploration activity, most of it centering on the Lincoln and Comet zones, which are adjacent to each other. A total of 85,085 feet of drilling have been accomplished in prior years, with 190 diamond drill holes, and modern underground development consists of a 2,850-foot declined ramp with 2,400 feet of crosscuts plus four raises.

SGMI plans to begin further exploration work and the construction of a new raise to comply with U.S. Mine Safety Health Administration regulations and improve ventilation.

Permits. The Amador County Board of Supervisors has issued a Conditional Use Permit ("CUP") allowing mining and milling of up to 1,000 tons per day, subject to conditions relating to land use, environmental and public safety issues, road construction and improvement, and site reclamation. Application has been made to the California regulatory authorities, to store de-watered tails at a dry stacked surface fill unit, and also use mill tailings for mine back fill. This permit is the final major permit required for the project; a decision is expected in second quarter 2005.

Visitor's Center. The visitor's center, operated by a third party, 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 $40,300 for 2004, $48,800 for 2003, $26,500 for the seven months ended December 31, 2002, and $41,200 in (former) fiscal year ended May 31, 2002, and are included in "real estate" in the consolidated statements of operations included in this report. These revenues offset a portion of costs for holding the Sutte r properties.

  
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Molybdenum

In 1974, 1977 and 1987, USE and Crested leased and then sold various mining claims and mines near the town of Crested Butte, Colorado, to AMAX Inc. of Greenwich, Connecticut. AMAX Inc. (acquired by Cyprus Minerals Company and renamed Cyprus Amax Minerals Company in November 1993, then later acquired by Phelps Dodge) delineated a deposit of molybdenum on the leased claims containing approximately 146,000,000 tons of mineralization averaging 0.43% molybdenum disulfide on the properties of USE and Crested.

Since June 2002, USE and Crested have been in litigation with Phelps Dodge concerning the properties and related agreements. In late 2004 and February 2005, the U.S. District Court issued orders in the litigation (see Item 3 - "Legal Proceedings"). Although additional rulings are expected concerning water rights associated with the properties, we expect to receive back from Phelps Dodge, in 2005, the patented and unpatented lode mining claims which contain the molybdenum deposit, as well as a mine water discharge treatment plant located on those properties. Later in 2005, we expect to be receiving clarification from the Colorado Department of Public Health and the Environment (which has jurisdiction over how the treatment plant is operated to comply with environmental laws) as to our responsibilities to operate the plant. Plant operating costs, for which we will be responsible, will likely exceed $1,000,000 annually.

For more than 20 years, Phelps Dodge and its predecessor companies worked on a mine plan for the Mt. Emmons property, obtaining rights to the water necessary to mine and process molybdenum, and obtaining other permits necessary to put the property into production. We do not know why Phelps Dodge, one of the largest international mining companies, decided to cease trying to put the Mt. Emmons property into production, although the fact that Phelps Dodge is producing molybdenum from other mines may have been a factor in their decision.

In light of the rebound in molybdenum oxide prices to the $30 - $35 per pound range in March 2005 (compared to an average of approximately $3.25 per pound over the last several years), we may seek joint venture partners to work on a new mine plan and obtain the permits required to put the property into production. In this scenario, the properties would be transferred to a new subsidiary of USE and Crested, U.S. Moly Corp., then the subsidiary would seek to raise capital for the project and enlist large mining companies or other entities to enter into a joint mining venture. See Part III to this Annual Report. Ownership of the subsidiary subsequently would be reduced to the extent additional shares are sold to investors.

Development of the Mt. Emmons property for mining will require extensive capital and a long time to implement. We would have to obtain that capital through equity financing and/or a joint venture or other arrangement, however, we have no such arrangements as of the date of this Annual Report and may not obtain such. Reportedly, the mine plan of Phelps Dodge and its predecessor companies encountered opposition from local and environmental groups, and that opposition likely will continue, as Mt. Emmons is located close to Crested Butte, Colorado, a year round recreation area. Even with the resources of a joint venture partner, successful resolution of various issues arising with local and environmental groups is not assured.


  
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Oil and Gas and Other Properties

Fort Peck Lustre Field (Montana). We operate a small oil production facility (two 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.

Wyoming. 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 non-affiliates and government agencies; the second floor is occupied by the Company. The property is mortgaged to the WDEQ as security for future reclamation work on the Sheep Mountain Crooks Gap uranium properties.

The Company also owns 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 aircraft fueling operation 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 175 acres of undeveloped land near Gunnison, Colorado.

Utah. On August 14, 2003, USE's wholly-owned subsidiary Plateau Resources Limited (and Plateau's wholly-owned subsidiary Canyon Homesteads, Inc.) sold all of the outstanding stock of Canyon Homesteads to The Cactus Group, LLC, for $3,470,000: $349,250 cash and $3,120,750 with The Cactus Group's five year promissory note. The note is secured with all the assets of The Cactus Group and Canyon (and is personally guaranteed by the six principals of The Cactus Group). The note is payable monthly (with annual interest at 7.5%) with a $2,940,581 balloon payment due in August 2008.

The sold properties are in Ticaboo, Utah, near Lake Powell, and included a motel, restaurant and lounge, convenience store, recreational boat storage and service facility, and improved residential and mobile home lots. Most of these properties had been acquired when the Shootaring Mill was acquired in the early 1990s.

RESEARCH AND DEVELOPMENT

No research and development expenditures have been incurred, either on the Company's account or sponsored by customer, 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, 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 statues, Abandoned Mine Reclamation Act and industrial development and siting laws and regulations also impact us. Similar law and regulations in California affect SGMI operations and Utah laws and regulations effect Plateau's operations.

  
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Management believes the Company complies in all material respects with existing environmental regulations.

As of December 31, 2004, we have recorded estimated reclamation obligations of $8,027,400. We anticipate paying for those reclamation efforts 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 Annual Report.

Other Environmental Costs. Actual costs for compliance with environmental laws may vary considerably from estimates, depending upon such factors as changes in environmental law and regulations (e.g., the new Clean Air Act), and conditions encountered in minerals exploration and mining. We do not anticipate that expenditures to comply with law regulating the discharge of materials into the environment, or which are otherwise designed to protect the environment, will have any substantial adverse impact on our competitive position.

Employees

As of the filing date of this Annual Report, USE had 35 full-time employees, including 11 working only for RMG. Persons who work only for RMG and Sutter Gold Mining Inc. are paid by USE. The expenses associated with USE's employees, including payroll taxes, fringe benefits and retirement plans is shared with Crested for all ventures in which it participates on a percentage ownership basis. 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 and 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 and make certain additional filings with the county and the BLM. Failure to pay such fees or make the required filing 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 time of falling metal prices, claims which were valid wh en located could become invalid if challenged.

Some of the Mt. Emmons claims which the Company expects to receive back from Phelps Dodge Corporation were patented by Phelps Dodge and others are unpatented claims.

 

  
-31-
 

Proposed Federal Legislation. The U.S. Congress from time to time has considered proposed revisions to the General Mining Law, which governs mining claims and related activities on federal public lands. If these proposed revisions were enacted, payment of royalties on production of minerals from federal lands could be required as well as new requirements for reclamation of mined land and other environmental control measures. The effect of any revision of the General Mining Law on operations cannot be determined until enactment, however, it is possible that revisions would materially increase the carrying and operating costs of mineral properties located on federal unpatented mining claims.

ITEM 3. Legal Proceedings

Material proceedings pending at December 31, 2004, and developments in those proceedings from that date to the date this Annual Report is filed, are summarized below. Other proceedings which were pending during the year have been settled or otherwise finally resolved.

Sheep Mountain Partners Arbitration/Litigation

In 1991, disputes arose between USE/Crested d/b/a/ USECC, and Nukem, Inc. and its subsidiary Cycle Resource Investment Corp. ("CRIC"), concerning the formation and operation of their equally owned Sheep Mountain Partners (SMP) 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 of Colorado in Civil Action No. 91B1153. The Federal Court stayed the arbitration proceedings and discovery proceeded. In February 1994, all of the parties agreed to consensual and binding arbitration of all of their disputes over SMP before an arbitration panel (the "Panel").

The Panel entered an Order and Award in 1996, finding generally in favor of USE and Crested on certain of their claims and imposed a constructive trust in favor of Sheep Mountain Partners on uranium contracts Nukem entered into to purchase uranium from CIS republics, and also awarded SMP damages of $31,355,070 against Nukem. Further legal proceedings ensued. On appeal, the 10th Circuit Court of Appeals ("CCA") issued an Order and Judgment affirming the U.S. 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 in favor of SMP against Nukem.

As a result of further proceedings, the U.S. District Court appointed a Special Master to conduct an accounting of the constructive trust. The U.S. District Court adopted the Special Master’s report in part and rejected it in part, and entered judgment on August 1, 2003 in favor of USECC and against Nukem for $20,044,183. In early 2004, the parties appealed this judgment to the CCA.

On February 24, 2005, a three judge panel of the CCA vacated the judgment of the U.S. District Court and remanded the case to the Panel for clarification of the 1996 Order and Award. In remanding this case, the CCA stated: "The arbitration award in this case is silent as to the definition of 'purchase rights' and the 'profits therefrom,' including the valuation of either. Also unstated in the award is the duration of the constructive trust and whether and what costs should be deducted when computing the value of the constructive trust. Further, the arbitration panel failed to address whether prejudgment interest should be awarded on the value of the constructive trust. As a result, the district court's valuation of the constructive trust was based upon extensive guesswork. Therefore, a remand to the arbitration panel for clarification is necessary, despite the long and tortured procedural history of this case."

The timing and ultimate outcome of this litigation is not predicted. We believe that the ultimate outcome will not have an adverse affect on our financial condition or results of operations.


  
-32-
 

Contour Development Litigation

On July 8, 1998, USE and Crested filed a lawsuit in the U.S. District Court of Colorado in Case No. 98WM1630, against Contour Development Company, L.L.C. and entities and persons associated with Contour Development Company, L.L.C. for substantial damages from the defendants for dealings in real estate owned by USE and Crested in Gunnison, Colorado. This litigation was settled in 2004 with USE and Crested receiving nominal cash and seven real estate lots in and near Gunnison. Two lots have been sold and five are for sale.

Phelps Dodge Litigation

USE 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 (“PD”) and its subsidiary, Mt. Emmons Mining Company (“MEMCO”), over contractual obligations in USECC’s agreement with PD’s predecessor companies, concerning mining properties on Mt. Emmons, near Crested Butte, Colorado.

The litigation relates to agreements from 1974 when USE and Crested leased the mining claims to AMAX Inc., PD’s predecessor company. The mining claims cover one of the world’s largest and richest deposits of molybdenum, which was discovered by AMAX.

The June 19, 2002 complaint filed by PD and MEMCO sought a determination that PD’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, USE 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 Mineral Co. USECC’s counter and cross-claims alleged that in 1999, PD formed a wholly-owned subsidiary CAV Corporation, for the purpose of purchasing the controlling interest in Cyprus Amax and its subsidiaries (including MEMCO) and making Cyprus Amax a subsidiary of PD. Therefore, USECC asserted that the acquisition of Cyprus Amax by PD was a sale of MEMCO and the properties that triggered the obl igation of Cyprus Amax to pay USECC the $3.75 million plus interest.

The other issues in the litigation were whether USECC must, under terms of a 1987 Royalty Deed, accept PD's and MEMCO's 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. PD's and MEMCO's claim sought to obligate USECC to assume the operating costs of the water treatment plant. USECC asserted counterclaims against the defendants, including a claim for nonpayment of advance royalties.

On July 28, 2004, the Court entered an Order granting certain of PD's motions and denying USECC's counterclaims and cross-claims. The case was tried in late 2004.

On February 4, 2005, the Court entered Findings and Fact and Conclusions of Law and ordered that the conveyance of the Mt. Emmons properties under Paragraph 8 of the 1987 Agreement includes the transfer of ownership and operational responsibility for the Water Treatment Plant, and that PD does not owe USECC any advanced royalty payments. However, the Order did not address the NPDES permit. NPDES permits are administered and regulated by the Colorado Department of Public Health and the Environment (“CDPHE”). The timing and scope of responsibilities for maintaining and operating the plant will be addressed by the CDPHE later in 2005.

USECC has filed a motion with the Court to amend the Order to determine that the decreed water rights from the Colorado Supreme Court opinion (decided in 2002, finding that the predecessor owners of
the Mt. Emmons property had rights to water to develop a mine), and any other appurtenant water rights, be conveyed to USECC. The motion is pending.

  
-33-
 


Rocky Mountain Gas, Inc. (RMG)

Litigation involving leases on coalbed methane properties in Montana

In April 2001, RMG was served with a Second Amended Complaint, in which the Northern Plains Resource Council ("NPRC") had filed suit in the U. S. District Court of Montana, Billings Division (No. CV-01-96-BLG-RWA) against the United States Bureau of Land Management (“BLM”), RMG, certain of its affiliates (including USE and Crested) and 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.

In December 2003, Federal District Court Judge Anderson granted BLM’s and the other defendants Motion for Summary Judgment and ruled that BLM did not have to consider environmental impacts in an Environmental Impact Statement (“EIS”) prior to leasing because the 1994 Resource Management Plan (“RMP”) limited lease right to exploration and small scale development. On August 30, 2004, the Ninth Circuit Court of Appeals affirmed the District Court decision and held that the six-year statue of limitations precluded challenging the 1994 RMP and EIS. On February 10, 2005, NRPC's petition for rehearing or in the alternative petition for en banc hearing was denied by the Ninth Circuit Court of Appeals.

All of RMG's BLM Montana leases are held by RMG and are at least four years old. There is no record of any objections being made to the issue of those leases. 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 BLM leases in Montana.

Lawsuits challenging BLM's Records of Decisions

There is a lawsuit currently pending in the Montana Federal District Court challenging BLM's Records of Decisions for the Powder River Basin Oil and Gas EIS for the Wyoming portion of the basin, and the Statewide Oil and Gas EIS and Proposed Amendment for the Powder River and Billings Resource Management Plans in Montana:

In April of 2003 NPRC and the Northern Cheyenne Tribe and Native Action (the “Tribe”) filed a suit against BLM challenging the April 2003 decision by BLM approving the Final Statewide Oil and Gas Environmental Impact Statement (FEIS) and proposed amendments to the RMP. On February 25, 2005 Federal District Court Judge Anderson dismissed all counts with the exception of the allegation that the FEIS is inadequate because it failed to consider any alternatives to full-field development and ruled that BLM’s failure to analyze a phased development alternative renders the FEIS inadequate. BLM will now be required to perform a Supplemental EIS (“SEIS”) examining a phased development alternative, which could take 18 months to complete.

On April 5, 2005 Federal District Court Judge Anderson rejected the Tribe's request for a complete moratorium on CBM drilling in Montana and instead accepted the BLM's proposal that limited the number of Federal APDs issued by the BLM to a maximum of 500 wells per year, including federal, state and fee wells within a certain defined geographic area. The decision will prohibit the BLM from issuing Federal wells in RMG's Castle Rock property until the SEIS is completed, because it is not located with the defined geographic area. However, the decision does not limit the number of fee and state wells that can be approved in the Castle Rock property by the State of Montana. RMG will request the BLM to extend the expiration date of th e Federal leases for the period of the delay.

  
-34-
 


Neither the Company nor RMG is a party to this lawsuit. However, further permitting for federal CBM wells in Montana could be impacted until the issues have been resolved.

Litigation involving drilling

A drilling company, Eagle Energy Services, LLC filed a lawsuit against RMG for drilling services claiming $49,309.50 for non-payment in Civil Action No. C02-9-341. Eagle Energy’s bank, Community First National Bank of Sheridan, Wyoming, filed a similar suit for the same amount on an assignment from Eagle Energy against RMG in Civil Action No. CO2-9-328 in the 4th Judicial District of Sheridan County, Wyoming. In February 2005 RMG and Community First reached a full and complete settlement of Civil Action No. C02-9-328 and a Joint Motion to Dismiss with Prejudice is currently pending with the Court. RMG has also request ed Eagle Energy to join in a Motion to Dismiss in Civil Action No. C02-9-341 because the claim was settled as noted above. Management believes that the ultimate outcome of the matters will not have a material effect on the Company’s financial condition or result of operations.

ITEM 4. Submission of Matters to a Vote of Security Holders

On June 15, 2004, the annual meeting of shareholders was held for voting on the re-election of two directors: Michael Anderson and Harold F. Herron. 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 the two directors, the votes cast were:

Name of Director
  
For
  
Abstain*
Michael Anderson
  
11,554,562
  
334,210
Harold F. Herron
  
11,303,419
  
531,578

Also at the June, 2004 meeting, the shareholders approved an amendment to the 2001 Incentive Stock Option Plan, to reserve for issuance upon exercise of options that number of shares of common stock as equals 20% of the issued and outstanding shares of common stock at any point in time. With respect to this matter the votes cast were:

For
  
Against
  
Abstain*
         
3,851,612
  
1,327,608
  
21,833

* Includes Broker non-vote

  
-35-
 

PART II

ITEM 5. Market for Registrant's common equity, related Stockholder Matters and Issuer Purchases of Equity Securities

(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 on the Nasdaq Small Cap of the National Association of Securities Dealers Automated Quotation System ("Nasdaq"). The range by quarter of high and low sales prices was:

Fiscal Year ended December 31, 2004
    
High
    
Low
  
First quarter ended 3/31/04
  
$
3.45
  
$
2.41
  
Second quarter ended 6/30/04
    
3.14
   
2.11
  
Third quarter ended 9/30/04
    
2.59
    
2.12
  
Fourth quarter ended 12/31/04
    
3.05
    
2.10
  
               
Fiscal Year ended December 31, 2003
              
First quarter ended 3/31/03
  
$
3.85
  
$
2.95
  
Second quarter ended 6/30/03
    
5.92
   
3.12
 
Third quarter ended 9/30/03
    
5.70
   
3.15
 
Fourth quarter ended 12/31/03
    
3.68
   
2.30
 

(b)    Holders    

(1)          At March 31, 2005 the closing market price was $5.98 per share and there were approximately 641 shareholders of record, with 16,219,079 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.

(d)           Equity Plan Compensation Information - Information about Compensation Plans as of December 31, 2004:

  
-36-
 


Plan category
Number of securities to be issued upon exercise of outstanding options
Weighted average exercise price of outstanding options
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
 
(a)
(b)
(c)
Equity compensation plans approved by security holders
 
  
 
1998 USE ISOP 3,250,000 shares of common stock on exercise of outstanding options
1,464,646
$2.67
-0-
2001 USE ISOP 3,000,000 shares of common stock on exercise of outstanding options
2,659,000
$2.85
214,664
Equity compensation plans not approved by security holders
 
  
 
None
--
--
--
Total
4,123,646
$2.79
214,664
Sales of Unregistered Securities in 2004

During the twelve months ended December 31, 2004, pursuant to the shareholder-approved 2001 Stock Compensation Plan, 50,000 shares were issued to officers of the Company at the rate of 10,000 shares each: John L. Larsen, Keith G. Larsen, Harold F. Herron, Robert Scott Lorimer, and Daniel P. Svilar. The shares were issued at the closing market price of $3.02, $2.57, $2.46 and $2.22 as of January 5, 2004, April 1, 2004, July 1, 2004 and October 1, 2004, respectively.

In 2004, the Company issued 476,883 shares of common stock as payment of principal and interest to settle the note due two private investors; 123,879 shares of common stock in exchange for 124,444 shares of RMG stock as part of a provision given to an accredited investor when it invested in RMG common stock; 678,888 shares of common stock and 318,465 common stock warrants (exercisable until January 2007 at an exercise price of $3.28 per share) in the purchase of the Hi-Pro properties; 100,000 shares of common stock and 250,000 warrants (exercisable until March 2009 at an exercise price of $2.98 per share) to purchase common stock to an accredited investor in a private placement; 758,360 shares of common stock to an accredited investor in exchange for 500,000 shares of RMG Series A preferred stock; released 22,1 40 shares of forfeitable shares to employees and 50,000 shares of common stock to five employees under the 2001 Stock Award Program, which was approved by the shareholders at the 2002 shareholder's meeting, 125,000 shares to an investor who exercised its warrants and 70,439 shares to the

  
-37-
 

USE Employee Stock Ownership Plan for the calendar 2004 funding requirement. Three investment firms held an additional 300,000 shares of RMG preferred stock (at an exchange rate of 90% the Company's stock price on conversion date), convertible to the Company's common stock at 90% of the market value of the Company's common stock when converted. All this stock has been converted as of March 31, 2005. The Company also issued a total of 150,000 common stock purchase warrants (exercisable until February 2007, at an exercise price of $3.11 per share) to three accredited investment firms as part of their investment in RMG Series A preferred stock. Warrants on 125,000 of these shares have been exercised as of March 31, 2005. These transactions were exempt under Section 4(2) of the Securities Act.

 


-38-
 
ITEM 6. Selected Financial Data

The selected financial data is derived from and should be read with the financial statements for USE included in this Report.

   
December 31,
  
May 31,
  
   
2004
  
2003
  
2002
  
2001
  
2002
  
2001
  
2000
  
               
(Unaudited)
              
                               
Current assets
  
$
5,421,500
  
$
5,191,400
  
$
4,755,300
  
$
4,597,900
  
$
4,892,600
  
$
3,330,000
  
$
3,456,800
  
Current liabilities
    
6,058,000
    
1,909,700
   
2,044,400
    
2,563,800
    
1,406,400
    
2,396,700
    
6,617,900
  
Working capital deficit
    
(636,500
)
  
3,281,700
   
2,710,900
    
2,034,100
    
3,486,200
    
933,300
    
(3,161,100
)
Total assets
    
30,703,700
    
23,929,700
   
28,190,600
    
30,991,700
    
30,537,900
    
30,465,200
    
30,876,100
  
Long-term obligations (1)
    
13,615,300
    
12,036,600
   
14,047,300
    
13,596,400
    
13,804,300
    
13,836,700
    
14,025,200
  
Shareholders' deficit
    
6,281,300
    
6,760,800
   
8,501,600
    
8,018,700
    
11,742,000
    
8,465,400
    
4,683,800
  
                                             
(1)Includes $7,384,700, of accrued reclamation costs on properties at December 31, 2004$7,264,700 at December 31, 2003, and $8,906,800, at December 31, 2002, 2001 and May 31, 2001 and 2000, respectively. See Note K of Notes to Consolidated Financial Statements.

                               
   
Year Ended
  
Seven Months Ended
              
   
December 31,
  
December 31,
  
For Former Fiscal Years Ended May 31,
  
   
2004
  
2003
  
2002
  
2001
  
2002
  
2001
  
2000
  
               
(Unaudited)
              
                               
Operating revenues
 
$
4,641,700
  
$
837,300
  
$
673,000
  
$
545,900
  
$
2,004,100
  
$
3,263,000
  
$
3,303,900
  
Loss from
                                           
continuing operations
   
(6,659,300
)
  
(7,237,900
)
  
(3,524,900
)
  
(3,914,900
)
  
(7,454,200
)
  
(7,517,800
)
  
(11,356,100
)
Other income & expenses
   
13,000
    
(73,000
)
  
(387,100
)
  
1,005,000
   
1,319,500
   
8,730,800
   
802,200
 
Loss before minority interest, equity
                                            
in loss of affiliates, income
                                            
taxes, discontinued operations,
                                            
and cumulative effect of
   
   
   
   
   
   
       
accounting change
   
(6,646,300
)
  
(7,310,900
)
  
(3,912,000
)
  
(2,909,900
)
  
(6,134,700
)
  
1,213,000
   
(10,553,900
)
Minority interest in loss
                                           
of consolidated subsidiaries
   
397,700
    
235,100
   
54,800
   
24,500
   
39,500
   
220,100
   
509,300
 
Equity in loss of affiliates
   
--
    
--
   
--
   
--
   
--
   
--
   
(2,900
)
Income taxes
   
--
    
--
   
--
   
--
   
--
   
--
   
--
 
Discontinued operations, net of tax
   
--
    
(349,900
)
  
17,100
   
175,000
   
(85,900
)
  
488,100
   
(594,300
)
Cumulative effect of
                                           
accounting change
   
--
    
1,615,600
   
--
   
--
   
--
   
--
   
--
 
Preferred stock dividends
   
--
    
--
   
--
   
(75,000
)
  
(86,500
)
  
(150,000
)
  
(20,800
)
Net loss to common shareholders
 
$
(6,248,600
)
$
(5,810,100
)
$
(3,840,100
)
$
(2,785,400
)
$
(6,267,600
)
$
1,771,200
  
$
(10,662,600
)
 

-39-

                       
   
Year Ended
December 31,
  
Seven Months Ended
December 31,
  
For Former
Fiscal Years Ended May 31,
  
               
(Unaudited)
              
   
2004
  
2003
  
2002
  
2001
  
2002
  
2001
  
2000
  
Per share financial data
                              
                               
Operating revenues
 
$
0.35
  
$
0.07
  
$
0.06
  
$
0.07
  
$
0.22
  
$
0.42
  
$
0.43
  
                                             
Loss from
                                            
continuing operations
   
(0.51
)
  
(0.64
)
  
(0.33
)
  
(0.47
)
  
(0.80
)
  
(0.96
)
  
(1.39
)
                                             
Other income & expense
   
0.00
    
(0.01
)
  
(0.03
)
  
0.12
   
0.14
   
1.11
   
0.01
 
                                             
Loss before minority
                                           
interest, equity in loss
                                            
of affiliates, income taxes,
                                           
discontinued operations,
                                           
and cumulative effect of
   
   
   
   
   
   
       
accounting change
   
(0.50
)
  
(0.65
)
  
(0.36
)
  
(0.35
)
  
(0.66
)
  
0.15
   
(1.38
)
                                             
Minority interest in loss (income)
                                           
of consolidated subsidiaries
   
0.03
    
0.02
   
--
   
--
   
0.01
   
0.03
   
0.07
 
                                             
Equity in loss of affiliates
   
--
    
--
   
--
   
--
   
--
   
--
   
--
 
                                             
Income taxes
   
--
    
--
   
--
   
--
   
--
   
--
   
--
 
                                             
Discontinued operations,
                                           
net of tax
   
--
    
(0.03
)
  
--
   
0.02
   
(0.01
)
  
0.06
   
(0.08
)
                                             
Cumulative effect of
                                           
accounting change
   
--
    
0.14
   
--
   
--
   
--
   
--
   
--
 
                                             
Preferred stock dividends
   
--
    
--
   
--
   
(0.01
)
  
(0.01
)
  
(0.01
)
  
--
 
                                             
Net (loss) income
                                           
per share, basic
 
$
(0.47
)
$
(0.52
)
$
(0.36
)
$
(0.34
)
$
(0.67
)
$
0.23
  
$
(1.39
)
                                             
Net (loss) income
                                           
per share, diluted
 
$
(0.47
)
$
(0.52
)
$
(0.36
)
$
(0.34
)
$
(0.67
)
$
0.23
  
$
(1.39
)

 
-40-
 
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 the Company's 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 the minerals business, the Company's actual results may differ materially from the results discussed in any such forward-looking statements.

General Overview

U.S. Energy Corp. ("USE" or the "Company") and its subsidiaries historically have been involved in the acquisition, exploration, development and production of properties prospective for hard rock minerals including lead, zinc, silver, molybdenum, gold, uranium, oil and gas and commercial real estate. The Company manages all of its operations through a joint venture, USECC Joint Venture ("USECC"), with one of its subsidiary companies, Crested Corp. ("Crested") of which it owns a consolidated 70.1%. The narrative discussion of this MD&A refers only to USE or the Company but includes the consolidated financial statements of Crested, Rocky Mountain Gas, Inc. ("RMG"), Plateau Resources Ltd. ("Plateau"), USECC and other subsidiaries. The Company has entered into partnerships through which it either joint ventured or leased properties with non-related parties for the development and production of certain of its mineral properties. Due to either depressed metal market prices or disputes in certain of the partnerships, all mineral properties have either been sold, reclaimed or are shut down except coalbed methane. However, activities have resumed on a limited basis in uranium and gold. See Items 2 and 3 above. The Company has had no production from any of its mineral properties during the periods from May 31, 2001 through December 31, 2004, except coalbed methane.

The Company formed RMG to enter into the coalbed methane (CBM) business in 1999. The acquisition of leases and acreage for the exploration, development and production of coalbed methane became the primary business focus of the Company. At December 31, 2004, the Company on a consolidated basis, owned 91.1% of RMG. RMG has purchased or leased acreage for CBM exploration and development. RMG has entered into various agreements and joint operating agreements to develop and produce coalbed methane from these properties. Management of the Company plan to create value in RMG by growing RMG into an industry recognized producer of CBM. Management believes the fundamentals of natural gas supply and demand are, and will remain favorable well into the future. Management further believes that the investments the Company has made in RMG will provide a solid base of cash flows into the future.
 
The price that RMG receives for the sale of its coalbed methane is based on the Colorado Interstate Gas Index (“CIG”) for the Northern Rockies. Historically, the highest prices realized on the CIG over a twelve-month period are during the months of December and January and the lowest prices realized are during the months of late summer or early fall. The following table represents a summary of historical CIG prices:

   
Prices per mcf
  
   
2004
  
2003
  
2002
  
2001
  
2000
  
                       
12 Month High
  
$
6.98
  
$
5.01
  
$
3.33
  
$
8.63
  
$
5.95
  
12 Month Low
  
$
4.17
  
$
3.14
  
$
1.09
  
$
1.05
  
$
2.15
  
12 Month Average
  
$
5.17
  
$
3.98
  
$
1.97
  
$
3.50
  
$
3.37
  

 

    

   

   

   

   

 
December 31
  
$
6.20
  
$
4.44
  
$
3.33
  
$
2.13
  
$
5.95
  


  
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     Although management believes that gas prices will increase over the long term from present levels, no assurance can be given that will happen. Gas prices are directly affected by 1) weather conditions, which impact heating and cooling requirements; 2) electrical generation needs and 3) the amount of gas being produced by those companies in the gas production business. Many of the Company's industry competitors are very large international companies that are well funded. All of these factors are variable and cannot be accurately predicted.

In the first quarter 2004, the Company obtained $350,000 of equity funding from an accredited investor (100,000 shares of USE common stock, three year warrants to purchase 50,000 shares of USE common stock, at $3.00 per share; and five year warrants to purchase 200,000 shares at $3.00 per share).

In the third quarter 2004, we borrowed $3,000,000 from Geddes and Company of Phoenix, Arizona. The loan matures on July 30, 2006, bears 10% annual interest, and is secured principally by RMG's CBM properties in the Castle Rock prospect and 4,000,000 shares of RMG stock held by the Company. The loan may be prepaid in cash without penalty, but the lender at any time may convert loan principal to RMG common stock at $3.00 per share on the first $1,500,000 converted; and at $3.25, $3.50 and $3.75 per share for each additional $500,000 converted. In connection with the loan, RMG issued to the lender five year warrants to buy 600,000 shares of common stock of RMG: $3.00 per share for 300,000 shares; and $3.25, $3.50 and $3.75 per share for 100,000 shares at each price.

In the first quarter 2004, RMG raised $1,800,000 of equity financing from the sale of shares of 600,000 shares of Series A Preferred Stock in RMG, and warrants to purchase shares of common stock of the Company, to institutional investors. Proceeds were used to pay part of the Hi-Pro acquisition price, and for RMG working capital. As of March 3, 2005, all Series A Preferred Stock including dividends have been converted to and paid with 894,299 shares of the Company’s common stock. Additionally the institutional investors exercised all 150,000 of their warrants for which the Company received $251,100 during the fourth quarter of 2004 and $73,700 during the first quarter of 2005.

On January 30, 2004, RMG organized a wholly-owned subsidiary RMG I, LLC for the purchase of producing and non-producing CBM properties (the "Hi-Pro properties) near Gillette, Wyoming. RMG I, LLC ("RMG I"), a wholly-owned subsidiary of RMG, purchased CBM properties from Hi-Pro for $6,800,000. RMG and the Company participated in raising equity capital and mezzanine financing for this transaction.

During the last six months of the year ended December 31, 2004 and the first quarter of 2005 uranium, gold and molybdenum market prices have experienced significant increases. Due to these increased market price conditions and industry projected prices over the foreseeable future, the Company is in the process of re-evaluating its mineral properties for these metals. Management of the Company is developing plans to maximize the value of existing properties and is in the process of acquiring and in some cases re-acquiring uranium properties.

A major component of the Company’s future cash flow projections is the ultimate resolution of litigation with Nukem, Inc. (“Nukem”) over issues relating to Sheep Mountain Partners (“SMP”) assets. On August 1, 2003, the U. S. District Court of Colorado entered a Judgment in favor of the Company and USE against Nukem in the amount of $20,044,183. Nukem appealed this Judgment to the 10th Circuit Court of Appeals (“10th CCA”) and USECC cross appealed. Oral Arguments were heard by the 10th CCA on September 28, 2004.

On February 24, 2005, a three judge panel of the 10th CCA vacated the judgment of the U.S. District Court and remanded the case to the Panel for clarification of the 1996 Order and Award. In remanding this case, the 10th CCA stated: "The arbitration award in this case is silent as to the definition of 'purchase

  
-42-
 

rights' and the 'profits therefrom,' including the valuation of either. Also unstated in the award is the duration of the constructive trust and whether and what costs should be deducted when computing the value of the constructive trust. Further, the arbitration panel failed to address whether prejudgment interest should be awarded on the value of the constructive trust. As a result, the district court's valuation of the constructive trust was based upon extensive guesswork. Therefore, a remand to the arbitration panel for clarification is necessary, despite the long and tortured procedural history of this case."

Management is not able to predict the timing and ultimate outcome of the Nukem litigation. We do however believe that the ultimate outcome will not have an adverse affect on our financial condition or results of operations.

On February 4, 2005, the U.S. District Court of Colorado entered Findings of Fact and Conclusions of Law in a case involving the Company, Crested and Phelps Dodge Corporation authorizing the return of the Mt. Emmons molybdenum properties and associated water treatment plant to the Company and Crested. USECC has filed a motion with the Court to amend the Order to determine that the decreed water rights be conveyed to USECC. The motion is pending. The ultimate impact of this decision on the financial statements of the Company in management’s opinion will not be measurable until such time as the final decisions are reached and the property actually transferred to USECC.

Critical Accounting Policies

Asset Impairments - We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable.

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 and are subject to ceiling tests to insure the carrying value does not exceed the fair market value.

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.

Revenue Recognition - Revenues are reported on a gross revenue basis and are recorded at the time services are provided or the commodity is sold. 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.

Use of Accounting 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.

Liquidity and Capital Resources

During the year ended December 31, 2004, operations resulted in a loss of $6,248,700 and consumed $4,282,300 of cash. Investing activities also consumed cash in the amount of $5,051,200 primarily as a result of the purchase of additional CBM properties and the exploration expenses incurred on existing

  
-43-
 

CBM properties. Financing activities generated $9,091,300 as a result of the sale of the Company’s and RMG’s stock and third party debt. All these factors together resulted in a net reduction of cash and cash equivalents of $242,300.

Cash generated by the production of coalbed methane gas operations during the year ended December 31, 2004 was swept by the financing entities to pay principal and interest. Prior to the sweep of the cash for principal and interest payments, sufficient cash to pay well and field operating costs was advanced to RMG. RMG also receives a per well monthly fee of $193, net to RMG, average per well for operating the coalbed methane operations from the working interest owners.

The liquidity of the Company during the year ended December 31, 2004 was dependant therefore upon the sale of equity and increased debt to third parties. The Company anticipates repaying the debt once it is able to sell certain mineral or coalbed methane properties.

Capital Resources

As of April 11, 2005, the company and its subsidiary Rocky Mountain Gas, Inc. (“RMG”) has entered into a binding agreement with Enterra Energy Trust (“Enterra”) for the acquisition of RMG by Enterra in consideration of $20,000,000, payable pro rata to the RMG shareholders in the amounts of $6,000,000 in cash and $14,000,000 in exchangeable shares of one of the subsidiary companies of Enterra. The shares will be exchangeable for units of Enterra twelve months after closing of the transaction. The Enterra units are traded on the Toronto Stock Exchange and on Nasdaq; the exchangeable shares will not be traded. RMG will be acquired with approximately $3,500,000 of debt owed to its mezzanine lenders.

Two major components of anticipated future capital resources during 2005 therefore are the settlement of the litigation with Nukem and the sale of RMG to Enterra. Should the sale of RMG common stock to Enterra be concluded the Company will receive cash and trust units of Enterra which would be marketable in 12 months after the closing of the transaction. Management believes both these transactions will be concluded favorably, however, the ultimate outcome of the Nukem litigation and the Enterra transaction are not certain.
 
During the year ended December 31, 2003, the Company sold its interests in the town site operations to a non-affiliated entity, The Cactus Group ("Cactus"). As a result of the sale of the town site, the Company received cash of $349,300 and a promissory note from Cactus in the amount of $3,120,700. The Company received $166,000 in cash payments and $44,000 in room credits from Cactus during calendar 2004. The room credits will be used by the Company as it works on developing its uranium assets in southern Utah. Cactus is to continue making monthly payments, primarily interest, until August 2008 at which time a balloon payment of $2.8 million is due.

The Company has a $750,000 line of credit with a commercial bank. The line of credit is secured by certain real estate holdings and equipment. At December 31, 2004, the full line of credit was available to the Company and has been renewed by the bank through June 30, 2005. This line of credit is used for short term working capital needs associated with operations.

On February 9, 2005, the Company borrowed $4,000,000 from seven accredited investors, issuing $4,720,000 face amount of debentures (including three years of annual interest at 6%). Net proceeds to the Company were $3,700,000 after paying a commission and lenders' legal costs.

The debentures are unsecured; the face amount of the debentures are payable every six months from February 4, 2005, in five installments of 20%, in cash or in restricted common stock of the Company. We may pay this amortization payment in cash or in stock at the lower of $2.43 per share (the “set price”) or

  
-44-
 

90% of the volume weighted average price of The Company’s stock for the 90 trading days prior to the repayment date. The set price was determined on the formula of 90% of the volume weighted average price of the stock over the 90 trading days prior to February 4, 2005. The debentures are convertible to restricted common stock of the Company at the set price.

At any time, the Company has the right to redeem some or all of the debentures in cash or stock, in an amount equal to 120% of the face amount of the debentures until February 4, 2006; 115% from February 5, 2006 to February 4, 2007; and 110% from February 5, 2007 until maturity. Payment in stock would be at the set price. The holders may convert the debentures to stock even if USE should seek to redeem in cash.

If at any time, after registration for public resale of the conversion shares have been approved, the Company’s stock trades at more than 150% of the set price for 20 consecutive trading days, USE may convert the balance of the face amount of the debentures at the set price.

In the event of default, the investors may require payment (i) in cash equal to 130% of the then outstanding face amount; or (ii) in stock equal to 100% of face amount, with the stock priced at the set price, or (iii) in stock equal to 130% of the face amount, with the stock priced at 100% of the volume weighted average price of our stock for the 90 trading days prior to default.

The Company issued warrants to the investors, expiring February 4, 2008, to purchase 971,195 shares of restricted common stock, at $3.63 per share (equal to 110% of the Nasdaq closing price on February 3, 2005). The number of shares underlying the warrants equals 50% of the shares issuable on full conversion of the debentures at the set price (as if the debentures were so converted on February 4, 2005). Warrants to purchase an additional 100,000 shares, at the same price and for the same term as the warrants issued to the investors, were a registered broker-dealer as compensation for its services in connection with the transaction. If in any period of 20 consecutive trading days (after registration has been approved) the stock price of the Company’s common stock exceeds 200% of the warrants’ exercise price, on each of the trading days, all of the warrants will expire on the 30th day after the Company sends a call notice to the warrant holders.

During the quarter ended March 31, 2005, the Company received $1,529,300 from the exercise of 417,811 warrants by non-employee individuals and firms. The continued exercise of employee options and non-employee warrants is contingent upon the market price of the Company’s common stock remaining above the exercise prices.

Other sources of capital are cash on hand; collection of receivables; contractual funding of drilling and development programs by non-affiliates; sale of excess equipment and real estate properties; additional debt or equity financings through third parties; equity financing of the Company's subsidiaries and a line of credit with a commercial bank.

Capital Requirements

The capital requirements of the Company during 2005 remain its General and Administrative costs and expenses; the funding of costs associated with the maintenance and operation of its coalbed methane properties; permitting and development work on its gold property and the ongoing maintenance of its uranium properties. Additionally, pending the outcome of the litigation with Phelps Dodge, the Company may incur the costs associated with holding the molybdenum property. Although it is not known what the exact cost of maintaining the molybdenum properties is, it has been represented that the cost is approximately $1.0 million per year.


  
-45-
 

Maintaining Uranium Properties

SMP Uranium Properties

The average monthly care and maintenance costs associated with the Sheep Mountain uranium mineral properties was $23,100 during the year ended December 31, 2004. Included in the average monthly cost during the year ended December 31, 2004 is ongoing reclamation work on the former SMP properties. It is anticipated that a total of $192,700 in reclamation expenditures will be conducted during 2005.

On December 8, 2004, the Company and Crested d/b/a USECC entered into a Purchase and Sale Agreement (the "agreement") with Bell Coast Capital Corp. now Uranium Power Corp. ("UPC"), a British Columbia corporation (TSX-V "UPC-V") for the sale to UPC of an undivided 50% interest in the former SMP uranium properties. The initial purchase price for the 50% interest in the properties is $4,050,000 and 4,000,000 shares of common stock of UPC, payable by installments. All amounts are stated in US dollars.

The Company, Crested and UPC, will each be responsible for paying 50% of (i) current and future Sheep Mountain reclamation costs in excess of $1,600,000, and (ii) all costs to maintain and hold the properties.

UPC has agreed to contribute $10,000,000 to the joint venture (at $500,000 for each of 20 exploration projects that are approved). The Company, USE and UPC, each will be responsible for 50% of costs on each project in excess of $500,000. (see Note F)

On April 11, 2005 USECC and UPC signed a mining venture agreement. See Items 2 and 3 above.

Plateau Resources Uranium Properties

Plateau owned the Ticaboo townsite, motel, convenience store, boat storage, restaurant and lounge. During the year ended December 31, 2003, the Company sold its interest in the townsite operations to a non-affiliated entity, Cactus. As a result of the sale of the townsite, USECC received a promissory note from Cactus in the amount of $3,120,700. The Company received $166,000 in cash payments and $44,000 in room credits from Cactus during calendar 2004.

Additionally, Plateau owns and maintains the Shootaring Canyon Uranium Mill (the “Shootaring Mill”). During the year ended December 31, 2003, Plateau requested a change in the status of the Shootaring Mill from active to reclamation from the NRC. The NRC granted the change in license status which generated a surplus in the cash bond account of approximately $2.9 million which was released to Plateau. The Company received the benefit of this release of cash.

During the years ended December 31, 2004 and 2003, Plateau performed approximately $262,500 $209,600, respectively in reclamation on mining properties and the Shootaring Mill. Due to increases in the market price for uranium during the last six months of the year ended December 31, 2004 and the first quarter of 2005, the Company reconsidered its prior decision to reclaim the Shootaring Mill property. In March 2005, Plateau filed an application with the State of Utah to restart the Mill. Therefore, the Company will not expend any capital resources in the reclamation of the Mill during calendar 2005.

The cash costs per month, including reclamation costs, at the Plateau properties during calendar 2004 were approximately $32,600 per month. These costs are projected to increase to $75,000 to $100,000 per month during the year ending December 31, 2005 due to increased activity in the uranium business.

  
-46-
 

Sutter Gold Mining Inc. (SGMI) Properties

Because of the recent increase in the price of gold, management of Sutter Gold has decided to place the properties controlled by it into production. No extensive development work or mill construction will be initiated until such time as funding from debt and or equity sources is in place. The goal of the Company’s management is to have the SGMI properties be self supporting and thereby not requiring any capital resource commitment from the Company. On December 29, 2004, SGMC merged with Globemin Resources, Inc., a Canadian company, and changed its name to Sutter Gold Mining Inc. (“SGMI”). SGMI is traded on the TSX Venture Exchange. SGMI has sufficient capital to pay for the anticipated work which will be done on the properties during calendar 2005. Additional financing is being sought by SGMI. (s ee Note F)

Development of Coalbed Methane Properties

A portion of the costs during the year ended December 31, 2004 for the development of RMG’s coalbed methane properties were funded through an agreement that RMG entered into with CCBM, Inc. (“CCBM”) a subsidiary of Carrizo Oil and Gas of Houston, Texas. At December 31, 2003, CCBM had completely satisfied its cash and drilling commitments to RMG.

During the year ended December 31, 2003, RMG and CCBM entered into a Subscription and Contribution Agreement with Credit Suisse First Boston Private Equity parties (“CSFB”) to form Pinnacle Gas Resources, Inc. (“Pinnacle”). As a result of the formation, RMG and CCBM contributed certain undeveloped and producing coalbed methane properties to Pinnacle. RMG has the opportunity to increase its ownership in Pinnacle by advancing cash to purchase common stock in Pinnacle through the exercise of options, but that increase would be offset to the extent other parties contribute additional capital to Pinnacle. See Part I “Transaction with Pinnacle Gas Resources, Inc.” Management of the Company does not anticipate exercising these options during calendar 2005 unless surplus capital resources are received. RMG has no capital commitments on the properties contributed to Pinnacle. (see Note F)

RMG continues to pursue other investment and production opportunities in the CBM business. On January 30, 2004, RMG purchased the assets of Hi-Pro Production, LLC a non-affiliated entity which included both producing and non-producing properties. The purchase of these CBM assets was accomplished by the issuance of common stock and warrants of both RMG and USE and cash, the majority of which was borrowed as a result of mezzanine financing through Petrobridge Investment Management, LLC. See Part I “Acquisition of Producing and Non-Producing Properties from Hi-Pro Production, LLC” and Note F to the financial statements in this Annual Report.

All cash flows from gas production on the Hi-Pro properties are pledged to pay the acquisition debt. See Note F to the financial statements in this Annual Report and Part I, Acquisition of Producing and Non-Producing Properties form Hi-Pro Production, LLC. The acquisition debt also requires minimum net production volumes through June 30, 2006 and maintenance of financial ratios. The Hi-Pro properties are held by RMG I, LLC, a wholly-owned subsidiary of RMG and are the sole collateral for the debt.

At December 31, 2004, RMG I was not in compliance with all of the financial covenants under the Petrobridge agreement. A revocable waiver was granted through January 31, 2006 by the lender. As the wavier is conditional, the entire debt is classified as current. Management of RMG I continues to seek solutions in the production of coalbed methane gas to bring the project into compliance. Due to lower than projected sales volumes, the Hi-Pro field will remain out of compliance unless (1) higher prices are realized, (2) costs are reduced and (3) the debt is paid down. Because it is probable that RMG I will not

  
-47-
 

be in compliance with these ratios for the next reporting period the entire $3,214,800 is classified as current debt. Should the lender declare the note in default, the only asset available for recourse is the Hi-Pro property owned by RMG I. See Note F.

Future equity financing by RMG, or industry financings, will be needed for RMGI, LLC to drill and complete wells on the substantial undeveloped acreage acquired from Hi-Pro. New production from this acreage could be needed to service the acquisition debt to offset the impact of declining production from the producing properties and/or low gas prices.

As of April 11, 2005, the Company, USE, and RMG signed a binding agreement for the acquisition of RMG by Enterra Energy Trust. (see Capital Resources above.)

If the proposed transaction with Enterra is not consummated, management of the Company believes that continued exploration and development of RMG's unproven properties will be financed through cash that RMG and USE have on hand as well as ventures with industry partners. None of the Company’s capital resources should be needed therefore to fund operations or development work of RMG during 2005.

Debt Payments

Debt to non-related parties at December 31, 2004 was $7,180,700 net of a discount of $273,000. This debt consists of debt owed by RMG I to mezzanine lenders to purchase the Hi-Pro assets of $3.2 million; long term debt related to the purchase of vehicles and a corporate aircraft of $1.2 million, and convertible debt of $2.7million. The commitment of capital resources during calendar 2005 for equipment and liability insurance debt is $185,300. The mezzanine lenders for the Hi-Pro acquisition sweep all funds from operations of the field to pay interest and principal with the exception of funds to pay (a) lease operating expenses, (b) royalties and (c) production related taxes. At December 31, 2004, RMG I was not in compliance with five of the financial covenants under the Petrobridge agreement (see note F). A rev ocable waiver was granted through January 31, 2006 by the lender. As the waiver is conditional, the entire debt is classified as current. The convertible debt is not due until 2006 so will only require $300,000 of the Company’s capital resources to pay interest when due quarterly.

Reclamation Costs

The asset retirement obligations are substantially long term and are either bonded through the use of cash bonds or the pledge of assets. It is anticipated that $192,700 of reclamation work on the SMP properties in Wyoming will be performed during 2005.

The asset retirement obligation on the Plateau uranium mining and milling properties in Utah at December 31, 2004 was $5,249,100, which is reflected on the Balance Sheet. This liability is fully funded by cash investments that are recorded as long term restricted assets. Due to the increased market price of uranium, the reclamation of this property has been delayed significantly and is not anticipated to commence until 2032.

The asset retirement obligation of the Sheep Mountain uranium properties in Wyoming at September 30, 2004 are $2,339,900 and are covered by a reclamation bond which is secured by a pledge of certain real estate assets of the Company and Crested.

RMG asset retirement obligations at September 30, 2004 were $463,700. It is not anticipated that any reclamation work will commence on the coalbed methane properties during 2005.


  
-48-
 

The asset retirement obligation for SGMI is $22,400 which is covered by a cash bond. No cash resources will be used for asset retirement obligations at SGMI during the twelve months ended December 31, 2005.

Liquidity Summary

The Company's capital resources during the year ended December 31, 2004 were sufficient to fund mine standby costs; coalbed methane property acquisition, maintenance and operations; limited reclamation and general and administrative expenses. The anticipated development of our gold, uranium, molybdenum and coalbed methane gas properties will require additional funding. This funding will be derived either through joint ventures with industry participants, debt or equity financings.

The current market prices for gold, uranium, molybdenum and coalbed methane gas are at levels that will warrant the exploration and development of the Company’s mineral properties. Industry projections for all these metals along with gas anticipate prices remaining at the current levels or higher during the next decade. Management of the Company therefore believes that sufficient capital will be available to develop its mineral properties. The successful development and production of these properties will greatly enhance the liquidity and financial position of the Company.

Results of Operations

During the periods presented, the Company has discontinued certain operations. Reclassifications to previously published financial statements have therefore been made to reflect ongoing operations and the effect of the discontinued operations. The Company changed its year end to December 31 effective December 31, 2002.

Year ended December 31, 2004 Compared to the Year ended December 31, 2003

Revenues:

Operating revenues during the year ended December 31, 2004 increased significantly over those recognized during the prior year. The primary cause of this increase is as a result of the purchase of producing coalbed methane properties by RMG during the first quarter of 2004. The Company recognized $3,205,700 in gas sales during the twelve months ended December 31, 2004 as compared to only $287,400 during the prior year. The gas sales during the year ended December 31, 2003 were only for six months due to the formation of Pinnacle and the contribution of all of the Company’s producing properties to that entity.

The acquisition of producing gas properties also increased management fee revenues recognized by the Company during the year ended December 31, 2004. This increase came as a result of the Company being paid a per well fee for the operation of the wells by the other working interest owners as well as a monthly fee for employees who manage the day to day production of the producing properties. During the year ended December 31, 2004 the Company recognized $796,300 in management revenues as a result of these activities. No similar revenues were recognized during the year ended December 31, 2003.

Revenues from real estate operations decreased during the year ended December 31, 2004 from those recorded during the year ended December 31, 2003 by $78,200. This decrease was as a result of reduced lot sales at the Plateau operations in Utah. All other revenues for the year ended December 31, 2004 remained constant with those recognized during the previous year.


  
-49-
 

Costs and Expenses:

As a result of the Company purchasing and operating coalbed methane properties during the year ended December 31, 2004, the costs associated with gas operations increased significantly from $313,100 to $4,168,800. These costs and expenses reflect the costs of operations, repairs and maintenance and amortization of the purchase price on a units of production basis. The field which was purchased by the Company had not been well maintained for some time and therefore required major repairs and enhancements. Although the operation of a gas field constantly requires ongoing maintenance, it is not anticipated by management that the major enhancement costs will be required in the future as the Company has, and is committed to, perform the required maintenance on an ongoing basis. The enhancements and maintenance perfo rmed during the year ended December 31, 2004 have increased production and improved both the cash flow and results of operations relating to the gas property.

The production on all gas properties has a life certain and therefore begins to decline the longer the property is produced. The gas property that the Company purchased is on that decline curve and it is not known how long the property will continue to produce at its current levels. There are however additional coal seams that the management of the Company is evaluating for future development and production. The overall cost of the property is therefore anticipated to remain static; however, if the lower coals are not placed into production, the profitability of the property will decrease.

The holding costs associated with the Company’s mineral properties during the year ended December 31, 2004 remained constant with those costs recorded during the previous year. It is anticipated that these costs will increase during 2005 as the Company moves forward with the permitting process relating to its uranium and gold properties. Additionally the holding cost of the molybdenum property, which the Company most probably will receive back from Phelps Dodge, will increase these costs. All costs associated with the acquisition of additional properties will be capitalized but the permitting costs will be expensed.

Real estate operating costs and general and administrative costs were reduced during the year ended December 31, 2004 from those of the year ended December 31, 2003. The reduction of real estate costs is insignificant, $7,400, and is related to the reduction of the Company’s involvement in the southern Utah property sold to a third party which had previously been operated by Plateau. The reduction in general and administrative costs of $706,400 was due to the ongoing efforts of the Company’s management to reduce overhead and related expenses.
 
Other Income and Expenses:

Other Income and Expenses increased from net expenses of $73,000 during the year ended December 31, 2003 to net income of $13,000 during the year ended December 31, 2004. Although the net increase of $86,000 is insignificant there were some major changes in the individual components.

Due to the positive upward movement of the market prices for the minerals in which the Company is involved it has determined to retain its remaining mineral development and extraction equipment. The determination to retain this equipment is a direct cause of the reduction of $154,000 from the year ended December 31, 2003 to the year ended December 31, 2003 in the gain on the sale of assets.

The income recognized from the sale of investments is as a result of the liquidation of common stock of a company, Ruby Mining Company (“Ruby”), which the Company sold several years ago. The Company retained ownership of a portion of its former shares of common stock in Ruby and had no book basis in the shares. During the year ended December 31, 2004 the Company sold 832,500 shares of Ruby common stock and received $433,100. The Company also received $152,700 from the sale of a piece of

  
-50-
 

real estate during the year ended December 31, 2004 which had no book value.

Interest revenues recognized during the year ended December 31, 2004 decreased from those recognized during the year ended December 31, 2003 due to the reduced amount of cash invested in interest bearing accounts. Interest expenses increased from $799,100 during the twelve months ended December 31, 2003 by $266,300 to $1,065,400 at December 31, 2004 as a result of increased debt associated with the purchase of coalbed methane properties.

Net Loss:

High and non-recurring remediation and maintenance costs associated with the new coalbed methane producing property resulted in a net loss from those operations of $963,100. This loss is offset by an increase of management fees of $964,300 which is directly tied to the operations of coalbed methane properties. Increased interest expenses and reduced interest revenues are therefore the primary causes for the increase in the loss of $438,600 during the year ended December 31, 2004 to $6,248,700 as compared to the loss during the year ended December 31, 2003 of $5,810,100. These losses reflect net losses per share of $0.47 per share and $0.52 per share for the years ended December 31, 2004 and 2003 respectively.

Year ended December 31, 2003 Compared to the Year ended May 31, 2002
 
Revenues:
 
Revenues for the twelve months ended December 31, 2003 consisted of $334,300 from real estate operations, $287,400 from gas sales and $215,600 from management fees. Revenues from real estate operations during the fiscal year ended May 31, 2002 were $1,276,200. The decrease in real estate revenues was as a result of reduced sales of commercial real estate during the twelve months ended December 31, 2003. During fiscal 2002 the Company sold a tract of land in California which was no longer needed for the SGMC development plan for operations.

During the year ended December 31, 2003 the Company reported $287,400 in gas sales. There were no similar revenues during the twelve months ended May 31, 2002 as the Company had no production of coal bed methane gas at May 31, 2002.

The Company recognized a minimal increase in management fee revenues during the year ended December 31, 2003 to $215,600 over the $208,200 recognized in management fee revenues during the twelve months ended May 31, 2002. Management fee revenues were actually reduced after June 2003 when RMG contributed its producing and certain undeveloped properties to Pinnacle. Although RMG provided the transitional accounting services for Pinnacle through December 31, 2003, it received only its actual cost for those services.


Costs and Expenses:

Costs and expenses for the year ended December 31, 2003 were $8,075,200 as compared to $8,877,800 for the year ended May 31, 2002. Costs and expenses of real estate operations and the cost of real estate sold decreased by $1,045,500 during that twelve months ended December 31, 2003 when compared to the costs and expenses incurred during the fiscal year ended May 31, 2002. This decrease was primarily as a result of a tract of no longer needed. Real estate was sold by SGMC during the year ended May 31, 2002 while no similar sales occurred during the year ended December 31, 2003.


  
-51-
 

During the year ended December 31, 2003 the Company recognized $313,100 in gas operating expenses. No similar expenses were recorded during the fiscal year ended May 31, 2002 as the Company had not yet begun producing gas at that time.

Mineral holding costs decreased by $246,100 to $1,461,700 at December 31, 2003 from $1,707,800 at May 31, 2002. This decrease was as a result of the Company placing all its mining properties on a shut-down status and reducing costs of holding those properties.

General and administrative costs increased by $2,050,700 during the twelve months ended December 31, 2003 over the twelve months ended May 31, 2002. This increase was as a result of several non cash items. Non cash items which were expensed during the year ended December 31, 2003 were: depreciation and amortization of $554,200; accretion of asset retirement obligations of $366,700; amortization of debt discount of $537,700; amortization of non cash services of $134,700, and non cash compensation of $893,500 for a total of $2,486,800.

The amortization of debt discount increased primarily as a result of the acceleration in the discount amortization due to the conversion of approximately one half of the debt under the terms of $1.0 million of debt to common shares of the Company’s common stock.

On January 1, 2003, the Company adopted SFAS 143, Accounting for Asset Retirement Obligation. Under the terms of this accounting standard, the Company is required to record the fair value of the reclamation liability on its shut-down mining and gas properties as of the date that the liability was incurred. The accounting standard further requires the Company to review the liability and determine if a change in estimate is required as well as accrete the total liability for the future liability. As a result of the adoption of this accounting standard, the Company recorded the non cash accretion of $366,700.

Non cash compensation increased as a result of the initial funding of the 2001 Stock Award Plan whereby five of the executive officers of the company were granted a total of 100,000 shares of common stock at $3.10 per share. Under the plan, each officer is to receive 10,000 shares of common stock annually under the condition that the shares cannot be sold until the officer’s death or retirement. The plan was effective in 2001 and had not been funded. The funding for the twelve months ended December 2003 was therefore retroactive for two years. In addition to the increase due to the funding of the 2001 Stock Award Plan, the funding for the ESOP as well as the amortization of the deferred compensation recorded in prior periods were both for a full twelve months as compared to only seven months in the prior p eriod.

The increase in the amortization of non cash services during the year ended December 31, 2003 resulted from the issuance of additional stock and warrants for legal and financial consulting services. These services related to the formation of Pinnacle and litigation with Phelps Dodge.

Other Income and Expenses:

During the fiscal year ended May 31, 2002 the Company recognized $812,700 in gains from the sale of assets while during the year ended December 31, 2003 the Company recognized only $198,200. The Company was selling the majority of its construction equipment during the years ended May 31, 2002 and 2001. The majority of the surplus equipment to be sold was sold during those two years.

Interest income decreased $291,800 during the year ended December 31, 2003 when compared to the year ended May 31, 2002. This reduction in revenues occurred as a result of the company having less amounts of cash invested in interest bearing accounts during the year ended December 31, 2003. In May of 2002 the Company borrowed $1.5 million from third party lenders. During the year ended December

  
-52-
 

31, 2003 the Company recorded interest on this debt while there was not interest paid on this debt during fiscal 2002.

Effective January 1, 2003 the Company adopted SFAS 143 “Accounting for Asset Retirement Obligations” which requires the Company to record the fair value of the reclamation liability on its shut down mining and gas properties as of the date that the liability is incurred. The Company is further required to accrete the total liability for the full value of the future liability. As a result of adopting this new accounting policy the Company recorded a cumulative effect of accounting change of $1,615,600 as well as an accretion expense of 366,700.

Operations for the year ended December 31, 2003 resulted in a loss of $5,810,100 or $0.52 per share as compared to a loss of $6,181,100 or $0.66 per share during fiscal 2002.

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 $673,000 in revenues as compared to $545,900 in revenues during the seven months ended December 31, 2001. This increase of $127,100 in revenues was primarily as a result of the production and sale of CBM gas during the seven months ended December 31, 2002 of $119,400 while no revenues from CBM production were recognized during the same period of the previous year.

Through the purchase of the Bobcat Field, RMG began selling CBM 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 CBM of $235,800. Management believes with increased production volumes, reduced ongoing operating costs and increased market prices for natural gas, the CBM properties will show profits and cash flows during 2003.

Costs and Expenses:

Costs and expenses during the seven months ended December 2002 were $4,197,900 as compared to costs and expenses of $4,460,800 during the seven months ended December 31, 2001. This reduction of $262,900 was as a result of a reduction in the holding costs of shut-down mineral properties and an ongoing cost cutting program. These reductions in operating costs were offset primarily by the operating costs associated with CBM.

Other Income and Expeses:

     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 $0.34 per share for the seven months ended December 31, 2001.


  
-53-
 

Recent Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board ("FASB") issued FASB No. 123(R), Accounting for Stock-Based Compensation, which replaces FASB 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. The Company will be required to implement FASB 123(R) on the quarterly report for the quarter ended September 30, 2005. Under the terms of FASB 123(R) the Company will be required to expense the fair value of stock options issued to employees. The fair value is determined using an option-pricing model that takes into account the stock price at the grant date, the exercise price, the expected life of the option, the volatility of the underlying stock, the expected dividends on it, and the risk-free interest rate over the expected life of the option. The fair value of an option estimated at the grant date is not subsequently adjusted for changes in the price of the underlying stock or its volatility, life of the option, dividends on the stock, or the risk-free interest rate.

Effective January 1, 2003, the Company adopted SFAS No. 143 “Accounting for Asset Retirement Obligation.” The statement requires the Company to record the fair value of the reclamation liability on its shut down mining and gas properties as of the date that the liability is incurred. The statement further requires that the Company review the liability each quarter and determine if a change in estimate is required as well as accrete the total liability on a quarterly basis for the future liability.

The Company will also deduct any actual funds expended for reclamation during the quarter in which it occurs. The Company has no remaining book value for these properties.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This Statement establishes standards for how the Company will classify and measure certain financial instruments with characteristics of both liabilities and equity. It requires that the Company classify a financial instrument within its scope as a liability. Some of the provisions of this Statement are consistent with the current definition of liabilities in FASB Concepts Statement No. 6, "Elements of Financial Statements." The remaining provisions of this Statement are consistent w ith the FASB's proposal to revise that definition to encompass certain obligations that a reporting entity can or must settle by issuing its own equity shares, depending on the nature of the relationship established between the holder and the issuer. This Statement is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 had no material impact on the Company's financial position 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.

Future Operations

We have generated operating losses for the years ended December 31, 2004 and 2003, the seven months ended December 31, 2002 and the fiscal year ended May 31, 2002 as a result of costs associated with shut down mineral properties. Management of the Company intends to take advantage of the opportunity presented by the recent and future projected market prices for all the minerals and coalbed methane gas that it is involved with.


  
-54-
 

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 and Oil. Our decision to expand into the coalbed methane industry were predicated on the projections for natural gas prices. We believe that the energy demands of the United States of America will sustain higher natural prices. As a result of RMG’s hedging activities, the price of gas will not materially affect our operations for fiscal 2005.

Uranium and Gold. Changes in the prices of uranium and gold will affect our operational decisions the most. Currently, both gold and uranium have experienced an increase in price. We continually evaluate market trends and data and are seeking financing or a joint venture to place the Company’s gold and uranium properties in production. We are currently evaluating our gold and uranium properties as market prices have increased to the level that these properties could produce profitably. Management is evaluating how long this trend will continue and at what level market prices for gold and uranium will settle at for the long term.

Molybdenum. The price of Molybdenum at December 31, 2004 was at a 20 year high of $34 per pound. Since the U.S. District Court ruled in favor of those claims brought by Phelps Dodge, the Company and Crested believe they will receive the Mt. Emmons molybdenum property near Crested Butte, Colorado back. If the properties are received, the Company and Crested will seek financing or a joint venture partner to place the Mt. Emmons property into production. The Mt. Emmons property will have a very long life and changes in prices of molybdenum would affect the revenues from that property. The Mt. Emmons property will not be placed into production during 2005 or the near term.

Contractual Obligations

The Company has two divisions of contractual obligations as of December 31, 2004: debt to third parties of $7,180,700, and asset retirement obligations of $8,075,100. The debt will be paid over a period of five to seven years and the retirement obligations will be retired during the next 30 years. During the year ended December 31, 2004, RMG incurred new debt of $3.7 million in the acquisition of the assets of Hi-Pro, and the Company incurred $3.0 million of new debt to a private lender under a credit facility. The following table shows the schedule of the payments on the debt, and the expenditures for budgeted asset retirement obligations.

       
Less
 
One to
 
Three to
 
More than
       
than one
 
Three
 
Five
 
Five
   
Total
 
Year
 
Years
 
Years
 
Years
Long-term debt obligations
 
$ 7,180,700
 
$ 3,400,100
 
$ 3,771,500
 
$ 9,100
 
$ --
                     
Other long-term liabilities
 
8,075,100
 
192,700
 
471,100
 
1,946,100
 
5,465,200
Totals
 
$ 15,255,800
 
$ 3,592,800
 
$ 4,242,600
 
$ 1,955,200
 
$ 5,465,200
                     


  
-55-
 


ITEM 8. Financial Statements

Financial statements meeting the requirements of Regulation S-X for the Company follow immediately.

  
-56-
 

Report of Independent Registered Public Accounting Firm


U.S. Energy Corp. Board of Directors

We have audited the accompanying consolidated balance sheet of U.S. Energy Corp. and subsidiaries as of December 31, 2004 and the related consolidated statements of operations, shareholders’ equity and cash flows for the year ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion of these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (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 audit provides 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. and subsidiaries as of December 31, 2004 and the results of their operations and their cash flows for the year ended December 31, 2004, 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 significant losses from operations. In addition, the Company has a working capital deficit of $636,500 as of December 31, 2004. 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.




/s/  EPSTEIN, WEBER & CONOVER, PLC


Scottsdale, Arizona
March 9, 2005, except for Note P
as to which the date is April 11, 2005

  
-57-
 

Report of Independent Registered Public Accounting Firm


To U.S. Energy Corp.:

We have audited the accompanying consolidated balance sheet of U.S. Energy Corp. and subsidiaries as of December 31, 2003 and the related consolidated statements of operations, shareholders' equity and cash flows for the year ended December 31, 2003, the seven months ended December 31, 2002 and the fiscal year 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.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion of the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 present fairly, in all material respects, the financial position of U.S. Energy Corp. and subsidiaries as of December 31, 2003, and the results of their operations and their cash flows for the year ended December 31, 2003, the seven months ended December 31, 2002 and the fiscal year ended May 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note B to the financial statements effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and changed its method of accounting for asset retirement obligations.

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 significant 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.

/s/ GRANT THORNTON LLP



Oklahoma City, Oklahoma
February 27, 2004

 

 
-58-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
  
           
CONSOLIDATED BALANCE SHEETS
  
           
ASSETS
  
           
   
December 31,
  
December 31,
  
   
2004
  
2003
 
CURRENT ASSETS:
          
Cash and cash equivalents
  
$
3,842,500
  
$
4,084,800
  
Accounts receivable
              
Trade, net of allowance of $111,300
              
 and $27,800
    
797,500
   
300,900
 
Affiliates
    
13,500
   
96,800
 
Other
    
52,700
   
--
 
Current portion of long-term notes
              
receivable, net
    
49,500
   
102,500
 
Prepaid expenses
    
489,700
   
584,700
 
Inventories
    
176,100
   
21,700
 
Total current assets
    
5,421,500
   
5,191,400
 
               
INVESTMENTS:
              
Non-affiliated company
    
957,700
   
957,700
 
Restricted investments
    
6,852,300
   
6,874,200
 
Total investments
    
7,810,000
   
7,831,900
 
               
PROPERTIES AND EQUIPMENT:
              
Land
    
576,300
   
570,000
 
Buildings and improvements
    
5,922,400
   
5,777,700
 
Machinery and equipment
    
4,919,000
   
4,762,800
 
Proved oil and gas properties, full cost method
    
5,569,000
   
1,773,600
 
Unproved coal bed methane properties
              
excluded from amortization
    
5,101,900
   
1,204,400
 
Total properties and equipment
    
22,088,600
   
14,088,500
 
Less accumulated depreciation,
              
depletion and amortization
    
(8,322,000
)
  
(6,901,400
)
Net properties and equipment
    
13,766,600
   
7,187,100
 
               
OTHER ASSETS:
              
Notes receivable trade
    
2,971,800
   
2,950,600
 
Deposits and other
    
733,800
   
768,700
 
Total other assets
    
3,705,600
   
3,719,300
 
Total assets
  
$
30,703,700
  
$
23,929,700
  
               
 

 The accompanying notes are an integral part of these statements.
-59-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
  
           
CONSOLIDATED BALANCE SHEETS
  
           
LIABILITIES AND SHAREHOLDERS' EQUITY
  
           
   
December 31,
  
December 31,
  
   
2004
  
2003
 
CURRENT LIABILITIES:
          
Accounts payable
  
$
1,751,300
  
$
727,800
  
Accrued compensation expense
    
181,700
   
180,000
 
Asset retirement obligation
    
192,700
   
--
 
Current portion of long-term debt
    
3,400,100
   
932,200
 
Other current liabilities
    
532,200
   
69,700
 
Total current liabilities
    
6,058,000
   
1,909,700
 
               
LONG-TERM DEBT
   
3,780,600
   
1,317,600
 
               
ASSET RETIREMENT OBLIGATIONS
    
7,882,400
   
7,264,700
 
               
OTHER ACCRUED LIABILITIES
    
1,952,300
   
2,158,600
 
               
DEFERRED GAIN ON SALE OF ASSET
    
1,279,000
   
1,295,700
 
               
MINORITY INTERESTS
    
871,100
   
496,000
 
               
COMMITMENTS AND CONTINGENCIES
              
               
FORFEITABLE COMMON STOCK, $.01 par value
      
442,740 and 465,880 shares issued,
             
forfeitable until earned
    
2,599,000
   
2,726,600
 
               
PREFERRED STOCK,
              
$.01 par value; 100,000 shares authorized
              
No shares issued or outstanding
    
--
   
--
 
               
SHAREHOLDERS' EQUITY:
              
Common stock, $.01 par value;
             
unlimited shares authorized; 15,231,237
              
and 12,824,698 shares issued net of
              
treasury stock, respectively
    
152,300
   
128,200
 
Additional paid-in capital
    
59,157,100
   
52,961,200
 
Accumulated deficit
    
(49,321,700
)
  
(43,073,000
)
Treasury stock at cost,
             
972,306 and 966,306 shares respectively
    
(2,779,900
)
  
(2,765,100
)
Accumulated comprehensive loss
    
(436,000
)
  
--
 
Unallocated ESOP contribution
    
(490,500
)
  
(490,500
)
Total shareholders' equity
    
6,281,300
   
6,760,800
 
Total liabilities and shareholders' equity
  
$
30,703,700
  
$
23,929,700
  
               
 The accompanying notes are an integral part of these statements.
-60-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
  
                   
CONSOLIDATED STATEMENTS OF OPERATIONS
  
                   
           
Seven months ended
  
Year ended
  
   
Year ended December 31,
  
December 31,
  
May 31,
  
   
2004
 
2003
 
2002
 
2002
 
OPERATING REVENUES:
                  
Real estate operations
  
$
256,100
  
$
334,300
  
$
394,500
  
$
1,276,200
  
Gas sales
    
3,205,700
   
287,400
   
119,400
   
--
 
Management fees
   
1,179,900
   
215,600
   
159,100
   
208,200
 
     
4,641,700
   
837,300
   
673,000
   
1,484,400
 
                           
OPERATING COSTS AND EXPENSES:
                          
Real estate operations
    
295,500
   
302,900
   
189,700
   
1,348,400
 
Gas operations
    
4,168,800
   
313,100
   
355,200
   
--
 
Mineral holding costs
    
1,466,700
   
1,461,700
   
737,200
   
1,707,800
 
General and administrative
    
5,291,100
   
5,997,500
   
2,915,800
   
3,946,800
 
Impairment of goodwill
    
--
   
--
   
--
   
1,622,700
 
Other
    
--
   
--
   
--
   
80,900
 
Provision for doubtful accounts
    
79,000
   
--
   
--
   
171,200
 
     
11,301,100
   
8,075,200
   
4,197,900
   
8,877,800
 
                           
OPERATING LOSS
    
(6,659,400
)
  
(7,237,900
)
  
(3,524,900
)
  
(7,393,400
)
                           
OTHER INCOME & EXPENSES:
                          
Gain (loss) on sales of assets
    
46,300
   
198,200
   
(342,600
)
  
812,700
 
Gain (loss) on sale of investment
    
656,300
   
(32,400
)
  
(207,800
)
  
--
 
Interest income
    
375,800
   
560,300
   
524,500
   
852,100
 
Interest expense
    
(1,065,400
)
  
(799,100
)
  
(361,200
)
  
(345,300
)
     
13,000
   
(73,000
)
  
(387,100
)
  
1,319,500
 
                           
LOSS BEFORE MINORITY INTEREST,
                          
PROVISION FOR INCOME TAXES,
                          
DISCONTINUED OPERATIONS AND
                          
CUMULATIVE EFFECT OF
                         
ACCOUNTING CHANGE
    
(6,646,400
)
  
(7,310,900
)
  
(3,912,000
)
  
(6,073,900
)
                           
MINORITY INTEREST IN LOSS OF
                          
CONSOLIDATED SUBSIDIARIES
    
397,700
   
235,100
   
54,800
   
39,500
 
                           
LOSS BEFORE PROVISION FOR INCOME
                  
TAXES, DISCONTINUED OPERATIONS
                          
AND CUMULATIVE EFFECT OF
                          
ACCOUNTING CHANGE
    
(6,248,700
)
  
(7,075,800
)
  
(3,857,200
)
  
(6,034,400
)
                           
PROVISION FOR INCOME TAXES
    
--
   
--
   
--
   
--
 
                           
(continued)
                          
 The accompanying notes are an integral part of these statements.
-61-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
  
                   
CONSOLIDATED STATEMENTS OF OPERATIONS
  
                   
           
Seven months ended
  
Year ended
  
   
Year ended December 31,
  
December 31,
  
May 31,
  
   
2004
 
2003
 
2002
 
2002
 
                   
NET LOSS FROM CONTINUING
                  
OPERATIONS
  
$
(6,248,700
)
$
(7,075,800
)
$
(3,857,200
)
$
(6,034,400
)
                           
DISCONTINUED OPERATIONS,
                          
NET OF TAX
    
--
   
(349,900
)
  
17,100
   
(146,700
)
                           
CUMULATIVE EFFECT OF
                          
ACCOUNTING CHANGE
    
--
   
1,615,600
   
--
   
--
 
                           
NET LOSS
    
(6,248,700
)
  
(5,810,100
)
  
(3,840,100
)
  
(6,181,100
)
                           
PREFERRED STOCK DIVIDENDS
    
--
   
--
   
--
   
(86,500
)
                           
NET LOSS AVAILABLE TO COMMON
                          
SHAREHOLDERS
  
$
(6,248,700
)
$
(5,810,100
)
$
(3,840,100
)
$
(6,267,600
)
                           
NET LOSS PER SHARE BASIC
                          
CONTINUED OPERATIONS
  
$
(0.47
)
$
(0.63
)
$
(0.36
)
$
(0.65
)
DISCONTINUED OPERATIONS
    
--
   
(0.03
)
  
--
   
(0.01
)
PREFERRED DIVIDENDS
    
--
   
--
   
--
   
(0.01
)
EFFECT OF ACCOUNTING
                         
 ACCOUNTING CHANGE
    
--
   
0.14
   
--
   
--
 
   
$
(0.47
)
$
(0.52
)
$
(0.36
)
$
(0.67
)
                           
NET LOSS PER SHARE DILUTED
                          
CONTINUED OPERATIONS
  
$
(0.47
)
$
(0.63
)
$
(0.36
)
$
(0.65
)
DISCONTINUED OPERATIONS
    
--
   
(0.03
)
  
--
   
(0.01
)
PREFERRED DIVIDENDS
    
--
   
--
   
--
   
(0.01
)
EFFECT OF ACCOUNTING
                         
 ACCOUNTING CHANGE
    
--
   
0.14
   
--
   
--
 
   
$
(0.47
)
$
(0.52
)
$
(0.36
)
$
(0.67
)
                           
BASIC WEIGHTED AVERAGE
                         
SHARES OUTSTANDING
    
13,182,421
   
11,180,975
   
10,770,658
   
9,299,359
 
                           
DILUTED WEIGHTED AVERAGE
                         
SHARES OUTSTANDING
    
13,182,421
   
11,180,975
   
10,770,658
   
9,299,359
 
                           

 The accompanying notes are an integral part of these statements.
-62-
 
U.S. ENERGY & AFFILIATES
  
                                   
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
 
                                   
           
Additional
             
Unallocated
 
Total
 
   
Common Stock
 
Paid-In
 
Accumulated
 
Treasury Stock
 
ESOP
 
Shareholders'
 
   
Shares
 
Amount
 
Capital
 
Deficit
 
Shares
 
Amount
 
Contribution
 
Equity
 
                                   
Balance May 31, 2001
   
8,989,047
 
$
90,000
  
$
38,681,600
  
$
(27,155,200
)
  
949,725
 
$
(2,660,500
)
$
(490,500
)
$
8,465,400
  
                                                   
Funding of ESOP
   
70,075
   
700
   
236,200
   
--
   
--
   
--
   
--
   
236,900
 
Issuance of common stock
                                                 
to outside directors
   
3,429
   
--
   
14,400
   
--
   
--
   
--
   
--
   
14,400
 
Issuance of common stock
                                                 
for services rendered
   
45,000
   
500
   
147,600
   
--
   
--
   
--
   
--
   
148,100
 
Issuance of common stock
                                                 
warrants for services rendered
   
--
   
--
   
592,900
   
--
   
--
   
--
   
--
   
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
   
513,140
   
5,100
   
1,846,400
   
--
   
--
   
--
   
--
   
1,851,500
 
Issuance of common stock
                                                 
in exchange for subsidiary stock
   
912,233
   
9,100
   
3,566,900
   
--
   
--
   
--
   
--
   
3,576,000
 
Issuance of common stock
                                                 
to purchase property
   
61,760
   
600
   
246,200
   
--
   
--
   
--
   
--
   
246,800
 
Issuance of common stock
                                                 
through private placement
   
871,592
   
8,700
   
2,341,800
   
--
   
--
   
--
   
--
   
2,350,500
 
Issuance of common stock
                                                 
for exercised stock warrants
   
1,205
   
--
   
4,500
   
--
   
--
   
--
   
--
   
4,500
 
Issuance of common stock
                                                 
from employee options (1)
    
253,337
   
2,500
   
600,000
   
--
   
--
   
--
   
--
   
602,500
 
Net loss
   
--
   
--
   
--
   
(6,267,600
)
  
--
   
--
   
--
   
(6,267,600
)
Balance May 31, 2002(2)
    
11,720,818
 
$
117,200
  
$
48,278,500
  
$
(33,422,800
)
  
959,725
 
$
(2,740,400
)
$
(490,500
)
$
11,742,000
  
                                                   
(1)Net of 15,285 shares surrendered by employees for the exercise of 268,622 employee stock options.
                              
                                                   
(2)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 are an integral part of these statements.
-63-
 
 

U.S. ENERGY & AFFILIATES
  
                                   
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
 
(continued)
 
                                   
           
Additional
             
Unallocated
 
Total
 
   
Common Stock
 
Paid-In
 
Accumulated
 
Treasury Stock
 
ESOP
 
Shareholders'
 
   
Shares
 
Amount
 
Capital
 
Deficit
 
Shares
 
Amount
 
Contribution
 
Equity
 
                                   
Balance May 31, 2002
   
11,720,818
 
$
117,200
  
$
48,278,500
  
$
(33,422,800
)
  
959,725
 
$
(2,740,400
)
$
(490,500
)
$
11,742,000
  
                                                   
Funding of ESOP
   
43,867
   
400
   
134,700
   
--
   
--
   
--
   
--
   
135,100
 
Issuance of common stock
                                                 
to outside consultants
   
15,000
   
200
   
60,700
   
--
   
--
   
--
   
--
   
60,900
 
Issuance of common stock
                                                 
warrants
   
--
   
--
   
325,900
   
--
   
--
   
--
   
--
   
325,900
 
Issuance of common stock
                                                 
for settlement of law suit
   
20,000
   
200
   
77,600
   
--
   
--
   
--
   
--
   
77,800
 
Issuance of common stock
                                                 
from employee options (1)
    
26,711
   
300
   
(300
)
  
--
   
--
   
--
   
--
   
--
 
                                                   
Net loss
   
--
   
--
   
--
   
(3,840,100
)
  
--
   
--
   
--
   
(3,840,100
)
Balance December 31, 2002(2)
    
11,826,396
 
$
118,300
  
$
48,877,100
  
$
(37,262,900
)
  
959,725
 
$
(2,740,400
)
$
(490,500
)
$
8,501,600
  
 

(1)Net of 44,456 shares surrendered by employees for the exercise of 71,167 employee stock options.
                    
                                   
(2)Total Shareholders' Equity at December 31, 2002 does not include 465,880 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 are an integral part of these statements.
-64-
 
U.S. ENERGY & AFFILIATES
  
                                   
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
 
(continued)
 
           
Additional
             
Unallocated
 
Total
 
   
Common Stock
 
Paid-In
 
Accumulated
 
Treasury Stock
 
ESOP
 
Shareholders'
 
   
Shares
 
Amount
 
Capital
 
Deficit
 
Shares
 
Amount
 
Contribution
 
Equity
 
Balance December 31, 2002
   
11,826,396
 
$
118,300
  
$
48,877,100
  
$
(37,262,900
)
  
959,725
 
$
(2,740,400
)
$
(490,500
)
$
8,501,600
  
                                                   
Funding of ESOP
   
76,294
   
700
   
235,700
   
--
   
--
   
--
   
--
   
236,400
 
Issuance of common stock
                                                 
to outside directors
   
3,891
   
--
   
14,400
   
--
   
--
   
--
   
--
   
14,400
 
Issuance of common stock
                                                 
by release of forfeitable stock
   
78,286
   
800
   
434,400
   
--
   
--
   
--
   
--
   
435,200
 
Issuance of common stock
                                                 
from stock warrants
   
131,596
   
1,300
   
465,300
   
--
   
--
   
--
   
--
   
466,600
 
Issuance of common stock
                                                 
in stock compensation plan
   
100,000
   
1,000
   
309,000
   
--
   
--
   
--
   
--
   
310,000
 
Treasury stock from sale
                                                 
of subsidiary
   
--
   
--
   
--
   
--
   
1,581
   
(4,200
)
  
--
   
(4,200
)
Treasury stock from payment
                                                 
on balance of note receivable
   
--
   
--
   
--
   
--
   
5,000
   
(20,500
)
  
--
   
(20,500
)
Issuance of common stock
                                                 
to outside consultants
   
121,705
   
1,200
   
581,600
   
--
   
--
   
--
   
--
   
582,800
 
Issuance of common stock
                                                 
warrants to outside consultants
   
--
   
--
   
886,300
   
--
   
--
   
--
   
--
   
886,300
 
Issuance of common stock
                                                 
for settlement of lawsuit
   
10,000
   
100
   
49,900
   
--
   
--
   
--
   
--
   
50,000
 
Issuance of common stock
                                                 
in payment of debt
   
211,109
   
2,100
   
497,900
   
--
   
--
   
--
   
--
   
500,000
 
Issuance of common stock
                                                 
from employee options (1)
    
265,421
   
2,700
   
609,600
   
--
   
--
   
--
   
--
   
612,300
 
Net Loss
   
--
   
--
   
--
   
(5,810,100
)
  
--
   
--
   
--
   
(5,810,100
)
Balance December 31, 2003(2)
    
12,824,698
 
$
128,200
  
$
52,961,200
  
$
(43,073,000
)
  
966,306
 
$
(2,765,100
)
$
(490,500
)
$
6,760,800
  
                                                   
(1)Net of 10,200 shares surrendered by employees for the exercise of 275,621 employee stock options.
                              
                                                   
(2)Total Shareholders' Equity at December 31, 2003 does not include 465,880 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 are an integral part of these statements.
-65-
 
U.S. ENERGY & AFFILIATES
  
                                           
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
 
                                           
(continued)
 
                       
Accumulated
                 
           
Additional
         
Total Other
         
Unallocated
 
Total
 
   
Common Stock
 
Paid-In
 
Comprehensive
 
Accumulated
 
Comprehensive
 
Treasury Stock
 
ESOP
 
Shareholders'
 
   
Shares
 
Amount
 
Capital
 
Loss
 
Deficit
 
Loss
 
Shares
 
Amount
 
Contribution
 
Equity
 
Balance December 31, 2003
   
12,824,698
 
$
128,200
  
$
52,961,200
        
$
(43,073,000
)
        
966,306
 
$
(2,765,100
)
$
(490,500
)
$
6,760,800
  
                                                               
Funding of ESOP
   
70,439
   
700
   
207,800
         
--
   
--
   
--
   
--
   
--
   
208,500
 
Issuance of common stock
                                                             
by release of forfeitable stock
   
23,140
   
200
   
121,700
         
--
   
--
   
1,000
   
5,700
   
--
   
127,600
 
Issuance of common stock
                                                             
from stock warrants
   
125,000
   
1,300
   
249,800
         
--
   
--
   
--
   
--
   
--
   
251,100
 
Issuance of common stock
                                                             
in stock compensation plan
   
50,000
   
500
   
127,900
         
--
   
--
   
--
   
--
   
--
   
128,400
 
Treasury stock from payment
                                                             
on balance of note receivable
   
--
   
--
   
--
         
--
   
--
   
5,000
   
(20,500
)
  
--
   
(20,500
)
Issuance of common stock
                                                             
to retire debt
   
476,833
   
4,700
   
1,068,200
         
--
   
--
   
--
   
--
   
--
   
1,072,900
 
Issuance of common stock
                                                             
warrants to RMG investors
   
--
   
--
   
291,500
         
--
   
--
   
--
   
--
   
--
   
291,500
 
Issuance of common stock
                                                             
to RMG investors
   
882,239
   
8,900
   
1,803,700
         
--
   
--
   
--
   
--
   
--
   
1,812,600
 
Issuance of common stock
                                                             
to purchase property
   
678,888
   
6,800
   
1,976,300
         
--
   
--
   
--
   
--
   
--
   
1,983,100
 
Issuance of common stock
                                                             
in a private placement
   
100,000
   
1,000
   
349,000
         
--
   
--
   
--
   
--
   
--
   
350,000
 
                                                               
Comprehensive loss
                                                             
net loss
   
--
   
--
   
--
 
$
(6,248,700
)
  
(6,248,700
)
  
--
   
--
   
--
   
--
   
(6,248,700
)
Other comprehensive loss on
                                                             
hedging activity
   
--
   
--
   
--
   
(436,000
)
        
(436,000
)
  
--
   
--
   
--
   
(436,000
)
Comprehensive loss
                     
(6,684,700
)
                                    
Balance December 31, 2004(2)
    
15,231,237
 
$
152,300
  
$
59,157,100
        
$
(49,321,700
)
$
(436,000
)
  
972,306
 
$
(2,779,900
)
$
(490,500
)
$
6,281,300
  
                                                               
(2)Total Shareholders' Equity at December 31, 2004 does not include 442,740 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 are an integral part of these statements.
-66-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
  
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
  
                   
           
Seven Months Ended
  
Year Ended
  
   
Year Ended December 31,
  
December 31,
  
May 31,
  
   
2004
 
2003
 
2002
 
2002
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                  
Net loss
  
$
(6,248,700
)
$
(5,810,100
)
$
(3,840,100
)
$
(6,267,600
)
Adjustments to reconcile net loss
                          
to net cash used in operating activities:
                          
Minority interest in loss of
                          
consolidated subsidiaries
    
(397,700
)
  
(235,100
)
  
(54,800
)
  
(39,500
)
Amortization of deferred charge
    
343,400
   
284,700
   
101,900
   
266,500
 
Depreciation
    
1,445,200
   
554,200
   
360,100
   
541,500
 
Accretion of asset
                         
retirement obligations
    
346,700
   
366,700
   
--
   
--
 
Amortization of debt discount
    
384,300
   
537,700
   
211,200
   
--
 
Impairment of goodwill
    
--
   
--
   
--
   
1,622,700
 
Noncash services
    
50,400
   
134,700
   
31,500
   
787,700
 
Noncash dividend
    
--
   
--
   
--
   
11,500
 
Provision for doubtful accounts
    
79,000
   
--
   
--
   
171,200
 
Recognition of deferred gain
    
(16,700
)
  
--
   
--
   
--
 
(Gain) loss on sale of assets
    
(46,300
)
  
(199,300
)
  
342,600
   
(812,700
)
(Gain) on sale investments
    
(656,300
)
  
--
   
--
   
--
 
Write off of properties
    
--
   
--
   
21,500
   
--
 
Cumulative effect of accounting change
    
--
   
(1,615,600
)
  
--
   
--
 
Noncash compensation
    
336,900
   
608,800
   
212,900
   
268,700
 
Lease holding costs
    
--
   
50,000
   
--
   
--
 
Net changes in assets and liabilities:
                          
Accounts receivable
    
64,500
   
(470,300
)
  
(755,600
)
  
799,900
 
Other assets
    
(207,300
)
  
1,466,000
   
8,700
   
(47,500
)
Accounts payable
    
132,400
   
(827,200
)
  
609,900
   
(970,100
)
Accrued compensation expense
    
1,700
   
--
   
--
   
90,800
 
Prepaid drilling costs
    
--
   
(134,400
)
  
(107,700
)
  
242,100
 
Reclamation and other liabilities
    
(179,800
)
  
(393,200
)
  
--
   
--
 
NET CASH USED IN
                         
OPERATING ACTIVITIES
    
(4,568,300
)
  
(5,682,400
)
  
(2,857,900
)
  
(3,334,800
)
                           

 The accompanying notes are an integral part of these statements.
-67-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
  
                       
CONSOLIDATED STATEMENTS OF CASH FLOWS
  
   
(continued)
  
                       
               
Seven Months Ended
  
Year Ended
  
       
Year Ended December 31,
  
December 31,
  
May 31,
  
       
2004
 
2003
 
2002
 
2002
 
CASH FLOWS FROM INVESTING ACTIVITIES:
                  
Development of proved gas properties
        
$
(435,100
)
$
--
 
$
--
 
$
--
 
Development of unproved gas properties
          
(1,385,100
)
  
(176,400
)
  
(233,400
)
  
(142,100
)
Acquisition of producing gas properties
          
(1,198,000
)
  
--
   
(650,000
)
  
--
 
Acquisition of undeveloped gas properties
          
(3,213,000
)
  
--
   
(650,000
)
  
--
 
Proceeds on sale of gas interests
          
792,100
   
2,813,800
   
1,125,000
   
1,125,000
 
Proceeds on sale of property and equipment
          
49,700
   
1,604,400
   
1,566,000
   
752,000
 
Proceeds from sale investments
          
656,300
   
--
   
--
   
--
 
Net change in restricted investments
          
21,900
   
3,037,500
   
66,100
   
(236,800
)
Purchase of property and equipment
          
(294,500
)
  
(92,700
)
  
(411,200
)
  
(82,300
)
Net change in notes receivable
          
11,300
   
8,800
   
--
   
--
 
Net change in investments in affiliates
          
(64,500
)
  
(222,600
)
  
104,600
   
406,500
 
NET CASH (USED IN) PROVIDED BY
                        
BY INVESTING ACTIVITIES
          
(5,058,900
)
  
6,972,800
   
1,567,100 
    
1,822,300
 
                                 
CASH FLOWS FROM FINANCING ACTIVITIES:
                        
Issuance of common stock
          
601,100
   
1,078,900
   
--
   
2,957,400
 
Issuance of subsidiary stock
         
2,526,700
   
650,000
   
--
   
1,000,000
 
Proceeds from long term debt
          
7,460,400
   
2,600
   
892,800
   
631,700
 
Net activity on lines of credit
          
--
   
--
   
(200,000
)
  
(650,000
)
Repayments of long term debt
          
(1,203,400
)
  
(678,100
)
  
(225,300
)
  
(547,800
)
NET CASH PROVIDED BY
  
   
   
   
 
FINANCING ACTIVITIES
          
9,384,800
   
1,053,400
   
467,500
   
3,391,300
 
                                 
NET INCREASE (DECREASE) IN
                       
CASH AND CASH EQUIVALENTS
          
(242,300
)
  
2,343,800
   
(823,300
)
  
1,878,800
 
                                 
CASH AND CASH EQUIVALENTS
                        
AT BEGINNING OF PERIOD
          
4,084,800
   
1,741,000
   
2,564,300
   
685,500
 
                                 
CASH AND CASH EQUIVALENTS
                       
AT END OF PERIOD
        
$
3,842,500
  
$
4,084,800
  
$
1,741,000
  
$
2,564,300
  
                                 
SUPPLEMENTAL DISCLOSURES:
                        
Income tax paid
        
$
--
  
$
--
  
$
--
  
$
--
  
                                 
Interest paid
        
$
1,065,400
  
$
799,100
  
$
361,200
  
$
345,300
  

 The accompanying notes are an integral part of these statements.
-68-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
  
                       
CONSOLIDATED STATEMENTS OF CASH FLOWS
  
   
(continued)
  
               
Seven Months Ended
  
Year Ended
  
       
Year Ended December 31,
  
December 31,
  
May 31,
  
       
2004
 
2003
 
2002
 
2002
 
                       
NON-CASH INVESTING AND FINANCING ACTIVITIES:
              
 
Initial valuation of new asset
  
 
                  
retirement obligations
        
$
463,700
  
$
--
  
$
--
  
$
--
  
                                 
Acquisition of assets
                               
through issuance of stock
        
$
1,983,100
  
$
--
  
$
150,000
  
$
96,800
  
                                 
Issuance of stock to satisfy debt
        
$
1,072,900
  
$
500,000
  
$
--
  
$
3,568,500
  
                                 
Issuance of stock warrants in
                               
conjunction with debt
        
$
291,500
  
$
--
  
$
299,800
  
$
592,900
  
                                 
Satisfaction of receivable - employee
                                
with stock in company
        
$
20,500
  
$
20,500
  
$
--
  
$
79,900
  
                                 
Acquisition of assets
                               
through issuance of debt
        
$
--
  
$
26,300
  
$
--
  
$
180,600
  
                                 
Issuance of stock warrants for services
        
$
--
  
$
563,400
  
$
26,100
  
$
--
  
                                 
Issuance of stock for services
        
$
--
  
$
582,800
  
$
60,900
  
$
14,400
  
                                 
Issuance of stock as deferred compensation
        
$
--
  
$
151,900
  
$
--
  
$
261,300
  
                                 
Issuance of stock for retired employees
        
$
--
  
$
435,200
  
$
--
  
$
--
  
                                 
Sale of assets through issuance
                               
of a note receivable
        
$
--
  
$
--
  
$
--
  
$
442,200
  
                                 
Issuance of stock to retire preferred stock
        
$
--
  
$
--
  
$
--
  
$
1,840,000
  
 The accompanying notes are an integral part of these statements.
-69-
 
 
U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003, 2002 AND MAY 31, 2002
 
A.    BUSINESS ORGANIZATION AND OPERATIONS:

U.S. Energy Corp. was incorporated in the State of Wyoming on January 26, 1966. U.S. Energy Corp. and subsidiaries (the "Company" or "USE") 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. Only coalbed methane was being produced during the year ended December 31, 2004. 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 through subsidiaries 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"). SMP has been involved in significant litigation (see Note K). Sutter Gold Mining Inc. ("SGMI"), a Canadian corporation owned 65.5% by the Company at December 31, 2004, manages the Company's interest in gold properties. The Company also owns 100% of the outstanding stock of Plateau Resources Limited ("Plateau"), which owns the nonoperating uranium mill in southeastern Utah. Currently, the mill is nonoperating. Rocky Mountain Gas, Inc. ("RMG") was formed in November 1999 to consolidate all methane gas operations of the Company. The Company owns and controls 91.1% of RMG as of December 31, 2004.

The Company's Board of Directors changed the Company's year end to December 31 effective December 31, 2002.

Management's Plan

The Company has generated significant net losses during recent years and has an accumulated deficit of $49,321,700 at December 31, 2004. The Company has a working capital deficit of $636,500 at December 31, 2004. This working capital deficit is primarily a result of debt of RMG being classified as current. See Note F. The Company used cash in its operating activities during all the periods ended December 31, 2004 reported in these financial statements. During the year ended December 31, 2003 and the fiscal year ended May 31, 2002 the Company experienced positive cash flow of $2,343,800 and $1,878,800 respectively. The Company experienced negative cash flow of $242,300 and $823,300, respectively, for the year ended December 31, 2004 and the seven months ended December 31, 2002.

After these work commitments are 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, 2004 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:



 
-70-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)


·   Sell raw land it owns. 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.
·   Seek additional funding through either sale of equity or joint venture partner to place SGMI and uranium properties into production or sell the properties to industry partners.
·   Raise additional capital through a private placement.
·   Reduce overhead expenses.
·   Successfully conclude the litigation with Nukem. See Note K
·   Conclude the initial phase of the UPC Agreement on the SMP properties. See Note F
·   Conclude the sale of RMG to Enterra. See Note P. In the event that the Enterra transaction is not closed, management will pursue private placements or a public offering of RMG common stock.

As a result of these plans, management believes that they will generate sufficient cash flows to meet its cash requirements in calendar 2005, although there is no assurance the plans will be accomplished.

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%), SGMI (65.5%), Crested Corp. ("Crested") (70.1%), Yellowstone Fuels Corp. ("YSFC") (35.9%), Rocky Mountain Gas ("RMG") (91.1%) 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 of less than 20% are accounted for by the cost method. All material intercompany profits, transactions and balances have been eliminated. Because of management control, YSFC is consolidated into the financial statements of the Company.

Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in bank deposit accounts which exceed federally insured limits. At December 31, 2004, the Company had approximately 77% of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and 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.


  
-71-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
Accounts Receivable

The majority of the Company's accounts receivable are due from industry partners for operating expenses associated with coalbed methane gas wells for which RMG acts as operator and from sale of gas and properties on which the Company provided financing. 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 uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.

As of December 31, 2003, the Company was due $863,200 from CCBM, Inc. ("CCBM"), a Delaware corporation, which is wholly-owned by Carrizo Oil & Gas, Inc., Houston Texas (NMS "CRZO"),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 was accounted for on a cash basis due to its non-recourse nature with principal payments received credited against natural gas properties in accordance with the full cost method of accounting. During the year ended December 31, 2004, CCBM notified the Company that it was electing to reduce its participation interest in certain properties which reduced proportionately the amount due under the note. At December 31, 2004, the note from CCBM had been paid i n full.

Inventories

Inventories consist of aviation fuel and supplies used in developing oil and gas properties. 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.

Equipment
  
 
Office Equipment
3 to 5 years
 
Planes
10 years
 
Field Tools and Hand Equipment
5 to 7 years
 
Vehicles and Trucks
3 to 7 years
 
Heavy Equipment
7 to 10 years
Building
  
 
Service Buildings
20 years
 
Corporate Headquarters' Building
45 years
 
The Company capitalizes all costs incidental to the acquisition of mineral properties as incurred. Costs are charged to operations if the Company determines that the property is not economical. Mineral exploration costs are expensed as incurred. When it is determined that a mineral property can be economically developed as a result of establishing proved and probable reserves, costs subsequently incurred are capitalized and amortized using units of production over the estimated recoverable proved and probable reserves. Costs and expenses related to general corporate overhead are expensed as incurred.

  
-72-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
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 F).

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 added to the costs to be amortized.

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.

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 necessa ry to develop mineral interests, may result in asset impairment.

Fair Value of Financial Instruments

The carrying amount of cash equivalents, receivables, other current assets, accounts payable and accrued expenses approximate 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 generally unchanged from issuance of the long term debt.


  
-73-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
Revenue Recognition

Revenues from real estate operations are from the rental of office space in office buildings in Riverton, Wyoming. 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 entitlements method of accounting for natural gas revenues whereby revenues are recognized as the Company's share of the gas is produced and delivered to a purchaser 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. There were no significant imbalances at December 31, 2004.

Management fees are for operating and overseeing coalbed methane production and oil production on the Fort Peck Reservation in Montana. Management fees are recorded when the service is provided.

Comprehensive Income

Unrealized gains (losses) on the hedging of gas sales are excluded from net income but are reported as comprehensive income on the consolidated statements of stockholders' equity.

Hedging Activities

The results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of this exposure, the Company through RMG and its subsidiary RMG I has entered into certain derivative instruments. RMG I's derivative instruments covered approximately 92% of net gas sales for the twelve months ended December 31, 2004. All derivative instruments have been entered into and designated as cash flow hedges of gas price risk and not for speculative or trading purposes. As of December 31, 2004, RMG I's derivative instruments were comprised of swaps. For swap instruments, RMG I receives (pays) a fixed price for the hedged commodity and pays (receives) a floating market price, as defined in each instrument, to the counterparty. These instruments have been designated and ha ve qualified as cash flow hedges.  Should the Company not be able to deliver the gas under hedge, it would have to acquire the gas.  In the event the market price for gas exceeded the hedge price, the Company would recognize a loss.

The carrying values of these instruments are equal to the estimated fair values. The fair values of the derivative instruments were established using appropriate future cash flow valuation methodologies. The actual contribution to future results of operations will be based on the market prices at the time of settlement and may be more or less than fair value estimates used at December 31, 2004.

Net loss on hedging activities included in gas sales on the consolidated statement of operations were $254,100 during the period ended December 31, 2004. All forecasted transactions hedged as of December 31, 2004 are expected to occur by December 2005. Approximately 30,000 mmbtu per month are hedged at $4.14 per mmbtu through December 2005 and 15,000 mmbtu per month are hedged at $8.10 per mmbtu from January 1, 2005 through March 31, 2005, resulting in an estimated fair value liability of $435,900 as of December 31, 2004.


  
-74-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
Stock Based Compensation

SFAS 123, "Accounting for Stock-Based Compensation," ("SFAS 123") 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 t he following weighted average assumptions:
 

 
Year Ended
  
Seven Months ended
  
Year ended
 
December 31,
  
December 31,
  
May 31,
 
2004
  
2003
  
2002
  
2002
               
Risk-free interest rate
4.82%
  
5.61%
  
4.4%
  
5.6%
Expected lives (years)
7.1
  
7
  
8.5
  
10
Expected volatility
50.79%
  
58.95%
  
50.38%
  
62.65%
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.

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:

 
Year Ended
December 31,
  
Seven Months ended December 31,
  
Year ended May 31,
 
2004
  
2003
  
2002
  
2002
Net loss to common
             
shareholders as reported
$(6,248,700)
  
$(5,810,100)
  
$ (3,840,100)
  
$ (6,267,600)
Deduct: Total stock based
employee expense
              
determined under fair
              
value based method
(207,100)
  
(652,900)
  
(1,410,850)
  
(3,079,700)
Pro forma net loss
$(6,455,800)
  
$(6,463,000)
  
$ (5,250,950)
  
$ (9,347,300)
               
As reported, Basic
$ (.47)
  
$ (.52)
  
$ (.36)
  
$ (.67)
As reported, Diluted
(.47)
  
(.52)
  
(.36)
  
(.67)
Pro forma, Basic
(.49)
  
(.58)
  
(.49)
  
(1.01)
Pro forma, Diluted
(.49)
  
(.58)
  
(.49)
  
(1.01)


  
-75-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
      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.

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 Per Share

The Company reports net loss 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 5,628,820, 3,790,370, 4,910,900 and 3,999,468 at December 31, 2004, 2003 and 2002 and May 31, 2002, respectively.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the USA 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.


  
-76-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
Recent Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board ("FASB") issued FASB No. 123(R), Accounting for Stock-Based Compensation, which replaces FASB 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. The Company will be required to implement FASB 123(R) on the quarterly report for the quarter ending September 30, 2005. Under the terms of FASB 123(R) the Company will be required to expense the fair value of stock options issued to employees. The fair value is determined using an option-pricing model that takes into account the stock price at the grant date, the exercise price, the expected life of the option, the volatility of the underlying stock, the expected dividends on it, and the risk-free interest rate over the expected life of the option. The fair value of an option estimated at the grant date is not subsequently adjusted for changes in the price of the underlying stock or its volatility, life of the option, dividends on the stock, or the risk-free interest rate.

SFAS 143 Effective January 1, 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligation." The statement requires the Company to record the fair value of the reclamation liability on its shut down mining and gas properties as of the date that the liability is incurred. The statement further requires that the Company review the liability each quarter and determine if a change is estimate is required as well as accrete the total liability on a quarterly basis for the future liability.

The Company will also deduct any actual funds expended for reclamation during the quarter in which it occurs. As a result of the Company taking impairment allowances in prior periods on its shut down mining properties, it has no remaining book value for these properties.

The following is a reconciliation of the total liability for asset retirement obligations:

   
Year ended December 31,
  
   
2004
  
2003
  
Beginning balance
  
$
7,264,700
  
$
8,906,800
  
Impact of adoption of SFAS No. 143
    
--
   
(1,615,600
)
Addition to Liability
    
463,700
    
--
 
Liability Settled
    
--
   
(393,200
)
Accretion Expense
    
346,700
   
366,700
 
Ending balance
  
$
8,075,100
  
$
7,264,700
  
     
   
 


  
-77-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
      The following table shows the Company's net loss and net loss per share on a pro forma basis as if the provisions of SFAS No. 143 had been applied retroactively in all periods presented.
 

           
Seven months
      
           
ended
  
Year ended
  
   
Year ended December 31,
  
December 31,
  
May 31,
  
   
2004
  
2003
  
2002
  
2002
  
NET LOSS:
                          
Reported net loss
  
$
(6,248,700
)
$
(7,075,800
)
$
(3,857,200
)
$
(6,034,400
)
Cumulative effect of adoption
                          
of SFAS No. 143
    
--
   
--
   
(200,000
)
  
(333,000
)
Adjusted net loss
  
$
(6,248,700
)
$
(7,075,800
)
$
(4,057,200
)
$
(6,367,400
)
                           
PER SHARE OF COMMON STOCK:
                          
Reported net loss-basic
  
$
(0.47
)
$
(0.63
)
$
(0.36
)
$
(0.65
)
Cumulative effect of adoption
                          
of SFAS No. 143
    
--
   
--
   
(0.02
)
  
(0.04
)
Adjusted net loss-basic
  
$
(0.47
)
$
(0.63
)
$
(0.38
)
$
(0.69
)
                           
Reported net loss-diluted
  
$
(0.47
)
$
(0.63
)
$
(0.36
)
$
(0.65
)
Cumulative effect of adoption
                          
of SFAS No. 143
    
--
   
--
   
(0.02
)
  
(0.04
)
Adjusted net loss-diluted
  
$
(0.47
)
$
(0.63
)
$
(0.38
)
$
(0.69
)
                           
Weighted average - basic
    
13,182,421
   
11,180,975
   
10,770,658
   
9,299,359
 
                           
Weighted average - diluted
    
13,182,421
   
11,180,975
   
10,770,658
   
9,299,359
 

Computed on a pro-forma basis, the provisions of SFAS No. 143 would have been $7,291,200, $7,091,200 and $6,758,200 at December 31, 2002 and May 31, 2002 and 2001, respectively.

In May 2003 the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This Statement establishes standards for how the Company will classify and measure certain financial instruments with characteristics of both liabilities and equity. It requires that the Company classify a financial instrument within its scope as a liability. Some of the provisions of this Statement are consistent with the current definition of liabilities in FASB Concepts Statement No. 6, "Elements of Financial Statements." The remaining provisions of this Statement are consistent wi th the FASB's proposal to revise that definition to encompass certain obligations that a reporting entity can or must settle by issuing its own equity shares, depending on the nature of the relationship established between the holder and the issuer. This Statement is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 had no material impact on the Company's financial position or results of operations.

  
-78-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 
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:

There are no related party disclosures related to these financial statements

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.    RESTRICTED INVESTMENTS:

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, 2004 and 2003, 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:

Phelps Dodge

During prior years, the Company and Crested conveyed interests in mining claims to AMAX Inc. (“AMAX”) in exchange for cash, royalties and other consideration. AMAX merged with Cyprus Minerals (“Cyprus Amax”) which was purchased by Phelps Dodge Mining Company (“Phelps Dodge”) in December 1999. The properties have not been placed into production as of December 31, 2004.

Amax and later Cyprus Amax paid the Company and Crested an annual advance royalty of 50,000 (25,000 lbs. to each) pounds of molybdenum (or its cash equivalent). During fiscal 2000, Phelps Dodge assumed this obligation.

Phelps Dodge filed suit against the Company and Crested on June 19, 2002 regarding these matters. On February 4, 2005, the U.S. District Court of Colorado entered Findings of Fact and Conclusions of Law in a case involving the Company, Crested and Phelps Dodge Corporation authorizing the return of the Mt. Emmons molybdenum properties and associated water treatment plant to the Company and Crested. USECC has filed a motion with the Court to amend the Order to determine that the decreed water rights be conveyed to USECC. The motion is pending. The ultimate impact of this decision on the financial statements of the Company in management’s opinion will not be measurable until such time as the final decisions are reached and the property actually transferred to the Company. (See Note K)

  
-79-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 
Sutter Gold Mining, Inc.

Sutter Gold Mining Company (“SGMC”) was established in 1990 to conduct operations on mining leases and to produce gold from the Lincoln Project in California.

SGMC has not generated any significant revenue. All acquisition and mine development costs since inception were capitalized. SGMC put the property on a shut down status and took an impairment on the associated assets due to the decline in the spot price for gold and the lack of adequate financing in prior periods. During fiscal 2000, a visitor’s center was developed and became operational. SGMC has leased the visitor’s center to partially cover stand-by costs of the property.

On December 29, 2004, a majority of SGMC was acquired by Sutter Gold Mining Inc. ("SGMI") (formerly Globemin Resources, Inc.) of Vancouver, B.C. SGMI is traded on the TSX Venture Exchange. Approximately 90% of SGMI's common stock was exchanged for 40,190,647 shares of SGMI common stock. At December 31, 2004, the Company owned and controlled 65.5% of the common stock of SGMI.

At December 31, 2004, the spot market price for gold had attained levels that management believes will allow SGMI to produce gold from the property on an economic basis. This conclusion is based on engineering analysis completed on the property, although, economic reserve have not been delineated. Management of SGMI is therefore pursuing the equity capital market and non-affiliated investors to obtain sufficient capital to complete the development of the mine, construct a mill and place the property into production.

SMP

During fiscal 1989, USE and Crested, through USECC, entered into an agreement to sell a 50% interest in their Sheep Mountain properties to a subsidiary of Nukem Inc., CRIC. USECC and CRIC immediately contributed their 50% interests in the properties to a newly-formed partnership, SMP. The SMP Partnership was established to further develop and mine the uranium 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 fourteen years. See Note K for the status of the related litigation/arbitration.

Due to the litigation and arbitration proceedings involving SMP, the Company has expensed all of its costs related to SMP and has no carrying value of its investment in SMP at December 31, 2004 OR December 31, 2003.

On December 8, 2004, the Company and Crested entered into a Purchase and Sale Agreement (the “agreement”) with Bell Coast Capital Corp. now named Uranium Power Corp. (“UPC”), a British Columbia corporation (TSX-V “UPC-V) for the sale to UPC of an undivided 50% interest in the SMP uranium properties. A summary of certain provisions in the agreement follows.

The initial purchase price for the 50% interest in the properties is $4,050,000 and 4,000,000 shares of common stock of UPC, payable by installments. All amounts are stated in US dollars.


  
-80-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 
Initial cash and equity purchase price:

October 29, 2004
  
$
175,000
  
Non-refundable deposit against execution of the definitive agreement.
           
November 29, 2004
 
  
$
 
175,000
 
  
Released from escrow on January 27, 2005 which was five days after TSX-V approval of the agreement.
 
           
June 29, 2005
  
$
500,000
  
and 1,000,000 common shares of UPC stock subject to TSX-V regulations.
           
June 29, 2006
  
$
800,000
  
and 750,000 common shares of UPC stock subject to TSX-V regulations.
           
December 29, 2006
  
$
800,000
  
and 750,000 common shares of UPC stock subject to TSX-V regulations.
           
June 29, 2007
  
$
800,000
  
and 750,000 common shares of UPC stock subject to TSX-V regulations.
           
December 29, 2007
  
$
800,000
  
and 750,000 common shares of UPC stock subject to TSX-V regulations
Total
 
$
4,050,000
  
4,000,000 common shares of UPC

Upward adjustment to initial cash purchase price:

The cash portion of the initial purchase price will be increased by $3,000,000 (in two $1,500,000 installments) after the uranium oxide price (long term indicator) is at or exceeds $30.00/lb for four consecutive weeks (the “price benchmark”). If the price benchmark is attained on or before April 29, 2006, the first installment will be due six months after price attainment (but not before April 29, 2006). If the price benchmark is attained after April 29, 2006, the first installment will be due six months after attainment. In either event, the second installment will be due six months after the first installment is due. These payment obligations will survive closing of the purchase of the 50% interest in the properties; if the installments are not timely paid, UPC will forfeit all of its 50% interest i n the properties, and in the joint venture to be formed.

The Company and Crested and UPC, will each be responsible for paying 50% of (i) current and future Sheep Mountain reclamation costs in excess of $1,600,000, and (ii) all costs to maintain and hold the properties.

Closing of the agreement is required on or before December 29, 2007, with UPC’s last payment of the initial purchase price (plus, if applicable, the increase in the cash portion). At the closing, UPC will contribute its 50% interest in the properties, and the Company and Crested will contribute their aggregate 50% interest in the properties, to a joint venture, wherein UPC and the Company and Crested each will hold a 50% interest. The joint venture generally will cover uranium properties in Wyoming and other properties identified in the Company's and Crested’s uranium property data base, but excluding the Green

  
-81-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 
Mountain area and Kennecott’s Sweetwater uranium mill, the Shootaring Canyon uranium mill in southeast Utah (and properties within ten miles of that mill), and properties acquired in connection with a future joint venture involving that mill.

UPC will contribute up to $10,000,000 to the joint venture (at $500,000 for each of 20 exploration projects). The Company, Crested and UPC, each will be responsible for 50% of costs on each project in excess of $500,000.

PLATEAU RESOURCES LIMITED

During fiscal 1994, the Company entered into an agreement with Consumers Power Company to acquire all the issued and outstanding common stock of Plateau Resources Limited (“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 Pleateau stock and agreed to assume all environmental liabilities and reclamation bonding obligations. At December 31, 2004, Plateau has a cash security in the amount of $6.8 million to cover reclamation and annual licensing of the properties (see Note K). The Directors of the Company and Crested have agreed to divide equally the cash flows derived from operations and a portion of certain reclamation obligations.

On August 1, 2003, the Company and Crested sold interest in the Ticaboo Townsite in southern Utah as a result of Pleateau entering into a Stock Purchase Agreement to sell all the outstanding shares of Canyon Homesteads, Inc. (“Canyon”) to The Cactus Group LLC, a newly formed Colorado limited liability company. The Cactus Group purchased all of the outstanding stock of Canyon for $3,370,000. Of that amount, $349,300 was paid in cash at closing and the balance of $3,120,700 is to be paid under the terms of a promissory note, which bears interest at 7.5%.

Pursuant to the note agreement, the Company and Crested received $166,000 in payments on the note receivable and $44,000 in room credits. At December 31, 2004, the note was current. The Company and Crested are to receive $10,000 per month for the months of January through March 2005 and $24,000 per month on a monthly basis after March of 2005 until August of 2008, at which time, a balloon payment of $2.8 million is due. The note is secured with all the assets of The Cactus Group and Canyon along with personal guarantees by the six principals of The Cactus Group. As additional consideration for the sale, the Company and Crested will also receive the first $210,000 in gross proceeds from the sale of either single family or mobile home lots in Ticaboo.

The Company and Crested are currently evaluating the best utilization of Plateau’s assets. Evaluations are ongoing to determine when, or if, the mine and mill properties should be placed into production. The primary factor in these evaluations relates to uranium market prices.

ROCKY MOUNTAIN GAS, INC.

In 1999, the Company and Crested organized Rocky Mountain Gas, Inc. (“RMG”) to enter into the coalbed methane gas/natural gas business. RMG is engaged in the acquisition of coalbed methane gas properties and the future exploration, development and production of methane gas from those properties. At December 31, 2004, RMG is owned 49.3% by the Company and 39.8% by Crested. At December 31, 2004, RMG owns 237,200 gross acres and 128,700 net acres.


  
-82-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 
CCBM

RMG sold an interest in its coalbed methane properties to CCBM. The agreement between CCBM and RMG is to finance the further development of coalbed methane acreage currently owned by RMG in Montana and Wyoming, and to acquire and develop more acreage in Wyoming and the Powder River Basin of Montana. At December 31, 2004, CCBM had completed its funding and drilling commitments. RMG assigned a 25% undivided interest in its Oyster Ridge property and a 6.25% undivided interest in its Castle Rock properties to CCBM. RMG also assigned varying interests in other properties to CCBM which were later contributed to Pinnacle Gas Resources, Inc. ("Pinnacle") see discussion below on Pinnacle.

RMG is the designated operator under a Joint Operating Agreement (“JOA”) between RMG and CCBM, which will govern all operations on the properties subject to a Purchase and Sale Agreement between RMG and CCBM, subject to pre-existing JOA’s with other entities, and operation or properties in the area of mutual interest (“AMI”). CCBM has the right to participate in other properties RMG may acquire under the area of mutual interest (“AMI”), until June 30, 2005.

PINNACLE

On June 23, 2003, a Subscription and Contribution Agreement was executed by RMG, CCBM and seven affiliates of Credit Suisse First Boston Private Equity (“CSFB Parties”). Under the Agreement, RMG and CCBM contributed certain of their respective interests, having an estimated fair value of approximately $7.5 million each, carried on RMG’s books at a cost of $957,600, comprised of (1) leases in the Clearmont, Kirby, Arvada and Bobcat CBM project areas and (2) oil and gas reserves in the Bobcat project area, to a newly formed entity, Pinnacle Gas Resources, Inc., a Delaware corporation (“Pinnacle”). In exchange for the contribution of these assets, RMG and CCBM each received 37.5% of the common stock of Pinnacle (“Pinnacle Common Stock”) as of the closing date and options to purch ase Pinnacle Common Stock (“Pinnacle Stock Options”). CFSB contributed $5.0 million for 25% of the common stock of Pinnacle.

The CSFB Parties also contributed approximately $13.0 million of cash to Pinnacle in return for the Redeemable Preferred Stock of Pinnacle (“Pinnacle Preferred Stock”), and warrants to purchase Pinnacle Common Stock (“Pinnacle Warrants”). The CSFB Parties also agreed to contribute additional cash, under certain circumstances, of up to approximately $11.8 million to Pinnacle to fund future drilling, development and acquisitions. The CSFB Parties currently have greater than 50% of the voting power of the Pinnacle capital stock through their ownership of Pinnacle Common Stock and Pinnacle Preferred Stock.

At December 31, 2004 RMG and CCBM each owned 16.7% of Pinnacle and the CSFB Parties owned 66.6%.

Pinnacle is a private corporation. Only such information about Pinnacle as its board of directors elects to release is available to the public. All other information about Pinnacle is subject to confidentiality agreements between Pinnacle, RMG and the other parties to the June 2003 transaction.


  
-83-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 

 
RMG I - HI-PRO

On January 30, 2004, RMG, through its wholly owned subsidiary RMG I, purchased the producing, and non-producing properties of Hi-Pro Production LLC ("Hi-Pro"), a company in the Powder River Basin of Wyoming. The terms of the purchase were as follows:

$ 776,700 
   
cash paid by RMG I, $75,000.
 
$ 588,300 8,300
    
net revenues from November 1, 2003 to December 31, 2003, which were retained by Hi-Pro.(1)
 
$ 500,000 
   
by USE's 30 day promissory note (secured by 166,667 restricted shares of USE common stock, valued at $3.00 per share.)(2)
 
$ 600,000 
   
by 200,000 restricted shares of USE common stock (valued at $3.00 per share).
  
$ 700,000 
   
by 233,333 restricted shares of RMG common stock (valued at $3.00 per share.)(3)
 
$        3,635,000
    
cash, loaned to RMG I under the credit facility agreement.
  
$        6,800,000
      
           (588,300)
    
reverse net revenues from November 1, 2003 to December 31, 2003, which were retained by Hi-Pro
  
$        6,211,700
        
_________________________

(1)    RMG I paid all January operating costs at closing. Net revenues from the purchased properties for January 2004 were credited to RMG I's obligations under the credit facility agreement.
           These net revenues were considered by the parties to be a reduction in the purchase price which RMG I otherwise would have paid at the January 30, 2004 closing.
(2)    Pursuant to the terms of the promissory note, USE issued 166,667 shares as payment in full of this obligation during the first quarter of 2004.
(3)    The RMG shares were convertible at Hi-Pro's sole election into restricted shares of common stock of USE. The number of USE shares to be issued were based upon (A) the number of RMG
          shares to be converted, multiplied by $3.00 per share, divided by (B) the average closing sale price of the shares of USE for the 10 trading days prior to notice of conversion. During the quarter
          ended June 30, 2004, all of these shares were converted into 312,221 shares of the Company's common stock. The Company has filed a resale registration statement with the Securities and
          Exchange Commission to cover public resale of these shares.

RMG I purchased these properties to continue its entry into the coalbed methane gas business and accounted for as a purchase transaction with the estimated fair value of assets and liabilities assumed in the acquisition as follows:

Estimated fair value of assets acquired
  
Current assets
$ 639,400
Oil and gas properties
6,538,300
Other property and equipment
146,700
Other long term assets
145,000
Total assets acquired
   $7,469,400


  
-84-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 

Estimated fair value of liabilities assumed
  
Current liabilities
$ 884,800
Asset retirement obligation
372,100
Total liabilities assumed
1,256,900
Net assets acquired
$ 6,212,500


RMG I financed $3.6 million of the cash component from a $25 million credit facility arranged by Petrobridge Investment Management, LLC (Petrobridge), a mezzanine lender headquartered in Houston, TX. The properties acquired from Hi-Pro serve as the sole collateral for the credit facility. As defined by the agreement, terms under the credit facility include the following: (1) advances under the credit facility are subject to lender's approval; (2) all revenues from oil and gas properties securing the credit facility will be paid to a lock box controlled by the lender. All disbursements for lease operating costs, revenue distributions and operating expense require approval by the lender before distributions are made; and (3) RMG I must maintain certain financial ratios and production volumes, among other requirem ents.
 
Results of operations for the year ended December 31, 2004 would not be materially affected had the purchase if Hi-Pro occurred on January 1, 2004.

At December 31, 2004, RMG I was not in compliance with five of the financial covenants under the Petrobridge agreement. The ratios and production figures that RMG I is not in compliance with are:

 
Terms of Loan
  
Actual at 12-31-04
Total Debt to EBITDA
No greater than 2 to 1
  
5.7 to 1
EBITDA to interest and rents
Not less than 3 to 1    
 
1.3 to 1
Current Ratio
Not less than 1 to 1    
 
.3 to 1
NPV of proved developed
Producing reserves to debt
Not less than 1 to 1    
 
.9 to 1
Sales Volumes
230 mmcf per quarter
  
182.2 mmcf

A revocable waiver was granted through January 31, 2006 by the lender. As the wavier is conditional, the entire debt is classified by RMG as current. Management of RMG I continues to seek solutions in the production of coalbed methane gas to bring the project into compliance. Due to lower than projected sales volumes, the Hi-Pro field will remain out of compliance unless (1) higher prices are realized, (2) costs are reduced and (3) the debt is paid down. It is probable that RMG I will not be in compliance with these ratios for the next reporting period. Should the lender declare the note in default, the only asset available for recourse is the Hi-Pro property owned by RMG I.


  
-85-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 
Oil and Gas Properties and Equipment Included the Following:
 

   
December 31,
  
May 31,
  
   
2004
  
2003
  
2002
  
2002
  
Oil and gas properties:
                          
Subject to amortization
    
1,773,600
   
1,773,600
   
1,773,600
   
1,773,600
 
Acquired in calendar 2004
    
3,785,400
   
--
   
--
   
--
 
Acquired in calendar 2003
    
--
   
--
   
--
   
--
 
Acquired in calendar 2002
    
650,000
   
650,000
   
650,000
   
--
 
     
6,209,000
   
2,423,600
   
2,423,600
   
1,773,600
 
Not subject to amortization:
                          
Acquired in calendar 2004
    
4,471,100
   
--
   
--
   
--
 
Acquired in calendar 2003
    
265,400
   
265,400
   
--
   
--
 
Acquired in calendar 2002
    
508,400
   
508,400
   
508,400
   
--
 
Acquired in fiscal 2002
    
363,900
   
363,900
   
363,900
   
363,900
 
Acquired in fiscal 2001
    
1,154,500
   
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
 
Less prior year's sales
    
(6,315,600
)
  
(2,500,000
)
  
(1,250,000
)
  
--
 
     
5,174,900
   
4,519,400
   
5,504,000
   
6,245,600
 
                           
Sale of gas property interests
    
(563,600
)
  
(3,815,600
)
  
(1,250,000
)
  
(1,250,000
)
     
4,611,300
   
703,800
   
4,254,000
   
4,995,600
 
Total oil and gas properties
    
10,820,300
   
3,127,400
   
6,677,600
   
6,769,200
 
Accumulated depreciation, depletion
                          
and amortization
    
(2,917,500
)
  
(1,923,000
)
  
(1,834,100
)
  
(1,773,600
)
                           
Net oil and gas properties
  
$
7,902,800
  
$
1,204,400
  
$
4,843,500
  
$
4,995,600
  
                           
 
The Company began drilling of its coalbed methane properties during 2002 and acquired producing properties in January of 2004 and June 2002.

The following sets forth costs incurred from oil and gas property acquisition and development activities:

   
December 31,
  
May 31,
  
   
2004
  
2003
  
2002
  
2002
  
Acquisition of properties/facilities
  
$
6,613,900
  
$
107,100
  
$
936,200
  
$
192,600
  
Development
    
1,642,600
   
158,300
   
97,200
   
87,400
 
   
$
8,256,500
  
$
265,400
  
$
1,033,400
  
$
280,000
  
                           
 
 

 
-86-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

The results from operations of oil and gas activities for the year ended December 31, 2004 and 2003 are as follows:
           
Seven Months
  
           
Ended
  
   
Year ended December 31,
  
May 31,
  
   
2004
  
2003
  
2002
  
          Sales to third parties
 
$
2,951,600
  
$
287,400
  
$
199,400
  
          Production costs
   
(2,322,200
)
  
(224,200
)
  
(335,200
)
          Depreciation, depletion and amortization
   
(994,500
)
  
(88,900
)
$
(65,200
)
          Loss from oil and gas production activities
 
$
(365,100
)
$
(25,700
)
$
(301,000
)
                     
 
Depreciation, depletion and amortization was $0.98, $1.09 and $1.14 per equivalent mcf of production for the year ended December 31, 2004, 2003 and the seven months ended December 31, 2002, respectively.

G.    DEBT:
 
As of December 31, 2004 and 2003 the company and its affiliates had current and long term liabilities associated with the comprehensive loss from hedging of coalbed methane gas, prepaid rents, leases, self funding of employee health insurance and accrued holding costs of its uranium properties in southern Utah as follows:
 
Current other liabilities:

   
Year Ended December 31,
  
   
2004
  
2003
  
Comprehensive loss from hedging
  
$
436,000
  
$
--
  
Prepaid rent
    
26,500
    
--
  
Mineral property lease
    
69,700
    
69,700
  
   
$
532,200
  
$
69,700
  
               

Long term other liabilities:
 
   
Year Ended December 31,
  
   
2004
  
2003
  
Employee health insurance self funding
  
$
297,900
  
$
247,500
  
Holding cost of uranium property
    
1,654,400
    
1,911,100
  
   
$
1,952,300
  
$
2,158,600
  
               
 
Lines of Credit

As of December 31, 2004, the Company had a $750,000 line of credit with a commercial bank. The line of credit bore interest at a variable rate (6.25% as of December 31, 2004). The weighted average interest rate for the year ended December 31, 2004 was 5.34%. As of December 31, 2004, there was no outstanding balance due under the line of credit. The line of credit expired on December 31, 2004 and has been renewed for 6 months to June 30, 2005. This line of credit is secured by a share of the net proceeds of fees from production of oil wells and certain assets of USECC.

  
-87-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

 
Long-term Debt
 

The components of long-term debt as of December 31, 2004 and 2003 are as follows:
  
               
       
December 31,
  
       
2004
 
2003
 
USECC installment notes - collateralized
          
   by equipment; interest at 5.25%  
 
          
to 9.0%, matures in 2005-2009
        
$
1,192,300
  
$
1,407,900
  
SGMC installment notes - collateralized
            
by certain properties, interest at
                   
8.0% maturity 2009
          
46,500
   
62,900
 
PLATEAU installment note - collateralized
            
by equipment, interest at 8.0%
          
--
   
--
 
USE convertible note - net of discount
            
collateralized by equipment coalbed methane
                    
leases and 4,000,000 shares of RMG stock
                    
interest at 10%, maturity 2006
          
3,000,000
       
Discount for issuance of USE warrants
          
(315,800
)
      
Amortization of warrants discount
          
42,800
       
           
2,727,000
   
--
 
USE convertible notes - net of discounts
            
by equipment, interest at 8.0%, maturity 2006
                
1,500,000
 
Discount for issuance of USE warrants
                
(969,900
)
Payment of principal
                
(500,000
)
Amortization of warrants discount
                
748,900
 
--
               
779,000
 
RMG production related note - collateralized
            
by gas properties and production,
                   
interest at 11.0%
          
3,700,000
       
Additional borrowings
          
479,700
       
Discount for issuance of USE warrants
          
(80,400
)
      
Discount for overriding royalty
          
(314,200
)
      
Payment of principal
          
(690,900
)
      
Amortization of warrant and royalty discount
          
120,600
       
           
3,214,800
   
--
 
           
7,180,600
   
2,249,800
 
Less current portion
  
(3,400,100
)
  
(932,200
)
         
$
3,780,500
  
$
1,317,600
  
                     
Principal requirements on long-term debt are $3,400,100, $2,873,100, $875,000, $23,400 and $9,000 for the years ended December 31, 2005 through 2009, respectively.
 
      
 

 
-88-
 

U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
On July 30, 2004, the Company entered into a credit agreement with Geddes and Company ("Geddes"), based in Phoenix, Arizona, to borrow up to $3 million (USE convertible notes above). Proceeds from the credit facility are to be used to acquire and develop gas properties, and for general corporate purposes of USE and the Company.

Collateral for the credit facility include:
  (a) the Company's coalbed methane leases in the Castle Rock property (located in the Montana portion of the Powder River Basin) and;

(b)        4 million shares of RMG's common stock owned by the Company.

In 2003, Caydal converted $500,000 of debt to 211,109 shares of common stock (33,333 shares at the original $3.00 conversion price, and 177,776 shares at the restructured price of $2.25). During the calendar year ended December 31, 2004, Caydal converted the balance of its debt of $500,000 into 222,220 shares of the Company's common stock. Tsunami parties (Tsunami") also converted its $500,000 in convertible debt into 222,220 shares of the Company's common stock. The Company paid $25,600 and $44,700 in interest to Caydal and Tsunami respectively by issuing 11,447 shares of common stock to Caydal and 20,946 shares of common stock to Tsunami.

H.    INCOME TAXES:

The components of deferred taxes as of December 31, 2004 and 2003 are as follows:

   
December 31,
  
   
2004
  
2003
  
Deferred tax assets:
          
Deferred compensation
    
1,565,700
 
$
445,400
  
Net operating loss carryforwards
    
13,978,900
   
11,596,000
 
Non-deductible reserves and other
    
523,000
   
437,200
 
Tax basis in excess of book basis
    
994,700
   
106,700
 
Total deferred tax assets
    
17,062,300
   
12,585,300
 
               
Deferred tax liabilities:
              
Book basis in excess of tax basis
    
(1,397,900
)
  
(486,200
) 
Development and exploration costs
    
(109,400
)
  
(107,600
) 
Total deferred tax liabilities
    
(1,507,300
)
  
(593,800
) 
     
15,555,000
   
11,991,500
 
Valuation allowance
    
(15,555,000
)
  
(11,991,500
)
Net deferred tax liability
  
$
--
  
$
--
  
               

 
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.

  
-89-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
The valuation allowance increased $3,563,500 for the year ended December 31, 2004 and increased $2,042,100 for the year ended December 31, 2003, increased $649,000 for the seven months ended December 31, 2002 and decreased $2,740,300 for the year ended May 31, 2002.

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:
           
Seven
      
           
months ended
  
Year ended
  
   
Year ended December 31,
  
December 31,
  
May 31,
  
   
2004
  
2003
  
2002
  
2002
  
Expected federal income tax
    
(2,133,800
)
  
(2,405,800
)
  
(1,305,600
)
  
(2,131,000
)
Net operating losses not previously
                          
benefitted and other
    
(1,429,700
)
  
363,700
   
655,700
   
4,871,300
 
Valuation allowance
    
3,563,500
   
2,042,100
   
649,900
   
(2,740,300
)
Income tax provision
  
$
--
  
$
--
  
$
--
  
$
--
  
                           

There were no taxes currently payable as of December 31, 2004 and December 31, 2003 related to continuing operations.

At December 31, 2004, the Company had available, for federal income tax purposes, net operating loss carryforwards of approximately $12,979,300 which will expire from 2006 to 2023. 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 during the year ended December 31, 2004 has been 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:

  
-90-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 

   
Year ended December 31, 2004
  
   
Coalbed
          
   
Methane
          
   
(and holding
          
   
costs for inactive
  
Real Estate
      
   
mining properties)
  
Operations
  
Consolidated
 
               
Revenues
  
$
3,205,700
  
$
256,100
  
$
3,461,800
  
Management fees
                
1,179,900
 
Total Revenues
              
$
4,641,700
  
                     
Operating loss
  
$
(2,429,800
)
$
(39,400
)
$
(2,469,200
)
Management fees
                
1,179,900
 
General corporate and other expenses
                
(5,370,100
)
Other income and expenses
                
13,000
 
Minority interest in loss of subsidiaries
                
397,700
 
Loss before income taxes
              
$
(6,248,700
)
                     
Identifiable assets at December 31, 2004
  
$
16,285,300
  
$
2,177,600
  
$
18,462,900
  
Investments in affiliates
                
957,700
 
Corporate assets
                
11,283,100
 
Total assets at December 31, 2004
              
$
30,703,700
  
                     
Capital expenditures
  
$
8,167,900
  
$
3,600
        
Depreciation, depletion and
                    
amortization
  
$
1,183,500
  
$
91,200
        
                     
Identifiable assets
                    
Net fixed assets
  
$
9,280,900
  
$
2,177,600
        
Other investments
    
6,852,300
   
--
       
Inventory
    
152,100
   
--
       
   
$
16,285,300
  
$
2,177,600
        
                     

 
-91-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 

   
Year Ended December 31, 2003
      
   
Coalbed
          
   
Methane
  
Motel/
      
   
(and holding
  
Real Estate/
      
   
costs for inactive
  
Airport
      
   
mining properties)
  
Operations
  
Consolidated
  
               
Revenues
  
$
287,400
  
$
334,300
  
$
621,700
  
Management fees
                
215,600
 
Total revenues
              
$
837,300
  
                     
Operating (loss) income
  
$
(1,487,400
)
$
31,400
  
$
(1,456,000
)
Management fees
                
215,600
 
General corporate and other expenses
                
(5,997,500
)
Other income and expenses
                
(73,000
)
Minority interest in loss of affiliates
               
235,100
 
Loss before income taxes
              
$
(7,075,800
)
                     
Identifiable net assets at
                    
December 31, 2003
  
$
9,365,000
  
$
3,030,100
  
$
12,395,100
  
Investment in non-affiliated company
                
957,600
  
Corporate assets
                
10,577,100
 
Total assets at December 31, 2003
              
$
23,929,800
  
                     
Capital expenditures
  
$
176,400
  
$
--
        
Depreciation, depletion and
                    
amortization
  
$
217,600
  
$
102,400
        
 

 
-92-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(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
  
Management fees
                
159,100
 
Total revenues
              
$
1,027,600
  
                     
Operating (loss) Income
  
$
(973,000
)
$
221,900
  
$
(751,100
)
Management fees
                
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
  
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
        

 
-93-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

   
Year Ended December 31, 2002
      
   
Coalbed
          
   
Methane
  
Motel/
      
   
(and holding
  
Real Estate/
      
   
costs for inactive
  
Airport
      
   
mining properties)
  
Operations
  
Consolidated
  
               
Revenues
  
$
--
  
$
1,795,900
  
$
1,795,900
  
Management fees
                
208,200
 
Total revenues
              
$
2,004,100
  
                     
Operating loss
  
$
(1,707,000
)
$
(133,000
)
$
(1,840,800
)
Management fees
                
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
  
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
        
 

 
-94-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(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 3,250,000 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 the year ended December 31, 2004 and 2003, the seven months ended December 31, 2002 and the year ended May 31, 2002 the following activity occurred under the 1998 ISOP:


               
Seven months
      
               
ended
  
Year ended
  
       
Year ended December 31,
  
December 31,
  
May 31,
  
       
2004
 
2003
 
2002
 
2002
 
Grants
                  
      Qualified    
--
 
--
 
--
 
--
 
      Non-Qualified    
--
 
--
 
--
 
--
 
       
--
 
--
 
--
 
--
 
                       
Price of Grants
                  
      High  
 
  
--
 
--
 
--
 
--
 
      Low  
 
  
--
 
--
 
--
 
--
 
                       
Exercised
                  
      Qualified  
 
  
--
 
77,832
 
71,166
 
243,250
 
      Non-Qualified  
 
  
--
 
71,453
 
1
 
55,372
 
       
--
 
149,285
 
71,167
 
298,622
 
Total Cash Received
$
--
  
$
364,200
  
$
170,800
  
$
742,000
  
                                 
Forfeitures/Cancellations
                        
Qualified
          
--
   
34,782
   
--
   
78,244
 
Non-Qualified
          
--
   
64,233
   
--
   
346,018
 
--
               
99,015
   
--
   
424,262
 
                                 

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 (amended in 2004 and approved by the shareholders) reserves for issuance shares of USE common stock equal to 20% of the USE shares of common stock issued and outstanding at any time. The 2001 ISOP has a term of 10 years.


  
-95-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
During the years ended December 31, 2004 and 2003, the seven months ended December 31, 2002 and the year ended May 31, 2002 the following activity occurred under the 2001 ISOP:

           
Seven months
      
           
ended
  
Year ended
  
   
Year ended December 31,
  
December 31,
  
May 31,
  
   
2004
 
2003
 
2002
 
2002
 
Grants
                  
Qualified
    
1,272,000
   
--
   
459,996
   
10,000
 
Non-Qualified
    
--
   
--
   
473,004
   
950,000
 
     
1,272,000
   
--
   
933,000
   
960,000
 
                           
Price ofGrants
                          
High
  
$
2.46
    
--
 
$
2.25
  
$
3.90
  
Low
  
$
2.46
    
--
 
$
2.25
  
$
3.82
  
                           
Exercised
                          
Qualified
    
--
   
73,780
   
--
   
--
 
Non-Qualified
    
--
   
52,556
   
--
   
--
 
 
      --    
126,336
   
--
   
--
 
Total Cash Received
  
$
--
  
$
284,300
  
$
--
  
$
--
  
                           
Forfeitures/Cancellations
                          
Qualified
    
12,000
   
65,108
   
--
   
--
 
Non-Qualified
    
--
   
252,556
   
50,000
   
--
 
     
12,000
   
317,664
   
50,000
   
--
 
                           


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.


  
-96-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
The following table represents the activity in employee options for the periods covered by the Annual Report for the year ended December 31, 2004 that are not in employee stock option plans:
 
           
Seven months
      
           
ended
  
Year ended
  
   
Year ended December 31,
  
December 31,
  
May 31,
  
   
2004
 
2003
 
2002
 
2002
 
Grants
                  
Qualified
    
--
   
--
   
--
   
10,000
 
Non-Qualified
    
--
   
10,000
   
--
   
--
 
 
      --    
10,000
   
--
   
10,000
 
                           
Price ofGrants
                          
High
    
--
 
$
2.90
  
$
--
  
$
3.82
  
Low
    
--
 
$
2.90
  
$
--
  
$
3.82
  
                           
Exercised
                          
Qualified
    
--
   
--
   
--
   
--
 
Non-Qualified
    
--
   
--
   
--
   
--
 
 
      --    
--
   
--
   
--
 
Total Cash Received
  
$
--
  
$
-
  
$
--
  
$
--
  
                           
Forfeitures/Cancellations
                          
Qualified
    
--
   
--
   
--
   
--
 
Non-Qualified
    
10,000
   
10,000
   
100,000
   
200,000
 
     
10,000
   
10,000
   
100,000
   
200,000
 
                           



  
-97-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
A summary of the Employee Stock Option Plans activity in all plans for the year ended December 31, 2004, 2003; the seven months ended December 31, 2002 and the year ended May 31, 2002 is as follows:
 

                   
Seven months ended
              
   
Year ended December 31,
  
December 31,
  
Year ended May 31,
  
   
2004
 
2003
 
2002
 
 
  
 
  
2002
 
 
  
 
  
       
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
    
2,873,646
 
$
2.74
    
3,565,946
 
$
2.76
    
2,854,113
       
$
2.92
    
2,606,997
       
$
2.69
  
Granted
    
1,272,000
   
2.46
    
10,000
   
2.90
   
933,000
         
2.25
   
970,000
         
3.90
 
Forfeited
    
(22,000
)
  
2.66
    
(426,679
)
  
3.17
   
(150,000
)
        
2.63
   
(424,262
)
        
3.30
 
Expired
    
--
   
--
   
--
   
--
   
--
         
--
   
--
         
--
 
Exercised
    
--
   
--
   
(275,621
)
  
2.35
   
(71,167
)
        
2.40
   
(298,622
)
        
2.84
 
Outstanding at period end
    
4,123,646
   
--
   
2,873,646
   
2.74
   
3,565,946
         
2.76
   
2,854,113
         
2.92
 
Exercisable at period end
    
2,863,646
   
--
   
2,873,646
   
2.74
   
2,612,946
         
2.94
   
1,984,113
         
2.49
 
                                                               
Weighted average fair
                                                              
value of options
                                                              
granted during
                                                              
the period
        
$
1.66
        
$
0.68
              
$
1.15
              
$
1.99
  
 
The following table summarized information about employee stock options outstanding and exercisable at December 31, 2004:

       
Weighted
    
Weighted
  
Number of
  
average
  
Number of
Average
  
options
  
remaining
  
options
Exercise
 
outstanding at
  
contractual
  
exercisable at
Price
  
December 31, 2004
  
Life in years
  
December 31, 2004
             
$ 2.65
 
4,123,646
 
7.1
 
2,863,646

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 year ended December 31, 2004 the Board of Directors of USE contributed 70,439 shares to the ESOP at the price of $2.96 for a total expense of $208,500. This compares to contributions to the ESOP during the year ended December 31, 2003, the seven months ended December 31, 2002 and fiscal year ended May 31, 2002 of 76,294, 43,867 and 70,075 shares to the ESOP at prices of $3.10, $3.08 and $3.29 per share, respectively. The Company has expensed $208,500, $236,400, $135,100 and $236,900 during the years ended December 31, 2004, 2003, the seven months ended December 31, 2002 and the fiscal year ended May 31, 2002, respectively related

  
-98-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
to these contributions. As of December 31, 2004, all shares of the USE stock that have been contributed to the ESOP have been allocated. The estimated fair value of shares that are not vested is approximately $85,500. USE has loaned the ESOP $1,014,300 to purchase 125,000 shares from the Company and 38,550 shares on the open market. During the year ended May 31, 1996, 10,089 of these shares were used to fund the Company's annual funding commitment and reduce the loan to the Company by $87,300. 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 were 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 received 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. Th e shares are held in trust by the Company's treasurer and are voted by the Company's non-employee directors. As of December 31, 2003, 392,536 shares had been issued to the five officers of the Company under the 1996 Stock Award Plan and 62,536 shares had been released to the estate of one of the officers. The 1996 Stock award program was closed out in the year ended December 31, 2003.

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, 10,000 shares may be issued to each officer each year. 100,000 shares were issued under the Plan during the year ended December 31, 2003. As compensation for the year ended December 31, 2003 and the seven months ended December 31, 2002. During the year ended December 31, 2004 an additional 50,000 shares were issued to the officers.


  
-99-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
Options and Warrants to Others

As of December 31, 2004, there are 1,505,174 options and warrants outstanding to purchase shares of the Company's common stock. The Company values these warrants using the Black-Scholes option pricing model and expenses that value over the life of the warrants. Activity for the periods ended December 31, 2004 for warrants is represented in the following table:
 

                   
Seven months ended
          
   
Year ended December 31,
  
December 31,
  
Year ended May 31,
  
   
2004
 
2003
 
2002
 
 
  
2002
 
 
  
       
Weighted
      
Weighted
      
Weighted
      
Weighted
  
       
Average
      
Average
      
Average
      
Average
  
       
Exercise
      
Exercise
      
Exercise
      
Exercise
  
   
Warrants
  
Price
  
Warrants
  
Price
  
Warrants
  
Price
  
Warrants
  
Price
  
Outstanding at beginning
                                  
of the period
    
907,209
 
$
3.51
    
990,383
 
$
3.37
    
860,152
 
$
3.43
    
314,158
 
$
3.05
  
Granted
    
868,465
   
2.87
   
224,875
   
4.32
   
145,147
   
2.95
   
572,364
   
3.62
 
Forfeited
    
(145,500
)
  
2.63
   
(176,453
)
  
3.67
   
(14,916
)
  
--
   
(25,165
)
  
2.88
 
Expired
    
--
   
--
   
--
   
--
   
--
   
--
   
--
   
--
 
Exercised
    
(125,000
)
  
2.01
   
(131,596
)
  
3.55
   
--
   
--
   
(1,205
)
  
3.75
 
Outstanding at period end
    
1,505,174
   
3.35
   
907,209
   
3.51
   
990,383
   
3.36
   
860,152
   
3.43
 
Exercisable at period end
    
1,044,152
   
3.43
   
831,724
   
3.41
   
979,908
   
3.37
   
860,152
   
3.43
 
                                                   
Weighted average fair
                                                  
value of options
                                                  
granted during
                                                  
the period
        
$
1.37
        
$
0.68
        
$
1.15
        
$
1.99
  
 
The following table summarized information about employee stock options outstanding and exercisable at December 31, 2004:

Weighted
  
Number of
  
average
  
Number of
Average
  
options
  
remaining
  
options
Exercise
 
outstanding at
  
contractual
  
exercisable at
Price
  
December 31, 2004
  
Life in years
  
December 31, 2004
             
$ 3.35
 
1,505,174
 
3.0
 
1,044,152


These options and warrants are held by persons or entities other than employees, officers and directors of the Company.


  
-100-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
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 of Directors amended the stock bonus plan. As a result, the earn-out dates of certain individuals were extended until retirement. The Company recorded $216,800 of compensation expense for the year ended December 31, 2004 compared to $284,700, $178,300 for the year ended December 31, 2003, the seven months ended December 31, 2002; and $298,300 for the year ended May 31, 2002, respectively. The accompanying balance sheet at December 31, 2004 includes a deferred charge of $322,600 of which $171,000 is included in prepaid expenses. 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
  
Balance at
             
     May 31, 2001
    
433,788
       
$
2,748,600
  
     May 31, 2002
    
67,000
 
$
3.90
    
261,300
 
Balance at
                    
     May 31, 2002 and
                    
     December 31, 2002
    
500,788
         
3,009,900
 
March 24, 2003
    
43,378
  
$
3.50
    
151,900
  
     Shares earned
    
(78,286
)
  
--
    
(435,200
)
Balance at
                    
     December 31, 2003
    
465,880
          
2,726,600
  
     Shares earned
    
(23,140
)
  
--
    
(127,600
)
Balance at
                    
     December 31, 2004
    
442,740
        
$
2,599,000
  

K.    COMMITMENTS, CONTINGENCIES AND OTHER:

Legal Proceedings

Material proceedings pending at December 31, 2004, and developments in those proceedings from that date to the date this Annual Report is filed, are summarized below. Other proceedings which were pending during the year have been settled or otherwise finally resolved.

Sheep Mountain Partners Arbitration/Litigation

In 1991, disputes arose between USE/Crested d/b/a/ USECC, and Nukem, Inc. and its subsidiary Cycle Resource Investment Corp. ("CRIC"), concerning the formation and operation of their equally owned Sheep Mountain Partners (SMP) 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 of Colorado in Civil Action No. 91B1153. The Federal Court stayed the arbitration proceedings and discovery proceeded. In February 1994, all of the parties agreed to consensual and binding arbitration of all of their disputes over SMP before an arbitration panel (the "Panel").


  
-101-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
The Panel entered an Order and Award in 1996, finding generally in favor of USE and Crested on certain of their claims and imposed a constructive trust in favor of Sheep Mountain Partners on uranium contracts Nukem entered into to purchase uranium from CIS republics, and also awarded SMP damages of $31,355,070 against Nukem. Further legal proceedings ensued. On appeal, the 10th Circuit Court of Appeals ("CCA") issued an Order and Judgment affirming the U.S. 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 in favor of SMP against Nukem.

As a result of further proceedings, the U.S. District Court appointed a Special Master to conduct an accounting of the constructive trust. The U.S. District Court adopted the Special Master’s report in part and rejected it in part, and entered judgment on August 1, 2003 in favor of USECC and against Nukem for $20,044,183. In early 2004, the parties appealed this judgment to the CCA.

On February 24, 2005, a three judge panel of the CCA vacated the judgment of the U.S. District Court and remanded the case to the Panel for clarification of the 1996 Order and Award. In remanding this case, the CCA stated: "The arbitration award in this case is silent as to the definition of 'purchase rights' and the 'profits therefrom,' including the valuation of either. Also unstated in the award is the duration of the constructive trust and whether and what costs should be deducted when computing the value of the constructive trust. Further, the arbitration panel failed to address whether prejudgment interest should be awarded on the value of the constructive trust. As a result, the district court's valuation of the constructive trust was based upon extensive guesswork. Therefore, a remand to the arbitration panel for clarification is necessary, despite the long and tortured procedural history of this case."

The timing and ultimate outcome of this litigation is not predicted. We believe that the ultimate outcome will not have an adverse affect on our financial condition or results of operations.

Contour Development Litigation

On July 8, 1998, USE and Crested filed a lawsuit in the U.S. District Court of Colorado in Case No. 98WM1630, against Contour Development Company, L.L.C. and entities and persons associated with Contour Development Company, L.L.C. for substantial damages from the defendants for dealings in real estate owned by USE and Crested in Gunnison, Colorado. This litigation was settled in 2004 with USE and Crested receiving nominal cash and seven real estate lots in and near Gunnison. Two lots have been sold and five are for sale.

Phelps Dodge Litigation

USE 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 (“PD”) and its subsidiary, Mt. Emmons Mining Company (“MEMCO”), over contractual obligations in USECC’s agreement with PD’s predecessor companies, concerning mining properties on Mt. Emmons, near Crested Butte, Colorado.

The litigation relates to agreements from 1974 when USE and Crested leased the mining claims to AMAX Inc., PD’s predecessor company. The mining claims cover one of the world’s largest and richest deposits of molybdenum, which was discovered by AMAX.


  
-102-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
The June 19, 2002 complaint filed by PD and MEMCO sought a determination that PD’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, USE 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 Mineral Co. USECC’s counter and cross-claims alleged that in 1999, PD formed a wholly-owned subsidiary CAV Corporation, for the purpose of purchasing the controlling interest in Cyprus Amax and its subsidiaries (including MEMCO) and making Cyprus Amax a subsidiary of PD. Therefore, USECC asserted that the acquisition of Cyprus Amax by PD was a sale of MEMCO and the properties that triggered the obl igation of Cyprus Amax to pay USECC the $3.75 million plus interest.

The other issues in the litigation were whether USECC must, under terms of a 1987 Royalty Deed, accept PD's and MEMCO's 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. PD's and MEMCO's claim sought to obligate USECC to assume the operating costs of the water treatment plant. USECC asserted counterclaims against the defendants, including a claim for nonpayment of advance royalties.

On July 28, 2004, the Court entered an Order granting certain of PD's motions and denying USECC's counterclaims and cross-claims. The case was tried in late 2004.

On February 4, 2005, the Court entered Findings and Fact and Conclusions of Law and ordered that the conveyance of the Mt. Emmons properties under Paragraph 8 of the 1987 Agreement includes the transfer of ownership and operational responsibility for the Water Treatment Plant, and that PD does not owe USECC any advanced royalty payments. However, the Order did not address the NPDES permit. NPDES permits are administered and regulated by the Colorado Department of Public Health and the Environment (“CDPHE”). The timing and scope of responsibilities for maintaining and operating the plant will be addressed by the CDPHE later in 2005.

USECC has filed a motion with the Court to amend the Order to determine that the decreed water rights from the Colorado Supreme Court opinion (decided in 2002, finding that the predecessor owners of the Mt. Emmons property had rights to water to develop a mine), and any other appurtenant water rights, be conveyed to USECC. The motion is pending.

Rocky Mountain Gas, Inc. (RMG)

Litigation involving leases on coalbed methane properties in Montana

In April 2001, RMG was served with a Second Amended Complaint, in which the Northern Plains Resource Council ("NPRC") had filed suit in the U. S. District Court of Montana, Billings Division (No. CV-01-96-BLG-RWA) against the United States Bureau of Land Management (“BLM”), RMG, certain of its affiliates (including USE and Crested) and some 20 other defendants. The plaintiff was 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.

In December 2003, Federal District Court Judge Anderson granted BLM’s and the other defendants Motion for Summary Judgment and ruled that BLM did not have to consider environmental impacts in an Environmental Impact Statement (“EIS”) prior to leasing because the 1994 Resource Management Plan (“RMP”) limited lease right to exploration and small scale development. On August 30, 2004, the Ninth
 

 
-103-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
Circuit Court of Appeals affirmed the District Court decision and held that the six-year statue of limitations precluded challenging the 1994 RMP and EIS. On February 10, 2005, NRPC's petition for rehearing or in the alternative petition for en banc was denied by the Ninth Circuit Court of Appeals.

All of RMG's BLM Montana leases are held by RMG and are at least four years old. There is no record of any objections being made to the issue of those leases. 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 BLM leases in Montana.

Lawsuits challenging BLM's Records of Decisions

There is a lawsuit currently pending in the Montana Federal District Court challenging BLM's Records of Decisions for the Powder River Basin Oil and Gas EIS for the Wyoming portion of the basin, and the Statewide Oil and Gas EIS and Proposed Amendment for the Powder River and Billings Resource Management Plans in Montana.

In April 2003 NPRC and the Northern Cheyenne Tribe and Native Action (the “Tribe”) filed a suit against BLM challenging the April 2003 decision by BLM approving the Final Statewide Oil and Gas Environmental Impact Statement (FEIS) and proposed amendments to the RMP. On February 25, 2005 Federal District Court Judge Anderson dismissed all counts with the exception of the allegation that the FEIS is inadequate because it failed to consider any alternatives to full-field development and ruled that BLM’s failure to analyze a phased development alternative renders the FEIS inadequate. BLM will now be required to perform a Supplemental EIS (“SEIS”) examining a phased development alternative, which could take 18 months to complete.

On April 5, 2005 Federal District Court Judge Anderson rejected the Tribe’s request for a complete moratorium on CBM drilling in Montana and instead accepted BLM’s proposal that limited the number of Federal APDs issued by BLM to maximum of 500 wells per year, including federal, state and fee wells within a certain defined geographic area. The decision will prohibit BLM from issuing Federal wells in RMG’s Castle Rock property until the SEIS is completed, because it is not located with the defined geographic area. However, the decision does not limit the number of fee and state wells that can be approved in the Castle Rock property by the State of Montana. RMG will request BLM to extend the expiration date of the Federal leases for the period of the delay.

Neither the Company nor RMG is a party to this lawsuit. However, further permitting for federal CBM wells in Montana could be impacted until the issues have been resolved.

Litigation involving drilling

A drilling company, Eagle Energy Services, LLC filed a lawsuit against RMG for drilling services claiming $49,309.50 for non-payment in Civil Action No. C02-9-341. Eagle Energy’s bank, Community First National Bank of Sheridan, Wyoming, filed a similar suit for the same amount on an assignment from Eagle Energy against RMG in Civil Action No. CO2-9-328 in the 4th Judicial District of Sheridan County, Wyoming. In February 2005 RMG and Community First reached a full and complete settlement of Civil Action No. C02-9-328 and a Joint Motion to Dismiss with Prejudice is currently pending with the Court. RMG has also request ed Eagle Energy to join in a Motion to Dismiss in Civil Action No. C02-9-341 because the claim was settled as noted above. Management believes that the ultimate outcome of the matters will not have a material effect on the Company’s financial condition or result of operations.

  
-104-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
Reclamation and Environmental Liabilities

Most of the Company's exploration activities are subject to federal and state regulations that require the Company to protect the environment. The Company conducts its operations in accordance with these regulations. The Company's current estimates of its reclamation obligations and its current level of expenditures to perform ongoing reclamation may change in the future. At the present time, however, the Company cannot predict the outcome of future regulation or impact on costs. Nonetheless, the Company has recorded its 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 Environmenta l Quality ("WDEQ") review the Company's reclamation, environmental and decommissioning liabilities, and the Company believes the recorded amounts are consistent with those reviews and related bonding requirements. To the extent that planned production on its properties is delayed, interrupted or discontinued because of regulation or the economics of the properties, the future earnings of the Company would be adversely affected. The Company believes it has 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 environmental obligations relate to former mining properties acquired by the Company. Since the Company currently does not have any properties in production, the Company'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 also does not believe that any significant capital expenditures to monitor or reduce hazardous substance s 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, 2004, estimated reclamation obligations related to the above mentioned mining properties total $8,075,100. The Company currently has three mineral properties or investments that account for most of their environmental obligations, SMP, Plateau and SGMI. 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 is 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 and the regulatory authorities and they jointly determined that the reclamation liability was $2,339,800. The Company is self bonded for this obligation by mortgaging certain of their real estate assets, including the Glen L. Larsen building, and by posting cash bonds.


  
-105-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
Sutter Gold Mining Inc.

SGMI'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 $28,200 which is covered by a cash reclamation bond. This amount was recorded by SGMC as a reclamation liability as of December 31, 2004.

Plateau Resources Limited

The environmental and reclamation obligations acquired with the acquisition of Plateau include obligations relating to the Shootaring Mill. As of December 31, 2004, the reclamation liability on the Plateau properties was $5.2 million. Plateau held a cash deposit for reclamation in the amount of $6.8 million.

Executive Compensation

The Company is committed to pay the surviving spouse or dependant children 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. The maximum compensation due under these agreements for the officers covered by the agreement for the first year after their deaths, should they die in the same year, is $311,400 at December 31, 2004.

Operating Leases

The Company is the lessor of portions of the office buildings and building improvements that it owns. The Company occupies the majority of the main office building. The leases are accounted for as operating leases and provide for minimum monthly receipts of $16,400 through December, 2006. All of the Company's leases are for two years or less.

The total costs of the office buildings and building improvements totaled $4,218,200 as of December 31, 2004 and 2003 and accumulated depreciation amounted to $2,374,400 and $2,283,200 as of December 31, 2004 and 2003, respectively. Rental income under the agreements was $245,000, $256,500, $187,000 and $375,900, for the years ended December 31, 2004 and 2003, the seven months ended December 31, 2002 and the fiscal year ended May 31, 2002.

Future minimum receipts for noncancellable operating leases are as follows:

Years Ending
    
December 31,
  
Amount
2005
  
$196,300
2006
  
$199,300

The Company, through RMG, has a lease commitment until January 30, 2006 in the amount of $1,300 per month on its field office. This lease can be cancelled upon 90 day notice by either party to the lease. RMG also has a lease for a compressor through December 2005. The monthly payment under this lease is

  
-106-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
approximately $17,400 per month. The total lease expense for these and another compressor lease that expired during the year was $440,000 and $41,300 for the years ended December 31, 2004 and 2003, respectively. Future commitments are as follows:

   
2005
$ 224,400
2006
$ 1,300

It is anticipated that the lease obligations for the year ended December 31, 2005 will remain consistent with those experienced during the year ended December 31, 2004 unless additional operation fields are required.

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 were sold and or converted for use elsewhere in the Company. The financial statements for the fiscal year ended May 31, 2001 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, 2004.

During the third quarter of the year ended December 31, 2003, the Company sold its motel and retail operations in southern Utah. The financial statements for all of the periods presented have been revised to present these operations as discontinued.

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.


  
-107-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
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, 2004. 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.

RMG's sales volumes of gas produced, average sales prices received for gas sold, and average production costs for those sales for the years ended December 31, 2004 and 2003 and for the seven months ended December 31, 2002 are as follows:
 
           
Seven months
  
           
ended
  
   
Year ended December 31,
  
December 31,
  
   
2004
  
2003
  
2002
  
               
Sales volumes (mcf)
    
728,051
   
81,516
   
64,315
 
Average sales price per mcf
  
$
4.05
  
$
3.71
  
$
1.86
  
Average cost (per mcf)
  
$
3.19
  
$
1.91
  
$
1.91
  
 
Changes in estimated reserve quantities

The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas and changes in such quantities and discounted future net cash flow were as follows:

   
(Unaudited) - Unescalated
  
               
   
MCF
  
   
Cubic Feet
  
           
Seven Months
  
   
Year Ended
  
Year Ended
  
Ended
  
   
December 31, 2004
  
December 31, 2003
  
December31, 2002
  
Proved developed and
              
Undeveloped reserves:
              
Beginning of year
  
--
  
585,603
  
--
  
Revision of previous estimates
    
(51,862
)
  
--
    
--
  
Purchase of minerals in place
    
3,404,693
    
--
    
649,918
  
Exchange of reserves in place (1)
    
--
    
(504,087
)
  
--
  
Extensions & Discoveries
    
817,459
    
--
    
--
  
Production
    
(1,114,349
)
  
(81,516
)
  
(64,315
)
End of year
    
3,055,941
    
--
    
585,603
  
                   
Proved developed producing
    
1,651,666
    
--
    
489,684
  
Proved developed non-producing
    
889,051
    
--
    
--
  
Proved undeveloped
    
515,224
    
--
    
95,919
  
Total proved reserves
    
3,055,941
    
--
    
585,603
  
  
-108-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
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 carry forwards. 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:

           
Seven Months
  
   
Year Ended
  
Year Ended
  
Ended
  
   
December 31, 2004
  
December 31, 2003
  
December 31, 2002
  
Future Cash Inflows
  
$
13,125,200
    
--
  
$
1,756,809
  
Future Production and
development costs
    
(5,208,800
)
  
--
    
(705,505
)
Future Net Cash Flows
    
7,916,400
    
--
    
1,051,304
  
Discount Factor
    
(1,401,800
)
  
--
    
(162,876
)
Standardized measure of
discounted future net cash flows
  
$
6,514,600
    
--
  
$
888,428
  

Changes in standard measure of discounted future net cash flows from proved gas reserves:

           
Seven Months
  
   
Year Ended
  
Year Ended
  
Ended
  
   
December 31, 2004
  
December 31, 2003
  
December 31, 2002
  
Standardized measure - beginning of year
  
$
--
  
$
888,428
  
$
--
  
Sale & Transfer, net of production cost
    
(629,400
)
  
(63,200
)
  
235,800
  
Net change in sales & transfer price, net of production cost
    
(58,200
)
  
--
    
--
  
Extensions, discoveries and improved recovery, net of future production and development cost
    
2,671,800
    
--
    
--
  
Exchange or reserves in place (1)
    
--
    
(825,228
)
  
--
  
Revision of quantity estimate
    
(110,500
)
  
--
    
--
  
Purchase of reserve in place
    
7,056,400
    
--
    
652,628
  
Change in production rate & other
    
(2,415,500
)
  
--
    
--
  
Standardized measure - end of period
  
$
6,514,600
  
$
--
  
$
888,428
  

(1) During June 2003, RMG contributed proved and unproved properties in exchange for a 37.5% interest in Pinnacle. At December 31, 2004, RMG owned 16.7% of Pinnacle.


  
-109-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(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
  
$
673,000
  
$
545,900
  
               
Costs and expenses
    
(4,197,900
 )   
(4,460,800
 ) 
Operating loss
    
(3,524,900
)
  
(3,914,900
)
               
Other income and expenses
    
(387,100
)
  
1,005,000
  
Loss before minority interest
    
(3,912,000
)
  
(2,909,900
)
               
Minority interest in loss of subsidiaries
    
54,800
    
24,500
  
Loss before income taxes
    
(3,857,200
)
  
(2,885,400
)
               
Provision for income taxes
    
--
    
--
  
Net loss from continuing operations
    
(3,857,200
)
  
(2,885,400
)
               
Discontinued operations, net of tax
    
17,100
    
175,000
  
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
  
$
0.06
  
$
0.07
  
               
Operating loss
    
(0.33
)
  
(0.47
)
               
Loss from continuing operations
    
(0.36
)
  
(0.35
)
               
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
  

  
-110-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
O.    SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

   
Three Months Ended
  
   
December 31,
  
September 30,
  
June 30,
  
March 31
  
   
2004
 
2004
 
2004
 
2004
 
                   
Operating revenues
  
$
1,140,500
  
$
1,266,300
  
$
1,367,400
  
$
867,500
  
                           
Operating loss
  
$
(1,624,500
)
$
(1,421,200
)
$
(1,742,400
)
$
(1,871,300
)
                           
Loss from continuing operations
  
$
(1,238,400
)
$
(1,626,100
)
$
(1,609,200
)
$
(1,775,000
)
                           
Discontinued operations, net of tax
  
$
--
  
$
--
  
$
--
  
$
--
  
                           
Net loss
  
$
(1,260,300
)
$
(1,604,200
)
$
(1,609,200
)
$
(1,775,000
)
                           
Loss per share, basic
                          
Continuing operations
  
$
(0.09
)
$
(0.12
)
$
(0.13
)
$
(0.14
)
Discontinued operations
  
$
--
  
$
--
  
$
--
  
$
--
  
   
$
(0.09
)
$
(0.12
)
$
(0.13
)
$
(0.14
)
                           
Basic weighted average shares outstanding
    
14,468,336
   
13,490,917
   
12,873,194
   
12,319,657
 
                           
Loss per share, diluted
                          
Continuing operations
  
$
(0.09
)
$
(0.12
)
$
(0.13
)
$
(0.14
)
Discontinued operations
  
$
--
  
$
--
  
$
--
  
$
--
  
   
$
(0.09
)
$
(0.12
)
$
(0.13
)
$
(0.14
)
                           
Diluted weighted average shares outstanding
    
14,468,336
   
13,490,917
   
12,873,194
   
12,319,657
 

 
-111-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)

   
Three Months Ended
  
   
December 31,
  
September 30,
  
June 30
  
March 31
  
   
2003
 
2003
 
2003
 
2003
 
                   
Operating revenues
  
$
109,000
  
$
119,300
  
$
241,300
  
$
367,700
  
                           
Operating loss
  
$
(1,664,800
)
$
(1,988,400
)
$
(2,418,800
)
$
(1,165,900
)
                           
Loss earnings from continuing operations
  
$
(1,780,800
)
$
(1,893,000
)
$
(2,214,100
)
$
(1,187,900
)
                           
Discontinued operations, net of tax
  
$
(124,800
)
$
(88,700
)
$
(17,400
)
$
(119,000
)
                           
Net earnings (loss)
  
$
(1,905,600
)
$
(1,981,700
)
$
(2,231,500
)
$
308,700
  
                           
Earnings per Share, basic
                          
Continuing operations
  
$
(0.16
)
$
(0.17
)
$
(0.20
)
$
(0.11
)
Discontinued operations
  
$
(0.01
)
$
(0.01
)
$
--
  
$
(0.01
)
Cumulative effect of accounting change
  
$
--
  
$
--
  
$
--
  
$
0.15
  
   
$
(0.17
)
$
(0.18
)
$
(0.20
)
$
0.03
  
                           
Basic weighted average shares outstanding
    
11,383,576
   
11,127,796
   
10,916,971
   
10,881,394
 
                           
Earnings per Share, diluted
                          
Continuing operations
  
$
(0.34
)
$
(0.17
)
$
(0.20
)
$
(0.10
)
Discontinued operations
  
$
(0.02
)
$
(0.01
)
$
--
  
$
(0.01
)
Cumulative effect of accounting change
  
$
--
  
$
--
  
$
--
  
$
0.14
  
   
$
(0.36
)
$
(0.18
)
$
(0.20
)
$
0.03
  
                           
Diluted weighted average shares outstanding
    
11,383,576
   
11,127,796
   
10,916,971
   
11,385,593
 

 
-112-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
P. SUBSEQUENT EVENT

HPC Capital Management

On February 9, 2005, U.S. Energy Corp. (the “company”) entered into, and closed, a securities purchase agreement with seven accredited investors for the issuance of $4,720,000 in face amount of debentures maturing February 4, 2008, and three year warrants to purchase common stock of the company. The face amount of the debentures includes simple annual interest at 6%; the investors paid $4,000,000 for the debentures. A commission of 7% on the $4,000,000 was paid by the company to HPC Capital Management (a registered broker-dealer) in connection with the transaction, and the company paid $20,000 of the investors’ counsel’s legal fees, resulting in net proceeds to the company of $3,700,000. Net proceeds will be used by the company for general workin g capital.

The debentures are unsecured; the face amount of the debentures are payable every six months from February 4, 2005, in five installments of 20%, in cash or in restricted common stock of the company. If the company gives notice that it intends to make the payment in cash, the investors have the right to take the payment in stock, at the lower of $2.43 per share (the “set price”) or 90% of the volume weighted average price of the company’s stock for the 90 trading days prior to the company’s notice that the six month payment is intended to be paid by the company in cash (the “VWAP price”). The set price equals 90% of the volume weighted average price of the company’s stock over the 90 trading days prior to February 4, 2005.

At any time, the debentures are convertible to restricted common stock of the company at the set price.

At any time, the company has the right to redeem some or all of the debentures in cash or stock, in amount equal to 120% of the face amount of the debentures until February 4, 2006; 115% from February 5, 2006 to February 4, 2007; and 110% from February 5, 2007 until maturity. Payment in stock would be at the set price.

If at any time the company’s stock trades at more than 150% of the set price for 20 consecutive trading days, the company may convert the balance of the face amount of the debentures to stock at 150% of the set price.

In the event of default, the investors may require payment (i) in cash equal to 130% of the then outstanding face amount; or (ii) in stock equal to 100% of face amount, with the stock priced at the set price, or (iii) in stock equal to 130% of the face amount, with the stock priced at 100% of the volume weighted average price of the company’s stock for the 90 trading days prior to default.

The company issued warrants to the investors, expiring February 4, 2008, to purchase 971,193 shares of restricted common stock, at $3.63 per share (equal to 110% of the closing price for the company’s stock on February 4, 2005). The number of shares underlying the warrants equals 50% of the shares issuable on full conversion of the debentures at the set price (as if the debentures were so converted on February 4, 2005).

Warrants to purchase 100,000 shares, at the same price and for the same term as the warrants issued to the investors, have been issued to HPC Capital Management as additional compensation for its services in connection with the transaction with the investors.


 
-113-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
If in any period of 20 consecutive trading days the company’s stock price exceeds 200% of the warrants’ exercise price, on each of the trading days, all of the warrants shall expire on the 30th day after the company sends a call notice to the warrantholders.

The company has agreed to file with the Securities and Exchange Commission a registration statement to cover the future sale by the investors of the shares issuable in payment and/or conversion of the debentures, and the shares issuable on exercise of the warrants. The registration statement also will cover the future sale by HCP Capital Management of the shares issuable on exercise of the warrants issued to HCP in connection with the transaction.

Enterra

As of April 11, 2005, the company and its subsidiary Rocky Mountain Gas, Inc. (“RMG”) has entered into a binding agreement with Enterra Energy Trust (“Enterra”) for the acquisition of RMG by Enterra in consideration of $20,000,000, payable pro rata to the RMG shareholders in the amounts of $6,000,000 in cash and $14,000,000 in exchangeable shares of one of the subsidiary companies of Enterra. The shares will be exchangeable for units of Enterra twelve months after closing of the transaction. The Enterra units are traded on the Toronto Stock Exchange and on Nasdaq; the exchangeable shares will not be traded. RMG will be acquired with approximately $3,500,000 of debt owed to its mezzanine lenders.

Closing of the transaction is subject to approval of the RMG shareholders; U.S. Energy Corp. and Crested Corp., the principal shareholders of RMG, have agreed to vote in favor of the acquisition. Closing is further subject to completion of due diligence by Enterra, and to obtaining regulatory and stock exchange approvals.

RMG’s minority equity ownership of Pinnacle Gas Resources, Inc. will not be included in the transaction with Enterra, which has resulted in a decrease in the consideration to be paid by Enterra from the previously-announced $30,000,000, to the $20,000,000 in the definitive agreement signed as of April 11, 2005. However, Enterra will be entitled to be paid up to (but not more than) $2,000,000 if proceeds from a future disposition of the minority equity interest in Pinnacle exceed $10,000,000.

Uranium Power Corp.

As of April 11, 2005, the company and Crested (as the USECC Joint Venture) signed a Mining Venture Agreement with UPC to establish a joint venture, with a term of 30 years, to explore, develop and mine the properties being purchased by UPC under the Purchase and Sale Agreement, and acquire, explore and develop additional uranium properties. The joint venture generally covers uranium properties in Wyoming and other properties identified in the USECC Joint Venture uranium property data base, but excluding the Green Mountain area and Kennecott’s Sweetwater uranium mill, the Shootaring Canyon uranium mill in southeast Utah (and properties within ten miles of that mill), and properties acquired in connection with a future joint venture involving that mill.

The initial participating interests in the joint venture (profits, losses and capital calls) are 50% for the USECC Joint Venture and 50% for UPC, based on their contributions of the Sheep Mountain properties. Operations will be funded by cash capital contributions of the parties; failure by a party to fund a capital call may result in a reduction or the elimination of its participating interest. In addition, a failure by UPC to pay for its 50% interest in the Sheep Mountain properties may result in a reduction or the elimination of

  
-114-
 
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 and 2002, AND MAY 31, 2002
(Continued)
 
UPC’s participating interest. A budget of $567,842 for the seven months ending December 31, 2005 has been approved, relating to reclamation work at the Sheep Mountain properties, exploration drilling, geological and engineering work, and other costs. A substantial portion of this work will be performed by (and be paid to) USECC Joint Venture as manager.

The manager of the joint venture is the USECC Joint Venture; the manager will implement the decisions of the management committee and operate the business of the joint venture. UPC and the USECC Joint Venture each have two representatives on the four person management committee, subject to change if the participating interests of the parties are adjusted. The manager is entitled to a management fee from the joint venture equal to a minimum of 10% of the manager’s costs to provide services and materials to the joint venture (excluding capital costs) for field work and personnel, office overhead and general and administrative expenses, and 2% of capital costs. The manager may be replaced if its participating interest becomes less than 50%.



 
-115-
 




REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM ON SCHEDULE


To U.S. Energy Corp:

In connection with our audit of the consolidated financial statements of U.S. Energy Corp. and subsidiaries referred to in our report dated February 27, 2004, which is included in the Company's annual report on Form 10-K, we have also audited Schedule II for the year ended December 31, 2003, the seven months ended December 31, 2002 and the year ended May 31, 2002. In our opinion, this schedule presents fairly, in all material respects, the information to be set forth therein.



/s/  GRANT THORNTON LLP

Oklahoma City, Oklahoma
February 27, 2004

  
-116-
 

U.S. ENERGY CORP.

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

   
Balance
  
Additions
          
   
beginning
  
charged to
  
Deductions
  
Balance end
  
   
of period
  
expenses
  
and Other
  
of period
  
                   
May 31, 2002
  
$
27,800
    
--
    
--
  
$
27,800
  
                           
December 31, 2002
  
$
27,800
    
--
    
--
  
$
27,800
  
                           
December 31, 2003
  
$
27,800
    
--
    
--
  
$
27,800
  
                           
December 31, 2004
  
$
111,300
    
--
    
--
  
$
111,300
  

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

     On December 17, 2004, the Company dismissed the audit firm Grant Thornton LLP (“GT”). GT had audited the company’s financial statements for more than the last two fiscal years.

     The Company has engaged the independent audit firm Epstein, Weber & Conover, Scottsdale, Arizona, to audit the company’s financial statements for the year ended December 31, 2004.

     GT’s audit report on the financial statements for the year ended December 31, 2003, the seven months ended December 31, 2002, and the (former) fiscal year ended May 31, 2002, contained a qualification of uncertainty as to whether the Company will continue as a going concern. The audit report did not contain an adverse opinion or a disclaimer of opinion, and was not otherwise qualified or modified as to audit scope or accounting principles.

     The decision to change audit firms was recommended by the Company’s audit committee, and approved by that committee and the board of directors.

     There has not been, during the two most recent fiscal years, or during any subsequent interim period preceding the change of audit firms, any disagreement with GT on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreement, if not resolved to the satisfaction of GT, would have caused it to make reference to the subject matter of the disagreement in connection with its report.

     In addition, during the two most recent fiscal years, there were no disagreements between the Company and GT which constituted “reportable events” under item 304(a)(1)(v) of Regulation S-K. Disclosure of such “reportable events” would be required even if the Company and GT did not express a difference of opinion regarding the event.


  
-117-
 

ITEM 9A. Controls and Procedures

The Company’s Principal Executive Officer and Principal Financial Officer have reviewed and evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 240.13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and the Principal Financial Officer have concluded that the Company’s current disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange commission’s rules and forms. There was no change in the Company’s internal controls that occurred during the further quarter of the period covered by this report that has materially affected, or is reasonably likely to affect, the Company’s internal controls over financial reporting.

ITEM 9B. Other Information

None


 
-118-
 



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, 2004, 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 2005, 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:

The Company has adopted a Code of Ethics. A copy of the Code of Ethics will be provided to any person without charge upon written request addressed to Daniel P. Svilar, Secretary, 877 North 8th West, Riverton, Wyoming 82501.

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 54, 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 40(f) listed proceeding.

Daniel P. Svilar, age 76, 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 officer or directors of USE or Crested. 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 2005, under the captions "Executive Compensation" and "Director's Fees and Other Compensation."

ITEM 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholders matters.

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 2005, under the caption "Principal Holders of Voting Securities."

  
-119-
 

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 2005, under the caption "Certain Relationships and Related Transactions."

ITEM 14. Principal Accountant Fees and Services

(1) - (4) Grant Thornton LLP billed us as follows for the years ended December 31, 2004 and 2003. Grant Thornton was dismissed as the Company’s audit firm in December 2004 (see Item 9 above). The information does not include fees paid to the new audit firm in late 2004.

 
   
Year ended December 31,
  
   
2004
  
2003
  
           
Audit fees (a)
  
$
115,300
  
$
80,100
  
Audit-related fees(b)
  
$
27,200
  
$
--
  
Tax fees(c )
  
$
33,700
  
$
15,800
  
All other fees(d)
  
$
40,400
  
$
13,100
  
 

(a)    Includes fees for audit of the annual financial statements and review of quarterly financial information filed with the Securities and Exchange Commission ("SEC").

(b)    For assurance and related services that were reasonably related to the performance of the audit or review of the financial statements, which fees are not included in the Audit Fees category. The Company had no Audit-Related Fees for the periods ended December 31, 2004, and 2003.

(c)    For tax compliance, tax advice, and tax planning services, relating to any and all federal and state tax returns as necessary for the years ended December 31, 2004 and 2003.

(d)    For services in respect of other reports required to be filed by the SEC and other agencies.

(5)(i) The audit committee approves the terms of engagement before we engage the audit firm for audit and non-audit services, except as to engagements for services outside the scope of the original terms, in which instances the services have been provided pursuant to pre-approval policies and procedures, established by the audit committee. These pre-approval policies and procedures are detailed as to the category of service and the audit committee is kept informed of each service provided. These policies and procedures, and the work performed pursuant thereto, do not include delegation any delegation to management of the audit committee's responsibilities under the Securities Exchange Act of 1934.

This approval process was used with respect to the engagement of Grant Thornton for the 2002 and 2003, and with respect for the appointment of the new audit firm Epsetin Weber & Conover for the audit of the 2004 financial statements and related services.

(5)(ii) The percentage of services provided for Audit-Related Fees, Tax Fees and All Other Fees for 2004 (and 2003), all provided pursuant to the audit committee’s pre-approval policies and procedures, were: Audit-Related Fees 66% (74%); Tax Fees 16% (14%); and All Other Fees 18% (12%).



  
-120-
 

GLOSSARY OF OIL AND NATUAL GAS TERMS

The following are definitions of terms commonly used in the oil and natural gas industry and this Annual Report.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons.

Btu. British thermal unit, which is the energy required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Coal Bed Methane ("CBM"). A form of natural gas, predominately methane, which is generated during coal formation and is contained in the coal microstructure.

Capital expenditures. Investment outlays for exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land related overhead expenditures; delay rentals; producing property acquisitions; other miscellaneous capital expenditures; compression equipment and pipeline costs.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a producing horizon known to be productive.

Exploratory well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Gross acres or gross wells. The total acres or wells, as the case may be, in which the Company has a working interest.

Lease Operating Expenses ("LOE"). All operating costs related to production activities including direct costs such as direct labor, direct materials, certain workover costs, repairs and maintenance, insurance costs, and gas collection costs.

Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.

MMcf. One thousand Mcf or One million cubic feet.

MMBtu. One million Btu.

Net acres or net wells. A net acre or well is deemed to exist when the sum of the Company's fractional ownership working interests in gross acres or wells, as the case may be, equals one. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

Operator. The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.


  
-121-
 

Reserves. Oil and natural gas on a net revenue interest basis, estimated to be commercially recoverable. "Proved developed reserves" include proved developed producing reserves and proved developed behind-pipe reserves. "Proved developed producing reserves" include only those reserves expected to be recovered from existing completion intervals in existing wells. "Proved undeveloped reserves" include those reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Undeveloped acreage. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves.

Working interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill and produce oil and natural gas on the leased acreage and requires the owner to pay their proportionate share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to governmental tax receipts and mineral interest royalties.

 
-122-
 

ITEM 15.  Exhibits, Financial Statements, Schedules, Reports and Forms 8-K. (a)  Financial Statements and Exhibits (1)  The following financial statements are filed as a part of the Report in Item 8:
  Page No.
Consolidated Financial Statements U.S. Energy Corp. and Subsidiaries

 56

   
Report of Independent Registered Public Accounting Firm Epstein, Weber & Conover

 57

   
Report of (former) Independent Registered Public Accounting Firm Grant Thornton, LLP

 58

   
Consolidated Balance Sheets - December 31, 2004 and December 31, 2003 

 59-60

   
Consolidated Statement of Operations for the Years Ended December 31, 2004 and 2003, the Seven Months Ended December 31, 2002 and the Year Ended May 31, 2002

 61-62

   
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2004 and 2003, the Seven Months Ended December 31, 2002, and the Year Ended May 31, 2002

 63-66

   
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003 and 2004, the Seven Months Ended December 31, 2002, and the Year Ended May 31, 2002

 67-69

   
Notes to Consolidated Financial Statements

 70-115

   
Report of Independent Certified Public Accountants on Schedule

 116

   
Schedule II - Valuation and Qualifying Accounts

 117

  (2)  All other schedules have been omitted because the required information in inapplicable or is shown in the notes to financial statements. (3)  Exhibits  

Exhibit No.		 Title of Exhibit SequentialPage No.
     
3.1 USE Restated Articles of Incorporation [2]
     
3.1(a) USE Articles of Amendment toRestated Articles of Incorporation [4]
     
3.1(b) USE Articles of Amendment (Second) toRestated Articleds of Incorporation(Establishing Series A Convertible Preferred Stock [9]
     
3.1(c) Articles of Amendment (Third) toRestated Articles of Incorporation(Increasing number of authorized shares) [14]
  

 
-123-
 

3.1(d) Articles of Amendment to the ArticlesOf Incorporation of Rocky Mountain Gas, Inc.(to establish Series A Preferred Stock in March 2004) [6]
     
3.2 USE Bylaws, as amended through April 22, 1992 [4]
     
4.1 Amendment to USE 1998 Incentive Stock Option Plan [11]
     
4.2 USE 2001 Incentive Stock Option PlanAnd Form of Stock Option Agreement *
     
4.3-4.10 [intentionally left blank]  
     
4.11 Rights Agreement, dated as of September 19, 2001between U.S. Energy Corp. and Computershare Trust Company, Inc. as Rights Agent.  The Articles ofAmendment of Articles of Incorporation creating theSeries A Preferred Stock is included herewith as anexhibit to the Rights Agreement.Form of Right Certificate (as an exhibit to theRights Agreement). Summary of Rights, which will be sent to all holdersof record of the outstanding shares of Common Stockof the registrant, also included as an exhibit to theRights Agreement [12]
     
4.12-4.20 [intentionally left blank]  
     
4.21 USE 2001 Officers' Stock Compensation Plan [18]
     
4.22-4.30 [intentionally left blank]  
     
10.1 Securities Purchase Agreement for $4.72 million debentures (February 2005) *
     
10.2 Form of Debenture (February 2005) *
     
10.2(a) Form of Warrant (February 2005) *
     
10.3 Credit Agreement, Secured Convertible Note, Security Agreement and Warrant (without sub-exhibits) - Geddes and Company (July 2004) *
     
10.4 Purchase and Sale Agreement, with three amendments(for purchase of Hi-Pro assets) [24]
     
10.5 Credit Agreement (mezzanine credit facility withPetrobridge Investment Management) [24]
     
10.6 Purchase and Sale Agreement (without exhibits) - Bell Coast Capital, n/k/a/ Uranium Power Corp. (December 2004) *
  

 
-124-  
 


10.7		 Mining Venture Agreement (without exhibits) - Uranium Power Corp. (April 2005) *
     
10.8 Pre-Acquisition Agreement, (without exhibits) Enterra Energy Trust, Dated as of April 11, 2005 *
     
14.0 Code of Ethics [6]
     
21.1 Subsidiaries of Registrant [11]
     
23.0 Consent of Netherland, Sewell & Associates, Inc., independentpetroleum engineers *
     
31.1 Certification under Rule 13a-14(a) John L. Larsen *
     
31.2 Certification under Rule 13a-14(a) Robert Scott Lorimer *
     
32.1 Certification under Rule 13a-14(b) John L. Larsen *
     
32.2 Certification under Rule 13a-14(b) Robert Scott Lorimer *
     
*  Filed herewith  
                                     
[1] Intentionally left blank.
   
[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] Intentionally left blank.
   
[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] Intentionally left blank.
   
[6] Incorporated by reference from the like-numbered exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003.
   
[7] Intentionally left blank.
   
[8] Intentionally left blank.
   
[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, 1998, filed September 14, 1998.
   
[10] Intentionally left blank.
   
[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, and amended on June 18, 2002 and September 25, 2002.
 
 

 
  -125-  
 

 
[12] Incorporated by reference to exhibit number 4.1 to the Registrant's Form 9-A12G filed, September 20, 2001.
   
[13] Intentionally left blank.
   
[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] Intentionally left blank.
   
[16] Intentionally left blank.
   
[17] Intentionally left blank.
   
[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] Intentionally left blank.
   
[20] Intentionally left blank.
   
[21] Intentionally left blank.
   
[22] Intentionally left blank.
   
[23] Intentionally left blank.
   
[24] Incorporated by referenced from the exhibit filed with the Registrant's Form 8-K, filed March 5, 2004.
                                       (b)        Reports on Form 8-K.             In the last quarter of 2004, the Registrant filed two Reports on Form 8-K, one on December 13, 2004 for an Item 1.01 event and one on December 22, 2004 for an Item 4.01 event. (c)        See paragraph a(3) above for exhibits. (d)&n bsp;       Financial statement schedules, see paragraph (a)(1) above. No other financial statements are required to be filed.. 

 
  -126-  
 


 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
    U.S. ENERGY CORP. (Registrant)
         
         
Date: April 15, 2005   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 person on behalf of the Registrant and in the capacities and on the dates indicated.
         
         
Date: April 15, 2005   By: /s/ John L. Larsen  
      JOHN L. LARSEN, Director  
         
         
Date: April 15, 2005   By: /s/ Keith G. Larsen  
      KEITH G. LARSEN, Director  
         
         
Date: March 15, 2005   By: /s/ Harold F. Herron  
      HAROLD F. HERRON, Director  
         
         
Date: April 15, 2005   By: /s/ Don C. Anderson  
      DON C. ANDERSON, Director  
         
         
Date: April 15, 2005   By: /s/ H. Russell Fraser  
      H. RUSSELL FRASER, Director  
         
         
Date: April 15, 2005   By: /s/ Michael T. Anderson  
      MICHAEL T. ANDERSON, Director  
         
         
Date: April 15, 2005   By: /s/ Michael H. Feinstein  
      MICHAEL H. FEINSTEIN, Director  
         
         
Date: April 15, 2005   By:  /s/ Robert Scott Lorimer  
      ROBERT SCOTT LORIMER  
      Principal Financial Officer/  
      Chief Accounting Officer  
  

 
  -127-