Item 1 B - Unresolved Staff Comments.
None.
Item 2 - Properties
Oil and Natural Gas
The following table sets forth our net proved reserves as of the dates indicated. Our reserve estimates as of December 31, 2009 are based on reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), and Cawley, Gillespie & Associates, Inc. (“CGA”). Our reserve estimates as of December 31, 2008 are based on a reserve report prepared by Ryder Scott Company, L.P. Ryder Scott and CGA are nationally recognized independent petroleum engineering firms. Ryder Scott is a Texas Registered Engineering Firm (F-1580) and CGA is a Texas Registered Engineering Firm (F-693). Ryder Scott prepared the estimates related to our Gulf Coast Basin, including Louisiana and Texas properties and CGA prepared the estimates or our North Dakota properties. The reserve estimates were based upon the review by the relevant engineering firm(s) of production histories and other geological, economic, ownership and engineering data, as provided by us and by the operators. Copies of these reports are filed as exhibits to this Annual Report.
We do not have in-house geological, geophysical and reserve engineering expertise. We therefore primarily rely on the operators of our producing wells who provide production data to our contract reserve engineers. Once the reserve engineers have reviewed all data and established preliminary reserves for the operators of the wells for which we rely on the operator, they also prepare a standalone report for us.
Summary of Oil and Gas Reserves as of Fiscal Year End Based on Average Fiscal-Year Prices (1)
(1)
Reserves for 2009 are based on average prices per barrel of oil and per MMbtu of natural gas at the first of each month in the 12-month period prior to the end of the reporting period.
U.S. Energy has no reserves of synthetic oil or synthetic gas, and does not produce or have reserves of any petroleum products.
As of December 31, 2009, our proved reserves totaled 1,086,203 BOE (100% proved developed), comprised of 811,789 Bbls of oil (75% of the total), 1,502,296 Mcf of natural gas and 24,031 Bbls of natural gas liquid. See the "Glossary of Oil and Gas Terms" for an explanation of these and other terms. You should not place undue reliance on estimates of proved reserves. See "Risk Factors - Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves”.
Proved Undeveloped Reserves
We had no proved undeveloped reserves at December 31, 2009.
Oil and Gas Production, Production Prices, and Production Costs
The following table sets forth certain information regarding our net production volumes, average sales prices realized and certain expenses associated with sales of oil and natural gas for the periods indicated. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included in this Annual Report. The information set forth below is not necessarily indicative of future results.
(1) Amounts shown are based on oil and natural gas sales, divided by sales volumes. Natural gas produced but flared is not included.
(2) Production costs are comprised of oil and natural gas production expenses (excluding ad valorem and severance taxes), and are computed using production costs as determined under ASC 932-235-55.
Drilling and Other Exploratory and Development Activities
The following table sets forth information with respect to development and exploration wells we completed from January 1, 2007 through December 31, 2009. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells.
The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered. See "Management's Discussion and Analysis of Financial Condition and Results of Operation - General Overview ."
Oil and Natural Gas Properties, Wells, Operations and Acreage
The following table details our working interests in producing wells as of December 31, 2009. A well with multiple completions in the same bore hole is considered one well. Wells are classified as oil or natural gas wells according to the predominant production stream, except that a well with multiple completions is considered an oil well if one or more is an oil completion.
(1)
The average working interest for the five Williston Basin wells producing at December 31, 2009 is 49.89%; the remaining three wells (Southeast Texas and Louisiana), have 8.5%, 14%, and 25% working interests, respectively.
The following map reflects where our oil and gas wells are generally located in the Williston Basin of North Dakota:
Acreage
The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2009.
Present Activities
As of March 1, 2010, we were drilling 1 gross (0.2 net) wells in Louisiana (offshore), and in the process of completing 3 gross (0.92 net) wells in the Williston Basin.
Molybdenum - Mount Emmons Project
We re-acquired the Mount Emmons (formerly known as the Lucky Jack molybdenum property) located near Crested Butte, Colorado on February 28, 2006. The property was returned to us by Phelps Dodge Corporation (“PD”) in accordance with a 1987 Amended Royalty Deed and Agreement between us and Amax Inc. (“Amax”). The Mount Emmons Project includes a total of 25 patented and approximately 1,219 unpatented mining and mill site claims, which together approximate 9,311 acres, or over 13 square miles of claims.
We own both surface and mineral rights at the Mount Emmons Project in fee pursuant to mineral patents issued by the United States of America. All fee property requires the payment of property taxes to Gunnison County. Unpatented mining and mill site claims require the payment of an annual maintenance fee of $125 per claim to the Bureau of Land Management; the total amount paid for claim maintenance fees in 2009 was $126,500, which was paid by TCM.
The breakdown of the property is as follows:
The Mount Emmons Project is located in Gunnison County, Colorado. The property is accessed by vehicle traffic on Gunnison County Road 12.
Thompson Creek Metals Company (USA) has an option to acquire up to a 75% interest in the Project. See Part I above.
We had leased various patented and unpatented mining claims on the Mount Emmons molybdenum property to Amax in 1974. In the late 1970s, Amax delineated a large deposit of molybdenum on the properties, reportedly containing approximately 155 million tons of mineralized material averaging 0.44% molybdenum disulfide (MoS2). In 1981, Amax constructed a water treatment plant at the Mount Emmons molybdenum property to treat water flowing from the old Keystone mine workings and for potential use in milling operations. By 1983, Amax had reportedly spent an estimated $150 million in the acquisition of the property, securing water rights, extensive exploration, ore body delineation, mine planning, metallurgical testing and other activities involving the mineral deposit. Amax was merged into Cyprus Minerals in 1992 to form Cyprus Amax. PD then acquired Mount Emmons in 1999 through its acquisition of Cyprus Amax. Thereafter, PD acquired additional conditional water rights and patents to certain mineral claims.
The exploration work conducted in the late 1970’s by Amax, Inc. as discussed in Cyprus Amax’s Patent Claim Application to the Bureau of Land Management dated December 23, 1992, defined the initial mineralized material at the Mount Emmons Project as follows: “Molybdenite is present in randomly distributed veinlets (i.e. stockwork veining) and in some larger veins that are up to two feet wide. This mineralized zone is found in metamorphosed sedimentary rocks and in Tertiary igneous complex which acted as the source of the mineralization.”
There also are a number of existing mine adits located on the property. Historic work completed by Amax, Inc. in the 1970s and early 1980s included: 2,400 feet of new drift with 18 underground diamond drill stations to facilitate underground drilling (consisting of 168 diamond drill holes for a total of 157,037 feet of core drilling). The majority of the drilling was concentrated within 3,000 feet north and south; 3,000 feet east and west and 2,000 vertical feet defining the area of mineralized material. A bulk sample was collected from this area and sent off site for metallurgical testing. Amax, Inc. also facilitated the completion of an Environmental Impact Statement (“EIS”) as required by NEPA for the Plan of Operations submitted to the United States Forest Service (“USFS”). The Amax, Inc. EIS is now outdated.
In its 1992 patent application, Cyprus Amax stated that the size and grade of the Mount Emmons deposit was determined to approximate 220 million tons of mineralized material grading 0.366% molybdenite. In a letter dated April 2, 2004, the BLM estimated that there were about 23 million tons of mineralized material containing 0.689% molybdenite, and that about 267 million pounds of molybdenum trioxide was recoverable. This letter covered only the high-grade mineralization which is only a portion of the total mineral deposit delineated to date. The BLM relied on a mineral report prepared by Western Mine Engineering (“WME”) for the U.S. Forest Service, which directed and administered the WME contract. WME’s analysis was based upon a price of $4.61 per pound for molybdic oxide and was used by the BLM in determining that nine claims satisfied the patenting requirement that the mining claims contain a valuable mineral that could be mined profitably. WME consulted a variety of sources in preparation of its report, including a study prepared in 1990 by American Mine Services, Inc. and a pre-feasibility report later prepared by Behre Dolbear & Company, Inc. in 1998.
Even with the historical data available, the size, configuration and operations of the mine plan that may be proposed by TCM have not been finalized. These factors, as well as the prevailing prices for molybdic oxide when the mine is active, will determine the economic viability of the project. We note that the statements made by the predecessor owners of the Mount Emmons Project regarding “recoverable” minerals and “mineable “reserves” were based on costs, permitting requirements, and commodity prices then prevailing. The $4.61 price used by WME should not be considered to be a current breakeven price for Mount Emmons. It is anticipated that a full feasibility study will be prepared in the future, using current and expected capital costs, and operating expenses, to estimate the viability of the project. It will be possible to classify some, or none, of the mineralized resources as “reserves” or “recoverable” only after a full feasibility study, based on a specific mine plan, has been completed.
In December 2008, an additional 160 acres of fee land in the vicinity of the claims was purchased for $4 million ($2 million in January 2009, $400,000 annually for five years). We share with TCM the purchase cost of this land on a 50-50 basis.
Geology
The sedimentary sequence in the Mount Emmons area spans from late Cretaceous to early Tertiary time. The oldest formation is the Mancos, a 4,000 foot sequence of shales with some interbedding limestone and siltstones. The Mancos Formation is not exposed on Mount Emmons, but may be seen in valley bottoms a few miles to the north, south, and east. All of the Mancos Formation encountered in the vicinity of the Mount Emmons mineralization has been strongly metamorphosed and attempts to correlate internal divisions of the unit have not been made. The overlying Mesaverde Formation, also of the late Cretaceous age, consists of a massive repetitive sequence of alternating sandstones, siltstones, shales and minor coals. Coal seams were not observed in any of the diamond drill holes, or in any of the underground drifts. On Mount Emmons the Mesaverde Formation varies from 1,100 to 1,700 feet thick. The variability in thickness of the Mesaverde Formation is mainly due to post-depositional erosion. The Ohio Creek Formation, dominantly a coarse sandstone with local chert pebble conglomerate and well-defined shale to siltstone beds, overlies the Mesaverde Formation. The Ohio Creek Formation is of early Tertiary (Paleocene) age and remains fairly consistent at 400 feet thick on Mount Emmons. Capping Mount Emmons is the Wasatch Formation, also of early Tertiary (Paleocene to Eocene) age.
On a more regional scale, within the Ruby Range the Wasatch Formation may reach 1,700 feet in thickness. However, on Mount Emmons specifically, all but the basal 600 to 700 feet has been eroded. The Wasatch Formation is composed of alternating sequences of immature shales, siltstones, arkosic sandstones, and volcanic pebble conglomerates. The Mount Emmons stock has intruded the Mancos and Mesaverde sediments, strongly metamorphosing both formations to hornfels up to 1500 feet outward from the igneous body.
Sedimentary rocks on Mount Emmons generally dip 15 - 20 degrees to the southeast, south, and southwest as is consistent with the locations of the Oh-Be-Joyful anticline and Coal Creek syncline.
During crystallization of the Red Lady Complex, hydrothermal fluids collected near the top of the magma column. These fluids were released after a period of intense fracturing in the solid upper portions of the Red Lady Complex and the surrounding country rock. This release of fluids was responsible for the formation of the major part of the Mount Emmons molybdenum mineralized zone and the associated alteration zones. Hydrothermal alteration associated with the Mount Emmons stock occurs in several distinct overlapping zones. Altered rocks include sedimentary rocks of the Mancos, Mesaverde, Ohio Creek and Wasatch Formations, the rhyodacite porphyry sills, and rocks of the Mount Emmons stock.
Water Treatment Plant; Site Facilities
PD’s 2006 re-conveyance of the property to U.S. Energy also included the transfer of ownership and operational responsibility of the mine water treatment plant located on the property. The water treatment permit issued under the Colorado Discharge Permit System was assigned to us by the Colorado Department of Health and Environment. We are responsible for all operating and maintenance costs until such time as Thompson Creek Metals elects to acquire a 15% interest in the property. Thereafter, costs will be shared according to our and Thompson Creek’s participation interests. We also are evaluating using the plant in milling operations.
The water treatment plant was constructed by Amax, Inc. in 1981 (at a cost of approximately $15 million) to treat mine discharge water from the historic lead and zinc Keystone Mine. A certified water treatment plant operations contractor with four licensed and/or trained employees operate the water treatment plant on a continuous basis, treating water discharged from the historic lead and zinc Keystone Mine. The plant utilizes a standard lime pH adjustment to precipitate heavy metals from the water. Mine water is then filtered and discharged in compliance with the approved NPDES Permit for the plant, and solids are dewatered and mixed with cement for proper disposal in accordance with state and federal law.
Additional equipment used in the operation of the water treatment plant includes a large front-end loaders, forklifts, specialized snow removal equipment and pickup trucks. The Mount Emmons Project currently has a 24-hour, seven days a week security contract service to protect the property.
Several capital upgrades to onsite facilities have been made since 2006. Current facilities include a core and office building, five ancillary pump houses and underground pipelines and utilities, which move water from five water storage ponds to the water treatment plant. Surface access is maintained to the four underground adits and the ancillary pump houses.
Historical Capital Expenditures by Prior Owners, and Related Information
Amax, Inc. reportedly spent approximately $150 million in exploration and related activities on the Mount Emmons Project, which included construction of the water treatment plant. During 2007, Kobex Resources, the predecessor of TCM, spent approximately $10.5 million on the property. From August 2008 to December 31, 2009, TCM has spent approximately $7.6 million on the property. The 2010 TCM budget for the Project is projected to be $8.4 million. Our annual operating cost for the water treatment plant is approximately $1.6 million. The total costs associated with future drilling and the development of the Project has not yet been determined by TCM.
We are using grid electric power to operate the water treatment plant and other facilities from the local electric utility serving Gunnison County. We have been granted conditional water rights from the State of Colorado for operation and development of the Project. TCM is reviewing and evaluating potential future power and water needs, however no definitive development project plans have been finalized or approved at this time.
Additional drilling will need to be conducted to further delineate the depth, grades and volume of mineralized materials before we can determine if there are reserves present in the project (presently in the advanced exploration stage). The time table for completing drilling, and the permitting and construction of the mine and milling facilities, is dependent upon several factors, including State and Federal regulations and availability of capital, which is driven by the market price for molybdenum.
Activities in 2009 and Plans for 2010
TCM, the Project Manager, is currently preparing and evaluating engineering and environmental reports and studies to prepare a Plan of Operations, which we anticipate will be submitted to the USFS in 2010. We expect that the Initial Plan of Operations will facilitate the base line data collection needed for additional permitting efforts. The Initial Plan of Operations review will follow the NEPA process, requiring the collection of environmental baseline data and studies for the preparation of an environmental analysis.
Information About Molybdenum Markets
The metallurgical market for molybdenum is characterized by cyclical and volatile prices, little product differentiation and strong competition. In the market, prices are influenced by production costs of domestic and foreign competitors, worldwide economic conditions, world supply/demand balances, inventory levels, the U.S. Dollar exchange rate and other factors. Molybdenum prices also are affected by the demand for end-use products in, for example, the construction, transportation and durable goods markets. A substantial portion the of world’s molybdenum supply is produced as a by-product of copper mining. Today, by-product production is estimated to account for approximately 60% of global molybdenum production.
Annual Metal Week Dealer Oxide mean prices averaged $11.29 in 2009, compared to $29.71 in 2008 ($17.79 in the fourth quarter 2008 and $10.00 as of December 31, 2008). The decrease in the average annual price for molybdenum is a result of the global recession which has led to dramatic reductions in steel output and pricing, and correspondingly in market demand for molybdenum and its pricing.
Energy Housing
Remington Village - Gillette, Wyoming. We have built and own a nine building multifamily apartment complex, with 216 units on 10.15 acres (purchased in 2007) located in Gillette, Wyoming. The apartments are a mix of one, two, and three bedroom units, with a clubhouse and family amenities for the complex. This project is held by our wholly-owned subsidiary Remington Village, LLC.
Occupancy averaged 88.6% in 2009. For that year, we realized average monthly revenues of approximately $219,000 (a 7 % return on investment (approximately 6.8% higher than the return realized on our Treasury Bills for the year)). The occupancy rate at December 31, 2008 was 88% and 80% at December 31, 2009. The decrease in occupancy rate from 2008 to 2009 is due to the national economic downturn and reduced activities in the oil and gas sector in Wyoming. Construction of a coal fired power plant 7 miles north of Gillette is expected to continue through 2011. A continued increase in oil and gas and coal mine activities in the area from the modest increases viewed in late 2009 and early 2010 may favorably impact our occupancy rate in 2010 and later years.
In January 2010 we pledged the apartment complex along with our corporate aircraft as collateral for a $10 million commercial line of credit with a financial institution.
In August 2007, Zions Bank provided secured construction financing, which also was guaranteed by U.S. Energy. The loan was $16.8 million at December 31, 2008. Total cost to buy the land, pay a developer’s fee, obtain permits and entitlements, site work and construction, was approximately $24.5 million at December 31, 2008, of which $7.7 million cash was invested by us (including $1.2 million for land purchase). The interest rate on the loan balance at December 31, 2008 was 2.71% (payable monthly) based on LIBOR. Loan maturity was March 1, 2009. In January 2009, we paid off the construction financing ($16.8 million) with internal funds. The property currently has no debt, although we may seek further collateral financing for the project in 2010 to provide additional access to capital for our oil and gas activities as warranted.
Fremont County, Wyoming
U.S. Energy owns a 14-acre tract in Riverton, Wyoming, with a two-story 30,400 square foot office building. The first floor is rented to non-affiliates and government agencies; the second floor is occupied by the Company. We also own a 10,000 square foot aircraft hangar on land leased from the City of Riverton with 7,000 square feet of associated offices and facilities; two vacant lots covering 13.2 acres in Fremont County, Wyoming, and two city lots and improvements including one small office building.
On December 28, 2007, we purchased 13.84 acres of undeveloped land across the street from USE’s corporate office building for $500,400 cash, with the intention of developing the land for mixed commercial and multifamily residential purposes. Our basis in the property and improvements at December 31, 2009 is $656,300. When the real estate market recovers we intend to sell the property without development. The timing of sale is not known.
Sold Uranium Properties - Possible Future Revenues
In 2007, we sold all of our uranium assets for cash and stock of the purchaser. Included in the sold assets were the Shootaring Canyon uranium mill in Utah and unpatented uranium claims in Wyoming, Colorado, Arizona and Utah. Pursuant to the asset purchase agreement, we may also receive from the purchaser:
·
$20,000,000 cash when the Shootaring Canyon Mill has been operating at 60% or more of its design capacity of 750 short tons per day for 60 consecutive days.
·
$7,500,000 cash on the first delivery (after commercial production has occurred) of mineralized material from any of the claims we sold to a commercial mill (excluding existing ore stockpiles on the properties).
·
From and after commercial production occurs at the Shootaring Canyon Mill, a production payment royalty (up to but not more than $12,500,000) equal to five percent of (i) the gross value of uranium and vanadium products produced at and sold from the mill; or (ii) mill fees received by the purchaser from third parties for custom milling or tolling arrangements, as applicable. If production is sold to an affiliate of the purchaser, partner, or joint venturer, gross value shall be determined by reference to mining industry publications or data.
The timing of future receipt of funds from any of these contingencies is not predicted.
Royalty on Uranium Claims
We hold a 4% net profits interest on unpatented mining claims on Rio Tinto’s Jackpot uranium property located on Green Mountain in Wyoming.
Research and Development
No research and development expenditures have been incurred, either on the Company’s account or sponsored by a customer of the Company, during the past three fiscal years.
Environmental
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 National Environmental Policy Act (“NEPA”), 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 proposed mining operations at the Mount Emmons property, Colorado’s mine permitting statute, the Abandoned Mine Reclamation Act, and industrial development and siting laws and regulations, also may affect the project. We believe we are in compliance in all material respects with existing environmental regulations. For information on the approximate reclamation costs (decommissioning, decontamination and other reclamation efforts for which we are primarily responsible or potentially responsible) related to the Mount Emmons project, see the consolidated financial statements included in Part II of this Annual Report.
Gas and oil operations also are subject to various federal, state and local governmental and environmental regulations, including regulations governing natural gas and oil production, federal and state regulations for environmental quality and pollution control, and state limits on allowable rates of production by well. These regulations may affect the amount of natural gas and oil available for sale, the availability of adequate pipeline and other regulated transportation and processing facilities, and other matters. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. From time to time, various proposals are made by regulatory agencies and legislative bodies. Regulatory changes can adversely impact the permitting and exploration and development of mineral and oil and gas properties including the availability of capital.
Although all of our oil and gas properties are operated by third parties, the activities on the properties are still subject to environmental protection regulations. Operators are required to obtain drilling permits, restrict substances that can be released into the environment, and require remedial work to mitigate pollution from operations (such as pollution from operations), close and cover disposal pits, and plug abandoned wells. Violations by the operator could result in substantial liabilities, and we would have to pay our share. Based on the current regulatory environment in those states where we have oil and natural gas investments, we don’t expect to make any material capital expenditures for environmental control facilities.
Failure to comply with these regulations could result in substantial fines, environmental remediation orders and/or potential shut down of a project until compliance is achieved. Failure to timely obtain required permits to start operations at a project could cause delay and/or the failure of the project resulting in a potential write-off of the investments made.
Employees
As of March 11, 2010, we had 18 full-time employees.
Mining Claim Holdings
Title
Approximately 25 of the Mount Emmons mining claims are patented claims; however the majority of claims are unpatented.
Unpatented claims are located upon federal and public land pursuant to procedures established by the General Mining Law, which governs mining claims and related activities on Federal public lands. 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 U.S. Bureau of Land Management (“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 vulnerability not associated with other types of property interests. It is impossible to ascertain the validity of unpatented mining claims solely from public 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 economic feasibility of mining minerals located thereon. However, we believe that all of our Mount Emmons mining claims are valid and in good standing.
Proposed Federal Legislation
The U.S. Congress from time to time has considered proposed revisions to the General Mining Law, including as recently as 2009. If these proposed revisions are enacted, payment of royalties on production of minerals from federal lands could be required as well as additional procedural measures, 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 legal proceedings pending at December 31, 2009, and developments in those proceedings from that date to the date this Annual Report was filed, are summarized below.
Water Rights Litigation -Mount Emmons Molybdenum Property
1.
Concerning the Application of the United States of America in the Gunnison River, Gunnison County, Case No. 99CW267. This case involves an application filed by the United States of America to appropriate 0.033 cubic feet per second of water for wildlife use and for incidental irrigation of riparian vegetation at the Mount Emmons Iron Bog Spring, located in the vicinity of Mount Emmons. MEMCO filed a Statement of Opposition to protect proposed mining operations against any adverse impacts by the water requirements of the Iron Bog on such operations. This case is pending while the parties attempt to reach a settlement on the proposed decree terms and conditions.
2.
Concerning the Application of U.S. Energy, Case No. 2008CW81. On July 25, 2008, the Company filed an Application for Finding of Reasonable Diligence with the Water Court concerning the conditional water rights associated with Mount Emmons. The conditional water decree (“Decree”) requires the Company to file its proposed plan of operations and associated permits (“Plan”) with the Forest Service and BLM within six years of entry of the 2002 Decree, or within six years of the final determination in the Applicant’s pending patent application, whichever occurs later. Although the BLM issued the mineral patents on April 2, 2004, the patents remained subject to a challenge by High Country Citizens’ Alliance, the Town of Crested Butte, and the Board of County Commissioners of Gunnison County (collectively “Protestors”). The Company vigorously defended this legal action through the Federal District Court for the District of Colorado and the Tenth Circuit Court of Appeals. On April 30, 2007, the United States Supreme Court made a final determination upholding BLM’s issuance of the mineral patents. The Company believes that the deadline for filing the Plan specified by the Decree is April 30, 2013 (six years from the final determination of issuance of the mineral patents by the United States Supreme Court). The Forest Service has indicated that the deadline should be April 2, 2010 (six years from the issuance of the mineral patents by BLM). The United States, on behalf of the Forest Service and BLM, filed a Statement of Opposition on this specific issue only. Statements of Opposition were also filed by six other parties including the City of Gunnison, the State of Colorado, and High Country Citizens’ Alliance in September for various reasons, including requesting the Company be put on strict proof as to demonstrating evidence of reasonable diligence in developing the conditional water rights. Although, the Company and TCM will be prepared to file a Plan by the April 2, 2010 proposed deadline, the Company and TCM will pursue a ruling from the Water Court that the deadline specified in the Decree requires the filing of the Plan by April 30, 2013.
Ordinance Related to the Crested Butte Watershed
On May 19, 2008, the Town Council adopted a revised Watershed Ordinance. The Company and TCM intend to work with the Town of Crested Butte concerning activities at Mount Emmons consistent with lawful and applicable rules, regulations, and statutes. It is possible that unexpected delays, and/or increased costs, may be encountered in developing a new mine plan for Mount Emmons as a result of the revised Watershed Ordinance.
Appeal of Approval of Notice of Intent to Conduct Prospecting for the Mount Emmons Molybdenum Property
On March 8, 2008, High Country Citizens’ Alliance (‘HCCA”) filed a request for hearing before the Colorado Land Reclamation Board (“Board”) of the approval of a Notice of Intent to Conduct Prospecting Notice for the Mount Emmons molybdenum property (“NOI”), which was approved by the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) on January 3, 2008. The NOI as approved provided for continued exploration of the molybdenum deposit to update, improve and verify, in accordance with current industry standards and legal requirements, mineralization data that was collected by Amax in the late 1970’s.
On March 28, 2008, the Company and the Colorado Attorney General’s Office filed independent Motions to Dismiss alleging among other matters that: (i) HCCA had no standing to appeal the NOI; (ii) the NOI is not an appealable decision under Colorado law; (iii) HCCA’s appeal is not timely; and (iv) the appeal is based on information obtained in violation of Colorado law.
On May 14, 2008, the Board denied HCCA’s Request for Hearing and also denied their Request for a Declaratory Order. Citing Colorado law, the Board determined that HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law.
On August 28, 2008, HCCA appealed the Board’s decision in Denver District Court. Plaintiff: High Country Citizen’s Alliance v. Defendants: Colorado Mined Land Reclamation Board, Colorado Division of Reclamation Mining and Safety and U.S. Energy Corp., Case No.: 08CV6156 (District Court, 2d Jud. Dist., City and County of Denver). The Board has filed an answer with the Court. The DRMS and the Company (in conjunction with TCM) have both filed the responsive pleadings in addition to motions to dismiss the HCCA complaint. No hearing date has been scheduled in the District Court of Colorado concerning DRMS’s issuance of the NOI to the Company for the Mount Emmons molybdenum property.
Water Treatment Facility - Permit Renewal Protest
The Company received a NPDES Permit renewal for Mount Emmons from the Colorado Department of Public Health and Environment - Water Quality Division (“Water Quality Division”) effective September 1, 2008. The NPDES Permit is for a five (5) year period (2008 - 2013). On August 28, 2008, the Town of Crested Butte, Board of County Commissioners for the County of Gunnison and High Country Citizens’ Alliance (“Petitioners”) filed a Request for Adjudicatory Hearing before the Water Quality Division to challenge the NPDES Permit. The Petitioners seek revisions to the Permit that would require the Company to maintain a prepaid operating contract and provide additional financial security for long term operation of the plant.
A hearing before the Administrative Law Judge (“ALJ”) in the Office of Administrative Courts was held on October 2, 2009 in Denver, Colorado. On October 30, 2009 the ALJ issued an order upholding the issuance of the NPDES Permit and rejecting the Petitioners request for financial assurances as a condition of the NPDES permit.
Item 4 - Submission of Matters to a Vote of Security Holders
On June 26, 2009, the annual meeting of shareholders was held for the election of two directors to serve until the terms stated in the Proxy Statement (until the 2012 Annual Meeting of Shareholders and until their successors are elected or appointed and qualified). With respect to the election of the directors, the votes cast were as follows:
Name of Director
Votes For
Withheld
Keith G. Larsen
16,525,397
322,997
Allen S. Winters
16,449,761
398,633
The directors now are Keith G. Larsen, Mark J. Larsen, Robert Scott Lorimer, H. Russell Fraser, Allen S. Winters, Michael T. Anderson and Michael Feinstein.
The shareholders also voted on the ratification of appointment of Hein & Associates LLP, the votes cast were as follows:
Votes For
Votes Against
Abstain
Ratification of appointment of Hein & Associates LLP as independent auditors for the current fiscal year.
14,482,178
214,537
42,203
PART II
Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchase of Equity Securities
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 Capital Market of the National Association of Securities Dealers Automated Quotation System ("Nasdaq"). Quarterly high and low sale prices follow:
Holders
At March 11, 2010 the closing market price was $6.41 per share. There were approximately 2,132 shareholders of record, with 26,418,713 shares of common stock issued and outstanding at December 31, 2009.
We paid a onetime special $0.10 per share cash dividend to common shareholders of record on July 6, 2007. There are no contractual restrictions on our present or future ability to pay cash dividends.
Issuance of Securities in 2009
During the twelve months ended December 31, 2009, USE issued a total of 5,189,655 shares and cancelled 706,071 shares. A brief discussion of the issuance of the shares follows:
Registered Securities
During the twelve months ended December 31, 2009, we issued 1,984 shares of common stock as a result of the exercise of options which had been issued to an employee and 71,088 shares as a result of the exercise of warrants which had been issued to two consultants. We also issued 36,583 shares pursuant to the terms of our ESOP. The ESOP funding represents the minimum required amount during the twelve months ended December 31, 2009.
In December 2009, we issued 5 million shares of common stock in a public offering, for gross proceeds of $26.2 million. These securities were offered and sold under a universal shelf registration statement on Form S-3 (SEC File No. 333-162607), declared effective on November 6, 2009. Madison Williams and Company LLC acted as Sole Book-Running and Lead Manager for the public offering (which commenced on December 1, 2009) of the 5 million shares, and C.K. Cooper & Company acted as Co-Manager. The registration statement covers $100 million. Additional shares may be sold under this registration statement in the future.
From November 6, 2009 through December 31, 2009, we paid a total of $1.9 million for underwriting discounts and commissions, expenses paid to or for the underwriters, and other expenses (including printing, legal and audit fees and costs, travel, and related items). Net proceeds to U.S. Energy from the public offer and sale of the 5 million shares was $24.3 million.
As of December 31, 2009, none of the net proceeds had been used. We anticipate using net proceeds in 2010 for oil and gas exploration and development costs and general working capital.
Unregistered Securities
During the twelve months ended December 31, 2009, we issued 80,000 shares pursuant to the 2001 Stock Award Plan, 20,000 shares to each of the executive officers of the Company.
Cancellation of Shares
During the twelve months ended December 31, 2009, the Company completed its Stock Buyback Program by purchasing and cancelling 706,071 shares at a cost of $1.4 million. The program purchased and cancelled a total of 3,094,200 shares at a cost of $8.0 million during 2007, 2008 and 2009.
Equity Plan Compensation Information - Information about Compensation Plans as of December 31, 2009
(1)
Four Officers (CEO, COO, CFO and General Counsel) of the Company receive 5,000 shares of common stock at the beginning of each calendar quarter, 20,000 shares per year under this plan. The Company pays the taxes on these shares as the Officers have agreed to not pledge, sell or in any other way leverage these shares. The shareholders of the Company approved this plan.
Stock Performance Graph
The following graph compares the cumulative return on a $100 investment in our common stock for the five years ended December 31, 2009, to that of the cumulative return on a $100 investment in the S&P 500, the NASDAQ Market Index, and the S&P Small Cap 600 Energy Index. In calculating the cumulative return, we assumed reinvestment of the $0.10 per share cash dividend paid in July 2007. The indices are included for comparative purpose only. This graph is not "soliciting material," is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Exchange Act, whether made before or after the date the Annual Report was filed and irrespective of any general incorporation language in any such filing.
COMPARISON OF CUMULATIVE TOTAL RETURN
AMONG U.S. ENERGY CORP., THE S&P 500, THE NASDAQ MARKET INDEX, AND THE
S&P SMALL CAP 600 ENERGY INDEX
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data is derived from and should be read with the financial statements included in this Report.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULT OF OPERATIONS
Forward Looking Statements
Statements in this discussion about expectations, plans and future events or conditions are forward looking statements. Actual future results, including oil and natural gas production growth, financing sources, and environmental and capital expenditures, could be materially different depending on a number of factors, such as commodity prices, political or regulatory events, and other matters. Please see “Cautionary Statement Regarding Forward-Looking Statements” and Item 1A
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
None
Item 8
Item 8 - Financial Statements
Financial statements meeting the requirements of Regulation S-X are included below.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
U.S. Energy Corp.
We have audited the accompanying balance sheets of U.S. Energy Corp. and subsidiary (the “Company”) as of December 31, 2009 and 2008, and the related statements of operations, shareholders’ equity, and cash flows for each of the two years in the period ended December 31, 2009. 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of U.S. Energy Corp. and subsidiary as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 12, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ Hein and Associates LLP
HEIN & ASSOCIATES LLP
Denver, Colorado
March 12, 2010
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders ofU.S. Energy Corp.
We have audited the accompanying consolidated statements of operations, stockholders’ equity and cash flows of U.S. Energy Corp. and Subsidiaries (the Company) for the year ended December 31, 2007. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on 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, and 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 consolidated results of operations and cash flows of U.S. Energy Corp. and Subsidiaries, for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note J to the consolidated financial statements, effective January 1, 2007, the Company changed its method of accounting for uncertain tax positions. As discussed in Note B to the consolidated financial statements, effective January 1, 2009, the Company changed its presentation of noncontrolling interests.
/s/ Moss Adams LLP
Scottsdale, Arizona
March 12, 2008, except as to the reclassification adjustments to reflect discontinued operations described in Note N as to which the date is March 12, 2009, and except as to the presentation of noncontrolling interests as to which the date is March 12, 2010.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
A. BUSINESS ORGANIZATION AND OPERATIONS
U.S. Energy Corp. was incorporated in the State of Wyoming on January 26, 1966. U.S. Energy Corp. (the "Company" or "USE") engages in the acquisition, exploration, holding, sale and/or development of mineral properties. Principal asset interests at December 31, 2009 are in oil and gas, molybdenum, geothermal and real estate. Historically, the Company also participated in other base and precious metals. Our uranium and gold assets were sold during 2008 and 2007.
B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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. Significant estimates include oil and gas reserves used for depletion and impairment considerations and the cost of future asset retirement obligations. Due to inherent uncertainties, including the future prices of oil and gas, these estimates could change in the near term and such changes could be material.
Principles of Consolidation
The financial statements of the Company as of December 31, 2009 and December 31, 2008 include only the accounts of the Company and its wholly owned subsidiary Remington Village, LLC (“Remington Village”). The consolidated financial statements contained in this report for the year ended December 31, 2007 also include subsidiaries of the Company which were either merged into the Company or liquidated and dissolved during 2008 and 2007. These subsidiaries were majority-owned or controlled subsidiaries: Plateau Resources Limited, (“Plateau”) (100%), Four Nines Gold, Inc. ("FNG") (50.9%), SGMI (54.4%), Yellow Stone Fuels, Inc. (“YSFI”) (49.1%), Crested Corp. (“Crested”) (70.9%), and the USECC Joint Venture ("USECC"), a consolidated joint venture which was equally owned by the Company and Crested. On December 15, 2008, the Company purchased a 25% ownership interest in Standard Steam Trust LLC (“SST”) which is accounted for using the equity method. At December 31, 2009 the Company’s ownership interest in SST was reduced to 23.8%.
Cash and 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, 2009 and 2008, the Company had its cash and cash equivalents with several financial institutions, primarily invested in U.S. Treasury Bills. 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.
Marketable Securities
The Company categorizes its marketable securities as available-for-sale or held-to-maturity. Increases or decreases in the fair value which are considered temporary are recorded within equity as comprehensive income or losses. Gains or losses as a result of sale are recorded in operations when realized.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Accounts Receivable
The Company determines any required allowance by considering a number of factors including the length of time trade and other accounts receivable are past due and the Company's previous loss history. The Company provides reserves for account receivable balances when they become uncollectable. Payments subsequently received on such reserved receivables are credited to the allowance for doubtful accounts. During the year ended December 31, 2009, the Company recorded $109,000 in uncollectable receivables related to its multi family housing project. The balance of accounts receivable at December 31, 2009 are for the sale of oil and gas and have been received subsequent to the balance sheet date. No reserve for uncollectable receivables was booked during the year ended December 31, 2009 and 2008.
Restricted Investments
The Company accounts for cash deposits held as collateral for reclamation obligations as restricted investments. Maturities or release dates less than twelve months from the end of the reported accounting period are reported as current assets while maturities or release dates in excess of twelve months from report dates are reported as long term assets.
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:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Components of Property and Equipment as of December 31, 2009 and 2008 are as follows:
Oil and Gas Properties
The Company follows the full cost method in accounting for its oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated average prices per barrel of oil and per MMbtu of natural gas at the first of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs. During the year ended December 31, 2009, the Company recorded a non-cash impairment of $1.1 million during the quarter ended March 31, 2009 and $404,000 during the quarter ended September 30, 2009.
Mineral Properties
The Company capitalizes all costs incidental to the acquisition of mineral properties. Mineral exploration costs are expensed as incurred. When exploration work indicates that a mineral property can be economically developed as a result of establishing proved and probable reserves, costs for the development of the mineral property as well as capital purchases and capital construction 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. All capitalized costs are charged to operations if the Company subsequently determines that the property is not economical due to permanent decreases in market prices of commodities, excessive production costs or depletion of the mineral resource.
Mineral properties at December 31, 2009 and 2008 reflect capitalized costs associated with the Company’s Mount Emmons molybdenum property near Crested Butte, Colorado. The Company has entered into an agreement with Thompson Creek Metals Company USA (“TCM”) to develop this property. TCM may earn up to a 75% interest in the project for the investment of $400 million. The Company’s carrying balance in the Mount Emmons property at December 31, 2009 and 2008 is as follows (in thousands):
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Long-Lived Assets - Real Estate
The Company evaluates its long-lived assets, which consist of commercial real estate, for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Impairment calculations are generally based on market appraisals. If estimated future cash flows, on an undiscounted basis, are less than the carrying amount of the related asset, an asset impairment is considered to exist. Changes in significant assumptions underlying future cash flow estimates may have a material effect on the Company's financial position and results of operations. At December 31, 2009 and 2008, no impairment existed on the Company’s long-lived assets as the appraised value at December 31, 2009 and 2008 exceeded construction and carrying value and rental rates remained strong and costs within projected limits.
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 the 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.
Asset Retirement Obligations
The Company accounts for its asset retirement obligations under FASB ASC 410-20, "Asset Retirement Obligations." The Company records the fair value of the reclamation liability on its inactive mining properties and its operating oil and gas properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required as well as accretes the discounted liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. The Company deducts any actual funds expended for reclamation during the quarter in which it occurs.
The following is a reconciliation of the total liability for asset retirement obligations:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Revenue Recognition
The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. Natural gas balancing obligations as of December 31, 2009 and 2008 were not significant.
Revenues from real estate operations are reported on a gross revenue basis and are recorded at the time the service is provided.
Management fees are recorded when the service is provided. Management fees are for operating and overseeing services performed on mineral properties in which the Company participates with joint venture or industry partners.
Stock Based Compensation
The Company measures the cost of employee services received in exchange for all equity awards granted including stock options based on the fair market value of the award as of the grant date.
The Company has computed the fair values of its options granted to employees using the Black Scholes pricing model and the following weighted average assumptions:
The Company recognizes the cost of the equity awards over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. As share-based compensation expense is recognized based on awards ultimately expected to vest, the expense has been reduced for estimated forfeitures based on historical forfeiture rates.
Income Taxes
The Company recognizes 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 carry forwards.
Additionally, the Company recognizes deferred tax assets for the expected future effects of all deductible temporary differences, loss carry forwards and tax credit carry forwards. 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. Management believes it is more likely than not that such tax benefits will be realized and a valuation allowance has not been provided.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Net Income (Loss) Per Share
Basic earnings per share are computed based on the weighted average number of common shares outstanding. Common shares held by the ESOP are included in the computation of earnings per share. Total shares held by the ESOP at December 31, 2009, 2008, and 2007 were 642,913, 606,330 and 541,735, respectively. 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 and warrants to purchase common stock, if dilutive. Using the treasury stock method, potential common shares relating to options and warrants are excluded from the computation of diluted loss per share for the years ending December 31, 2009 and 2008 because they were anti dilutive. Potential shares relating to options and warrants were included in the diluted earnings per share for the year ended December 31, 2007. Dilutive options and warrants totaled 282,504, 226,246, and 1,719,982 at December 31, 2009, 2008 and 2007, respectively.
Recent Accounting Pronouncements
FASB Codification Discussion - We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (GAAP) that we follow to ensure we consistently report our financial condition, results of operations, and cash flows.
The FASB recognized the complexity of its standard-setting process and embarked on a revised process in 2004 that culminated in the release on July 1, 2009, of the FASB Accounting Standards Codification,™ sometimes referred to as the Codification or ASC. The Codification does not change how the Company accounts for its transactions or the nature of related disclosures made. However, when referring to guidance issued by the FASB, the Company refers to topics in the ASC. The above change was made effective by the FASB for periods ending on or after September 15, 2009.
FASB ASC 810-10 - In June 2009, the FASB issued an amendment to ASC 810-10, Consolidation. As a result, in December 2009, the FASB issued ASC 2009-17, Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities. This guidance amends ASC 810-10-15 to replace the quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a Variable Interest Entity (“VIE”) with a primarily qualitative approach focused on identifying which enterprise has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and requires additional disclosures about an enterprise’s involvement in VIEs. This guidance is effective as of the beginning of the reporting entity’s first annual reporting period that begins after November 15, 2009 and earlier adoption is not permitted. The adoption of ASC 810-10 is not expected to have a material effect on our financial position and results of operations.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
FASB ASC 810-10-65 - In December 2007, the FASB issued guidance now codified as ASC Section 810-10-65, “Consolidation-Transition and Open Effective Date Information” (“ASC 810-10-65”), which requires companies to treat non-controlling interests (commonly referred to as minority interest) as a separate component of shareholders’ equity and not as a liability. This pronouncement will apply prospectively, except for the presentation and disclosure requirements, which will apply retrospectively. ASC 810-10-65 is effective for periods beginning on or after December 15, 2008 and will impact the accounting for non-controlling interests after the effective date, to the extent the Company enters into an acquisition with a non-controlling interest. The adoption of this standard resulted in a different presentation of noncontrolling interests on the Company’s consolidated financial statements.
FASC ASC 815-10-50 - In March 2008, the FASB issued guidance related to the disclosures about derivative instruments and hedging activities under FASB ASC 815-10-50, Derivatives and Hedging. This guidance requires companies to provide enhanced disclosures about (a) how and why they use derivative instruments, (b) how derivative instruments and related hedged items are accounted for under applicable guidance, and (c) how derivative instruments and related hedged items affect a company’s financial position, financial performance, and cash flows. These disclosure requirements are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company has no hedges in place as of December 31, 2009. If the Company elects to hedge production in 2010 it will comply with FASB ASC 815-10-50.
Accounting Standards Update No. 2009-01 - In June 2009, the FASB issued Accounting Standards Update No. 2009-01 which amends ASC 105, Generally Accepted Accounting Principles. This guidance states that the ASC will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Once effective, the Codification’s content will carry the same level of authority. Thus, the U.S. GAAP hierarchy will be modified to include only two levels of U.S. GAAP: authoritative and non-authoritative. This is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company adopted ASC 105 as of September 30, 2009 and thus have incorporated the new Codification citations in place of the corresponding references to legacy accounting pronouncements.
Accounting Standards Update No. 2010-03 - In December 2008, the Securities and Exchange Commission published a Final Rule, Modernization of the Oil and Gas Reporting Requirements. The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect impairment and depletion calculations. In January 2010, the FASB issued Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosure, to align the oil and gas reserve estimation and disclosure requirement of the SEC Final Rule with the ASC 932. The new disclosure requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company’s adoption of this Final rule for this annual reported dated December 31, 2009 affected our oil and gas disclosures but had no material effect on our financial position and results of operations.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Accounting Standards Update No. 2009-05 - In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value, which amends ASC 820, Fair Value Measurements and Disclosures. This Update provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure the fair value using one or more of the following techniques: a valuation technique that uses the quoted price of the identical liability or similar liabilities when traded as an asset, which would be considered a Level 1 input, or another valuation technique that is consistent with ASC 820. This Update is effective for the first reporting period (including interim periods) beginning after issuance. The Company adopted this guidance as of September 30, 2009, which did not have a material impact on our consolidated financial statements.
Accounting Standards Update 2010-09 - In May 2009, the FASB issued FASB ASC 855, “Subsequent Events,” and in February 2010, the FASB issued ASC Update 2010-09, “Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements,” which establishes standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. Under this standard, entities that file or furnish financial statements with the SEC, such as the Company, are required to use an issued date in evaluating subsequent events. This standard, as updated, is effective February 24, 2010, and the Company adopted it at that date. The adoption did not have a material impact on the Company’s results of operations or financial position.
The Company has reviewed other current outstanding statements from the FASB 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
Sutter Gold Mining Company, Inc. (“SGMI”)
On August 22, 2008, the Company sold 39,062,720 common shares of SGMI that it owned, to RMB Resources Ltd. (“RMB”), as trustee for the Telluride Investment Trust. The sale of these shares represented approximately 49.9% of the outstanding common shares of SGMI for purchase price of $5.1 million. Under the terms of the agreement, the Company retained an equity position of approximately 3,550,361 shares and the 5% net profits interest royalty. The Company also participated in a non-brokered private placement by SGMI with the purchase of 4,545,455 units for total cash consideration of $496,000. Based on these transactions, the Company owns approximately 8,095,816 shares or 7.8% of SGMI. As a result of participating in the private placement the Company also received 24-month warrants to purchase an additional 2,272,728 common shares of SGMI at a price of Cdn. $0.15 per share.
The Company recorded a gain of $5.4 million from the sale of its controlling interest in SGMI during the year ended December 31, 2008. The Company also recorded losses from discontinued operations of SGMI of $501,000 and $2.0 million for the years ended December 31, 2008 and 2007, respectively.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
D. FAIR VALUE
The Company adopted Financial Accounting Standards Board Accounting Standards Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820) on January 1, 2008, as it relates to financial assets and liabilities. The Company adopted FASB ASC 820 on January 1, 2009, as it relates to nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that prioritizes the inputs the Company to measure fair value. The three levels of the fair value hierarchy defined by FASB ASC 820 are as follows:
·
Level 1 - Unadjusted quoted prices is available in active markets for identical assets or liabilities.
·
Level 2 - Pricing inputs, other than quoted prices within Level 1, which are either directly or indirectly observable.
·
Level 3 - Pricing inputs that are unobservable requiring the Company of valuation methodologies that result in management’s best estimate of fair value.
The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of the Company’s asset retirement obligations and other accrued liabilities are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair value of the asset retirement obligations and other accrued liabilities are reflected on the balance sheet as detailed below.
See Note B for a roll forward of the asset retirement obligation.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
As of December 31, 2009, the Company held $23.2 million of investments in government securities and marketable securities. The fair value of the investments is reflected on the balance sheet as detailed below.
The following table summarizes, by major security type, the fair value and any unrealized gain of the Company’s investments. The unrealized gain is recorded on the consolidated balance sheet as other comprehensive income, a component of stockholders’ equity.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
The Company’s other financial instruments include cash and cash equivalents, accounts receivable, accounts payable, other current liabilities and long-term debt and short-term construction debt. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and other current liabilities approximate fair value because of their immediate or short-term maturities. The carrying value of the Company long-term debt approximates its fair market value since it interest rates have remained generally unchanged from the issuance of the long-term debt. The carrying value of the Company short-term construction debt, at December 31, 2008, approximates its fair market value since it bears interest at a floating market interest rate. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:
E. MINERAL PROPERTY TRANSACTIONS
Mount Emmons Molybdenum Properties
On August 19, 2008, USE and Thompson Creek Metals Company USA (“TCM”), a Colorado corporation headquartered in Englewood, Colorado, entered into an Exploration, Development and Mine Operating Agreement for USE’s Mount Emmons molybdenum property. TCM assigned the agreement to Mt. Emmons Moly Company, a Colorado corporation and wholly owned subsidiary of TCM effective September 11, 2008. Under the terms of the agreement TCM may acquire up to a 75% interest for $400 million (option payments of $6.5 million and project expenditures of $393.5 million).
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
The Agreement covers two distinct periods of time: The Option Period, during which TCM may exercise an option (the “Option”) to acquire up to a 50% interest in Mount Emmons; and the Joint Venture Period, during which TCM will form a joint venture with USE and also have an option to acquire up to an additional 25% interest in Mount Emmons. The following table sets forth the required option and property expenditures that Thompson Creek must make to own its interest in the Mount Emmons molybdenum property:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Costs to operate the water treatment plant at the property will be paid solely by USE until TCM elects to exercise its option to own an interest in the property.
Failure by TCM to incur the required amount of expenditures by a deadline, or make an Option Payment to USE, subject to the terms of the Agreement, the Agreement may be terminated without further obligation to USE from TCM. TCM may terminate the Agreement at any time, but if earned and elected to accept, TCM will retain the interest earned and be responsible for that share of all costs and expenses related to Mount Emmons.
The Joint Venture Period; Joint Venture Terms:
Within six months of TCM’s election to acquire the 50% interest, TCM, in its sole discretion, shall elect to form a Joint Venture and either: (i) participate on a 50%-50% basis with USE, with each party to bear their own share of expenditures from formation date; or (ii) acquire up to an additional 25% interest in the project by paying 100% of all expenditures equal to $350 million (for a total of $400 million, including the $50 million to earn the 50% interest in the second stage of the Option Period), at which point the participation would be 75% TCM and 25% USE. Provided however, if TCM makes expenditures of at least $70 million of the $350 million in expenditures and TCM decides not to fund the additional $280 million in expenditures, TCM will have earned an additional 2.5% (for a total of 52.5%). Thereafter, TCM will earn an incremental added percentage interest for each dollar it spends toward the total $350 million amount.
At any time before incurring the entire $350 million, TCM in its sole discretion, may determine to cease funding 100% of expenditures, in which event USE and TCM then would share expenditures in accordance with their participation interests at that date, in accordance with the Joint Venture. With certain exceptions, either party’s interest is subject to dilution in the event of non-participation in funding the Joint Venture’s budgets.
Management of the Property
TCM is the Project Manager of Mount Emmons. A four person Management Committee governs the projects’ operations, with two representatives each from USE and TCM. TCM will have the deciding vote in the event of a committee deadlock.
If and when Mount Emmons goes into production, TCM will purchase USE’s share of the molybdic oxide produced at an average price as published in Platt’s Metals Weekly price less a discount with a cap and a floor. The discount band will be adjusted every five years based upon the United States’ gross domestic product.
Oil and Gas Exploration
The Company participates in oil and gas projects as a non-operating working interest owner and has active agreements with several oil and gas exploration and production companies. Our working interest varies by project, but typically ranges from approximately 5% to 65%. These projects may result in numerous wells being drilled over the next three to five years.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
On August 24, 2009, the Company and Brigham Oil & Gas, L.P. (“Brigham”) a Delaware limited partnership wholly-owned by Brigham Exploration Company (a Delaware corporation), entered into a Drilling Participation Agreement (the “DPA”). The DPA provides for the Company and Brigham to jointly explore for oil in the Bakken and Three Forks formations, in up to fifteen 1,280 acre spacing units (19,200 gross acres) in a portion of Brigham’s Rough Rider prospect in Williams and McKenzie Counties, North Dakota. The terms of the DPA call for the drilling of up to 15 initial Bakken wells in 15 separate 1,280 acre spacing units. Under the terms of the DPA, the Company committed to drilling six initial wells (and earning subsequent working interests in six 1,280 acre spacing units) and exercised its option to drill nine additional wells (and earning subsequent working interests in nine additional 1,280 acre spacing units). Upon the drilling and completion of the first or initial well in each 1,280 acre spacing unit, the Company will earn 36% of Brigham’s original working interest in the remaining acreage (or drilling locations) in each 1,280 acre unit or 19,200 gross acres in the Rough Rider project area.
Under the DPA the wells to be drilled are broken into three groups. The first group consists of six wells, the second group of four wells and the final of five wells. The Company participated for 65% of Brigham’s original working interest in each initial well drilled in the first six well program. As of December 31, 2009, Brigham elected to participate in the next 9 wells at 50% of their working interest which decreased the Company’s participation in those wells to 50% from the 65% participation interest on the first six wells. Each participation amount for both Brigham and the Company will be subject to dilution or expansion based on other working interest owners’ participation in the initial wells and/or subsequent wells in each 1,280 acre spacing unit. Upon receiving a pooled payout of all of the costs and expenses incurred to drill and complete the six initial wells in the six initial 1,280 acre spacing units, the Company will assign back 35% of its 65% of Brigham’s original working interest to Brigham after which the Company will own 42.25% of Brigham’s original working interest in the initial well in each 1,280 acre spacing unit. The Company is also entitled to a pooled payout on the second group of four wells similar to the first six well program. Participation in the third group of five wells and spacing units entitles the Company to a well by initial well per spacing unit payout before a 27.7% back in assignment to Brigham.
At December 31, 2009, 6 wells, 2.99 net wells to the Company, had been drilled and completed with net costs of $18.7 million. There were an additional 2 wells, 0.58 net wells to the Company, being drilled at December 31, 2009 at a net cost of $1.4 million. The remaining seven wells will be drilled during 2010. As a result of participating in all 15 wells, the Company will earn the rights to drill up to 30 total wells in the Bakken formation and an additional 30 wells in the Three Forks formation for a total of 60 wells, based on current spacing in North Dakota. Brigham operates all of the wells. If the spacing is ultimately increased to three wells per 1,280 acre spacing unit, the potential number of drilling locations could increase to 90. The drilling of each well typically takes 30 days while the completion typically takes 21-28 days.
Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at December 31, 2009 and 2008 which were not included in the amortized cost pool were $5.4 and $3.0 million, respectively. These costs consist of wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs and are related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at December 31, 2009 and 2008. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are evaluated, drilled or abandoned.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Ceiling Test Analysis - The Company performs a quarterly ceiling test for each of its oil and gas cost centers, which in 2009, there was only one. The ceiling test incorporates assumptions regarding pricing and discount rates and over which management has no influence in the determination of present value. In arriving at the ceiling test for the quarter ended December 31, 2009, the Company used $61.18 per barrel for oil and $3.866 per MMbtu for natural gas (and adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of the Company’s producing property. The discount factor used was 10%.
During the year ended December 31, 2009, the Company recorded impairments totaling $1.5 million, $1.1 million in the first quarter of 2009 and $405,000 in the third quarter of 2009. This impairment was as a result of two factors, (1) low prices for natural gas during the quarter ended March 31, 2009, $3.58 per MMbtu and (b) a dry hole drilled during the quarter ended September 30, 2009, which resulted in costs exceeding the ceiling test.
Wells in Progress - Wells in progress represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then transferred to evaluated property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods.
Sale of Mineral Interests
Uranium One Asset Purchase Agreement (“Uranium One”) - Uranium
On April 30, 2007, the Company and certain of its then subsidiary companies, completed the sale of uranium assets, including a uranium mill in Utah and unpatented mining claims in Wyoming, Colorado, Arizona and Utah and certain contractual rights the Company had with a third party for the development of uranium properties. The uranium assets were sold to sxr Uranium One Inc. (“Uranium One,”) headquartered in Toronto, Canada with offices in South Africa and Australia (Toronto Stock Exchange and Johannesburg Stock Exchange, “UUU”), and certain of its private subsidiary companies. Uranium One assumed liabilities associated with the uranium assets it acquired, including (but not limited to) those future reclamation liabilities associated with the uranium mill in Utah, and the mining claims.
The Company holds a 4% net profits interest on Rio Tinto’s Jackpot uranium property located on Green Mountain in Wyoming. This interest was not included in the sale of uranium assets to Uranium One.
On October 29, 2007, Uranium One purchased a commercial property associated with uranium assets it had previously purchased from the Company, for $2.7 million. Cash proceeds from the sale of the property were $2.6 million. The Company recorded a gain on the sale of assets from the sale of the property of $472,000.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
F. SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
Capitalized Costs
The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties, and in exploration and development activities:
The Company’s DD&A per equivalent BOE was $22.07 in 2009 and $25.20 in 2008.
Undeveloped properties as of December 31, 2009 include costs incurred in the following years:
Costs Incurred
Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Results of Operations
Results of operations from oil and natural gas producing activities are presented below:
Oil and Natural Gas Reserves (Unaudited)
Proved reserves are estimated quantities of oil and 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 reserves are reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.
Proved oil and natural gas reserve quantities at December 31, 2009 and the related discounted future net cash flows before income taxes are based on the estimates prepared by Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. The reserve report for the period ended December 31, 2008 was prepared by Ryder Scott Company, L.P. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.
The Company’s net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below:
Standardized Measure (Unaudited)
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves as of year-end is shown below:
Future cash flows are computed by applying average prices per barrel of oil and per MMbtu of natural gas at the first of each month in the 12-month period prior to the end of the reporting period to year-end quantities of proved oil and natural gas reserves. Average prices used in computing year end 2009 and 2008 future cash flows were $61.18/barrel and $41.41/barrel, respectively, for oil and $3.866/MMbtu and $5.88/MMbtu for natural gas, respectively. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Change in Standardized Measure (Unaudited)
Changes in standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below:
Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pretax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pretax discounted basis.
G. GEOTHERMAL
During the year ended December 31, 2009, the Company increased its minority interest in Standard Steam Trust, LLC (“SST”), a Denver, Colorado based private geothermal resource acquisition and development company, to $4.3 million from $3.5 million at December 31, 2008. The Company recognized a $1.4 million equity loss during the year ended December 31, 2009. The Company’s net investment at December 31, 2009 was $3.0 million. Due to not funding yearend cash call from SST the Company’s ownership interest decreased from 25% to 23.8%.
SST is managed by Terra Caliente, LLC (“Terra”), also a private Denver based company, with oversight by an advisory board (USE is one of three members) as to budgets, major expenditures, sale or other disposition of prospects, and similar matters. SST was formed to explore for, acquire and develop geothermal properties to the level where they could be sold to industry partners for the development of electrical generation plants.
H. ENERGY SECTOR HOUSING
Remington Village - Gillette, Wyoming.
During 2008, the Company completed construction of a nine building multifamily apartment complex, with 216 units on 10.15 acres located in Gillette, Wyoming.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
In August 2007, Zions Bank provided secured construction financing (also guaranteed by USE). The amount due under the construction loan was $16.8 million at December 31, 2008. Total cost to buy the land, pay a developer’s fee, obtain permits and entitlements, site work and construction, was approximately $24.5 million. During the year ended December 31, 2009 the Company retired the construction loan on the property of $16.8 million from cash reserves.
I. OTHER LIABILITIES AND DEBT
As of December 31, 2009 and 2008, the Company had current and long term liabilities associated with the following funding commitments:
In December 2008, the Company and TCM purchased land for $4 million ($2 million in January 2009, $400,000 annually for five years). The Company is responsible for one-half the purchase price. As of December 31, 2009 the Company has paid $1.2 million leaving $800,000 to be paid at the rate of $200,000 per year through 2013.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
At the date of filing of this annual report the Company has a $10,000,000 line of credit from a commercial bank. The line of credit has a variable interest rate (5.5% minimum). The line of credit expires January 31, 2011. As of the date of this report none of the line of credit had been drawn down. The line of credit is collateralized by certain the Company’s multifamily housing project, Remington Village, and the Company’s aircraft.
J. INCOME TAXES
The income tax provision differs from the amounts computed by applying the statutory federal income tax rate to income from continuing operations before taxes. The reasons for these differences are as follows:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
The tax impact of change in asset classification relates to the Company’s investment in shares of Sutter Gold Mining, Inc. that it owned at December 31, 2008. When this asset was previously accounted for as a subsidiary, no deferred tax asset for the excess of tax basis over book basis was recognized. As this investment is now being treated as a marketable security, subject to impairment, a deferred tax asset was established in 2008.
In 2009, the Company performed a basis study to reconcile its book basis in depreciable property to its tax basis in such property. As a result of this study the Company determined that its deferred tax liability related to these basis differences was understated. Accordingly, the Company increased the associated deferred tax liability in 2009. This increase is reflected above in the tax impact of adjustment resulting from basis study.
The components of deferred taxes as of December 31, 2009 and 2008 are as follows:
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. No valuation allowance is provided at December 31, 2009 and December 31, 2008 as the Company believes that it is more likely than not that the deferred tax assets will be utilized in future years.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
During the year ended December 31, 2009, net current deferred tax assets increased by $289,000 and net non-current deferred tax liabilities decreased by $1.6 million. The total change in net deferred tax liabilities was a decrease of $1.9 million. This decrease comprised of a deferred income tax benefit $2.1 million, the reduction of other comprehensive income in the amount of $217,000 resulting from the future tax impact of unrealized gain on marketable securities, and an increase to additional paid in capital of $38,000 resulting from the exercise of certain incentive stock options and warrants.
The book basis in excess of tax basis in the schedule above relates primarily to the $7.3 million difference created from the excess of the purchase price over the carrying value of the assets acquired in the purchase of the remaining minority interest of Crested Corp. in 2007.
At December 31, 2009, the Company has a net operating loss carry-forward for federal income tax purposes of $5.1 million which is available to offset future federal taxable income through 2029. In addition, the Company has alternative minimum tax credit carry-forwards of $810,000 which are available to offset future federal income taxes over an indefinite period.
Current taxes receivable at December 31, 2009 is comprised of $353,000 of federal income taxes. At December 31, 2008, current taxes receivable was $5.9 million.
The Company’s practice is to recognize interest and/or penalties related to income tax matters in income tax expense. The Company had no accrued interest or penalties at December 31, 2009 or December 31, 2008.
Pursuant to ASC 740-10, the Company identified and evaluated any potential uncertain tax positions. The Company has concluded that there are no uncertain tax positions requiring recognition in the financial statements.
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.
K. SEGMENTS AND MAJOR CUSTOMERS
During the years ended December 31, 2009 and December 31, 2008, the Company, for financial reporting purposes, operated in three business segments, the exploration for and sale of oil and gas, rental of multifamily housing units and mining. As of December 31, 2009, no one customer had a majority of the units under contract in the Company’s multifamily housing project in Gillette, Wyoming.
During the year ended December 31, 2007, the Company was involved in one reportable business segment, commercial activities which include operations managed by third parties and the sale of real estate lots at the Company’s commercial real estate property in southern Utah which has been sold. The Company also received management fees for mineral properties which were not consolidated business segments in prior years but are broken out separately in the attached table for comparison. The Company’s operating segments are reflected in the tables below:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued
L. SHAREHOLDERS’ EQUITY
During 2009, the Company issued 5,189,655 shares of common stock. Issued shares consist of (a) 5,000,000 shares issued in a public offering during the fourth quarter; (b) 36,583 shares issued for the 2009 ESOP contribution; (c) 80,000 shares issued to officers of the Company pursuant to the 2001 Stock Compensation Plan; (d) 71,088 shares issued as a result of warrants being exercised and (e) 1,984 shares as a result of the exercise of options by an employee of the Company.
Stock Buyback Plan
During the year ended December 31, 2009, the Company completed its $8.0 million stock buyback plan. The Company purchased 706,071 shares for $1.4 million or an average purchase price of $1.98 per share. During prior years the Company purchased 2,388,129 shares at an average cost of $6.6 million or $2.76 per share. The total number of shares purchased under the stock buyback program was 3,094,200 shares for approximately $8.0 million or an average purchase price of $2.59 per share.
Stock Option Plans
The Board of Directors adopted the U.S. Energy Corp. 1989 Stock Option Plan for the benefit of the Company’s 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 until the 1998 ISOP was replaced by the 2001 ISOP. The last options issued under the 1998 ISOP will expire if not exercised by January 9, 2011 and the 1998 ISOP will be terminated at that date.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
During the years ended December 31, 2009, 2008 and 2007 the following activity occurred under the 1998 ISOP:
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 the Company's employees. The 2001 ISOP (amended by approval of the shareholders in 2004 and 2007) reserves for issuance 25% of the Company’s shares of common stock issued and outstanding at any time. The 2001 ISOP has a term of 10 years. Options issued under the 2001 ISOP remain exercisable until their expiration date under the terms of the 2001 ISOP.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
During the years ended December 31, 2009, 2008 and 2007 the following activity occurred under the 2001 ISOP:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
A summary of the Employee Stock Option Plans activity in all plans for the year ended December 31, 2009, 2008 and 2007 is as follows:
During the year ended December 31, 2009 a total of 1,984 options were exercised by an employee by the payment of $5,000. No options were exercised during the year ended December 31, 2008. The exercise of 1,419,524 options during the year ended December 31, 2007 resulted in the net issuance of 1,109,894 shares. The options were exercised due to the payment of cash for 688,697 shares and cashless exercise of 730,827 options as a result of the cancellation of 309,630 shares.
Option related compensation expense is recognized over the vesting period of the options and is calculated using the Black Scholes option pricing model. The Company initially assumed no forfeitures, but has subsequently reduced the cumulative expense based on historical forfeiture.
No option related compensation expense was recognized for options which vested prior to the adoption of FAS 123R. Prior to the adoption of FAS 123R, the Company accounted for option compensation pursuant to APB Opinion No. 25. The following table sets forth the option compensation related expense for the years ended December 31, 2007 through the vesting period of the employee options outstanding at December 31, 2009:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued
The following table summarizes information about employee stock options outstanding and exercisable at December 31, 2009:
The following table sets forth the number of options available for grant as well as the intrinsic value of the options outstanding and exercisable:
Employee Stock Ownership Plan
The Board of Directors of the Company adopted the U.S. Energy Corp. 1989 Employee Stock Ownership Plan ("ESOP") in 1989, for the benefit of all the Company’s employees. Employees become eligible to participate in the ESOP after one year of service which must consist of at least 1,000 hours worked. After the employee becomes a participant in the plan, he or she must have a minimum of 1,000 hours of service in each plan year to be considered for allocations of funding from the Company. Employees become 20% vested after three years of service and increase their vesting by 20% each year thereafter until such time as they are fully vested after eight years of service.
An employee’s total compensation paid, which is subject to federal income tax, up to an annual limit of $245,000, $230,000 and $225,000 for the years ended December 31, 2009, 2008 and 2007, respectively, is the basis for computing how much of the total annual funding is contributed into his or her personal account. An employee’s compensation divided by the total eligible compensation paid to all plan participants is the percentage that each participant receives on an annual basis. The Company funds 10% of all eligible compensation annually in the form of common stock and may fund up to an additional 15% to the plan in common stock. As of December 31, 2009, all shares of the Company’s stock that have been contributed to the ESOP have been allocated. The estimated fair value of shares that are not vested is approximately $156,900.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued
During the year ended December 31, 2009, the Board of Directors of the Company approved a contribution of 36,583 shares to the ESOP at the price of $5.93 for a total expense of $217,000. This compares to contributions to the ESOP during the year ended December 31, 2008 and 2007 of 126,876 and 84,995 shares to the ESOP at prices of $1.64 and $4.25 per share, respectively. The expense for the contributions during the years ended December 31, 2008 and 2007 were $208,000 and $361,000 respectively.
During prior years, the Company loaned the ESOP $1,014,000 to purchase 125,000 shares from the Company and 38,550 shares on the open market. The Company paid the ESOP 2,350 shares as dividends on the shares the ESOP had purchased. 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 $87,000. During a previous year, the loans were also adjusted by $437,000 to reflect their value at the time. During 2008, the Company accepted, and the ESOP returned, the remaining 155,811 shares that were being held as collateral as full satisfaction of the debt. The shares were cancelled by the Company.
Warrants to Others
As of December 31, 2009, there were 581,367 warrants outstanding to purchase shares of the Company's common stock. Of the total outstanding warrants, 494,701 were exercisable. The Company values these warrants using the Black-Scholes option pricing model and expenses that value over various terms based on the nature of the award. Activity for the periods ended December 31, 2009, 2008 and 2007 for warrants is presented in the following table:
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
The following table summarizes information about non employee warrants outstanding and exercisable at December 31, 2009:
These warrants are held by persons or entities other than employees and officers of the Company.
The Company has computed the fair values of its warrants granted to outside consultants and outside directors using the Black Scholes pricing model and the following weighted average assumptions:
M. COMMITMENTS, CONTINGENCIES AND OTHER
Legal Proceedings
Water Rights Litigation -Mount Emmons Molybdenum Property
1.
Concerning the Application of the United States of America in the Gunnison River, Gunnison County, Case No. 99CW267. This case involves an application filed by the United States of America to appropriate 0.033 cubic feet per second of water for wildlife use and for incidental irrigation of riparian vegetation at the Mount Emmons Iron Bog Spring, located in the vicinity of Mount Emmons. MEMCO filed a Statement of Opposition to protect proposed mining operations against any adverse impacts by the water requirements of the Iron Bog on such operations. This case is pending while the parties attempt to reach a settlement on the proposed decree terms and conditions.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued
2.
Concerning the Application of U.S. Energy, Case No. 2008CW81. On July 25, 2008, the Company filed an Application for Finding of Reasonable Diligence with the Water Court concerning the conditional water rights associated with Mount Emmons. The conditional water decree (“Decree”) requires the Company to file its proposed plan of operations and associated permits (“Plan”) with the Forest Service and BLM within six years of entry of the 2002 Decree, or within six years of the final determination in the Applicant’s pending patent application, whichever occurs later. Although the BLM issued the mineral patents on April 2, 2004, the patents remained subject to a challenge by High Country Citizens’ Alliance, the Town of Crested Butte, and the Board of County Commissioners of Gunnison County (collectively “Protestors”). The Company vigorously defended this legal action through the Federal District Court for the District of Colorado and the Tenth Circuit Court of Appeals. On April 30, 2007, the United States Supreme Court made a final determination upholding BLM’s issuance of the mineral patents. The Company believes that the deadline for filing the Plan specified by the Decree is April 30, 2013 (six years from the final determination of issuance of the mineral patents by the United States Supreme Court). The Forest Service has indicated that the deadline should be April 2, 2010 (six years from the issuance of the mineral patents by BLM). The United States, on behalf of the Forest Service and BLM, filed a Statement of Opposition on this specific issue only. Statements of Opposition were also filed by six other parties including the City of Gunnison, the State of Colorado, and High Country Citizens’ Alliance in September for various reasons, including requesting the Company be put on strict proof as to demonstrating evidence of reasonable diligence in developing the conditional water rights. Although, the Company and TCM will be prepared to file a Plan by the April 2, 2010 proposed deadline, the Company and TCM will pursue a ruling from the Water Court that the deadline specified in the Decree requires the filing of the Plan by the April 30, 2013.
Ordinance Related to the Crested Butte Watershed
On May 19, 2008, the Town Council adopted a revised Watershed Ordinance. The Company and TCM intend to work with the Town of Crested Butte concerning activities at Mount Emmons consistent with lawful and applicable rules, regulations, and statutes. It is possible that unexpected delays, and/or increased costs, may be encountered in developing a new mine plan for Mount Emmons as a result of the revised Watershed Ordinance.
Appeal of Approval of Notice of Intent to Conduct Prospecting for the Mount Emmons Molybdenum Property
On March 8, 2008, High Country Citizens’ Alliance (‘HCCA”) filed a request for hearing before the Colorado Land Reclamation Board (“Board”) of the approval of a Notice of Intent to Conduct Prospecting Notice for the Mount Emmons molybdenum property (“NOI”), which was approved by the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) on January 3, 2008. The NOI as approved provided for continued exploration of the molybdenum deposit to update, improve and verify, in accordance with current industry standards and legal requirements, mineralization data that was collected by Amax in the late 1970’s.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
On March 28, 2008, the Company and the Colorado Attorney General’s Office filed independent Motions to Dismiss alleging among other matters that: (i) HCCA had no standing to appeal the NOI; (ii) the NOI is not an appealable decision under Colorado law; (iii) HCCA’s appeal is not timely; and (iv) the appeal is based on information obtained in violation of Colorado law.
On May 14, 2008, the Board denied HCCA’s Request for Hearing and also denied their Request for a Declaratory Order. Citing Colorado law, the Board determined that HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law.
On August 28, 2008, HCCA appealed the Board’s decision in Denver District Court. Plaintiff: High Country Citizen’s Alliance v. Defendants: Colorado Mined Land Reclamation Board, Colorado Division of Reclamation Mining and Safety and U.S. Energy Corp., Case No.: 08CV6156 (District Court, 2d Jud. Dist., City and County of Denver). The Board has filed an answer with the Court. The DRMS and the Company (in conjunction with TCM) have both filed the responsive pleadings in addition to motions to dismiss the HCCA complaint. No hearing date has been scheduled in the District Court of Colorado concerning DRMS’s issuance of the NOI to the Company for the Mount Emmons molybdenum property.
Water Treatment Facility - Permit Renewal Protest
The Company received a NPDES Permit renewal for Mount Emmons from the Colorado Department of Public Health and Environment - Water Quality Division (“Water Quality Division”) effective September 1, 2008. The NPDES Permit is for a five (5) year period (2008 - 2013). On August 28, 2008, the Town of Crested Butte, Board of County Commissioners for the County of Gunnison and High Country Citizens’ Alliance (“Petitioners”) filed a Request for Adjudicatory Hearing before the Water Quality Division to challenge the NPDES Permit. The Petitioners seek revisions to the Permit that would require the Company to maintain a prepaid operating contract and provide additional financial security for long term operation of the plant.
A hearing before the Administrative Law Judge (“ALJ”) in the Office of Administrative Courts was held on October 2, 2009 in Denver, Colorado. On October 30, 2009 the ALJ issued an order upholding the issuance of the NPDES Permit and rejecting the Petitioners request for financial assurances as a condition of the NPDES permit.
Asset Retirement Obligations
Reclamation liabilities at December 31, 2009 were those related to the Mount Emmons molybdenum property and oil and gas wells drilled in the Gulf Coast area and Williston Basin of North Dakota.
Mount Emmons
The Mount Emmons molybdenum property is located on fee property within the boundary of U.S. Forest Service (“USFS”) land. Although mining of the mineral resource will occur on the fee property, associated ancillary activities will occur on USFS land. The Company and TCM expect to submit a Plan of Operations to the USFS in 2010 for the USFS approval, which approval is required before initial construction and mining and processing may occur. Under the procedures mandated by National Environmental Protection Act (“NEPA”), the USFS will prepare an environmental analysis in the form of an Environmental Assessment and/or and Environmental Impact Statement to evaluate the predicted environmental and social economic impacts of the proposed development and mining of the Mount Emmons molybdenum property. The NEPA process provides for public review and comment of the proposed plan.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued
Obtaining and maintaining the various permits for the mining operations at Mount Emmons will be complex, time-consuming, and expensive. Changes in a mine’s design, production rates, quality of material mined, and many other matters, often require submission of the proposed changes for agency approval prior to implementation. In addition, changes in operating conditions beyond the Company and TCM’s control, or changes in agency policy and Federal and State law, could further affect the successful permitting of the mine operations.
Although the Company is confident that the Plan of Operations for Mount Emmons will ultimately be approved by the USFS, the timing and cost, and ultimate success of the mining operation cannot be predicted. The reclamation liability at December 31, 2009 for Mount Emmons was $128,000.
Oil and Gas Wells
The Company is responsible for its portion of reclamation costs on the oil and gas wells it participates in once the well is no longer economic and needs to be plugged and abandoned. At December 31, 2009, the Company’s liability for its wells was $83,000. The wells are projected to be reclaimed at various times beginning in 2013 and ending in 2043. In the event that the reclamation cost changes the reclamation cost will be adjusted.
401(K) Plan
The Board of Directors of the Company adopted the U.S. Energy Corp. 401(K) Plan ("401(K)") in 2004. The Company matches 50% of an employee’s salary deferrals up to a maximum contribution per employee of $4,000 annually. The Company expensed $48,000, $51,000 and $60,000 for the years ended December 31, 2009, 2008 and 2007, respectively related to these contributions.
Executive Officer Compensation
In December 2001, the Board of Directors adopted (and the shareholders approved) the 2001 Stock Award Plan to compensate its executive officers. The Stock Award Plan was amended on June 22, 2007 by a vote of the shareholders. Under the Plan, 20,000 shares may be issued annually to each officer during his employment. During the years ended December 31, 2009, 2008 and 2007, the Company collectively issued 80,000, 85,000 and 62,500 shares of stock to these officers, respectively. While in the Company’s employ, the officers have agreed not to sell, pledge or otherwise dispose of or encumber the shares granted under the 2001 Stock Award Plan. In consideration of this agreement the Company has agreed to pay all taxes due on the shares granted to the officers.
The Company is committed to pay the surviving spouse or dependent children of the former Chairman and Founder, who passed away on September 4, 2006, one years’ full salary and 50% of that amount annually for an additional four years thereafter. During the years ended December 31, 2009, 2008 and 2007, the Company paid $85,000, $85,000 and $116,000, respectively under this plan. The Company will continue to pay $85,000, or the pro-rata amount on an annual basis, until September 5, 2011. The Board of Directors also approved payment of 50% of the then existing wages to the Company’s former General Counsel for a period of five years. The Company will pay $85,000 annually under this agreement beginning at date of retirement, January 12, 2007, to January 12, 2012. Neither of these two retirement benefits to former officers are funded.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
On October 20, 2005, the Board of Directors of the Company adopted an Executive Retirement Policy for the then Chairman/CEO President/COO, CFO/Treasurer/V.P. Finance and Senior Vice President. Under the terms of the Retirement Plan, the retired executive will receive payments equaling 50% of the greater of (i) the amount of compensation the Executive Officer received as base cash pay on his/her final regular pay check or (ii) the average annual pay rate, less all bonuses, he/she received over the last five years of his/her employment with Company. To be eligible for this benefit, the executive officer must serve in one of the designated executive offices for 15 years, reach the age of 60 and be an employee of the Company on December 31, 2010. Through each executive’s employment contract the Company has also agreed to pay for health insurance for the executive and his spouse from date of retirement, after age 60, until the executive is eligible for medicare. During 2007, the Board of Directors voted unanimously to fund the retirement benefit for the then active officers who qualified under the plan. The funding is held in a separate trust account that is managed by an independent trustee and is subject only to the claims of creditors in the event of insolvency of the Company. At December 31, 2009, the Company had funded the executive retirement account with the amount calculated by a third party actuary, of $619,000. Additional amounts will be deposited annually until each executive’s 60th birthday. At December 31, 2009, there were three officers who were included in the Retirement Plan and four that may qualify for the health insurance benefit.
Compensation expense for executives under all plans for the year ended December 31, 2009, 2008 and 2007 was $192,000, $108,000 and $565,000, respectively. The total accrued liability for executive retirement under all plans at December 31, 2009, 2008 and 2007 was $915,000, $879,000 and $927,000, respectively.
The Company has also established a mandatory retirement age of 70 unless the board specifically requests the services of an employee or officer beyond that age. Certain officers and one employee have agreements for payment of severance in the event of a change of control of the Company.
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 its main office building. The leases are accounted for as operating leases and expire at various periods through September, 2011, and provide for minimum monthly receipts of $7,000 through December 2010.
The total costs of the office buildings and building improvements totaled $4.8 million as of December 31, 2009 and 2008, respectively and accumulated depreciation amounted to $2.6 million and $2.5 million as of December 31, 2009 and 2008, respectively. Rental income under the agreements was $138,000, $102,000 and $136,000 for the years ended December 31, 2009, 2008 and 2007, respectively.
Future minimum receipts for non-cancelable operating leases are as follows:
Years Ending
December 31,
Amount
$134,000
96,000
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
N. DISCONTINUED OPERATIONS
On August 22, 2008, the Company sold its controlling interest in SGMI. As a result of the sale the revenues and expenditures of SGMI for the years ended December 31, 2008 are presented in the December 31, 2008 Statement of Operations as Discontinued Operations. The revenues and expenses associated with SGMI during the years ended December 31, 2007 have also been reclassified to Discontinued Operations in the Statements of Operations presented in this report. The following table represents the gain (loss) from discontinued operations as well as the gain from the sale of the discontinued operations during the year ended December 31, 2008.
(1) The Company’s Statement of Operations contained in this report for the year ended December 31, 2007 is $3,600 less as a result of the recognition of intercompany management fees which were previously eliminated.
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
O. SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
U.S. ENERGY CORP.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008 and 2007
(Continued)
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
Effectiveness of Disclosure Controls and Procedures
We are required to maintain disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that are assigned to ensure that required information is recorded, processed, summarized and reported within the required timeframe, as specified in the rules set forth by the SEC. Our disclosure controls and procedures are also designed to ensure that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2009 and, based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2009.
Management’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, and effected by our Board, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Forward looking statements regarding the effectiveness of internal controls during future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, we believe that, as of December 31, 2009, our internal control over financial reporting was effective based on those criteria.
Our internal control over financial reporting as of December 31, 2009, has been audited by Hein & Associates LLP, the independent registered public accounting firm who also audited our consolidated financial statements. Hein & Associates LLP’s report on our internal control over financial reporting appears on page 125 of this Annual Report.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
U.S. Energy Corp.
We have audited U.S. Energy Corp.’s (the “Company”) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. U.S. Energy Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, U.S. Energy Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of U.S. Energy Corp. and subsidiaries and the related consolidated statement of operations, shareholders’ equity and cash flows for the year ended December 31, 2009 of U.S. Energy Corp. and our report dated March 12, 2010 expressed an unqualified opinion.
/s/ Hein & Associates LLP
HEIN & ASSOCIATES LLP
Denver, Colorado
March 12, 2010
Item 9B
Item 9B - Other Information
None
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, 2009, we will file such information under cover of a Form 10-K/A.
Item 10
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 2010, 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 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 Steven R. Youngbauer, Secretary, 877 North 8th West, Riverton, Wyoming 82501.
Information Concerning Executive Officers Who Are Not Directors
Steven R. Youngbauer is not a director of USE. Mr. Youngbauer (age 60) has been General Counsel and Corporate Secretary for USE since January 23, 2007. He serves at the will of the board of directors. There are no understandings between Mr. Youngbauer and any other person pursuant to which he was named an officer or General Counsel. He has no family relationships with any of the other executive officer or directors of USE. During the past five years, Mr. Youngbauer has not been involved in any Reg. S-K Item 401(f) proceeding.
Item 11
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 2010, under the captions “Executive Compensation and Director's Fees” and “Other Compensation”.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related 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 2010, under the caption "Principal Holders of Voting Securities."
Item 13
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 2010, under the caption “Certain Relationships and Related Transactions.”
Item 14
Item 14 - Principal Accountant Fees and Services
The information required by Item 14 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders to be held in June 2010, under the caption “Principal Accountant Fees and Services”.
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcfe. One billion cubic feet of natural gas equivalent. In reference to natural gas, natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate or natural gas liquids.
Boe. A barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquid.
Completion. The installation of permanent equipment for the production of oil or natural gas. Completion of the well does not necessarily mean the well will be profitable.
Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled.
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 stratigraphic horizon known to be productive.
Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or gas well.
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 gas in another reservoir, or to extend a known reservoir.
Fault. A break in the rocks along which there has been movement of one side relative to the other side.
Fault Block. A body of rocks bounded by one or more faults.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.
Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.
Mcf. One thousand cubic feet of natural gas.
MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest we own.
Net Production. Production that we own less royalties and production due others.
Oil. Crude oil, condensate or other liquid hydrocarbons.
Operator. The individual or company responsible for the exploration, development, and production of an oil or gas well or lease.
Pay. The vertical thickness of an oil and gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.
PV10. The pre-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids, 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 Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Royalty. An interest in an oil and 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.
Standardized Measure. The after-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.
Trend. A geographical area that has been known to contain certain types of combinations of reservoir rock, sealing rock and trap types containing commercial amounts of hydrocarbons.
Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
PART IV
Item 15
Item 15 - Exhibits, Financial Statements, Schedules, Reports, and Forms 8-K
(a) Exhibit No.
Title of Exhibit
2.1
Agreement and Plan of Merger dated as of January 23, 2007, by and between U.S. Energy Corp. and Crested Corp. (incorporated by reference from Exhibit 10.3 to the Company’s Annual Report on Form 10-K filed April 2, 2007)
3.1
Restated Articles of Incorporation (incorporated by reference from Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed September 14, 1990)
3.1(a)
Articles of Amendment to Restated Articles of Incorporation (incorporated by reference from Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed September 14, 1992)
3.1(b)
Articles of Amendment (Second) to Restated Articles of Incorporation (establishing Series A Convertible Preferred Stock) (incorporated by reference from Exhibit 3.1(B) to the Company’s Annual Report on Form 10-K filed September 13, 2000)
3.1(c)
Articles of Amendment (Third) to Restated Articles of Incorporation (increasing number of authorized shares) (incorporated by reference from Exhibit 3.1(C) to the Company’s Registration Statement on Form S-3 (333-75864), filed December 21, 2001)
3.1(d)
Articles of Amendment to Restated Articles of Incorporation (providing that directors may be removed by the shareholders only for cause) (incorporated by reference from Exhibit 10.1 to the Company’s Report on Form 8-K filed June 26, 2006)
3.1(e)
Articles of Amendment to Restated Articles of Incorporation (creating Series P Preferred Stock) (see exhibit 4.11 below)
3.2
Restated Bylaws, as amended through April 17, 2009 (incorporated by reference from Exhibit 3.2 to the Company’s Report on Form 8-K filed April 21, 2009)
4.1
Amendment to 1998 Incentive Stock Option Plan (incorporated by reference from Exhibit 4.1 to the Company’s Annual Report on Form 10-K filed August 29, 2001, and amended on June 18, 2002 and September 25, 2002)
4.2
2001 Incentive Stock Option Plan (amended in 2003) (incorporated by reference from Exhibit 4.2 to the Company’s Annual Report on Form 10-K filed April 15, 2005)
4.3
2008 Stock Option Plan for Independent Directors and Advisory Board Members (incorporated by reference from Exhibit 4.3 to the Company’s Annual Report on Form 10-K filed March 13, 2009)
4.4 - 4.8
Intentionally omitted
4.9
Warrant to Purchase Common Shares, effective October 15, 2005, between R. Jerry Falkner and U.S. Energy Corp. (incorporate by reference from exhibit 4.9 to the Company’s Annual Report on Form 10-KA filed November 4, 2009)
4.10
Class B Warrant to Purchase Common Shares dated March 2, 2004 as amended through July 16, 2007, between Bourne Capital, LLC and U.S. Energy Corp.
4.11
Rights Agreement dated as of September 19, 2001, amended as of September 30, 2005, between U.S. Energy Corp. and Computershare Trust Company, Inc. as Rights Agent. The Articles of Amendment to the Restated Articles of Incorporation creating the Series P Preferred Stock are included as Exhibit C to the Rights Agreement, as well as the form of Right Certificate and Summary of Rights (incorporated by reference from Exhibit 4.1 to the Company’s Registration Statement on Form 8-A12G/A filed November 17, 2005)
4.12 - 4.20
[intentionally left blank]
4.21
USE 2001 Officers’ Stock Compensation Plan (incorporated by reference from Exhibit 4.21 to the Company’s Annual Report on Form 10-K filed September 13, 2002)
10.1
Exploration, Development and Mine Operating Agreement dated August 19, 2008, by and between U.S. Energy Corp. and Thompson Creek Metals Company USA - Redacted(1) (incorporated by reference from Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed November 10, 2008)
10.2
Form of Production Payment Royalty Agreement (Exhibit A to the Asset Purchase Agreement with sxr Uranium One, Inc.) (incorporated by reference from Exhibit 10.2 to the Company’s Report on Form 8-K filed February 23, 2007)
10.3
Agreement to Establish a Rule 10b5-1 Buying Plan (Stock Buyback Plan), dated September 19, 2008 between U.S. Energy Corp. and RBC Capital Markets Corporation (incorporated by reference from Exhibit 8.1 to the Company’s Report on Form 8-K filed September 19, 2008)
10.4
Voting Agreement dated as of January 23, 2007 between U.S. Energy Corp. and Crested Corp. and Certain Shareholders of Crested Corp. (incorporated by reference from Exhibit 10.4 to the Company’s Annual Report on Form 10-K filed April 2, 2007)
10.5
Amendment to Agreements, effective January 31, 2007, between Uranium Power Corp. and U.S. Energy Corp., Crested Corp., and USECC (incorporated by reference from Exhibit 10.5 to the Company’s Annual Report on Form 10-K filed April 2, 2007)
14.0
Code of Ethics (incorporated by reference from Exhibit 14 to the Company’s Annual Report on Form 10-K filed March 30, 2004)
16.0
Concurrence letter of former accountants (incorporated by reference from Exhibit 16(B) to the Company’s Report on Form 8-K/A filed February 1, 2007)
21.1
Subsidiaries of Registrant (incorporated by reference from Exhibit 21.1 to the Company’s Report on From 10-KA filed November 4, 2009)
23.0*
Consent of Ryder Scott Company L.P.
23.1*
Consent of Independent Registered Accounting Firm (Hein & Associates LLP)
23.2*
Consent of Independent Registered Accounting Firm (Moss Adams LLP)
23.3*
Consent of Cawley, Gillespie & Associates, Inc.
(b)
Reports on Form 8-K. In the last quarter of 2009, the Registrant filed nine (9) reports on Form 8-K:
October 16, 2009 - Production from Brad Olson 9-16 well.
October 22, 2009 - Filing of Form S-3 registration statement.
November 3, 2009 - Production from BCD Farms 16-21 well.
November 17, 2009 -Production from Lee 16-21 well.
December 1, 2009 - Production from Strand 16-9 well.
December 1, 2009 - Commencement of underwritten public offering.
December 7, 2009 - Election to participate in additional wells with Brigham Exploration Company.
December 16, 2009 - Underwriting Agreement.
December 16, 2009 - Flow back rate of Williston 25-36 well.
(c)
See paragraph a(3) above for exhibits.
(d)
Financial statement schedules, see above. No other financial statements are required to be filed.
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.