Much Vj Search 2013 Boe

Maria Garcia
• Tuesday, 18 May, 2021
• 40 min read

Show preshow less Loading... Research is the title of a reality television program aired on Canadian music video TV station MuchMusic.


2006 marked the first year that the Research embarked on a reality series format, consisting of ten episodes over a ten-week period. In previous years, the Research took place over a 2-day period, broadcast live on MuchMusic beginning Saturday afternoon and completing on Sunday evening, when a new VJ was crowned.

10th: Norm 09th: Nathalie 08th: Larissa 07th: Rebecca 06th: Frank 05th: Casey-Jo 04th: Erik 03rd: Nikki 02nd: Sean 01st: Tim Each person had to randomly pick either Yellow card or Our Lady Peace to interview, but they were only allowed to ask them one question.

Casey-Jo Loos and Tim Keegan performed the weakest in their interview with the supermodel, and are both taken off the air. It is announced to the viewers at the end of this episode they will be choosing one of the seven people from The Loser Loft that would be given the opportunity to return.

Most people think that the fact he looks good/took off his shirt a couple of times is one of the few reasons of voting Tim back on. Fans then find out that they now have the chance to vote for whom they feel should be the winner: Erik Batik, Nicole MAH, Tim Keegan or Sean Ge hon.

20 VJ hopefuls started in Vancouver and travelled across Canada on the Much Bus with eliminations happening in each stop. Once the bus arrived in Toronto, the Top 10 moved into “Camp Much living in the MuchMusic environment for two weeks.

Much VJ Search April 12, 2013, April 12, 2013, Toronto is the next stop for the remaining VJ hopefuls. Much VJ Search April 11, 2013, April 11, 2013, The competition moves to Ottawa, Ont.

Much VJ Search April 10, 2013, April 10, 2013, The contestants travel to Thunder Bay, Ont., where a big challenge awaits. Much VJ Search April 9, 2013, April 9, 2013, The VJ hopefuls visit Winnipeg.

Much VJ Search April 5, 2013, April 5, 2013, A fourth hopeful is sent home after a trip to Regina, Sask., where the contestants face an elimination challenge involving college students. Much VJ Search April 4, 2013, April 4, 2013, The VJ hopefuls travel to Calgary, where they face challenges and an elimination.

Much VJ Search April 3, 2013, April 3, 2013, The VJ hopefuls face challenges and an elimination in Ban ff, Alta. Much VJ Search April 2, 2013, April 2, 2013, The VJ hopefuls face challenges and an elimination in Vancouver.

Netflix in 2020: A Complete Guide New year, new movies and shows And in this country, especially for the younger crowd, the title of “MuchMusic VJ still carries tremendous cachet.

The Fruits Fruit Sensation: MuchVJSearch officially opens on that date next month at noon. As a press release pointed out on Monday: “No experience is required; the only criteria needed are a passion for music and pop culture, a kick CSS personality, a flair for television, and the gift of gab.

The successful candidate gets to interview the top bands in the music biz, meet hardcore fans, travel across the country, and work out of the iconic Much HQ at 299 Queen St. W. in Toronto.” The following risk factors should be carefully considered in evaluating the information in this Annual Report.

Continuing turmoil in the global financial system may have a material impact on our ability to finance the purchase, exploration and/or exploitation of oil and gas properties. The availability of credit to our industry partners may also affect their ability to generate new exploration and development prospects, to meet their obligations to us, and/or on their liquidity, which could result in operational delays or even their failure to make required payments.

The development of oil and gas properties involves substantial risks that may result in a total loss of investment. The business of exploring for and developing natural gas and oil properties involves a high degree of business and financial risk, and thus a significant risk of loss of initial investment even a combination of experience, knowledge and careful evaluation may not be able to overcome.

Changes in government regulations and issuance of local drilling restrictions or moratoria; As a non-operator, we have limited ability to control the manner in which drilling and other exploration and development activities on our properties are conducted, which may increase these risks.

Declines in the prices we receive for our oil and natural gas production adversely affect many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth and the carrying value of our oil and natural gas properties, all of which depend primarily or in part upon those prices. Declines in the prices we receive for our oil and natural gas also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations.

In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and, as a result, adversely affect our quantities of proved reserves. Lower molybdenum prices would adversely affect the feasibility of developing the Mt.

The Williston Basin oil price differential could have adverse impacts on our revenues. This discount, or differential, may widen in the future, which would reduce the price we would receive for our production.

Such a price downturn also could reduce cash flow from the Williston Basin properties and adversely impact our ability to participate fully in drilling with Brigham, We were able to maintain adequate working capital in 2012 primarily through borrowing under the Credit Facility and cash flow from operations.

Working capital at December 31, 2012, was $12.8 million, an amount sufficient to continue substantial exploration and development work on our oil and gas properties, but not enough to take full advantage of the opportunities we now have or to be in position to pursue new opportunities. In 2013, we have budgeted $27.1 million for work on existing oil and gas programs and acquisitions.

Pursuant to these provisions, if a well is proposed to be drilled or completed but a working interest owner doesn’t participate, the resulting revenues (which otherwise would go to the non-participant) flow to the participants until they receive from 150% to 300% of the capital they provided to cover the non-participant’s share. In order to be in position to avoid non-consent penalties and to make opportunistic investments in new assets, we will continually evaluate various options to obtain additional capital, including borrowings under the Credit Facility and sales of one or more of a portion of our non-producing oil and gas assets, equity securities and Remington Village.

Initial results from one or more of the oil and gas programs could be marginal but warrant investing in more wells. Dry holes, over-budget exploration costs, low commodity prices, or any combination of these or other adverse factors, could result in production revenues below projections, thus adversely impacting cash expected to be available for continued work in a program, its ultimate returns falling below projections, and a reduction in cash available for investment in other programs.

We are paying the annual costs (approximately $2.0 million) to operate and maintain the water treatment plant and stormwater management system at the Mt. For example, our ability to borrow under the Credit Facility may be limited if we are unable, or run a significant risk of becoming unable, to comply with the financial covenants that we are required to satisfy under the agreement.

Borrowing base reductions may occur as a result of unfavorable changes in commodity prices, asset sales, performance issues or other events. In addition to reducing the capital available to finance our operations, a reduction in the borrowing base could cause us to be required to repay amounts outstanding under the Credit Facility in excess of the reduced borrowing base, and the funds necessary to do so may not be available at that time.

Other sources of external debt or equity financing may not be available when needed on acceptable terms or at all, especially during periods in which financial market conditions are unfavorable. We compete with many public and private exploration and development companies in finding investment opportunities.

Our principal competitors are small to mid-size companies with in-house petroleum exploration and drilling expertise. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours.

Operations in the Williston Basin and the Eagle Ford Shale involve utilizing the latest drilling and completion techniques in an effort to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling horizontally through the shale formation, running casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore.

Ultimately, the success of these latest drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficient period of time. The drilling and completion of a horizontal well in the Williston Basin or the Eagle Ford formation currently costs approximately $7.5 million (Eagle Ford) and approximately $11.5 million (Taken/Three Forks) on a gross basis, which is significantly more expensive than a typical onshore shallow conventional well.

Accordingly, unsuccessful exploration or development activity affecting even a few wells could have a significant impact on our results of operations. Due to the limited horizontal production data for wells targeting the Taken and Three Forks formations, drilling and production results are more uncertain than those encountered in other formations and areas with longer histories.

In addition, increases in the number of wells drilled per spacing unit could impact per-well performance. Brigham (and other operators) have reported successful completion of Three Forks wells in other parts of the Williston Basin.

The Three Forks, underlying the Taken, is an unconventional carbonate formation (sand and porous rock) which is prospective for oil and gas. However, the Three Forks has been explored to a lesser extent than the Taken in many areas of the basin, and its characteristics are not as well-defined.

The foregoing considerations also apply to our opportunities to drill the same formations with Savanna and other operators in the Williston Basin. The Eagle Ford Shale, covering 14 counties in South Texas, is now a very active area for exploration and development, involving large companies (such as Shell, ConocoPhillips, and Chesapeake Energy) as well as a host of mid-size to small independents.

However, like the Taken and Three Forks, since the database is still evolving, the Eagle Ford characteristics are not well-defined and thus can present more uncertainty than more mature drilling areas. If our access to oil and gas markets is restricted, it could negatively impact our production and revenues.

Securing access to takeaway capacity may be particularly difficult in less developed areas of the Williston Basin. Market conditions or limited availability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production.

The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, rail transportation and processing facilities owned and operated by third parties.

In particular, access to adequate gathering systems or pipeline or rail takeaway capacity is limited in the Williston Basin. Oil sales generally commence immediately after completion work is finished, but natural gas is flared (burned off) until the well can be hooked up to a transmission line.

Installation of a gathering system can take from 90 to 120 days, or longer, depending on well location, weather conditions, and availability of service providers. As of the date of this Annual Report, all but one of our Williston Basin wells are selling gas.

If continued drilling in the Williston Basin, and other areas such as the Eagle Ford, proves to be successful, the amount of oil and natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines or rail tankers currently available in these areas. If this occurs, it will be necessary for new rail takeaway lines, pipelines and gathering systems to be built.

Certain pipeline or rail projects that are planned for the Williston Basin and other areas may not occur. In such event, we might have to shut in our wells until a pipeline connection or rail capacity is available.

We may not be able to drill wells on a substantial portion of our Williston Basin and Eagle Ford Shale acreage. The extent of our participation will depend on drilling and completion results, commodity prices, the availability and cost of capital relative to ongoing revenues from completed wells, applicable spacing rules and other factors.

Lower oil and natural gas prices may cause us to record ceiling limitation write-downs, which would reduce stockholders’ equity. Under full cost accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lowest of the cost or fair market value of unproved properties.

The risk of a ceiling test write-down increases when oil and gas prices are depressed, if we have substantial downward revisions in estimated proved reserves or if we drill unproductive wells. Excluded from amounts subject to depletion are costs associated with evaluated properties.

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 escalated costs, adjusted for contract provisions, any financial derivatives that hedge our oil and gas revenue and asset retirement obligations, and escalated oil and gas prices during the period, (ii) the cost of properties not being amortized, and (iii) the lowest of cost or market value of unproved properties included in the cost being amortized, less (iv) income tax effects related to tax assets directly attributable to the natural gas and crude oil properties. 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.

We perform a quarterly and annual ceiling test for each of our oil and gas cost centers. The ceiling test incorporates assumptions regarding pricing and discount rates over which we have no influence in the determination of present value.

In arriving at the ceiling test for the year ended December 31, 2012, we used $94.71 per barrel for oil and $2.757 per MBT for natural gas to compute the future cash flows of each of the producing properties at that date. During 2012 capital costs for oil and gas properties exceeded the ceiling test limit, and we recorded a non-cash write down of $5.2 million primarily due to lower prices for oil and natural gas, higher actual and forecast capitalized well costs and higher forecast lease operating expenses.

Capitalized costs for oil and gas properties did not exceed the ceiling test limit in 2011. We may be required to recognize additional pre-tax non-cash impairment charges (write-downs) in future reporting periods depending on the results of oil and gas operations and/or market prices for oil, and to a lesser extent natural gas.

Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of these non-operated assets. As a non-operator, our ability to exercise influence over the operations of the drilling programs is limited.

In the usual case in the oil and gas industry, new work is proposed by the operator and often is approved by most of the non-operating parties. We would avoid a penalty of this kind only if a majority of the working interest owners agree with us and the proposal does not proceed.

The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside our control, including: The fact that we do not operate our prospects with industry partners makes it more difficult for us to predict future production, cash flows and liquidity needs.

Oil and gas reserve reports are prepared by independent consultants to provide estimates of the quantities of hydrocarbons that can be economically recovered from proved properties, utilizing current commodity prices and taking into account expected capital and other expenditures. Estimating quantities of proved oil and natural gas reserves is a complex process.

It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes, availability of capital, estimates of required capital expenditures and work over and remedial costs, and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of the reserves, the economically recoverable quantities of oil and natural gas attributable to the properties, the classifications of reserves based on risk of recovery, and estimates of our future net cash flows.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value.

Also, the use of a 10% discount factor to calculate PV10 and standardized measure values may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. The use of hedging arrangements in oil and gas production could result in financial losses or reduce income.

We use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil and gas production. The fair value of our derivative instruments will be marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments will be recognized in current earnings.

Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for the relevant period.

If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when: The steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies.

In addition, depending on the type of derivative arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil prices. If, as a result of the Dodd-Frank Act or its implementing regulations, capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy.

In particular, a requirement to post cash collateral in connection with our derivative positions, which are currently collateralized on a non-cash basis by our oil and natural gas properties and other assets, would likely make it impracticable to implement our current hedging strategy. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy.

In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, the loss of our lease and prospective drilling opportunities. Unless production is established within the spacing units covering the undeveloped acres on which some of our potential drilling locations are identified, the leases for such acreage will expire.

As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. A substantial portion of our producing properties are located in the Williston Basin, making us vulnerable to risks associated with having operations concentrated in this geographic area.

Because our operations are geographically concentrated in the Williston Basin (87% of our production in the fourth quarter of 2012 was from the Williston Basin), the success and profitability of our operations may be disproportionally exposed to the effect of regional events. These include, among others, fluctuations in the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and other transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure capacity.

In addition, our operations in the Williston Basin may be adversely affected by seasonal weather and lease stipulations designed to protect wildlife, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in the Williston Basin also increases exposure to unexpected events that may occur in this region such as natural disasters or labor difficulties.

Any one of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of these risks could have a material adverse effect on our financial condition and results of operations.

We may incur losses as a result of title deficiencies in oil and gas leases. Typically, operators obtain a preliminary title opinion prior to drilling.

To date, our operators have generally provided preliminary title opinions prior to drilling. If curative title work is recommended to provide marketability of title (and assurance of payment from production), but is not successfully completed, a loss may be incurred from drilling a productive well because the operator (and therefore the Company) would not own the interest.

However, since June 2011, we have established our own insurance policies for our oil and gas operations that are broader in scope and coverage and are in our control. These policies provide coverage for bodily injury and property damage as well as costs to remediate events adversely impacting the environment.

We would be liable for claims in excess of coverage and for any deductible provided for in the relevant policy. If uncovered liabilities are substantial, payment thereof could adversely impact the Company’s cash on hand, resulting in possible curtailment of operations.

A feasibility study would establish the potential economic viability of the molybdenum property based on a reassessment of historical and additional drilling and sampling data, the design of and costs to build and operate a mine and mill, the cost of capital, and other factors. A feasibility study conducted by professional consulting and engineering firms will determine if the deposits contain proved reserves (i.e., amounts of minerals in sufficient grades that can be extracted profitably under current commodity pricing assumptions and estimated development and operating costs).

However, when such a study is obtained, it may not support our internal valuations of the property, and additionally may not be sufficient to attract new partners or investment capital. Oil and gas exploration, development and production activities are subject to certain federal, state and local laws and regulations relating to a variety of issues, including environmental quality and pollution control.

These laws and regulations increase costs and may prevent or delay the commencement or continuance of operations. Specifically, the industry generally is subject to regulations regarding the acquisition of permits before drilling, well construction, the spacing of wells, unitization and pooling of properties, habitat and endangered species protection, reclamation and remediation, restrictions on drilling activities in restricted areas, emissions into the environment, management of drilling wastes, water discharges, chemical disclosures and storage and disposition of hazardous wastes.

The adoption or enforcement of stricter regulations, if enacted, could have a significant impact on our operating costs. Other laws impose reclamation obligations on abandoned mining properties, in addition to or in conjunction with federal statutes.

Changes in applicable laws and regulations could increase our costs, reduce demand for our production and impede our ability to conduct operations or have other adverse effects on our business. Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us.

For example, many of our activities involve the use of hydraulic fracturing, which is a process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water and chemicals into the rock formation.

Legislative and regulatory efforts at the federal level and in some states and localities have been made to impose new or more burdensome permitting, disclosure and safety requirements on hydraulic fracturing operations and in some cases to prohibit hydraulic fracturing altogether in designated areas. These restrictions, to the extent adopted in areas in which we operate, could increase our costs and make it more difficult, or impossible, to pursue some of our development projects.

For example, the Environmental Protection Agency (the “EPA”) amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act, or the SDA, to exclude hydraulic fracturing from the definition of “underground injection.” The 111th United States Congress considered bills entitled the Fracturing Responsibility and Awareness of Chemicals Act, or the FRANC Act, to amend the SDA to repeal this exemption, but Congress adjourned without taking any significant action on the bills. The FRANC Act was re-introduced in the 112th Congress and, if enacted, would amend the definition of “underground injection” in the SDA to encompass hydraulic fracturing activities.

It is not possible to predict whether the current or a future session of Congress may act further on hydraulic fracturing legislation. In addition, in March 2010, at the request of the U.S. Congress, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources.

A final draft report is expected to be released for public comment and peer review in 2014. Currently, hydraulic fracturing is regulated primarily at the state level through permitting and other compliance requirements.

In addition, Montana has enacted regulations requiring operators to disclose information about hydraulic fracturing fluids on a well-by-well basis. Further, operators must generally obtain approval from the state before hydraulic fracturing occurs and submit a report after the work is performed.

Additionally, the Colorado Department of Public Health and Environment is preparing to undertake the renewal of the existing discharge permit, which expires August 31, 2013. Beginning in 2013, we will also be commencing a more comprehensive study of natural and human-induced conditions that may be affecting water quality in Coal Creek.

Additionally, President Obama’s 2013 fiscal year budget includes proposals that would, if enacted into law; make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

In addition, climate change has emerged as an important topic in public policy debate. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases (“Gags”).

Products produced by the oil and natural gas exploration and production industry are a source of certain Gags, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other Gags present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of Gags under existing provisions of the Clean Air Act.

Any laws or regulations that may be adopted to restrict or reduce emissions of Gags would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. For example, as part of state-level efforts to reduce these emissions, operating restrictions on emissions by drilling rigs and completion equipment could be enacted, leading to an increase in drilling and completion costs.

Also, the emergence of trends such as a worldwide increase in hybrid power motor vehicle sales, and/or decreased personal motor vehicle use by individuals in response to regulatory changes and/or perceived negative impacts on the climate from Gags could result in lower world-wide consumption of, and prices for, crude oil. Seasonal weather conditions adversely affect our ability to conduct drilling activities in some areas where we operate.

Oil and natural gas operations in the Williston Basin and the Gulf Coast are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities sometimes cannot be conducted as effectively during the winter months, and this can materially increase our operating and capital costs.

Gulf Coast operations are also subject to the risk of adverse weather events, including hurricanes. Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in new regions, causing periodic shortages. In addition, there is currently a shortage of hydraulic fracturing capacity in many of the areas in which we operate.

Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in our exploration, production and midstream operations. These types of shortages and subsequent price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

It could take several years to obtain the necessary governmental approvals and permits establishing proven and probable mineral reserves and to develop and construct mining and processing facilities. Commons will result in the discovery of economic mineral reserves or the development of the project into a producing mine.

Commons Project, including a potential land exchange transaction, may not be successful. Commons Project is located on fee property within the boundary of U.S. Forest Service (“USES”) land.

The NEPAL process provides for public review and comment of the proposed plan. In addition, we will be required to provide financial assurance that the reclamation plan will be achieved (by bonding and/or insurance) before a mining permit will be issued.

In addition, changes in operating conditions beyond our control, or changes in agency policy and federal and state laws, could further affect the successful permitting of the mine operations and the costs of complying with environmental permits and related requirements. The timing, cost, and ultimate success of our future development efforts and mining operations cannot be predicted.

Our employees have experience in dealing with the acquisition of and financing of mineral properties, but we have a limited technical staff and executive group. The loss of key employees could adversely impact our business, as finding replacements could be difficult as a result of competition for experienced personnel in the oil and gas and minerals industry.

Future equity transactions and exercises of outstanding options or warrants could result in dilution. Issued without registration under the Securities Act of 1933, it was sold at a discount to market prices.

In addition, the perception that such issuance may occur could adversely affect the market price of our common stock. We paid a one-time special cash dividend of $0.10 per share on our common stock in July 2007.

Accordingly, stockholders must look solely to increases in the price of our common stock to realize a gain on their investment, and this may not occur. Although our shareholder rights plan expired in 2011, certain provisions of our governing documents and applicable law could have anti-takeover effects.

For example, we are subject to a number of provisions of the Wyoming Management Stability Act, an anti-takeover statute, and have a classified or “staggered” board. These fluctuations have particularly affected the market prices of securities of oil and gas companies like ours.

Our oil and gas business is currently focused in the Rocky Mountain region (specifically the Williston Basin of North Dakota and Montana), Louisiana, and Texas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt.

As a non-operator, we rely on our operating partners to propose, permit, drill, complete and produce oil and gas wells. Our operating partners also produce, transport, market and account for all oil and gas production.

Commons Project located in west central Colorado, which is a long-term development mining project, (ii) geothermal resources through a minority interest in Standard Steam Trust LLC (“SST”) and (iii) real estate through our ownership of Remington Village, a multi-family housing project serving the residential market in Gillette, Wyoming, which is generating positive cash flow and is accounted for as a property held for sale at December 31, 2012. At December 31, 2012, we have two operating segments: Oil and Gas and Maintenance of Mineral Properties (including molybdenum and geothermal).

Our principal executive office is located at 877 North 8th West, Riverton, Wyoming 82501, telephone 307-856-9271. May also find information related to our corporate governance, board committees and code of ethics on our website.

We are also actively pursuing potential acquisitions of exploration, development and production-stage oil and gas properties or companies. However, PV10 data is not an alternative to the standardized measure of discounted future net cash flows, which is calculated under GAAP and includes the effects of income taxes.

The following table reconciles PV10 to the standardized measure of discounted future net cash flows as of the dates indicated, which are presented in Note F to the consolidated financial statements. The Company holds a geographically and geologically diverse portfolio of oil-weighted prospects in varying stages of exploration and development.

We believe that these arrangements allow us to deliver value to shareholders without having to build the full staff of geologists, engineers and land personnel required to work on diverse projects involving horizontal drilling in North Dakota and South Texas and conventional exploration in Gulf Coast prospects. However, consistent with industry practice with smaller independent oil and gas companies, we also utilize specialized consultants with local expertise as needed.

The Company currently has oil and gas projects with operating partners in the following areas: Under the DPA, we earned working interests, out of Brigham’s interests, in fifteen 1,280-acre spacing units in Brigham’s Rough Rider project area by participating in the drilling of one initial well on each unit of acreage.

In some areas, the rights may be depth limited to the Taken and the upper part of the Three Fork formations under the terms of the leases obtained by Brigham from third parties, while other leases may have rights to all depths. Our earn-in rights were staged in three groups of units and were earned upon paying our share of all drilling and completion costs, or plugging and abandonment costs (if applicable), for all the initial wells (one for each unit) in each group.

For future wells drilled in these units, we will hold 36% of Brigham’s initial working interest (without back in rights), subject to proportionate reduction for third party leasehold rights, which working interest was subsequently reduced by the sale to Brigham on December 15, 2011, as noted below. In accordance with the DPA, we elected to take the remaining 50% of the working interest available to Brigham.

We have earned 36% of Brigham’s initial working interest in all the acreage in the units in the Third Group (which will not be subject to back in rights), proportionately reduced for third party leasehold rights, which working interest was subsequently reduced by the sale to Brigham on December 15, 2011, as noted below. Effective December 15, 2011, the Company sold an undivided 75% of its undeveloped acres in the Rough Rider prospect to Brigham for $13.7 million.

After the sale, our working interest in the undeveloped acreage in the Rough Rider Prospect ranges from 3.41% to 9.90%. At this time, we anticipate that Brigham will drill at least three additional gross wells in the Rough Rider acreage in 2013.

However, our working interest rights in all acreage remaining in the unit would not be affected by the assignment. In December 2010, we signed two agreements with Savanna (a private oil and gas company based in Denver, Colorado), and other parties.

The Company paid $11.0 million in cash to acquire 35% of Savanna’s working interests in oil and gas leases covering approximately 6,050 acres net to Savanna’s interest in McKenzie County, North Dakota which interest was subsequently reduced by the sale to Resources, Inc. and Yuma Exploration and Production Company, Inc. on January 24, 2012, as noted below. Our interests in all the acreage in both prospects is subject to reduction by a 30% diversionary working interest under each prospect upon expiration of the “Project Payout Period” or “Project Payout,” as those terms are defined in the agreements, whichever occurs first.

Project Payout will occur when we have received proceeds from the sale of production (or from the sale of all or part of the acreage to third parties) equal to 130% of: the $11.0 million paid on execution of the agreements, plus all drilling and completion costs (including dry hole costs) and surface gathering facilities for all wells drilled on the acreage (and on any additional acreage acquired in the two Areas of Mutual Interest contemplated by the agreements). On January 24, 2012 (but effective as of December 1, 2011), the Company sold an undivided 75% of its undeveloped acreage in the SE HR Prospect and the Yellowstone Prospect to Resources, Inc. (56.25%) and Yuma Exploration and Production Company, Inc. (18.75%) for a total of $16.7 million.

As of December 31, 2012, we have interests in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEER prospects with Savanna. On September 21, 2012, but effective July 1, 2012, we acquired interests in 27 producing Taken and Three Forks formation wells and related acreage in McKenzie, Williams and Mount rail Counties of North Dakota for $2.3 million after adjusting for related revenue and operating expenses from the effective date through September 21, 2012.

The initial well was drilled by Cirque and reached its total depth of 13,403 feet during the last week of December 2011. The Stevens Sand objective target was encountered and had hydrocarbon shows, but did not have sufficient porosity or permeability to be deemed productive.

In 2011, we entered into two participation agreements with Crimson Exploration Inc. (“Crimson”) to acquire working interests in oil prospects and associated leases located in Naval and Dimwit Counties, Texas (the “Leona River prospect” and “Booth Tortuga prospect”) and working interests in 11 gross wells (2.98 net) producing from the Austin Chalk formation. The prospects include Eagle Ford, Bud and Pearsall shale oil window targets.

Through the date of this report, we have drilled 3 gross (.90 net) Eagle Ford formation horizontal wells. On November 13, 2012, the Company acquired a 60% interest in 889.39 gross acres (444 net) of deep oil and gas rights (which include the Bud formation) located within the Booth Tortuga prospect acreage for $266,000.

As a result of subsequent acquisitions, our current total acreage in the Leona River and the Booth Tortuga prospects is approximately 13,507 gross acres (3,861 net). Based upon assumed 120 acre spacing units, there is a potential for up to 98 gross and 29.6 net Eagle Ford or other formation drilling locations.

Looking forward, the Company continues to seek additional leasing opportunities in the Eagle Ford oil window jointly with Crimson. During the fourth quarter of 2012, average daily production from this well was approximately 5 BOE /d net to the Company (99% oil and 1% natural gas).

The Company has an interest in one natural gas and oil producing well with PetroQuest Energy, L.L.C. During the fourth quarter of 2012, average daily production from this well was approximately 80 BOE /d net to the Company (100% natural gas).

The Company earned a working interest in all the acreage by participating in the initial test well and paying $135,000 in seismic, land acquisition and legal costs. The Company agreed to carry the seller in an 18.75% working interest to the casing point decision (“CPD”) in the initial test well, and a 12.5% carried working interest in the second test well to the CPD.

This acreage is believed to have conventional and horizontal Taken and Three Forks resource potential. Greeley also committed to drill a vertical test well to depths sufficient to core the Taken and Three Forks formations on or before December 31, 2015.

We delivered an 80% NRI to the purchaser and a 1% ORRIS to Energy Investments, Inc., (WII”), a land broker, in connection with the sale. In 2013 and beyond, the Company intends to seek additional opportunities in the oil and natural gas sector, including but not limited to further acquisition of assets, participation with current and new industry partners in their exploration and development projects, acquisition of operating companies, and the purchase and exploration of new acreage positions.

On July 30, 2010, we established a Senior Secured Revolving Credit Facility (the “Credit Facility”) through our wholly-owned subsidiary, Energy One LLC, which allows us to borrow up to a maximum of $100 million (with a current borrowing base of $30.0 million) from a syndicate of banks, financial institutions and other entities, including Wells Fargo Bank, National Association (“Wells Fargo,” and together with other members of the syndicate, the “Lenders”). This arrangement is available only for our oil and gas segment, and provides us with the flexibility of investing and funding drilling/completion work.

From time to time until expiration of the Facility (July 30, 2014), if Energy One is in compliance with the Facility Documents, Energy One may borrow, pay, and re-borrow from the Lenders, up to an amount equal to the borrowing base. Any proposed increase in the borrowing base will require approval by all Lenders, and any proposed borrowing base decrease will require approval by Lenders holding not less than two-thirds of the outstanding loans and loan commitments.

Interest rates on outstanding loans are adjustable each day by Wells Fargo as administrative agent. Energy One is required to comply with customary affirmative and negative covenants under the Credit Agreement.

EBIT DAX is defined in the Credit Agreement as consolidated net income plus non-cash charges. At December 31, 2012, Energy One had $10.0 million in debt outstanding under the Credit Facility.

At December 31, 2012, we owned a minority ownership interest, 19.54%, in SST, a geothermal limited liability company. We do not currently expect to fund any future cash call, and as a result, we may experience further dilution of our ownership of SST.

In 2008, we completed construction of Remington Village, a nine-building, 216-unit multifamily apartment complex in Gillette, Wyoming for a total all-in cost of $24.5 million. Therefore plans to sell this property to continue growing its oil and gas business.

The property is collateralized with a $10 million conventional note with First Interstate Bank of Riverton, Wyoming. In September 2012, we made the decision to sell our corporate aircraft and related facilities, and we plan to use the proceeds to further the development of our oil and gas business, reduction of debt or for general corporate purposes.

Our reserve estimates as of December 31, 2010, 2011 and 2012 are based on reserve reports prepared by Carla, Gillespie & Associates, Inc., or CGA, Ryder Scott Company, L.P., or Ryder Scott, and Netherlands, Sewell & Associates, Inc., or NSA. CGA, Ryder Scott and NSA are nationally recognized independent petroleum engineering firms.

Our primary contact at CGA is Mr. W. Todd Broker, Senior Vice President. Our primary contact at Ryder Scott is Mr. James F. Latham, Senior Vice President.

NSA prepared the estimates for our Austin Chalk and Eagle Ford properties in Texas in 2011 and 2010. Ryder Scott prepared the estimates related to our Gulf Coast Basin, including Louisiana and Texas properties in 2011 and 2010.

The following table details the changes in the quantity of proved undeveloped reserves during the year ended December 31, 2012: Additionally, no proved undeveloped reserves are scheduled for development beyond five years of booking.

The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2012. All of our leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms, unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised.

While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there is no assurance that we can do so. Commons Project is located near Crested Butte, Colorado and includes a total of 160 fee acres, 25 patented and approximately 1,345 unpatented mining and mill site claims, which together approximate 9,853 acres, or over 15 square miles of claims and fee lands.

Commons Project in fee pursuant to mineral patents issued by the federal government. Unpatented mining and mill site claims require the payment of an annual maintenance fee to the Bureau of Land Management; the total amount paid for mining and mill site claim maintenance fees in 2012 was $193,000.

Commons Project to treat water flowing from the historic Keystone mine workings and for potential use in milling operations. By 1983, Max had reportedly spent an estimated $150 million in the acquisition of the property, securing water rights, extensive exploration, orebody delineation, mine planning, metallurgical testing and other activities involving the mineral deposit.

Thereafter, PD acquired additional conditional water rights and patents to certain mineral claims. The property was returned to us by PD in accordance with a 1987 Amended Royalty Deed and Agreement between us and Max.

The exploration work conducted in the late 1970s by Max as discussed in Cyprus Max’s Patent Claim Application to the Bureau of Land Management dated December 23, 1992, defined the initial mineralized material at the Mt. In its 1992 patent application, Cyprus Max stated that the size and grade of the Mt.

Commons deposit was determined to approximate 220 million tons of mineralized material grading 0.366% molybdenum. In a letter dated April 2, 2004, the U.S. Bureau of Land Management (the “BLM”) estimated that there was about 23 million tons of mineralized material containing 0.689% molybdenum, and that about 267 million pounds of molybdenum trioxide was recoverable.

The analysis set forth in the letter was based upon a price of $4.61 per pound for Olympic 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. 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.

On April 21, 2011, Thompson Creek Metals Company USA (“Thompson Creek” or “TCM”) terminated the August 10, 2008, Exploration, Development and Mine Operating Agreement (“the Agreement”) with the Company. On December 6, 2011, TCM notified the Company that it wishes to sell its interest in the property.

Emmons' area spans from the late Cretaceous to the early Tertiary periods. The oldest formation is the Marcos, a 4,000-foot sequence of sales with some interbedding limestone and siltstones.

Emmons' mineralization has been strongly metamorphosed and attempts to correlate internal divisions of the unit have not been made. The overlying Menagerie Formation, also of the late Cretaceous age, consists of a massive repetitive sequence of alternating sandstones, siltstones, sales and minor coals.

Coal seams were not observed in any of the diamond drill holes, or in any of the underground drifts. The Ohio Creek Formation is of early Tertiary (Paleocene) age and remains fairly consistent at 400 feet thick on Mt.

Commons 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.

The Wasatch Formation is composed of alternating sequences of immature sales, siltstones, arkosic Emmons' stock has intruded the Marcos and Menagerie sediments, strongly metamorphosing both formations to hornets up to 1,500 feet outward from the igneous body.

Commons 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. The plant utilizes a standard lime pH adjustment to precipitate heavy metals from the water.

Mine water is then filtered and discharged to Coal Creek in accordance with the requirements of the CDs permit for the plant, and solids are watered and mixed with cement for proper disposal in accordance with state and federal law. Modifications and improvements to the treatment system were tested and implemented in 2012 to enhance compliance with existing and anticipated future discharge requirements.

We also maintain coverage under the CDs General Permit for Stormwater Discharges associated with the Metal Mining Industry. Commons Project subject to the general requirements of the permit itself, which are applicable to all active and inactive metal mining operations in Colorado, and a site-specific stormwater management plan.

In 2013, we will also be commencing a more comprehensive study of natural and human-induced conditions in the region that may be affecting water quality in Coal Creek. Surface access is maintained to the four underground admits and the ancillary pump houses.

Max reportedly spent approximately $150 million in exploration and related activities on the Mt. In addition, our annual operating cost for the water treatment plant is approximately $1.8 million.

The total costs associated with future drilling and the development of the project has not yet been determined. On October 10, 2012, the Company submitted a full mine plan of operations to the U.S. Forest Service to satisfy the requirements of the conditional water rights decree.

During 2013, we will be working with the U.S. Forest Service to achieve a completeness determination of the mine plan of operations. 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. Annual Metal Week Dealer Oxide mean prices averaged $12.81 in 2012, compared to $15.59 in 2011.

We own Remington Village, a nine building multifamily apartment complex, with 216 units on 10.15 acres 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.

The decrease in occupancy rate from 2010 to 2011 was due to the national economic downturn, reduced activities in the oil and gas sector in Wyoming and competition with available single family housing. The Company plans to sell this property in 2013 and redirect the sale proceeds to growing its oil and gas business.

U.S. Energy owns a 14-acre tract in Riverton, Wyoming, with a two-story 30,400 square foot office building. In addition, we own three city lots covering 13.84 acres adjacent to our corporate office building and two unrelated vacant lots covering approximately 10.23 acres in Fremont County, Wyoming.

When the real estate market recovers we intend to sell these properties without development. There can be no assurance that sales of these assets, or of Remington Village, will be completed on the terms, or in the time frame, we expect or at all.

If production is sold to an affiliate of the purchaser, partner, or joint venture, gross value shall be determined by reference to mining industry publications or data. We hold a 4% net profits interest on unpatented mining claims on Rio Tinto’s Jackpot uranium property located on Green Mountain in Wyoming.

Markets for oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. Our competitors principally consist of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators.

Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive. Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment.

These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands. Failure to comply with these requirements can result in civil and/or criminal penalties and liability for non-compliance, clean-up costs and other environmental damages.

It is also possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect. Commons Project beginning in 2013 in an effort to identify sources of heavy metals loading to Coal Creek.

Commons Project, see the consolidated financial statements included in Part II of this Annual Report. With respect to hydraulic fracturing, the EPA amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act, or the SDA, to exclude hydraulic fracturing from the definition of “underground injection.” The 111 TH United States Congress considered bills entitled the Fracturing Responsibility and Awareness of Chemicals Act, or the FRANC Act, to amend the SDA to repeal this exemption, but Congress adjourned without taking any significant action on the bills.

The FRANC Act was re-introduced in the 112 TH Congress and, if enacted, would amend the definition of “underground injection” in the SDA to encompass hydraulic fracturing activities. The FRANC Act’s proposal to require the reporting and public disclosure of chemicals used in the fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

It is not possible to predict whether the current or a future session of Congress may act further on hydraulic fracturing legislation. In addition, in March 2010, at the request of the U.S. Congress, EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts hydraulic fracturing may have on drinking water resources.

A final draft report is expected to be released for public comment and peer review in 2014. Currently, regulation of hydraulic fracturing primarily is conducted at the state level through permitting and other compliance requirements.

For example, Colorado and Wyoming recently have enacted rules to regulate hydraulic fracturing. In April 2011, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to capture 95 percent of the volatile organic compounds (“VOC”) emissions from natural gas wells that are hydraulically fractured.

EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. Climate change has emerged as an important topic in public policy debate regarding our environment.

It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases (“Gags”). Products produced by the oil and natural gas exploration and production industry are a source of certain Gags, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other Gags present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of Gags under existing provisions of the Clean Air Act. Any laws or regulations that may be adopted to restrict or reduce emissions of Gags would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.

Gas and oil operations also are subject to various federal, state and local regulations governing natural gas and oil production and state limits on allowable rates of production by well. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect groundwater resources, 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.

Regulatory changes can adversely impact the permitting and exploration and development of mineral and oil and gas properties including the availability of capital. In addition, oil and gas and mineral projects are subject to extensive permitting requirements.

Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular business, which could result in curtailment of projected future operations. The Company is responsible for all costs to operate the water treatment plant at the Mt.

Additional insurance will be obtained as the level of activity in exploration and development expands. Until the corporate airplane is sold, the Company maintains a $20 million per event liability policy.

We also maintain a $4 million physical damage insurance policy on the aircraft which approximates its replacement value. We maintain $20.4 million of coverage for the real property written on a Special Form/Replacement Cost basis.

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. 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.

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.

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