Edgar Filing: TETON ENERGY CORP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM __________ TO __________

COMMISSION FILE NUMBER 1-31679

TETON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE		84-1482290
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

410 17^th Street – Suite 1850
Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (303) 565-4600

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, par value $0.001		American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act). Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter periods that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act). Large accelerated filer o Accelerated filer o Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

As of December 31, 2005, approximately 11,329,652 shares of common stock were outstanding. The aggregate market value of the common stock held by non-affiliates of the issuer, as of December 31, 2005, was approximately $55,484,102 based on the closing bid of $5.90 for the issuer’s common stock as reported on the American Stock Exchange. Shares of common stock held by each director, each officer named in Item 12, and each person who owns 10% or more of the outstanding common stock have been excluded from this calculation in that such persons may be deemed to be affiliates. The determination of affiliate status is not necessarily conclusive.

As of March 3, 2006 the issuer had 11,666,079 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE - NONE

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

INDEX

		Page

	PART I
Item 1	Business	6
Item 1A	Risk Factors	11
Item 2	Description of Properties	14
Item 3	Legal Proceedings	16
Item 4	Submission of Matters to a Vote of Security Holders	16

	PART II
Item 5	Market for the Registrant’s Common Equity and Related Stockholder Matters	17
Item 6	Selected Financial Data	18
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 7A	Quantitative and Qualitative Disclosures about Market Risks	26
Item 8	Financial Statements and Supplementary Data	27
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	61
Item 9A	Controls and Procedures	61
Item 9B	Other Information	61

	PART III
Item 10	Directors and Executive Officers of the Registrant	62
Item 11	Executive Compensation	65
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	68
Item 13	Certain Relationships and Related Transactions	70
Item 14	Principal Accountant Fees and Services	70

	PART IV
Item 15	Exhibits and Financial Statement Schedules	72

	SIGNATURES

Forward-Looking Statements

We have included in this report, statements which are intended as “forward-looking statements” under the Private Securities Litigation Reform Act of 1995. These include statements that are not simply a statement of historical fact but describe what we “believe,” “anticipate,” or “expect” will occur. We caution you not to place undue reliance on the forward-looking statements made in this report. Although we believe these statements are reasonable, there are many factors, which may affect our expectation of our operations. These factors include, among other things, the following:

·	general economic conditions

·	the market price of, and demand for, oil and natural gas

·	our ability to service future indebtedness

·	our success in completing development and exploration activities

·	expansion and other development trends of the oil and gas industry

·	our present company structure

·	our accumulated deficit

·	acquisitions and other business opportunities that may be presented to and pursued by us

·	our ability to integrate our acquisitions into our company structure

·	changes in laws and regulations

Glossary of Commonly Used Terms, Abbreviations, and Measurements

Within this Report, the following terms and conventions have specific meanings:

Commonly Used Terms and Abbreviations

Barrels of oil equivalent (BOE) - Gas volume that is expressed in terms of its energy equivalent in barrels of oil, which is calculated as 6,000 cubic feet of gas equals 1 barrel of oil equivalent (BOE); or 42 U.S. gallons of oil at 40 degrees Fahrenheit.

basin - A depressed sediment-filled area, roughly circular or elliptical in shape, sometimes very elongated. Regarded as a good area to explore for oil and gas.

basis - When referring to natural gas, the difference between the futures price for a commodity and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location and contract pricing.

Btu - One British thermal unit - a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

cash flow hedge - A derivative instrument that complies with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

collar - A financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk of fluctuation between the minimum (floor) price and the maximum (ceiling) price.

Denver-Julesburg (“DJ”) Basin - A geologic depression encompassing Eastern Colorado and Western Nebraska.

development well - A well drilled into a known producing formation in a previously discovered field.

exploratory well - A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.

farm tap - Natural gas supply service in which the customer is served directly from a well or gathering pipeline.

field - A geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface.

futures contract - An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.

gas - All references to “gas” in this report refer to natural gas.

gross - “Gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which the Company has a working interest.

hedging - The use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.

net - “Net” gas and oil wells or “net” acres are determined by summing the fractional ownership working interests the Company has in gross wells or acres.

Piceance Basin - A 6,000 square mile area in Western Colorado encompassing portions of Garfield and Mesa counties, with portions extending northward into Rio Blanco County and south into Gunnison and Delta counties

productive - Able to economically produce oil and/or gas.

proved reserves - Reserves that, based on geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reserves under existing economic and operating conditions.

proved developed reserves - Proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

proved undeveloped reserves - Proved reserves that are expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.

reserves - The estimated value of oil, gas and/or condensate, which is economically recoverable.

reservoir - A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

transportation - Moving gas through pipelines on a contract basis for others.

throughput - Total volumes of natural gas sold or transported by an entity.

working interest - An interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.

Measurements

Barrel = Equal to 42 U.S. gallons.

Bbl = barrel

Bcf = billion cubic feet

Bcfe = billion cubic feet of natural gas equivalents

Mcf = thousand cubic feet

Mcfe = thousand cubic feet of natural gas equivalents

MMBtu = million British thermal units

MMcf = million cubic feet

MMcfe = million cubic feet of natural gas equivalents

PART I

Item 1. BUSINESS.

Background

Teton Energy Corporation (the “Company”, “Teton”, “we” or “us”) was formed in November 1996 and is incorporated in the State of Delaware. We are an independent energy company engaged primarily in the development, production and marketing of natural gas and oil in North America. Our strategy is to increase shareholder value by profitably growing reserves and production, primarily through acquiring under-valued properties with reasonable risk-reward potential and by participating in or actively conducting drilling operations in order to exploit our properties. We seek high-quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns.

The Company’s current operations are focused in two basins in the Rocky Mountain Region of the United States. From its inception until 2004, the Company was primarily engaged in oil and gas exploration, development, and production in Western Siberia, Russia. In July 2004, the Company’s shareholders voted to sell its Russian operations to the Company’s Russian partner. The gross proceeds received by the Company totaled $15,000,000.

Since July 2004, the Company has actively pursued opportunities primarily in North America in order (1) to redeploy the cash generated in the sale of its Goloil asset and (2) to continue the Company’s growth. During the first six months of 2005, we acquired approximately 182,000 undeveloped acres in the Eastern Denver-Julesburg Basin (the “DJ Basin”) located in Nebraska on the Nebraska-Colorado border. The properties carry a net revenue interest of approximately 81.0%.

In February 2005, the Company acquired 25% of the membership interests in Piceance Gas Resources, LLC, a Colorado limited liability company (“Piceance LLC”). Piceance LLC owns certain oil and gas rights and leasehold assets covering 6,314 acres in the Piceance Basin in Western Colorado. The properties owned by Piceance LLC carry a net revenue interest of 78.75%.

Recent Events

On January 27, 2006, the Company closed an acreage earning agreement (the “Acreage Agreement”) with Noble Energy, Inc. (“Noble”). If the terms of the Acreage Agreement are fulfilled, Noble will earn an undivided 75% working interest in our DJ Basin acreage. Under the terms of the Acreage Agreement, Noble will earn the 75% working interest in the DJ Basin project by (1) the payment of $3 million; and (2) the drilling and completion of 20 wells on or before March 1, 2007, with a minimum of 10 wells to be drilled and completed by December 31, 2006. In the event Noble fails to complete the minimum wells called for by each of these milestones, its right to drill additional oil and gas wells will terminate; however, Noble will retain an interest in the wells drilled, but without the right to drill additional wells on the portion of the drilled lease so assigned.

On February 28, 2006, Orion Energy Partners, L.P., the holder of 50% of the membership interests in Piceance LLC and Piceance LLC’s contract operator sold its interest to Berry Petroleum Company (“Berry”) for an announced price of $159,000,000. Berry also announced February 28, 2006, that it was increasing its 2006 capital budget by $48,000,000 to develop the Piceance LLC acreage during 2006.

Business Strategy

The Company’s objective is to expand its natural gas and oil reserves, production and revenues through a strategy that includes the following key elements:

Pursue Attractive Reserve and Leasehold Acquisitions. To date, acquisitions have been critical in establishing our asset base. We believe that we are well positioned, given our initial success in identifying and quickly closing on attractive opportunities in the Piceance and DJ Basins, to effect opportunistic acquisitions that can provide upside potential, including long-term drilling inventories and undeveloped leasehold positions with attractive return characteristics. Our focus is to acquire assets that provide the opportunity for developmental drilling and/or the drilling of extensional step out wells, which we believe provide us with significant upside potential while not exposing us to the risks associated with drilling new field wildcat wells in frontier basins.

Pursuit of Selective Complementary Acquisitions. We seek to acquire long-lived producing properties with a high degree of operating control, or oil and gas entities that are known to be competent in the area, that offer opportunities profitably to increase our natural gas and crude oil reserves.

Drive Growth Through Drilling. We plan to supplement our long-term reserve and production growth through drilling operations. In 2005, we participated in drilling 10 gross wells on our Piceance Basin acreage, of which we have a 25% interest, and our current plans are to participate in drilling an additional 20 gross wells on Piceance acreage and 10 gross wells on our DJ Basin acreage in 2006.

Maximize Operational Control. To date, we do not own any assets where we are the operator. It is strategically important to our future growth and maturation as an independent exploration and production company to be able to serve as operator of our properties when possible, as that will enable us to exert greater control over costs and timing in and manner of our exploration, development and production activities.

Operate Efficiently, Effectively, and Maximize Economies of Scale Where Practical. Our objective is to generate profitable growth and high returns for our stockholders, and we expect that our unit cost structure will benefit from economies of scale as we grow and from our continuing cost management initiatives. As we manage our growth, we are actively focusing on reducing lease operating expenses, general and administrative costs and finding and development costs. In addition, our acquisition efforts are geared toward pursuing opportunities that fit well within existing operations or in areas where the Company is establishing new operations or where it believes that a base of existing production will produce an adequate foundation for economies of scale necessary to grow a business within a geography or business segment.

Governmental Regulation

The Company’s business and the oil and natural gas industry in general are heavily regulated. The availability of a ready market for natural gas production depends on several factors beyond the Company’s control. These factors include regulation of natural gas production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas, protect rights to produce natural gas between owners in a common reservoir and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state, and local agencies.

The Company believes that it is in substantial compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted so we are unable to predict the future cost or impact of complying with such laws and regulations.

The following discussion of the regulation of the United States natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Company’s operations may be subject.

Regulation of Oil and Natural Gas Exploration and Production

The Company’s oil and natural gas operations are subject to various types of regulation at the federal, state and local levels. Prior to commencing drilling activities for a well, the Company (or its operating subsidiaries, operating entities, or operating partners) must procure permits and/or approvals for the various stages of the drilling process from the applicable federal, state and local agencies in the state in which the area to be drilled is located. Such permits and approvals include those for the drilling of wells, and such regulation includes maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.

The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and natural gas industry increases the Company’s costs of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.

Natural Gas Marketing, Gathering, and Transportation

Federal legislation and regulatory controls have historically affected the price of the natural gas and the manner in which production is transported and marketed. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (“FERC”) regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all natural gas that we produce in the future may now be sold at market prices, subject to the terms of any private contracts that may be in effect.

Natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation, because the prices that companies such as ours receive for our production are affected by the cost of transporting the gas to the consuming market. Through a series of comprehensive rulemakings, beginning with Order No.436 in 1985 and continuing through Order No.636 in 1992 and Order No. 637 in 2000, FERC has adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters, and by increasing the transparency of pricing for pipeline services. FERC has also developed rules governing the relationship of the pipelines with their marketing affiliates, and implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and most pipelines have also implemented the large-scale divestiture of their gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generally provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. Sellers and buyers of gas have gained direct access to the particular pipeline services they need, and are better able to conduct business with a larger number of counterparties.

Environmental Regulations

The Company’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the natural gas industry in general, the business and prospects of the Company could be adversely affected.

The nature of the Company’s business operations results in the generation of wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by the Company’s operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as “hazardous wastes,” and therefore be subject to more rigorous and costly operating and disposal requirements.

Stricter standards in environmental legislation may be imposed on the industry in the future. For instance, legislation has been proposed in Congress from time to time that would reclassify certain exploration and production wastes as “hazardous wastes” and make the reclassified wastes subject to more stringent handling, disposal and clean-up restrictions. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as on the industry in general. Compliance with environmental requirements generally could have a materially adverse effect upon our capital expenditures, earnings or competitive position.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the present or past owners or operators of the disposal site or sites where the release occurred and the companies that transported or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Furthermore, although petroleum, including natural gas and crude oil, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and thus such wastes may become subject to liability and regulation under CERCLA. State initiatives further to regulate the disposal of crude oil and natural gas wastes are also pending in certain states, and these various initiatives could have adverse impacts on our business.

In August 2005, the Energy Policy Act of 2005 was enacted (the “Energy Act”). The Energy Act contains certain provisions that facilitate oil and gas leasing and permitting on federal lands. The Energy Act also provides for certain incentives for oil and gas productions.

The Company’s operations may be subject to the Clean Air Act (the “CAA”) and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.

The Federal Water Pollution Control Act (the “FWPCA” or the “Clean Water Act”) and resulting regulations, which are implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities that are the source of water discharges and compliance could have a materially adverse effect on our capital expenditures, earnings, or competitive position.

Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

Operating Hazards and Insurance

The Company’s exploration and production operations include a variety of operating risks, including the risk of fire, explosions, above-ground and underground blowouts, craterings, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company’s pipeline, gathering and distribution operations are subject to the many hazards inherent in the natural gas industry. These hazards include damage to wells, pipelines and other related equipment, and surrounding properties caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any significant problems related to its facilities could adversely affect the Company’s ability to conduct its operations. In accordance with customary industry practice, the Company maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect the Company’s operations and financial condition. The Company cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all.

Employees

As of December 31, 2005, the Company had 6 employees, and 2 part-time consultants that dedicate over 25% of their time to the Company.

The Company’s employees are not covered by a collective bargaining agreement. The Company considers relations with its employees to be excellent.

Item 1A. RISK FACTORS

Risks Related to our Business

We have incurred significant losses. We expect future losses and we may never become profitable.

We have incurred significant losses in the past. The Company incurred net losses from continuing operations for the years ended December 31, 2005, 2004, and 2003 of $3,777,449, $5,193,281, and $4,036,164, respectively. In addition, we had an accumulated deficit of $24,499,726 at December 31, 2005. We may fail to achieve significant revenues or sustain profitability. There can be no assurance of when, if ever, we will be profitable or be able to maintain profitability.

If we are unable to obtain additional funding our business operations will be harmed.

We believe that our current cash position and estimated 2006 cash from operations will not be sufficient to meet our current estimated operating and general and administrative expenses and capital expenditures through the end of fiscal year 2006. As a result, the Company will require additional funding. In addition, should our operating partners increase their capital expenditures beyond currently anticipated levels, we may be unable to participate in additional wells if we are unable to secure such additional funding. Additionally, we do not know if additional financing will be available when needed, or if it is available, if it will be available on acceptable terms. Insufficient funds may prevent us from implementing our business strategy.

Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile energy prices.

Our business depends on the level of activity in oil and gas exploration, development and production in markets worldwide. Oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic and weather-related factors significantly affect this level of activity. Oil and gas prices are extremely volatile and are affected by numerous factors, including:

•

worldwide demand for oil and gas;

•

the ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain production levels and pricing;

•

the level of production in non-OPEC countries;

•

the policies of the various governments regarding exploration and development of their oil and gas reserves;

•

local weather;

•

fluctuating pipeline takeaway capacity;

•

advances in exploration and development technology;

•

the political environment surrounding the production of oil and gas;

•

level of consumer product demand; and

•

the price and availability of alternative fuels.

Our business involves numerous operating hazards.

Our operations are subject to certain hazards inherent in drilling for oil or natural gas, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings, or fires. The occurrence of these events could result in the suspension of drilling operations, weather, equipment shortages, damage to or destruction of the equipment involved and injury or death to rig personnel. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to damage claims by other oil and gas companies.

Although we and/or our operating partners maintain insurance in the areas in which we operate, pollution and environmental risks generally are not fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses, and we do not have insurance coverage or rights to indemnity for all risks. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position and results of operations.

All of our current producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our current operations are focused on the Rocky Mountain region, which means our producing properties are geographically concentrated in that area. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation of natural gas produced from the wells in these basins.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that are significantly larger and have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater liability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

Generally accepted accounting principles require that we periodically review the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of the prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have material adverse effect on our results of operations in the periods taken.

Governmental laws and regulations may add to our costs or limit our drilling activity.

Our operations are affected from time to time in varying degrees by governmental laws and regulations. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including assessment of natural resource damage.

There are risks associated with forward-looking statements made by us and actual results may differ.

Some of the information in this 10K contains forward-looking statements that involve substantial risks and uncertainties. You can identify these statements by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. You should read statements that contain these words carefully because they:

• discuss our future expectations;

• contain projections of our future results of operations or of our financial condition; and

• state other “forward-looking” information.

We believe it is important to communicate our expectations. However, there may be events in the future that we are not able to accurately predict and/or over which we have no control. The risk factors listed in this section, other risk factors about which we may not be aware, as well as any cautionary language in this prospectus, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. You should be aware that the occurrence of the events described in these risk factors could have an adverse effect on our business, results of operations and financial condition (See Cautionary Note Regarding Forward-Looking Statements on page 4).

Risks Relating To Our Common Stock

Our stock price and trading volume may be volatile, which could result in losses for our stockholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common stock include:

• actual or anticipated quarterly variations in our operating results;

• changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;

• announcements relating to our business or the business of our competitors;

• conditions generally affecting the oil and natural gas industry;

• the success of our operating strategy; and

• the operating and stock price performance of other comparable companies.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

Our Insiders beneficially own a significant portion of our stock.

As of December 31, 2005 our executive officers, directors and affiliated persons beneficially own approximately 18.24% of our common stock. As a result, our executive officers, directors and affiliated persons will have significant influence to:

• elect or defeat the election of our directors;

• amend or prevent amendment of our articles of incorporation or bylaws;

• effect or prevent a merger, sale of assets or other corporate transaction; and

• affect the outcome of any other matter submitted to the stockholders for vote.

In addition, sales of significant amounts of shares held by our directors and executive officers, or the prospect of these sales, could adversely affect the market price of our common stock. Management’s stock ownership may discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which in turn could reduce our stock price or prevent our stockholders from realizing a premium over our stock price.

We do not expect to pay dividends in the foreseeable future. As a result, holders of our common stock must rely on stock appreciation for any return on their investment.

We do not anticipate paying cash dividends on our common stock in the foreseeable future. Certain of our existing credit agreements prohibit the payment of cash dividends without lender consent. Any payment of cash dividends will also depend on our financial condition, results of operations, capital requirements and other factors and will be at the discretion of our board of directors. Accordingly, holders of our common stock will have to rely on capital appreciation, if any, to earn a return on their investment in our common stock. Furthermore, we may in the future become subject to contractual restrictions on, or prohibitions against, the payment of dividends.

Item 2. DESCRIPTION OF PROPERTIES.

We currently operate in two basins in the Rocky Mountain Region of the United States: the Piceance Basin, which is located in northwestern Colorado and the Denver-Julesburg (“DJ”) Basin, which is located in eastern Colorado and western Nebraska.

Eastern DJ Basin

Teton acquired its interest in this moderate risk exploration play in April 2005. The Company’s acreage in this area, consisting of over 182,000 gross leased acres with a working interest of 100% and average net revenue interest of approximately 81%, is located on the eastern flank of the DJ basin in Chase, Dundy, Perkins, and Keith counties in Nebraska. The drilling target of this play is primarily the Niobrara formation, within which is trapped biogenic gas in the Beecher Island chalk of the Upper Cretaceous Niobrara formation. The gas is contained in shallow structural traps at depths ranging from 1,700-2,500 feet. The acreage is located approximately 20 to 30 miles to the east of the main Niobrara gas productive trend that has been established to the west in Yuma, Phillips, and Sedgwick counties, Colorado and in Duell and Garden counties, Nebraska. Based on current service company rates, the Company anticipates that gross drilling and completion costs for a Niobrara well are approximately $150,000 - $200,000.

It was the Company’s intent to acquire this large acreage position and subsequently sell an undivided interest across the acreage to a large, reputable operator with experience in the area in order to (i), reduce the risks associated with a large, moderately-risked exploration play and (ii), leverage the Company’s interests to an operator with the financial and personnel resources to quickly analyze the potential, identify locations and efficiently drill and complete a large number of wells in a timely fashion.

In January 2006, the Company announced the closing of a transaction with Noble, whereby Noble will operate and will earn a 75% working interest in Teton's over 182,000 acres by (i), paying Teton $3 million dollars and (ii), drilling and completing 20 wells at no cost to Teton. The Parties anticipate that the 20 wells will be drilled and completed by the first quarter of 2007. During that time, Teton will receive 25% of any revenues derived from the first 20 wells. After completion of the first 20 wells, Teton and Noble will split all costs associated with future drilling according to each party's working interest percentage.

Piceance Basin

Teton’s properties in the Piceance Basin consists of a 25% working interest (19.69% net revenue interest) in a 6,314-acre block located in Garfield County, Colorado, townships T5S-96W and T6S-96-97W, immediately to the northwest of Grand Valley gas field, the westernmost of the four gas fields that comprise the continuous, basin-centered, tight gas sand accumulation (“the Piceance Fairway”).

These properties are in the vicinity of major gas production from continuous basin-centered, tight gas sand accumulations within the Williams Fork formation of the Upper Cretaceous Mesaverde group and the shallower Lower Tertiary Wasatch formation. The primary targets for drilling on this large acreage position are the 1,200’-1,500’ thick, gas-saturated sands of the middle and lower Williams Fork formation at approximately 8,300’-9,700’ in depth.

In addition, the subject acreage is surrounded on the west, east, and southeast by completed gas wells. To the northwest of the block is the Trail Ridge gas field (Wasatch and Mesaverde). To the west, south, and east are gas wells of the greater Grand Valley field.

The Company estimates, based on current service company costs, that drilling and completion costs for a Williams Fork well will be, on average, approximately $1,700,000. Based on currently approved field spacing rules, the Company estimates that the venture partners can drill as many as 628 wells on the 6,300 acre block with an estimated average 1.3 BCF ultimate recovery per well. Our natural gas production in this area is gathered by our own gathering system and delivered to markets through the Williams Pipeline.

The chart below sets forth certain production data for the fiscal year ending December 31, 2005, for the period ending June 30, 2004, prior to such sale, and for the fiscal year ending December 31, 2003. Additional oil and gas disclosure can be found in Note 12 of the Financial Statements. Production data with respect to 2004 and 2003 represents results of discontinued operations from the Company’s former operations in the western Siberian region of the Russian Federation. Teton sold its interest in these assets effective as of July 1, 2004.

PRODUCTION DATA

	2005		2004		2003

Total gross oil production, barrels		-		1,393,616		2,528,260

Total gross gas production, MCF		457,331		-		-

Net oil production, barrel (1)		-		348,404		632,065

Net gas production, MCF (1)		90,037		-		-

Average oil sales price, $/Bbl (2)		-	$	18.98	$	18.11

Average gas sales price, $/MCF	$	7.86		-		-

Average production cost per barrel (3)		-	$	16.12	$	16.11

Average production cost per MCF including production taxes	$	1.10		-		-

Gross productive wells
Oil		-		24.0		21.0
Gas		3.0		-		-

Total		3.0		24.0		21.0

Net productive wells
Oil		-		12.0		10.5
Gas		.75		-		-

Total		.75		12.0		10.5

(1)	Net production and net well count is based on Teton's effective net interest as of the end of each year.

(2)	Average oil sales price is a combination of domestic (Russian) and export price.

(3)	Excludes production payment to Limited Liability Company Energosoyuz-A.

The following chart sets forth the number of productive wells and dry exploratory and productive wells drilled and completed during the last three fiscal years. For the year ended December 31, 2004 and 2003, the wells are in the Goloil license area prior to the sale of Teton’s interest in Goloil:

NET WELLS DRILLED

Year Ended December 31,	2005				2004				2003
	Gross		Net (1)		Gross		Net (1)		Gross		Net (1)
Number of Wells Drilled
Exploratory
Productive		3.0		.75		-		-		-		-
In progress		7.0		1.75		-		-		-		-
Dry		-		-		-		-		-		-
Total		10.0		2.50		-		-		-		-

Development
Productive		-		-		3.0		1.5		7.0		3.5
In progress		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Total		-		-		3.0		1.5		7.0		3.5


Total
Productive		3.0		.75		3.0		1.5		7.0		3.5
In progress		7.0		1.75
Dry		-		-		-		-		-		-
Total		10.0		2.50		3.0		1.5		7.0		3.5

(1)	Net well count is based on Teton's effective net interest as of the end of each year.

Developed and Undeveloped Acreage

The following table sets forth the total gross and net developed acres and total gross and net undeveloped acres of the Company as of December 31, 2005:

	Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net

Piceance Basin, Colorado		30		6		6,284		1,571
Eastern DJ Basin, Nebraska		0		0		195,251		183,864
Total		30		6		201,535		185,435

Our offices are located in Denver, Colorado. We lease our offices from an unaffiliated third party. The term of such lease is three years, and the lease expires in July 2008.

Item 3. LEGAL PROCEEDINGS.

We are not a party to any legal proceedings.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

No matters were submitted to a vote of our security holders during the fourth quarter of 2005.

PART II

Item 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDERS MATTERS.

Teton's common stock is listed and principally traded on the American Stock Exchange, under the symbol “TEC.” Our common stock is also listed for trading on the Frankfurt Stock Exchange (Germany) under the symbol “TP9.”

The following table sets forth, on a per share basis, the high and low closing price on the American Stock Exchange:

	High		Low
2005 period
First quarter	$	3.81	$	1.32
Second quarter	$	4.53	$	2.06
Third quarter	$	8.00	$	4.45
Fourth quarter	$	7.20	$	4.90

2004 period
First quarter	$	5.24	$	3.36
Second quarter	$	4.00	$	1.80
Third quarter	$	2.55	$	1.25
Fourth quarter	$	1.85	$	1.20

Holders: As of December 31, 2005, there were approximately 154 holders of record of our common stock.

Dividends: Teton has not paid any dividends on its common stock since inception. Teton does not anticipate declaration or payment of any dividends at any time in the foreseeable future.

Recent Issuances of Unregistered Securities

During the fourth quarter, there were no issuances of unregistered securities.

Equity Compensation Plan Information

The following table sets forth information about our equity compensation plans at December 31, 2005:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights				Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance

Equity compensation plans approved by security holders:
2005 Long-term Incentive Plan⁽¹⁾		800,000	^⁽³⁾		(4)	(1)
2004 Non-Employee Stock Compensation Plan⁽²⁾		287,500			(4)
2003 Employee Stock Compensation Plan⁽²⁾		2,875,334		$	3.54	--

(1)

The Company’s Long-Term Incentive Plan provides for the issuance of a maximum number of shares of common stock equal to 20% of the total number of shares of Common Stock outstanding as of the effective date for the plan’s first year and for each subsequent plan year, (i) that number of shares equal to 10% of the total number of shares of Common Stock outstanding as of the first day of each respective plan year, plus (ii) that number of shares of Common Stock reserved and available for issuance but unissued during any prior plan year during the Term of the Plan; provided, however, in no event shall the number of shares of Common Stock available for issuance under the Plan as of the beginning of any Plan Year plus the number of shares of Common Stock reserved for outstanding awards under the Plan exceed 35% percent of the total number of shares of Common Stock outstanding at that time, based on a three-year period of grants.

(2)	The 2004 Non-Employee Stock Compensation Plan and the 2003 Employee Stock Compensation Plan were terminated upon the adoption of the 2005 Long-term Incentive Plan.

(3)

Includes 800,000 performance share units awarded in July 2005. A performance share unit is equal in value to one share of the Company’s common stock and subject to vesting on the basis of the achievement of specified performance targets as specified in the applicable administration document or award agreement. Upon vesting, performance share Units will be settled by delivery of shares to the Participant equal to the number of vested performance share units. In January 2006, the Compensation Committee determined that the 2005 performance targets had not been met. As a result, 160,000 performance share units from the original grant of 800,000 will not vest under the 2005 Grant.

(4)	Not applicable.

See Note 7 to the financial statements for discussion of options issued in 2005.

Item 6. SELECTED FINANCIAL DATA.

The following table sets forth selected financial data, derived from the financial statements, regarding Teton’s financial position and results of operations as of the dates indicated. This selected financial data should be read in conjunction with our financial statements and notes to the financial statements.

	As of and for the Year Ended December 31,
	2005			2004			2003			2002			2001
Summary of Operations
Loss from continuing operations	$	(3,777,449	)	$	(5,193,281	)	$	(4,036,164	)	$	(10,191,307	)	$	(1,373,470	)
Discontinued operations, net of tax		(255,000	)		12,383,582			(1,598,680	)		(782,616	)		(284,138	)
Net income (loss)		(4,032,449	)		7,190,301			(5,634,844	)		(10,973,923	)		(1,657,608	)
Income (loss) per share for:
Continuing operations	$	(.38	)	$	(.64	)	$	(1.00	)	$	(3.28	)	$	(.05	)
Discontinued operations		(.02	)		1.37			(.23	)		(.25	)		(.01	)
Net income		(.40	)		.73			(1.23	)		(3.53	)		(.06	)

Balance Sheet
Total assets		22,131,495			17,611,565			20,718,375			10,012,395			2,211,312
Notes payable		--			--			--			--			844,210
Cash dividends per common share		--			--			--			--			--

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion and analysis of our plan of operation should be read in conjunction with the financial statements and the related notes. This management’s discussion and analysis of financial condition and results of operations is intended to provide investors with an understanding of our past performance, financial condition, and prospects. The following will be discussed and analyzed:

·	Overview of Business

·	Industry and Operating Trends

·	Components of Our Operating Results

·	Results of Operations & Comparison of Results Between Years

·	Outlook for 2006

·	Liquidity and Capital Resources

·	Subsequent Events

·	Critical Accounting Policies and Estimates

·	Recent Accounting Pronouncements

Overview

We are an independent oil and gas exploration and production company with operations in the Rocky Mountain region of the U.S. We generate revenues by the production of oil and gas from properties which we own independently or with other parties. Currently we have interests in two different plays: We own a 25% interest in a drilling program in the Piceance Basin in western Colorado on 6,314 gross acres (1,579 net to the Company) and a separate acreage play of over 182,000 acres in the eastern DJ Basin in Nebraska. Prior to July 1, 2004 our primary focus was oil and gas exploration, development and production in the Russian Federation and former Commonwealth of Independent States (“CIS”)(see Note 3 to the financial statements). Since January 2005, our focus has been on acquiring and developing assets in North America, with a particular emphasis on the Rocky Mountain Region in the United States. At December 31, 2005, our Piceance program had three wells on production. There was no production at December 31, 2005, in respect of the acreage in the DJ Basin.

Financial highlights for the year ended December 31, 2005 include the following:

·	The Company sold 90,037 mcf of natural gas from its Piceance Basin properties at an average wellhead price of $8.90. Actual price realization after fuel, gathering, marketing, and transportation averaged $7.86 per mcf, resulting in revenues net to the Company of $707,420.

·	The Company’s net loss from continuing operations decreased to $3,777,449 in 2005 ($.38 per share) from $5,193,281 in 2004 ($.64 per share).

The following summarizes the Company’s operational highlights during 2005:

·	On February 15, 2005 the Company acquired a 25% interest in Piceance LLC which owns 6,314 acres in the Piceance Basin for a total purchase price, including the fair value of stock and warrants issued of approximately $6.4 million.

·	During the second quarter of 2005 the Company acquired an interest in over 182,000 acres in the Eastern DJ Basin for a total investment, including the fair value of stock and warrants issued of approximately $4.2 million.

·	Piceance LLC drilled and completed three wells in 2005 and drilled to total depth an additional seven wells, which seven wells are planned to be on production in the first half of 2006.

Effective December 31, 2005 the Company entered into an acreage earning agreement, which allows Noble Energy, Inc. to earn a 75% interest in our eastern DJ Basin acreage for $3.0 million and a carry on 20 wells to be drilled and completed by March 1, 2007. The Company entered into a definitive agreement in December 2005 and closed on January 27, 2006.

·	Further evaluation and restructuring of its cost structure resulting in the elimination of its Moscow office and the consolidation of the functions of its Steamboat Springs, Colorado offices into its corporate headquarters in Denver, Colorado.

During 2005, the Company concentrated on developing opportunities in the Rocky Mountain region of the United States. It concentrated on close-in exploration and/or extension development projects involving resource plays in basins deemed to be prolific. To that end, during 2005 the Company participated in the drilling and completion of wells in the Piceance Basin and further participated in the drilling of an additional seven wells to total depth. The Company began its exploration program on over 182,000 acres in the eastern DJ Basin and entered into an acreage earning agreement with Noble.

Results of Operations 2005 Compared to 2004

The Company had a net loss from continuing operations for 2005 of $3,777,449 compared to a net loss of $5,193,281 for the same period in 2004. Factors contributing to the smaller net loss for the year included the following:

Oil and gas production net to the Company’s interest in 2005 was 90,037 mcf resulting in $707,420 in oil and gas sales, at an average wellhead price of $8.90 per mcf for the year. The Company’s price net of fuel, gathering, transportation and marketing fees totaling $89,209 or $7.86 per mcf. The Company’s net production began in July 2005. Oil and gas production net to the Company in 2004 was 384,404 bbls. Revenues between 2005 and 2004 are not comparable, as effective July 1, 2004 the Company sold its Russian oil production.

Lease operating expenses for the year were $50,932 and production taxes were $48,196 (or 7% of revenues) net to the Company resulting in operating income from oil and gas activities from Piceance LLC of $608,292 before depreciation and depletion, exploration costs, general and administrative expenses and other income. Lease operating expenses include $30,909 incurred directly by Teton for consultants working directly on the Piceance Basin properties.

During 2005, general and administrative expense decreased from $5,332,991 during 2004 to $4,006,747 for 2005. General and administrative expenses include the non-cash expense of $795,375 recorded in conjunction with the issuance of common stock to certain individuals affiliated with the Company. Factors contributing to the decrease in administrative expense in 2005 included reduced due diligence costs associated with the pursuit of acquisitions (including acquisitions that failed to close), elimination of the Company’s Moscow, Steamboat Springs, and Houston offices, reduction in investor relations-related expenses, and reduction of corporate personnel associated with its overseas operations.

Significant changes in general and administrative expenses, exclusive of the $795,375 non-cash charge relating to the issuance of stock for the year ended December 31, 2005 compared to 2004 include:

·	Advertising and public relations and related consulting expenses decreased $457,820 in 2005 primarily due to the fact that the Company eliminated several consulting contracts in the second quarter of 2004 and expensed the costs to terminate such contracts during such quarter.

·	The Company expensed $415,494 in due diligence costs in 2004 compared to $28,886 in 2005 related to acquisitions that were not completed.

The Company’s public company compliance expense and related legal and accounting expenses decreased $251,476 in 2005. Significant costs were incurred in 2004 related to the sale of Goloil, legal and accounting expense incurred on acquisitions that did not close and costs to prepare the proxy to solicit votes for the sale of Goloil. Components of Company’s compliance and legal costs incurred in 2005 include costs incurred in respect to the establishment of the shareholders rights plan, the Long Term Incentive Plan, the preparation of three registration statements, and legal costs associated with the departure of a former Officer and Director of the Company.

·	Franchise taxes, included in general and administrative expenses decreased $64,483 in 2005.

·	Travel and entertainment expenses decreased $217,581 in 2005 relative to 2004 as the Company no longer incurs the significant costs of traveling to Russia.

Compensation paid to employees decreased $572,911 in 2005 relative to 2004 because the Company has reduced its number of employees from 11 to 6, partially offset by an increase in severance paid to employees of $222,000 primarily related to the severance costs recorded for a former Officer and Director of the Company.

Exploration expenses for 2005 relate to delay rentals and geological and geophysical expenses incurred by the Company primarily on the eastern DJ Basin leases that were acquired in April.

Results of Operations 2004 Compared to 2003

The Company had a net loss from continuing operations for the year ending December 31, 2004 of $5,193,281 compared to a loss of $4,036,164 for the prior year, an increase of $1,157,117. The increase from 2003 to 2004 was primarily due to the increase in general and administrative expenses from $3,920,791 for the year ending December 31, 2003 to $5,332,291 for the year ending December 31, 2004. This was due to several reasons including:

·	The Company unsuccessfully pursued several acquisitions which resulted in the expensing of the various due diligence costs incurred on such acquisitions of $409,000.

·	The Company increased its payroll during the early part of 2004 as it increased its staffing levels to begin its investment and acquisition program, incurring expense of $358,000.

·	Based on a performance review of management for 2003, the Board paid out bonuses to senior management in the first quarter of 2004 of $300,000.

·	The Company began compensating outside Directors in cash and stock payments of $140,000.

·	The Company incurred significant legal, investor relations, accounting and other expenses in selling its interest in Goloil and in preparation of the related proxy statement in order to obtain shareholder approval of such sale of $188,000.

·	The Company incurred severance and other one-time costs associated with the reduction of staff, offices and other commitments of $218,000.

·	The Company incurred additional costs of $70,000 associated with the maintenance and ultimate closing of its Moscow office in 2004.¹

Discontinued Operations 2004 Compared to 2003

See Note 3 to financial statements for a summary of the income (loss) from discontinued operations. The Company considered the sale of Goloil to be effective July 1, 2004. Accordingly, the operating activities of Goloil for the six months ended June 30, 2004 were included in the Company’s 2004 statement of operations as a net loss from discontinued operations. Goloil’s operating revenues and expenses for six months of 2004 were less than 2003 because Teton had recorded a full year of operations for 2003. Goloil sold its production in 2004 at an average price of $18.98 per barrel compared to the $18.11 price for oil sold in 2003. However, 2004 production was sold exclusively to the domestic and near abroad markets and not the export market which during 2004 yielded prices substantially above the price received in the domestic and near abroad markets. Prior to September 30, 2003, Goloil had sold its oil for a blended oil price which included sales to the export market.

The $13,086,761 gain included the $8,960,000 proceeds from the sale of Goloil stock, net of $997,000 in expenses plus the elimination of approximately $5.1 million in net liabilities reflecting the Company’s pro-rata share of Goloil as of June 30, 2004

The Company’s net loss from continuing operations decreased from $10,191,307 in 2002 to a net loss of $4,036,164 in 2003. This was primarily due to the fact that general and administrative expenses decreased from $4,744,952 in 2002 to $3,920,791 in 2003, primarily due to a decrease of $1,562,575 in fees paid to consultants for capital raising activities offset by increases in compensation to officers and employees ($323,951) professional fees ($109,146) travel and entertainment ($193,773), and expenses related to marketing, advertising, and investor relations ($167,987).

Financing charges recorded decreased from $5,498,106 in 2002 to $132,818 in 2003. In 2002, the Company recorded a $4,715,000 non-cash financing charge as a result of warrants issued with debentures and in-the-money conversion features present at issuance.

¹ The Company opened a representative office in Moscow in December 2003 to manage its Russian operations, as well as to establish a higher profile in the Russian oil industry and facilitate greater deal flow as it pursued acquisition opportunities in Russia and in other FSU states. The Moscow office was closed in December 2004 as a result of the Company’s decision to exit Russia and the Company incurred closing costs which were included in continuing operations at December 31, 2004.

Outlook for 2006

The following summarizes the goals and objectives for the Company for 2006:

· Continue to sustain the Piceance Basin drilling program.

· Negotiate and finalize a senior debt facility.

· Execute the eastern DJ exploration and drilling program with Noble.

· Build up the operating capabilities of the Company.

· Pursue additional asset and project opportunities.

Liquidity and Capital Resources

The Company had a cash balance of $7,064,295 at December 31, 2005 and a working capital surplus of $4,987,397.

The Company currently estimates the cost of its development and exploration programs to be $12 million for the year ending December 31, 2006. Our capital budget could be substantially increased if Berry, as operator for the Piceance play, increases the drilling program. The Company is undertaking to put in place a senior debt facility during 2006. The Company expects that its current cash balances, combined with operating cash flow, amounts available from a senior debt facility (assuming such facility is in fact established), proceeds from the exercise of warrants and the proceeds from the acreage earning agreement of the eastern DJ Basin will provide it with adequate resources to meet its capital needs for 2006.

The Company may require additional financing during 2006 if the Company identifies other acquisitions that meet its investment criteria. Such additional financing may be debt or equity or a combination of both. See Sources and Uses of Funds below.

Sources and Uses of Funds

Historically, Teton’s primary source of liquidity has been cash provided by equity offerings. Equity offerings are expected to continue to play an important role in financing Teton’s business for the foreseeable future. In addition, the Company is working to establish a borrowing facility with one or more commercial banks, most likely in the form of a revolving line of credit that will be used primarily for the acquisition of producing properties and for developmental drilling and other capital expenditures. We also expect that revenue will play an increasing role in 2006 in its sources of funds owing to increased production from its current and anticipated future wells.

Cash Flows and Capital Expenditures

During the year ended December 31, 2005 the Company expended $2,496,087 in its operating activities primarily to finance its efforts in respect of potential acquisitions and in respect of personnel costs. This amount compares to $4,420,775 used in operating activities in 2004.

During 2005, the Company used $11,302,692 in its investing activities related to the completion of its acquisition of the membership interest in Piceance, LLC, the commencement of drilling and completion operations in the Piceance and on acquiring the DJ Basin acreage.

During 2005, 743,868 warrants were exercised, purchasing common shares of the Company for net proceeds to the Company of $3,497,501.

Commitments

The Company has entered into a three year lease for office space which expires in July 2008. Future contractual commitments under such lease are $56,967 for 2006, $56,967 for 2007 and $33,231 for 2008.

Income Taxes, Net Operating Losses and Tax Credits

At December 31, 2005 the Company has a net operating loss carry forward for U.S. income tax purposes of $24,000,000. Approximately $19 million of such net operating loss is subject to U.S. Internal Revenue Code Section 382 limitations. Utilization of this portion of the NOL is limited to approximately $900,000 per annum.

Subsequent Events

Subsequent to December 31, 2005 the members of Piceance LLC applied to the fee owner of the land on which Piceance LLC’s oil and gas rights and leases are located to transfer the interests directly to each of the members. Such transfer occurred on February 28, 2006.

Subsequent to December 31, 2005 the Company closed on an Acreage Earning Agreement with Noble Energy, Inc. and received $2.7 million in cash.

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations were based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Significant accounting policies are described in Note 2 to the financial statements. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” the Company has identified certain of these policies as being of particular importance to the portrayal of the financial position and results of operations and which require the application of significant judgment by management. The Company analyzes our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, marketable securities, income taxes, derivatives and contingencies, and bases those estimates on historical experience and various other assumptions that management believes are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect the more significant judgments and estimates used in the preparation of the financial statements.

Successful Efforts Method of Accounting

The Company accounts for natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine that proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Impairment of Gas and Oil Properties

The Company reviews oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates the expected future cash flows of the developed proved properties and compares such future cash flows to the carrying amount of the proved properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, an adjustment will be made to the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require the Company to record an impairment of the recorded book values associated with gas and oil properties. We did not record an impairment during the years ended December 31, 2005, 2004 or 2003.

Stock Based Compensation

The Company adopted a Long-Term Incentive plan in 2005 under which the Company will issue performance share units convertible into common shares of the Company subject to vesting on the basis of the achievement of specified performance targets. Quarterly, the Company will compare actual results to the performance targets (which are on an annual basis) and accrue its best estimate of the fair value of shares to be issued, at the end of the plan year, as compensation expense.

Recently Issued Accounting Standards and Pronouncements

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“Statement 154”). SFAS 154 requires retrospective application to prior periods’ financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The implementation of SFAS 154 is not expected to have a material impact on our condensed consolidated results of operations, financial position or cash flows.

In December 2004, the FASB issued SFAS No. 153 “Exchanges of Non-monetary Assets—an amendment of APB Opinion No. 29.” This Statement amended APB Opinion No. 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. A non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Company believes the impact of this new standard will not have a material impact upon the Company’s financial position, results of operations or cash flows. SFAS 153 is effective for all reporting periods beginning after June 15, 2005.

In December 2004, the Financial Accounting Standards Board ("FASB") issued SFAS No. 123 (revised 2004), "Share-Based Payment." SFAS No. 123R replaced SFAS No. 123 and superseded APB 25. SFAS No. 123R will require compensation cost related to share-based payment transactions to be recognized in financial statements. As permitted by SFAS No. 123, the Company elected to follow the guidance of APB 25, which allowed companies to use the intrinsic value method of accounting to value their share-based payment transactions with employees. Based on this method, the Company did not recognize compensation expense in its financial statements as the stock options granted had an exercise price equal to the fair market value of the underlying Common Stock on the date of the grant. SFAS No. 123R requires measurement of the cost of share-based payment transactions to employees at the fair value of the award on the grant date and recognition of expense over the requisite service or vesting period. SFAS No. 123R requires implementation using a modified version of prospective application, under which compensation expense for the unvested portion of previously granted awards and all new awards will be recognized on or after the date of adoption. SFAS No. 123R also allows companies to adopt SFAS No. 123R by restating previously issued financial statements, basing the amounts on the expense previously calculated and reported in their pro forma footnote disclosures required under SFAS No. 123. The provisions of SFAS No. 123R will be adopted by the Company effective January 1, 2006, using the modified prospective application method. The effect of the adoption of SFAS No. 123R is expected to be significant to future financial statements as a result of applying the current fair value recognition provisions of SFAS No. 123. The amount of unvested stock compensation as of December 31, 2005 is $98,625, which will be recorded in future periods as earned.

In February 2005, the staff of the Securities and Exchange Commission sent a letter to oil and gas registrants regarding situations that require additional financial statement disclosures, pending final resolution of accounting treatment. The following are items related to registrants using the successful efforts method of accounting:

	•		Companies may enter concurrent commodity buy/sale arrangements, or transactions in contemplation of other transactions, often to assure that the commodity is available at a specific location. Pending resolution of accounting questions with the Emerging Issues Task Force, the Commission staff has requested additional disclosures for any such material arrangements, including separate disclosure on the face of the income statement of any related proceeds and costs reported on a gross basis. These disclosures are not applicable, since the Company has not entered any transactions of this nature.
	•		Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, specifies that drilling costs for completed exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain criteria are met. In April 2005, the FASB issued FASB Staff Position 19-1, Accounting for Suspended Well Costs. FSP 19-1 provides guidance for evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, however, early application is permitted. Pending adoption of FSP 19-1, the Commission staff has requested additional disclosures be included in registrants’ financial statements regarding their accounting policy for capitalization of exploratory drilling costs, as well as disclosure of capitalized exploratory drilling cost amounts included in the financial statements. At December 31, 2005, the Company had $2,105,884 in 7 exploratory wells which had been drilled to total depth. These wells will be completed in the first half of 2006.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS.

Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange and interest rates and commodity prices. As of August, 2004, when the Company sold its interest in Goloil, the Company is no longer exposed to foreign currency exchange risk.

Currently, the Company is not involved in any hedge contracts, although we may consider hedge agreements in the future to manage the exposure to commodity price risk.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Consolidated Financial Statements

and

Independent Auditors' Report

December 31, 2005, 2004 and 2003

TETON ENERGY CORPORATION

Table of Contents

	Page

Report of Independent Registered Public Accounting Firm		F - 1

Consolidated Financial Statements

Consolidated Balance Sheets		F - 2

Consolidated Statements of Operations and Comprehensive Loss		F - 4

Consolidated Statements of Changes in Stockholders' (Deficit) Equity		F - 5

Consolidated Statements of Cash Flows		F - 6

Notes to Consolidated Financial Statements		F - 9

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Teton Energy Corporation

Denver, Colorado

We have audited the accompanying consolidated balance sheets of Teton Energy Corporation (formerly Teton Petroleum Company) and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations and comprehensive loss, changes in stockholders' (deficit) equity and cash flows for each of the years in the three year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with 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 consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Teton Energy Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

/s/Ehrhardt Keefe Steiner & Hottman PC

Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado

March 7, 2006

TETON ENERGY CORPORATION

Consolidated Balance Sheets

December 31, 2005 and 2004

	December 31,
	2005			2004
Assets
Current assets
Cash and cash equivalents	$	7,064,295		$	17,433,424
Trade accounts receivable		247,769			-
Advances to operator		224,429			-
Prepaid expenses and other assets		137,729			100,917
Total current assets		7,674,222			17,534,341

Property and equipment
Oil & gas properties (using successful efforts method of accounting)
Proved		1,717,213			-
Unproved		10,636,279			-
Wells in progress		2,105,884			-
Facilities in progress		120,554			-
Fixed assets		71,045			64,621
Total property and equipment		14,650,975			64,621
Less accumulated depreciation and depletion		(193,702	)		(12,397	)
Net property and equipment		14,457,273			52,224

Other assets		-			25,000
Total non-current assets		14,457,273			77,224

Total assets	$	22,131,495		$	17,611,565

See notes to consolidated financial statements.

F-2

TETON ENERGY CORPORATION

Consolidated Balance Sheets

December 31, 2005 and 2004

	December 31,
	2005			2004
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	1,281,457		$	136,984
Accrued liabilities		297,351			88,072
Accrued payroll and severance		396,589			75,689
Accrued royalties		94,403			-
Accrued franchise taxes payable		62,025			111,000
Deposit on sale of assets		300,000			-
Accrued liability of discontinued operations		255,000			-
Total current liabilities		2,686,825			411,745

Non-current liabilities
Asset retirement obligation		3,851			-
Total non-current liabilities		3,851			-
Total liabilities		2,690,676			411,745

Commitments

Stockholders' equity
Series A convertible preferred stock, $.001 par value, 25,000,000 shares authorized, 0 and 281,460 issued and outstanding at December 31, 2005 and 2004. Liquidation preference at December 31, 2005 and 2004 of $0 and $1,248,838		-			281
Common stock, $.001 par value, 250,000,000 shares authorized, 11,329,652 shares issued and outstanding at December 31, 2005 and 9,130,257 shares issued and outstanding at December 31, 2004		11,329			9,130
Additional paid-in capital		43,929,216			37,657,686
Accumulated deficit		(24,499,726	)		(20,467,277	)
Total stockholders' equity		19,440,819			17,199,820

Total liabilities and stockholders' equity	$	22,131,495		$	17,611,565

See notes to consolidated financial statements.

F-3

TETON ENERGY CORPORATION

Consolidated Statements of Operations and Comprehensive Loss

	For the Years Ended December 31,
	2005			2004			2003

Oil and gas sales	$	707,420		$	-		$	-

Cost of sales and expenses:
Lease operating expenses		50,932			-			-
Production taxes		48,196			-			-
General and administrative		4,006,747			5,332,991			3,920,791
Depletion, depreciation and amortization		181,276			-			-
Exploration		445,108			-			-
Total cost of sales and expenses		4,732,259			5,332,991			3,920,791

Loss from operations		(4,024,839	)		(5,332,991	)		(3,920,791	)

Other income (expense)
Other income		247,390			139,710			17,445
Financing charges		-			-			(132,818	)
Total other income (expense)		247,390			139,710			(115,373	)

Loss from continuing operations		(3,777,449	)		(5,193,281	)		(4,036,164	)
Discontinued operations, net of tax		(255,000	)		12,383,582			(1,598,680	)
Net income (loss)		(4,032,449	)		7,190,301			(5,634,844	)
Imputed preferred stock dividends for inducements and beneficial conversion charges		-			(521,482	)		(2,780,693	)
Preferred stock dividends		(61,455	)		(105,949	)		--
Net income (loss) applicable to common shares		(4,093,904	)		6,562,870			(8,415,537	)

Other comprehensive income (loss), net of tax
effect of exchange rates		-			(898,756	)		168,256

Comprehensive (loss) income	$	(4,093,904	)	$	5,664,114		$	(8,247,281	)

Basic and diluted weighted average common shares outstanding		10,282,394			9,028,967			6,840,303
Basic and diluted loss per common share for continuing operations	$	(0.38	)	$	(0.64	)	$	(1.00	)
Basic and diluted weighted average income (loss) per common shares for discontinued operations	$	(0.02	)	$	1.37		$	(0.23	)

Basic and diluted income (loss) per common share	$	(0.40	)	$	0.73		$	(1.23	)

See notes to consolidated financial statements.

F-4

TETON ENERGY CORPORATION

Consolidated Statements of Changes in Stockholders' (Deficit) Equity

	Preferred Stock						Common Stock				Additional Paid-in			Unamortized Preferred Stock			Foreign Currency Translation			Accumulated			Total Stockholders' (Deficit)
	Shares			Amount			Shares		Amount		Capital			Dividends			Adjustment			Deficit			Equity

Balance - December 31, 2002		-		$	-			6,289,520	$	6,289	$	26,165,215		$	-		$	730,500		$	(22,022,734	)	$	4,879,270
Common stock issued for cash - net of commissions of $98,100		-			-			437,012		437		1,091,463			-			-			-			1,091,900
Common stock issued for settlement of accounts payable and accrued liabilities		-			-			79,793		80		219,920			-			-			-			220,000
Options issued to advisory board and common stock issued for services		-			-			1,035		1		97,901			-			-			-			97,902
Warrants issued with notes payable		-			-			-				110,170			-			-			-			110,170
Preferred stock issued for cash, net of commissions of $473,838 (cash) and $99,168 (non-cash)		2,226,680			2,226			-		-		9,110,830			-			-			-			9,113,056
Preferred stock converted to common stock		(1,645,099	)		(1,645	)		1,776,708		1,776		(131	)		-			-			-			-
Preferred stock issued in exchange for notes payable and accrued interest of $9,225		36,650			37			-		-		159,389			-			-			-			159,426
In-the-money conversion feature charges to be amortized		-			-			-		-		1,182,452			(1,182,452	)		-			-			-
Amortization of in-the-money conversion feature charges		-			-			-		-		(1,063,842	)		1,063,842			-			-			-
Net loss		-			-			-		-		-			-			-			(5,634,844	)		(5,634,844	)
Foreign currency translation adjustment		-			-			-		-		-			-			168,256			-			168,256
Balance - December 31, 2003		618,231			618			8,584,068		8,583		37,073,367			(118,610	)		898,756			(27,657,578	)		10,205,136
Common stock issued for settlement of accrued liabilities		-			-			13,750		14		58,686			-			-			-			58,700
Common stock issued for services		-			-			32,175		33		101,296			-			-			-			101,329
Warrants issued for services		-			-			-		-		149,061			-			-			-			149,061
Preferred stock issued for cash, net of commissions of $50,000(cash) and $22,863 (non-cash)		126,436			126			-		-		499,872			-			-			-			499,998
Preferred stock converted to common stock		(463,207	)		(463	)		500,264		500		(37	)		-			-			-			-
Amortization of Preferred Stock dividends		-			-			-		-		(118,610	)		118,610			-			-			-
Preferred stock dividends		-			-			-		-		(105,949	)		-			-			-			(105,949	)
Foreign currency translation adjustment		-			-			-		-		-			-			(898,756	)		-			(898,756	)
Net income for year		-			-			-		-		-			-			-			7,190,301			7,190,301
Balance - December 31, 2004		281,460			281			9,130,257		9,130		37,657,686			-			-			(20,467,277	)		17,199,820
Common stock issued for settlement of accrued liabilities		-			-			12,828		13		10,487			-			-			-			10,500
Common stock issued for services		-			-			298,276		298		944,726			-			-			-			945,024
Common stock issued for asset acquisitions		-			-			862,963		863		1,467,143			-			-			-			1,468,006
Warrants issued for asset acquisition		-			-			-		-		413,872			-			-			-			413,872
Warrants exercised net of AMEX fees of $48,862		-			-			743,868		744		3,496,757			-			-			-			3,497,501
Preferred stock converted to common stock		(281,460	)		(281	)		281,460		281		-			-			-			-			-
Preferred stock dividends		-			-			-		-		(61,455	)		-			-			-			(61,455	)
Net loss for year		-			-			-		-		-			-			-			(4,032,449	)		(4,032,449	)

Balance - December 31, 2005		-		$	-			11,329,652	$	11,329	$	43,929,216		$	-		$	-		$	(24,499,726	)	$	19,440,819

See notes to consolidated financial statements.

F-5

TETON ENERGY CORPORATION

Consolidated Statements of Cash Flows

	For the Years Ended December 31,

	2005			2004			2003

Cash flows from operating activities
Net (loss) income
Adjustments to reconcile net (loss) income to net cash used in operating activities	$	(4,032,449	)	$	7,190,301		$	(5,634,844

Depreciation, depletion, and amortization		181,276			11,380			1,046
Gain on sale of discontinued operations		-			(13,086,761	)		-
Stock, stock options and warrants issued for services and interest		834,774			250,390			107,128
Warrants issued for notes payable extensions		-			-			110,170
Changes in assets and liabilities
From discontinued operations		255,000			1,149,609			2,045,001
Trade accounts receivable		(247,769	)		-			-
Advances to operators		(224,429	)		-			-
Prepaid expenses and other assets		(36,812	)		(5,224	)		(4,247	)
Royalties and payroll taxes payable		333,492			-			-
Accounts payable and accrued liabilities		140,829			69,530			311,901
		1,236,361			(11,611,076	)		2,570,999
Net cash used in operating activities		(2,796,088	)		(4,420,775	)		(3,063,845	)

Cash flows from investing activities
Sales deposit liability		300,000			-			-
Proceeds from sale of discontinued operations		-			7,963,450			-
Repayments of loan from discontinued operating entity		-			6,040,000			-
Increase in deposits		-			(25,000	)		-
Increase in oil and gas properties		(11,302,692	)		-
Increase in fixed asset additions		(6,395	)		(45,420	)		(20,684	)
Increase in non-current assets of discontinued operating entity		-			(2,988,882	)		(7,072,462	)
Net cash (used in) provided by investing activities		(11,009,087	)		10,944,148			(7,093,146	)

Cash flows from financing activities
From discontinued operations		-			3,258,378			4,470,984
Proceeds from stock subscription		-			-			1,939,610
Proceeds from issuance of stock, net of $50,000 and $473,838 commissions		-			499,998			10,251,924
Proceeds from exercise of warrants, net of AMEX fees of $48,462		3,497,501			-			-
Proceeds from notes payable		-			-			628,750
Payments on notes payable		-			-			(478,750	)
Dividends		(61,455	)		(81,463	)		-
Net cash provided by financing activities		3,436,046			3,676,913			16,812,518

Effect of exchange rates of cash and cash equivalents		-			(282,856	)		168,256

Net (decrease) increase in cash and cash equivalents		(10,369,129	)		9,917,430			6,823,783

Cash and cash equivalents - beginning of year		17,433,424			7,515,994			692,211

Cash and cash equivalents - end of year	$	7,064,295		$	17,433,424		$	7,515,994

(Continued on the following page.)

See notes to consolidated financial statements.

F-6

TETON ENERGY CORPORATION

Consolidated Statements of Cash Flows

(Continued from the previous page.)

Supplemental disclosure of cash flow information:

Cash paid for:	Interest
2005	$	--
2004	$	--
2003	$	18,202

Supplemental disclosure of non-cash activity:

During the year ended December 31, 2005, the Company had the following transactions:

The Company issued 12,828 shares of common stock to outside directors for settlement of accrued liabilities of $10,500 at December 31, 2004.

The Company issued 281,460 shares of common stock upon the conversion of 281,460 shares of preferred stock.

The Company issued 450,000 shares of common stock, valued at $837,000 and 200,000 warrants, valued at $251,949 in conjunction with the purchase of a 25% interest in Piceance Gas Resources, LLC.

The Company issued 412,962 shares of common stock, valued at $631,006 and 206,481 warrants, valued at $161,923, in conjunction with the purchase of acreage in the eastern Denver-Julesburg Basin.

The Company issued 287,500 shares to three consultants of the Company, valued at $905,624 for services, $110,250 of which has been capitalized in oil and gas properties.

The Company issued 10,776 shares of common stock valued at $39,400 for services rendered by the outside directors.

The Company recorded an asset retirement obligation in the amount of $3,851, with a corresponding increase to oil and gas properties.

$1,256,259 of capital expenditures are included in accounts payable at December 31, 2005.

(Continued on the following page.)

See notes to consolidated financial statements.

F-7

TETON ENERGY CORPORATION

Consolidated Statements of Cash Flows

(Continued from the previous page.)

During the year ended December 31, 2004, the Company had the following transactions:

The Company has issued warrants to consultants for services valued at $149,061.

13,750 shares of common stock were issued for the settlement of accrued liabilities at December 31, 2003 valued at $58,700.

The Company has issued 32,175 shares of common stock for services to consultants and outside directors valued at $101,329.

Approximately $1,317,000 of capital expenditures for discontinued operations were included in current liabilities of discontinued operations at June 30, 2004 and approximately $1,786,000 of capital expenditures were in accounts payable at December 31, 2003 for a decrease during the six months ended June 30, 2004 of $469,000.

Conversion of 463,207 shares of preferred stock, plus dividends of 37,057 shares converted into 500,264 shares of common stock.

The Company accrued dividends to preferred stockholders of $24,486 at December 31, 2004.

During the year ended December 31, 2003, the Company had the following transactions:

128,700 warrants issued with debt and valued at $110,170 were initially recorded as a discount on the note payable. At December 31, 2003, the full amount of the discount had been amortized as financing costs.

79,793 shares of common stock were issued for settlement of accounts payable and accrued liabilities valued at $220,000.

$150,000 of promissory notes payable and accrued interest of $9,225 were converted into 36,650 shares of convertible preferred stock.

The Company issued 30,000 non-qualified options to advisory board members valued at $94,702.

The Company issued 1,035 shares of common stock for services valued at $3,201.

The Company has accrued a liability for $46,968 related to the obligation to issue 57,420 warrants to a consultant for capital raising services.

12,000 preferred shares were issued to consultants for services valued at $52,200 related to capital raising.

Approximately $1,786,000 of capital expenditures for oil and gas properties were included in current liabilities of discontinued operations at December 31, 2003.

See notes to consolidated financial statements.

F-8

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 1 – Nature of Organization

Teton Energy Corporation (“Teton” or the “Company”) is an independent oil and gas exploration and production company with operations in the Rocky Mountain region of the U.S. which currently include a drilling program in the Piceance Basin in western Colorado (see Note 4 to financial statements) and a separate acreage play of over 180,000 acres in the eastern DJ Basin (see Note 5 to financial statements). Prior to July 1, 2004 Teton’s primary focus was oil and gas exploration, development and production in the Russian Federation and former Commonwealth of Independent States through ownership of a 35.30% interest in ZAO Goloil, a Russian closed joint-stock company (“Goloil”). The Company sold all of its interest in Goloil effective July 1, 2004 (see Note 3 to financial statements).

The United States dollar is the principal currency of the Company's business and, accordingly, these consolidated financial statements are expressed in United States dollars.

Note 2 – Summary of Significant Accounting Policies

Discontinued Operations and Principles of Consolidation

See Note 3 for a summary of the income (loss) from discontinued operations. The Company completed the sale of Goloil to be effective July 1, 2004 for accounting purposes. Accordingly the operating activities of Goloil for the six months ended June 30, 2004 and the year ended December 31, 2003 have been included in the results from discontinued operations. The Company has accrued, at December 31, 2005, as part of its Goloil discontinued operations, $255,000 relating to a potential refund of a grant from the U.S. Trade and Development Agency (“TDA”) (see Note 3 to financial statements).

The accompanying consolidated financial statements include the accounts of Teton, its wholly owned subsidiaries Teton Piceance LLC, Teton DJ LLC and through June 30, 2004, its wholly owned subsidiary, Goltech Petroleum, LLC ("Goltech"). The Company consolidates its investment in Piceance Gas Resources, LLC, a Colorado limited liability company ("Piceance LLC"), using pro rata consolidation, whereby the Company has included its 25% pro rata share of Piceance LLC’s assets, liabilities, revenues, expenses and oil and gas reserves (See Note 12) in its financial statements. All intercompany accounts and transactions have been eliminated in consolidation.

F-9

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 2 - Summary of Significant Accounting Policies (continued)

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions it invests with. As of the balance sheet date, the Company had no cash equivalents.

Revenue Recognition

The Company recognizes crude oil or natural gas sales revenue at the point in time crude oil or natural gas quantities have been delivered to purchasers.

Comprehensive Income

Comprehensive income is defined as the change in equity during a period from transactions and other events from non-owner sources. Comprehensive income is the total of net income or loss and other comprehensive income or loss. The Company currently does not have any items which constitutes other comprehensive income or loss.

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. The Company also evaluates costs capitalized for exploratory wells, and if proved reserves cannot be determined within one year from drilling exploration wells, those costs are written-off and recorded as an expense. At December 31, 2005, the Company had $2,105,884 in 7 exploratory wells which had been drilled to total depth. These wells will be completed in the first half of 2006.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on the Company's experience of successful drilling and average holding period.

F-10

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 2 - Summary of Significant Accounting Policies (continued)

Capitalized costs of producing oil and gas properties are depreciated and depleted by the unit-of-production method using proved reserves. Significant development projects are excluded from the depletion calculation prior to assessment of the existence of proven reserves that are ready for commercial production. The Company did not have any significant development projects in process at December 31, 2005 that were excluded from the calculation of depletion. Support equipment and other property and equipment are depreciated over their estimated useful lives.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income based on the amount of proceeds.

On the sale of an entire interest in an unproved property for cash or cash equivalent the gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained (See Note 5).

The net carrying value of the Company's oil and gas properties is limited to an estimated net recoverable amount. The net recoverable amount is based on undiscounted future net revenues and is determined by applying factors based on historical experience and other data such as primary lease terms of properties and average holding periods. If it is determined that the net recoverable value is less than the net carrying value of the oil and gas properties, any impairment is charged to operations.

Property and Equipment

Property and equipment is stated at cost. Depreciation is provided utilizing the straight-line method over the estimated useful lives for owned assets, ranging from 5 to 7 years.

Impairment of Long-Lived Assets

The Company evaluates its long-lived assets for impairment, in accordance with the provisions established under Statement of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, when events or changes in circumstances indicate that the related carrying amount may not be recoverable. An impairment is considered to exist if the estimated fair value (based upon market selling prices, if available), or the total estimated future cash flows on an undiscounted basis is less than the carrying amount of the related assets. An impairment loss is measured and recorded based on the discounted estimated future cash flows. Changes in significant assumptions underlying future cash flow estimates or fair values of assets may have a material effect on the Company’s financial position and results of operations.

F-11

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 2 - Summary of Significant Accounting Policies (continued)

Asset Retirement Obligations

The Company has applied the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." For the year ending December 31, 2005, the Company has recorded $3,851 as the fair value of the Company’s estimated liability for the retirement of its oil and gas assets in the Piceance Basin of Colorado, along with a corresponding increase in the carrying value of the related oil and gas properties.

During 2003, the Company recorded $126,500 as the fair value of the Company’s estimated liability for the retirement of its Russian oil and gas assets along with a corresponding increase in the carrying value of the related oil and gas properties. The Company’s interest in these properties were sold during the third quarter of 2004 and the Company no longer has any retirement obligations associated with its former Russian oil and gas assets.

Stock-Based Compensation

The Company has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation." Accordingly, no compensation cost has been recognized for stock options issued to employees, officers and directors under the stock option plan. Had compensation cost for the Company's options issued to employees, officers and directors been determined based on the fair value at the grant date for awards consistent with the provisions of SFAS No. 123, as amended by SFAS No. 148, the Company's net loss and basic loss per common share would have been changed to the pro forma amounts indicated below:

	For the Years Ended December 31,
	2005			2004		2003

Net income (loss) applicable to common shareholders - as reported	$	(4,093,904	)	$	6,562,870	$	(8,415,537	)
Deduct fair value of employee compensation - as reported		--			--		--
Add fair value of employee compensation expense		19,725			3,512,305		4,974,141
Net income (loss) applicable to common shareholders - pro forma	$	(4,113,629	)	$	3,050,565	$	(13,389,678	)
Basic income (loss) per common share - as reported	$	(.40	)	$	.73	$	(1.23	)
Basic income (loss) per common share - pro forma	$	(.40	)	$	.34	$	(1.96	)

F-12

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 2 - Summary of Significant Accounting Policies (continued)

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used:

	For the Years Ended December 31,
	2005			2004			2003

Approximate risk free rate		3.71	%		4.06	%		4.00	%
Average expected life		10 years			10 years			10 years
Dividend yield		-	%		-	%		-	%
Volatility		109.0	%		55.0	%		100	%
Estimated fair value of total options granted	$	118,350		$	3,512,305		$	4,974,141
Estimated fair value per option granted	$	2.63		$	2.48		$	3.15

Foreign Currency Translation

All assets and liabilities of the Company's subsidiary were translated into U.S. dollars using the prevailing exchange rates as of the balance sheet date. Income and expenses are translated using the weighted average exchange rates for the period. Stockholders' investments are translated at the historical exchange rates prevailing at the time of such investments. Any gains or losses from foreign currency translation are included as a separate component of stockholders' equity. The prevailing exchange rates at June 30, 2004 and December 31, 2003 were approximately 1 U.S. dollar to 29.03 and 29.45, Russian rubles, respectively. For the six months ended June 30, 2004 and the year ended December 31, 2003, the average exchange rate for 1 U.S. dollar was 28.76 and 30.66, Russian rubles, respectively.

Basic Loss Per Share

The Company applies the provisions of Statement of Financial Accounting Standard No. 128, "Earnings Per Share" (FAS 128). All dilutive potential common shares have an antidilutive effect on diluted per share amounts and therefore have been excluded in determining net loss per share. The Company's basic and diluted loss per share are equivalent and accordingly only basic loss per share has been presented.

The following table reflects the effects of dilutive securities as of December 31:

	2005		2004		2003
Dilutive effects of options		2,875,334		2,993,037		1,578,037
Dilutive effects of warrants		1,731,764		7,359,728		7,389,981
Dilutive effects of convertible preferred shares		--		281,460		2,381,351
Dilutive effects of restricted shares_⁽¹⁾		195,000		--		--
Dilutive effects of performance share units_⁽²⁾		800,000		--		--

		5,602,098		10,634,225		11,349,369

(1)	Such shares vest in equal tranches over three years beginning January 1, 2006.

F-13

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 2 - Summary of Significant Accounting Policies (continued)

(2)

Such performance share units were awarded in July 2005. A performance share unit is equal in value to one share of the Company’s common stock and subject to vesting on the basis of the achievement of specified performance targets as specified in the applicable administration document or award agreement. Upon vesting, performance share Units will be settled by delivery of shares to the Participant equal to the number of vested performance share units. Subsequent to December 31, 2005, 160,000 performance share units were forfeited, as the performance targets for 2005 were not met.

During December, 2005, the Board of Directors approved an additional 2,000,000 performance share units to be reserved for 2006 grants.

Such securities have been excluded from the earnings per share calculation as their effect was anti-dilutive. However, such securities could dilute future earnings, if achieved. The 2003 share and per share amounts have been adjusted to reflect the 1 for 12 reverse split approved by the shareholders on March 19, 2003.

Fair Value of Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts payable and accrued liabilities approximated fair value as of December 31, 2005 and 2004 because of the relatively short maturity of these instruments.

The Company was exposed to foreign currency risks to the extent that transactions and balances were denominated in currencies other than the United States dollar. The Company currently does not have any currencies denominated in other than the United States dollar.

Income Taxes

The Company recognizes deferred tax liabilities and assets based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management’s assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable.

F-14

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 2 - Summary of Significant Accounting Policies (continued)

Recently Issued Accounting Pronouncements

F-15

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 2 - Summary of Significant Accounting Policies (continued)

	•		Companies may enter concurrent commodity buy/sale arrangements, or transactions in contemplation of other transactions, often to assure that the commodity is available at a specific location. Pending resolution of accounting questions with the Emerging Issues Task Force, the Commission staff has requested additional disclosures for any such material arrangements, including separate disclosure on the face of the income statement of any related proceeds and costs reported on a gross basis. These disclosures are not applicable, since the Company has not entered any transactions of this nature.
	•		Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, specifies that drilling costs for completed exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain criteria are met. In April 2005, the FASB issued FASB Staff Position 19-1, Accounting for Suspended Well Costs. FSP 19-1 provides guidance for evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, however, early application is permitted. Pending adoption of FSP 19-1, the Commission staff has requested additional disclosures be included in registrants’ financial statements regarding their accounting policy for capitalization of exploratory drilling costs, as well as disclosure of capitalized exploratory drilling cost amounts included in the financial statements. At December 31, 2005, the Company had $2,105,884 in exploratory wells in process, all of which have been determined to be successful subsequent to year end.

Note 3 - Sale of Goloil

As described in Note 1, the Company completed the sale of Goloil effective July 1, 2004. Accordingly, the operating activities of Goloil for the six months ended June 30, 2004 and the year ended December 31, 2003 have been included in the results from discontinued operations, summarized as follows:

	2005			2004			2003

Sales	$	--		$	6,552,138		$	11,437,802
Cost of sales and expenses		255,000			7,072,272			12,604,234
Loss from operations		(255,000	)		(520,134	)		(1,166,432	)
Other income (expense)
Interest expense		--			(166,216	)		(347,740	)
Net loss from discontinued operations, before tax		(255,000	)		(686,350	)		(1,514,172	)
Income tax		--			(16,829	)		(84,508	)
Net loss from discontinued operations, before gain on disposal		(255,000	)		(703,179	)		(1,598,680	)
Gain on sale of Goloil stock		--			13,086,761			--
Income (loss) from discontinued operations	$	(255,000	)	$	12,383,582		$	(1,598,680	)

F-16

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

The gain on sale of Goloil stock is calculated as follows:

Sale price for Goloil shares	$	8,960,229
Less direct transaction expenses:
Investment banking fee		(750,000	)
Net fees and expenses		(246,779	)
Net proceeds		7,963,450

Net deficit of investment in Goloil at date of sale		5,123,311

Gain on disposal of ZAO Goloil	$	13,086,76

On September 20, 1999 Goloil entered into a Grant Agreement (the “Agreement”) with the U.S. Trade and Development Agency (“TDA”) in which the TDA agreed to grant to Goloil, subject to the satisfaction of certain conditions, up to $300,000 (“the Grant”) partially to fund the cost of goods and services required for a feasibility study (the “Study”) of the Eguriakhskiy License Territory Pipeline Project in Russia. In turn, Goloil contracted with the Company to perform the Study. During the fourth quarter of 1999 the Company received $255,000 of the $300,000. Such amount was recorded as a reduction of the Russian property expenditures. In conjunction with the finalization of the Company’s discontinued Russian activities, the Company has determined that certain “success fee” criteria contained in the Agreement were met which would require it to refund the $255,000 to the TDA, and, accordingly, has recorded as a liability at December 31, 2005 the full amount received ($255,000) and included such amount as an expense of discontinued activities for the year ended December 31, 2005. On February 28, 2006, the Company provided the TDA with a final success fee report and refunded the amount of the Grant.

Note 4-Investment in Piceance Gas Resources, LLC

On February 15, 2005, the Company signed a membership interest purchase agreement with PGR Partners, LLC ("PGR") whereby the Company acquired 25% of the membership interest in Piceance LLC. Piceance LLC owns certain oil and gas rights and leasehold assets covering approximately 6,300 acres in the Piceance Basin in western Colorado. The properties owned by Piceance LLC carry a net revenue interest of 78.75%.

The purchase price for the membership interest in Piceance LLC was $5.25 million in cash, the issuance of 450,000 shares of the Company’s common stock, which had a fair market value of $837,000, and the issuance of warrants to purchase 200,000 shares of the Company’s common stock, exercisable for a period of five years at an exercise price of $2.00 per share. Assuming a volatility of 85%, a risk free interest rate of 3.71% and $0 dividends, the warrants had a fair value, using the Black Scholes method of valuation, of approximately $252,000 at the date of issuance.

F-17

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 4-Investment in Piceance Gas Resources, LLC (continued)

Subsequent to December 31, 2005 the members of Piceance LLC applied to and received the consent of the fee owner of the land on which Piceance LLC’s oil and gas rights and leases are located for Picenace LLC to transfer the underlying interest directly to each of the members. As a result, as of February 28, 2006, Teton’s 25% interest in the oil and gas rights and leases were transferred directly to Teton Piceance LLC, our wholly owned subsidiary.

Note 5- Acquisition of Eastern Denver-Julesburg Basin Acreage and Deposit on Sale of Assets

The Company entered into a formal Purchase and Sale Agreement on January 10, 2005 with Apollo Energy, LLC and ATEC Energy Ventures, LLC to acquire certain undeveloped acreage in the eastern Denver-Julesburg (“DJ”) Basin located in Nebraska. During the second quarter of 2005 the Company closed, in three different tranches, on leasehold interests covering over 182,000 acres. The properties carry a net revenue interest of approximately 81%.

The total consideration for the acres was $3,683,744, consisting of $2,890,744 in cash plus 412,962 in shares of common stock valued at $631,000 and warrants to purchase 206,481 shares of common stock, exercisable at $1.75 per share for a period of three years with a fair value, using Black Scholes of approximately $162,000 assuming a volatility of 82%, a risk-free interest rate of 3.21% and $0 dividends.

Included in capitalized costs at December 31, 2005 is $367,000 in legal and due diligence costs incurred during the negotiation and acquisition of such properties and $110,250 which is the fair value of the shares issued to a consultant engaged to perform due diligence for the Company.

Effective December 31, 2005 the Company entered into an Acreage Earning Agreement (the “Agreement”) with Noble Energy, Inc. (“Noble”), which closed on January 27, 2006. Under the terms of the Agreement, Noble will earn a 75% working interest in Teton’s DJ acreage after payment of the $3,000,000 and after drilling twenty wells by March 1, 2007 at no cost to Teton. During that time, Teton will receive 25% of any revenues derived from the first 20 wells. After completion of the first 20 wells, Teton and Noble will split all costs associated with future drilling according to each party’s working interest percentage.

The Company intends to record the entire $3,000,000 as a reduction of its investment in the Eastern DJ during the first quarter of 2006.

Note 6 - Notes Payable

During 2003:

The Company received proceeds of $628,750 from the issuance of promissory notes to three shareholders. In connection with these notes, 128,700 warrants valued at $110,170 were issued. At December 31, 2003, the full amount of the discount had been amortized and recorded as a non-cash financing charge. The Company had recorded the value of these warrants using the Black-Scholes option-pricing model using the following assumptions: volatility of 73%, a risk-free rate of 3.5%, zero dividend payments, and a life of one year.

F-18

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 6 - Notes Payable (continued)

The Company paid $478,750 of the promissory notes issued during 2003. The remaining $150,000 along with accrued interest of $9,225 was exchanged for Teton’s 8% convertible preferred shares.

Note 7 - Stockholders' Equity

Changes in Stockholders’ Equity during 2005

Private Placements of Common Stock

During the year ended December 31, 2005, 311,104 common shares were issued for (i) the settlement of accrued liabilities of $10,500; (ii) services provided by consultants of $905,624 and (iii) services provided by the advisory board of $39,400. The services were valued based upon the value of the shares issued, which management deemed to be the more readily determinable value.

The Company issued 450,000 shares of common stock, valued at $837,000 and 200,000 warrants, valued at $251,949 in conjunction with the purchase of a 25% interest in Piceance LLC.

The Company issued 412,962 shares of common stock, valued at $631,006 and 206,481 warrants, valued at $161,923, in conjunction with the purchase of acreage in the eastern DJ.

During the year ended December 31, 2005, 743,868 warrants were exercised, purchasing 743,868 common shares of the Company for net proceeds of $3,497,501, net of related AMEX fees of $48,862.

On June 2, 2005, the Board of Directors of the Company declared a dividend distribution of one Preferred Stock Purchase Right (each a “Right” and collectively the “Rights”) for each outstanding share of Common Stock, $0.001 par value (“Common Stock”), of the Company. The distribution was paid as of June 14, 2005 (the “Record Date”), to stockholders of record on that date. Each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of the Company’s Series C Preferred Stock, $0.001 par value at a price of $22.00, subject to adjustment on the occurrence of certain events which generally involve a person acquiring 15% of the Company’s Common Stock without the permission of the Board of Directors. The description and terms of the Rights are set forth in the Rights Agreement dated as of June 3, 2005, between the Company and Computershare Investor Services, LLC, as Rights Agent.

Convertible Preferred Stock

The terms of the certificate of designation for the Company’s Preferred Stock included “automatic conversion” to Common Stock once the Company’s Common Stock averaged $6.00 per share for a period of 30 days. On September 23, 2005, the Company notified holders of its Series A Preferred Stock and its Series B Preferred Stock (the “Preferred Stock”) that their shares of Preferred Stock would be automatically converted into shares of the Company’s Common Stock effective September 30, 2005, as such condition had been met, 281,460 outstanding shares of Preferred Stock were converted to 281,460 shares of common stock.

F-19

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 7 - Stockholders' Equity (continued)

Changes in Stockholders’ Equity during 2004

Private Placements of Common Stock

During the year ended December 31, 2004, 45,925 common shares were issued for (i) the settlement of accrued liabilities of $58,700; and (ii) services provided by consultants of $43,329 and (iii) services provided by the advisory board of $58,000.

50,000 warrants were issued to settle a liability at December 31, 2003 valued at $46,967. The Company also issued 100,000 warrants to a consultant valued at $102,094 for services. The services were valued based upon the value of the shares issued, which management deemed to be the more readily determinable value.

Private Placements of Series A Convertible Preferred Stock

The Company received the following proceeds from the issuance of privately placed preferred stock at a price of $4.35 per share:

Proceeds of $499,998 (net of cash costs of $50,000) from the issuance of 126,436 shares of 8% convertible preferred stock.

The preferred stock carried an 8% dividend, payable quarterly commencing January 1, 2004 and was convertible into common stock at a price of $4.35 per share. The preferred stock was entitled to vote on all matters presented to the Company’s common stockholders, with the number of votes being equal to the number of underlying common shares. The preferred stock also contained a liquidation preference of $4.35 per share plus accrued unpaid dividends. The preferred stock could be redeemed by the Company after one year for $4.35 per share upon proper notice of redemption being provided by the Company.

Changes in Stockholders’ Equity during 2003

On March 19, 2003, the stockholders authorized an increase in the Company’s common shares from 100,000,000 to 250,000,000 and authorized 25,000,000 shares of preferred stock for future issuance. In addition, the stockholders approved a 1 to 12 reverse stock split.

Private Placements of Common Stock

During the year ended December 31, 2003 the Company received the following proceeds from the issuance of privately placed common stock:

$1,091,900 (net of costs of $98,100) from the issuance of 437,012 shares of common stock and 396,667 common stock warrants. In connection with the private placement, the Company also issued a warrant for each $3.00 stock investment. The warrants have a term of two years and an exercise price of $6.00,

$1,939,610 during the year ended December 31, 2003 related to outstanding stock subscriptions receivable at December 31, 2002,

F-20

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 7 - Stockholders' Equity (continued)

80,828 common shares valued at $317,902 were issued for (i) settlement of accounts payable and accrued liabilities of $220,000; and (ii) services provided by the advisory board of $97,902. The services were valued based upon the value of the shares issued, which management deemed to be the more readily determinable value.

Private Placements of Series A Convertible Preferred Stock

During the year ended December 31, 2003 the Company received the following proceeds from the issuance of privately placed preferred stock issued at an offering price of $4.35 per share.

Proceeds of $9,145,450 (net of cash costs of $473,888 and net of $46,968 related to the obligation to issue warrants for capital raising) from the issuance of 2,266,680 shares of 8% convertible preferred stock.

$14,574 from the issuance of 40,000 preferred shares in exchange for a $150,000 note payable outstanding and accrued interest of $9,426.

We also issued 12,000 preferred shares to a consultant for capital raising services valued at $52,200.

The preferred shares carried an 8% dividend, payable quarterly commencing January 1, 2004 and were convertible into common stock at a price of $4.35 per share. The preferred stock was entitled to vote on all matters presented to the Company’s common stockholders, with the number of votes being equal to the number of underlying common shares. The preferred stock also contained a liquidation preference of $4.35 per share plus accrued unpaid dividends.

F-21

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 7 - Stockholders' Equity (continued)

In connection with the preferred share private placement for Tranches 1 and 2, certain placements were entered into when the underlying price of the common stock to which the preferred shares were convertible into, exceeded $4.35, the stated conversion rate. As a result of the underlying shares being in-the-money, the Company was required to compute a beneficial conversion charge, which was calculated as the difference between the conversion price of $4.35 and the closing stock price on the effective date of each offering, multiplied by the total of the related common shares to be issued upon conversion of the preferred stock. These charges were reflected as a dividend to the preferred shareholders and were recognized over the period in which the preferred stock first became convertible. For the Tranche 1 shares the charge was immediately recognized as the shares were immediately convertible into common shares. For Tranche 2 the shares could not be converted until a shareholder vote on January 27, 2004 took place approving the issuance of additional common shares. The calculated beneficial conversion feature on Tranche 2 was therefore amortized from the effective date of each issuance through January 27, 2004. This resulted in total beneficial conversion charges of $1,182,452, of which $1,063,842 was recorded during the fourth quarter of 2003, and $118,610 were amortized and recorded as preferred dividends in January of 2004.

The Company also sent each preferred shareholder an inducement offer to convert their shares of preferred into common shares. If converted within 60 days of closing, the investors were entitled to receive (i) dividends payable in common stock equivalent to one year’s worth of dividends; and (ii) Class B Warrants to purchase two shares of common stock for each $10 invested, exercisable at $6.00 per share.

In connection with the preferred share private placement for Tranche 1, shareholders converted 1,645,099 of 8% convertible preferred shares to common stock at a price of $4.35 per share. Common share dividends of 8% for a full year were paid totaling $546,173 and 1,431,237 warrants were issued valued at $1,170,678, for a total inducement charge of $1,716,851 recognized as a preferred dividend during the fourth quarter for those investors which accepted the inducement offer. The warrants issued were valued using the Black-Scholes option pricing model using the following assumptions: volatility of 55%, a risk-free rate of 1.875%, zero dividend payments, and a life of two years.

In connection with the preferred share private placement for Tranche 2, a common share dividend of 8% for a full year was paid totaling $157,601 and 402,991 warrants were issued valued at $337,805, for a total inducement charge of $495,406 which was recognized as a preferred dividend in the first quarter of 2004, associated with the preferred stock inducement offer ending on March 27, 2004. The warrants issued were valued using the Black-Scholes option pricing model using the following assumptions: volatility of 55%, a risk-free rate of 1.875%, zero dividend payments, and a life of two years.

Warrants to Purchase Common Shares

During 2003, the Company issued 440,140 warrants to entities for their services directly related to raising capital under private placements. The Company also issued 128,700 warrants in conjunction with debt valued at $110,170.

During 2003, the Company issued 1,019,883 warrants in connection with common stock private placement offerings, with an exercise price of $6.00 that expire December 30, 2004.

F-22

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 7 - Stockholders' Equity (continued)

The following table presents the activity for warrants outstanding:

				Weighted
				Average
				Exercise
	Shares			Price

Outstanding - December 31, 2002		4,587,780		$	5.52
Granted		3,210,249			2.49
Forfeited/canceled		(408,048	)		0.30

Outstanding - December 31, 2003		7,389,981			5.63
Granted		4,496,142			6.00
Forfeited/canceled		(4,526,396	)		5.98

Outstanding - December 31, 2004		7,359,727			5.62
Granted		406,481			1.87
Exercised		(743,868	)		4.77
Forfeited/canceled		(5,290,576	)		6.00

Outstanding - December 31, 2005		1,731,764		$	3.93

On May 11, 2004 the Board of Directors voted to extend by one year the expiration date of 3,943,151 warrants issued during the period from April 1, 2002 to December 15, 2003, with no change in the exercise price of $6.00. The above table includes the extension as an expiration and grant of such warrants.

The following table presents the composition of warrants outstanding and exercisable:

2005
Shares Outstanding
Range of Exercise Prices	Number		Price*		Life*

$1.75 - $3.24		1,083,009	$	1.87		3.12
$3.48 - $4.35		6,000		.01		0.01
$4.92 - $6.00		642,755		2.05		0.13

Total - December 31		1,731,764	$	3.93		3.26

*Price and Life reflect the weighted average exercise price and weighted average remaining contractual life, respectively.

F-23

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 8 - Stock Based Compensation

At the annual meeting on March 19, 2003, the Company’s shareholders approved an employee stock option plan and authorized 25,000,000 shares of Common Stock for issuance thereunder. At the same annual meeting at which the 2003 Plan was adopted, the Company’s shareholders also approved a 1:12 reverse split. Although the Board of Directors believed that a reasonable interpretation of both actions indicated that since the 2003 Plan was adopted at the same shareholders meeting as the reverse split and further since there were no shares technically outstanding at the time of the reverse split’s approval, that no adjustment need be made to the plan, it nevertheless elected to take a conservative approach and to remove any ambiguity by asking the stockholders, at the Company’s 2005 annual meeting, to approve a total pool of 3,000,000 options available for grant under the 2003 Plan. Such approval was granted by the stockholders.

The 2003 Plan provided for the granting of both incentive and non-qualified options. During the second quarter of 2003, the Company issued 30,000 non-qualified options to outside advisory board members which has been recorded as compensation expense during the three-months ended June 30, 2003 valued at $94,701, using the Black-Scholes option-pricing model with the following assumptions: volatility of 100%, a risk-free rate of 4%, zero dividend payments, and a life of ten years. On April 9, 2003 the Company issued 1,448,037 incentive options to employees, officers and directors valued at $4,571,026 using the Black-Scholes option-pricing model under the same assumptions described above. On August 3, 2003, 100,000 options valued at $308,414 were issued to a director under the 2003 Plan.

On March 30, 2004 1,415,000 options valued at $3,512,305 using the same assumptions as above were issued to employees, officers and directors. The Board issued the options in 2004 with the understanding that they would seek clarification from shareholders as to the ultimate number of options that can be issued. Accordingly, 994,000 of the options representing approximately $2,500,000 of the fair value of the total options granted could be voided if the shareholders did not approve an increase in the number of authorized shares available for issuance under the 2003 Plan. Such approval was granted by the stockholders.

During the second quarter of 2005, the Company issued 45,000 stock options to various employees of the Company under the 2003 Plan. These options are exercisable at $3.11 per share and vest over a three-year period, assuming the employees remain in the Company’s employ. These stock options are valued at $79,019 using the Black-Scholes option-pricing model with the following assumptions: volatility of 109.46%, a risk-free rate of 3.71%, zero dividend payments and a life of ten years. Beginning on January 1, 2006, when the Company adopts Statement of Financial Accounting Standards No. 123R, "Share-Based Payment" which is a revision of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation", the fair value of such shares will be recorded as an expense over the requisite service period for the employees.

On October 14, 2005, the Company filed a registration statement on Form S-8 registering the shares underlying options issued pursuant to the 2003 Plan.

F-24

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 8 - Stock Based Compensation (continued)

At the Company’s 2005 Annual Meeting the stockholders approved a Long Term Incentive Plan (the “LTIP”). The LTIP is a performance-based compensation plan whereby up to 10% of the outstanding shares at the beginning of each plan year, except for the first year wherein 20% of the outstanding shares are available (not to exceed, in any three year period, 35% of the outstanding shares of the Company) can be awarded to certain employees, directors and consultants. In most cases, awards will be linked to the performance of the Company as measured by performance metrics that, at the time of the grants, are deemed necessary by the Compensation Committee of the Board of Directors for the creation of shareholder value.

On July 26, 2005 the Compensation Committee finalized the award of 800,000 performance share units to the Company’s Executive Officers and Directors which could be awarded during 2005, 2006 and 2007 if the Company meets certain performance targets set in 2005. The performance share units are conditioned on the participants remaining employed by the Company, will vest over one, two and three year periods and will be awarded on a sliding scale from 50% to 200%, depending on the performance levels achieved by the Company. No LTIP shares were earned for 2005 as the objectives established by the Compensation Committee were not met.

On December 8, 2005, 195,000 shares of restricted stock were approved for issuance to be awarded to the Company’s Chief Executive Officer and two members of the Board, which vest in equal tranches over three years, beginning January 1, 2006. These shares were valued using the closing price of the Company’s stock on December 8, 2005 of $6.06 for a total value of $1,181,700. The shares will be recorded in future periods as services are provided over the service period.

At the annual meeting on July 16, 2004 the Company’s shareholders approved a stock-based compensation plan for non-employees (the “2004 Plan”). The maximum number of shares of Common Stock with respect to which awards could be granted is 1,000,000 shares. On April 5, 2005 the Board authorized the issuance of 140,000 restricted shares to the Company’s Chief Financial Officer, 112,500 restricted shares to the Company’s Legal Counsel and 35,000 restricted shares to a consultant providing land services on the Company’s acquisitions. The shares were not formally issued to the consultants until the third quarter; however the Company recorded such shares at their fair value on April 5, 2005 of $905,625. During the second quarter of 2005, the Company capitalized $110,250 of such amount and recorded the balance of $795,375 as general and administrative expenses.

Both the 2003 Plan and the 2004 Plan were terminated upon shareholder approval of the LTIP at the Company’s 2005 annual meeting; however, grants made under these plans remain outstanding until exercised or terminated pursuant to each plan’s terms.

As of December 31, 2005, 1,368,111 options with an exercise price of $3.48, 100,000 options with an exercise price of $3.71, 1,362,223 options with an exercise price of $3.60 and 45,000 options with an exercise price of $3.11 were outstanding. The weighted average fair value and contractual life of these issues were $2.48, $3.26 and $3.71 and 10.00, 8.59 and .61 years, respectively.

F-25

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 8 - Stock Based Compensation (continued)

The following table presents the activity for stock options outstanding and exercisable:

	Shares Outstanding
Range of Exercise Prices	Number			Price*			Life*

Outstanding - December 31, 2003		1,578,037		$	3.49			8.30
Issued		1,415,000			3.60			9.25

Outstanding - December 31, 2004		2,993,037			3.54			8.70
Issued		45,000			3.11			9.36
Cancelled/expired		(162,703	)		(3.52	)		(0.97	)

Outstanding - December 31, 2005		2,875,334			3.54			4.16

*Price and Life reflect the weighted average exercise price and weighted average remaining contractual life, respectively.

Note 9 - Income and Other Taxes

The provision for income taxes from continuing operations consists of the following components:

	2005		2004		2003
Current:
Federal		--		--		--
State		--		--		--
Total current		--		--		--

Deferred:
Federal		--		--		--
State		--		--		--
Total Deferred		--		--		--

Total income tax expense from continuing operations differed from the amounts computed by applying the federal statutory income tax rate of 35% to earnings (loss) before income taxes as a result of the following items for the years ended December 31:

	2005			2004			2003

Federal statutory income tax benefit from continuing operations	$	(1,322,107	)	$	(1,817,648	)	$	(1,412,657	)
State income tax benefit, net of federal income tax benefit from continuing operations		(112,282	)		(154,367	)		(116,088	)
Other		4,546			16,703			58,292
Change in valuation allowance		1,429,843			1,955,312			1,470,453

Income tax expense		--			--			--

F-26

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 9 - Income and Other Taxes (continued)

The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities at December 31, 2005 and 2004 are as follows:

	2005			2004
Current Deferred Tax Assets (Liabilities)
Other receivables	$	(7,441	)	$	(7,441	)
Prepaid expenses		(45,157	)		(30,908	)
A/P and accrued liabilities		550,205			156,463
Charitable contributions		--			--
Valuation allowance		(497,607	)		(118,114	)
Net current deferred tax asset (liability)		--			--

Non-Current Deferred Tax Assets (Liabilities)
Depreciation		(3,053	)		(3,623	)
Oil and gas properties		(801,210	)		--
Net Operating Loss		9,110,270			4,478,522
Valuation allowance		(8,306,007	)		(4,474,899	)
Net non-current deferred tax asset (liability)		--			--

Net Deferred Tax Asset (Liability)	$	--		$	--

At December 31, 2005, the Company had net operating loss carryforwards, for federal income tax purposes, of approximately $24 million. These net operating loss carryforwards, if not utilized to reduce taxable income in future periods, will expire in various amounts beginning in 2018 through 2025. Approximately $19 million of such net operating loss is subject to U.S. Internal Revenue Code Section 382 limitations. Utilization of this portion of the net operating loss is limited to approximately $900,000 per annum.

The Company has established a valuation allowance for deferred taxes that reduces its net deferred tax assets as management currently believes that these losses will not be utilized in the near term. The allowance recorded was $8.8 million and $4.6 million for 2005 and 2004 respectively. The Company increased the valuation allowance in 2005 by approximately $4.2 million due to the generation of net operating loss carryforwards.

Note 10 - Commitments

On October 5, 2005, in connection with the resignation of a former Officer and Director of the Company, the existing consulting agreement between the Company and the Officer was replaced with a severance agreement. The severance agreement provides that such former Officer and Director will receive a severance benefit equal to one-year’s salary, paid monthly. The severance payments may be terminated by the Company under certain circumstances prior to the total severance being paid. This severance benefit, totaling $216,000, was accrued at September 30, 2005, as the Company and the former Officer and Director had agreed upon and were committed to all of the basic terms of such severance agreement as of such date. At December 31, 2005 $153,804 remained payable in accordance with the terms of the settlement agreement.

F-27

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 10 – Commitments (continued)

Mr. Arleth, President and Chief Executive Officer, signed an employment agreement on May 1, 2003. The agreement is for a three-year term, with an initial salary of $10,000 per month that was increased to $15,000 per month beginning in January 2004 and $20,833 beginning January 2006. Under the terms of the agreement, Mr. Arleth is entitled to 24 months severance pay in the event of a change of position or control of the Company.

During 2005, the Company established a Simple IRA plan, allowing for the deferral of employee income. The plan provides for the Company to match employee contributions up to 3% of gross wages. For the year ended December 31, 2005 Company contributed $3,467 to such plan.

Note 11 – Subsequent Events

Subsequent to December 31, 2005 the members of Piceance LLC applied to and received the consent of the fee owner of the land on which Piceance LLC’s oil and gas rights and leases are located for Piceance LLC to transfer the underlying interests directly to each of the members. As a result, as of February 28, 2006, Teton’s 25% interest in the oil and gas rights and leases were transferred directly to Teton Piceance LLC, our wholly owned subsidiary.

Subsequent to December 31, 2005 the Company closed on the Agreement with Noble and received $2.7 million in cash.

F-28

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 12 - Unaudited Supplemental Oil and Gas Disclosures

The following is a summary of costs incurred in oil and gas producing activities:

Included below is the Company's investment and activity in oil and gas producing activities including the Piceance and DJ. For 2004 prior to the sale of Goloil, the Company includes a proportionate share of Goloil's oil and gas properties, revenues, and costs.

	For the Years Ended
	December 31,
	2005		2004		2003

Property acquisition costs	$	10,778,408	$	-	$	-
Facilities in progress		120,554		-		1,700,696
Wells in progress		2,105,884		-		-
Development costs		1,575,084		2,988,882		5,207,931

Total	$	14,579,930	$	2,988,882	$	6,908,627

The following reflects the Company's capitalized costs associated with oil and gas producing activities:

	December 31,
	2005			2004		2003

Property acquisition costs:
Proved	$	142,129		$	-	$	595,558
Unproved		10,636,279			-		-
Facilities in progress		120,554			-		-
Wells in progress		2,105,884			-		1,700,696
Development costs		1,575,084			-		10,808,813
		14,579,930			-		13,105,067
Accumulated depreciation, depletion, amortization and valuation allowances		(160,653	)		-		(2,064,585	)

Net capitalized costs	$	14,419,277		$	-	$	11,040,482

F-29

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 12- Unaudited Supplemental Oil and Gas Disclosures (continued)

Results of Operations from Oil and Gas Producing Activities

Results of operations from oil and gas producing activities (excluding general and administrative expense, and interest expense) are presented as follows:

	For the Years Ended
	December 31,
	2005			2004			2003

Oil and gas revenues	$	707,420		$	6,552,138		$	11,437,802
Oil and gas production expenses		(50,932	)		(1,331,273	)		(2,020,447	)
Transportation and marketing expenses		--			--			(807,266	)
Export duties		--			--			(1,492,999	)
Taxes other than income taxes		(48,196	)		(4,286,025	)		(5,864,920	)
Depletion, depreciation and amortization		(160,653	)		(747,481	)		(1,534,914	)

Results of operations from oil and gas producing activities	$	447,639		$	187,359		$	(282,744	)

Reserves (Unaudited)

Proved oil and gas reserves are 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 development oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The proved reserve information as of December 31, 2005 included herein is based on estimates prepared by Netherland Sewell & Associates, Inc., independent petroleum engineers. Proved reserve information for 2004 and 2003 was based on estimates provided by Gustavson Associates, Inc., independent petroleum engineers. All proved reserves of natural gas for 2005 are located in the Piceance Basin in Colorado. All proved reserves prior to July 1, 2004 were located in Russia.

F-30

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 12 - Unaudited Supplemental Oil and Gas Disclosures (continued)

	For the Years Ended
	December 31,
	2005			2004			2003
	MMCF			MBBLS			MBBLS
Proved reserves, beginning of period		-			8,262			13,264
Production		(90	)		(348	)		(632	)
Extensions and discoveries		4,099			-			-
Sale of reserves in place		-			(7,914	)
Revisions of previous estimates		-			-			(4,370	)

Proved reserves, end of period		4,009			-			8,262

Proved developed reserves, beginning of period		-			3,816			27,402

Proved developed reserves, end of period		853			-			22,896

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

SFAS No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates for those countries where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect the Company's expectations for actual revenues to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process.

F-31

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 12 - Unaudited Supplemental Oil and Gas Disclosures (continued)

The following summarizes the standardized measure and sets forth the Company's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in Statement of Financial Accounting Standards No. 69.

	For the Years Ended December 31, (in thousands of dollars)
	2005			2004		2003

Future cash inflows	$	30,514		$	--	$	114,992
Future production costs		(4,643	)		--		(80,812	)
Future development costs		(5,900	)		--		(14,595	)
Future income tax expense		--			--		(7,360	)
Future net cash flows (undiscounted)		19,971			--		12,225
Annual discount of 10% for estimated timing of cash flows		(11,255	)		--		(6,232	)

Standardized measure of future net discounted cash flows	$	8,716		$	--	$	5,993

Changes in Standardized Measure Base Case (Unaudited)

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

	For the Years Ended December 31, (in thousands of dollars)

	2005			2004			2003

Standardized measure, beginning of period,	$	--		$	5,993		$	25,424
Net changes in prices and production costs		--			--			(11,038	)
Sales of oil and gas produced during period		(608	)		(935	)		(445	)
Future development costs		--			--			(3,098	)
Revisions of previous quantity estimates		--			--			(11,806	)
Extensions and discoveries		9,323			--			--
Accretion of discount		--			300			2,542
Sale of reserves in place		--			(5,358	)		--
Changes in income taxes, net		--			--			4,414

Standardized measure, end of period	$	8,715		$	--		$	5,993

F-32

TETON ENERGY CORPORATION

Notes to Consolidated Financial Statements

Note 13 - Selected Quarterly Information (Unaudited)

The following represents selected quarterly financial information for the years ended December 31, 2004 and 2005. Certain amounts have been reclassified to conform to the presentation in this Form 10-K.

	For the Quarter Ended
2005	March 31,			June 30,			Sept 30, _⁽¹⁾			Dec 31_^,(2)

Loss from continuing operations	$	(655,507	)	$	(1,644,693	)	$	(802,285	)	$	(674,964	)
Discontinued operations, net of tax		--			--			--			(255,000	)
Net Income (Loss)		(655,507	)		(1,644,693	)		(802,285	)		(929,964	)
Basic and diluted loss per common share for continuing operations	$	(0.07	)	$	(0.17	)	$	(0.08	)	$	(0.06	)
Basic and diluted income (loss) per common share for discontinued operations	$	0.00		$	0.00		$	0.00		$	(0.02	)
Basic and diluted income (loss) per common share	$	(0.07	)	$	(0.17	)	$	(0.08	)	$	(0.08	)

2004

Loss from continuing operations	$	(2,086,915	)	$	(1,712,408	)	$	(488,126	)	$	(905,832	)
Discontinued operations, net of tax		(435,198	)		(267,981	)		13,086,761			--
Net Income (Loss)		(2,522,113	)		(1,980,389	)		12,598,635			(905,832	)
Basic and diluted loss per common share for continuing operations	$	(0.30	)	$	(0.19	)	$	(0.07	)	$	(0.09	)
Basic and diluted income (loss) per common share for discontinued operations	$	(0.05	)	$	(0.03	)	$	1.45		$	0.00
Basic and diluted income (loss) per common share	$	(0.35	)	$	(0.22	)	$	1.38		$	(0.10	)

(1)

The gain from the sale of Goloil stock included in results from discontinued operations for the quarter ended September 30, 2004 has been adjusted by approximately $718,000 due to an error in recording the foreign currency translation account at the time of the sale, partially offset by an over accrual of current income taxes due.

(2)	The loss from discontinued operations for the quarter ended December 31, 2005 is due to the repayment of $255,000 to the U.S. Trade Development Agency pursuant to the terms of a Grant Agreement dated September 20, 1999 (See Note 3).

F-33

TETON ENERGY CORPORATION

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, as required by Rule 13a-15(b) and Rule 15d-15(e) of the Securities Exchange Act of 1934, the Company’s management, including the Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining effective disclosure controls and procedures, as defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. As of December 31, 2005, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the year ending December 31, 2005. In designing and evaluating the disclosure controls and procedures, management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. . Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of such period, our disclosure controls and procedures are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act as of December 31, 2005 were effective in ensuring information required to be disclosed in this Annual Report on Form 10-K was recorded, processed, summarized and reported on a timely basis., and reported within the time periods specified in the SEC’s rules and forms, and that such information was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the first quarter of 2005, the Company instituted new controls and procedures designed to assure that there was a proper degree of review of complex equity transactions entries prior to their being incorporated into the Company’s accounting system and reported to the Company’s auditors as part of its pre-quarterly filing review. These changes were in response to an evaluation by management in 2004 that our disclosure controls and procedures were not effective during the year ended December 31, 2004, because the Company lacked the in-house expertise to account for complex equity transactions. Other than this change, there were no other change in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that occurred during the quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. OTHER INFORMATION

None.

TETON ENERGY CORPORATION

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

DIRECTORS AND EXECUTIVE OFFICERS

Directors, executive officers, and significant employees of Teton, their respective ages and positions with Teton are as follows:

Name	Age	Position
James J. Woodcock	67	Chairman & Director
Karl F. Arleth	57	President and CEO, Director
John T. Connor, Jr.	64	Director
Thomas F. Conroy	67	Director
William K. White	63	Director
Patrick A. Quinn	52	Chief Financial Officer

JAMES J. WOODCOCK has been a director since 2002 and Chairman of the Company’s Compensation Committee, since 2003 and Chairman of the Company since February 2005. Since 1981, Mr. Woodcock has been the owner and CEO of Hy-Bon Engineering Company, based in Midland, Texas. Hy-Bon is an engineering firm and manufacturer of vapor recovery, gas boosters, and casing pressure reduction systems for the oil industry. From 1997 to 2002, Mr. Woodcock was the chairman of Transrepublic Resources, a private oil and gas exploration firm located in Midland Texas. From 1996 until 2003, Mr. Woodcock was a board member and Chairman of the Board of Renovar Energy, a private waste to energy firm located in Midland Texas.

KARL F. ARLETH has been our President and Chief Executive Officer since May 2003 and a Director since 2002. From 2002 to 2003, Mr. Arleth was the Chief Operating Officer of Sefton Resources, Inc., an oil and gas exploration and production company. Since 2002, Mr. Arleth has served as a Board member of Sefton Resources, Inc. Between 1999 and 2001, he served as Chairman and CEO of Eurogas, Inc. in London. Ending in 1999, Mr. Arleth spent 21 years with Amoco and BP-Amoco.

TETON ENERGY CORPORATION

JOHN T. CONNOR, Jr. became a director in 2003 and chairs the Board's audit committee. He is the Founder and Portfolio Manager of the Third Millennium Russia Fund, a US based mutual fund specializing in the equities of Russian public companies. A former attorney at Cravath, Swaine & Moore in New York City, he has been a partner in leading law firms in New York, Washington and New Jersey. Mr. Connor is a member of the Council on Foreign Relations.

THOMAS F. CONROY has been a director since 2002. Mr. Conroy is a Certified Public Accountant with an MBA from the University of Chicago. Since August 2004, Mr. Conroy has been the Chairman of Mann-Conroy-Eisenberg & Assoc. LLC, a life insurance and reinsurance consulting firm. Since 2001, Mr. Conroy has been a managing principal of Strategic Reinsurance Consultants International LLC, a life reinsurance consulting and brokerage firm. Ending in 2001, Mr. Conroy, spent 27 years with ING and its predecessor organizations, serving in various financial positions and leading two of its strategic business units as President. As President of ING Reinsurance, he established their international presence, setting up facilities in The Netherlands, Bermuda, Ireland and Japan. He also served as an Officer and Board Member of Security Life of Denver Insurance Company and its subsidiaries. Mr. Conroy briefly served as our interim CFO and secretary from April 2002 until April 2003.

WILLIAM K. WHITE became a director in 2005. Mr. White is the founder and owner of Amado Energy L.P., an investment vehicle formed to focus on oil and gas mineral properties in the U.S.. Between 1996 and 2002, Mr. White was the Chief Financial Officer of Pure Resources, Inc., a NYSE-listed independent exploration and production concern prior to its sale to Unocal in October, 2002.

PATRICK A. QUINN, CPA, CVA. Mr. Quinn joined Teton in February 2004 to serve as the Company’s Chief Financial Officer on a contract basis. For the past 15 years, Mr. Quinn has been the CEO of Quinn & Associates, P.C., a firm he founded that provides accounting, tax, and auditing services primarily to the oil and gas industry.

TETON ENERGY CORPORATION

All directors serve as directors for a term of one year or until his successor is elected and qualified. All officers hold office until the first meeting of the board of directors after the annual meeting of stockholders next following his election or until his successor is elected and qualified. A director or officer may also resign at any time.

COMMITTEES OF THE BOARD OF DIRECTORS

The Board of Directors has a Compensation Committee, an Audit Committee and a Governance and Nominating Committee. The Audit Committee currently consists of three directors, John Connor, the Chairman, who is the Audit Committee financial expert, Mr. Conroy and Mr. White. The Compensation Committee consists of three directors, Mr. Conroy, Mr. White and Mr. Woodcock. The Nominating Committee is made up of Mr. Woodcock and Mr. Conroy.

Mr. Woodcock, Mr. Connor, Mr. Conroy and Mr. White are the board members determined to be independent under American Stock Exchange listing standards.

The purpose of the Compensation Committee is to review the Company's compensation of its executives, to make determinations relative thereto and to submit recommendations to the Board of Directors with respect thereto in order to ensure that such officers and directors receive adequate and fair compensation. During 2005, the Compensation Committee held two meetings by teleconference and held an executive session during a regularly scheduled board meeting to discuss compensation.

The Audit Committee is responsible for the general oversight of audit, legal compliance and potential conflict of interest matters, including (a) recommending the engagement and termination of the independent public accountants to audit the financial statements of the Company, (b) overseeing the scope of the external audit services, (c) reviewing adjustments recommended by the independent public accountant and addressing disagreements between the independent public accountants and management, (d) reviewing the adequacy of internal controls and management's handling of identified material inadequacies and reportable conditions in the internal controls over financial reporting and compliance with laws and regulations, and (e) supervising the internal audit function, which may include approving the selection, compensation and termination of internal auditors.

For the fiscal year ended 2005, the Audit Committee has also discussed with management and its independent auditors issues related to the overall scope and objectives of the audits conducted, the internal controls used by the Company, and the selection of the Company's independent auditor. Additional meetings were held with the independent auditor, with financial management present, to discuss the specific results of audit investigations and examinations and the auditor's judgments regarding any and all of the above issues.

The Audit Committee met four times by teleconference during 2005.

As provided in the Governance and Nominating Committee’s charter and our Company’s corporate governance principles, the Governance and Nominating Committee is responsible for identifying individuals qualified to become Directors. The Governance and Nominating Committee seeks to identify director candidates based on input provided by a number of sources, including (a) the Governance and Nominating Committee members, (b) our other Directors, (c) our stockholders, (d) our Chief Executive Officer or Chairman, and (e) third parties such as professional search firms. In evaluating potential candidates for director, the Governance and Nominating Committee considers the entirety of each candidate’s credentials.

Code of Ethics

The Company has adopted its Code of Ethics and Business Conduct that applies to all of the officers, directors and employees of the Company. The Code is posted on our website (www.teton-energy.com). We will disclose on our website any waivers of, or amendments to, our Code.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the 1934 Act requires that the Company’s Directors and certain of its officers file reports of ownership and changes of ownership of the Company common stock with the SEC and AMEX. Based solely on copies of such reports provided to the Company, the Company believes that all Directors and officers filed on a timely basis all such reports required of them with respect to stock ownership and changes in ownership during 2005 except that Messrs. Conroy, Connor, and Woodcock were late in reporting the grant of stock in partial compensation for services as directors, and Mr. White was late in reporting his initial holdings upon becoming a director of the Company.

TETON ENERGY CORPORATION

Item 11. EXECUTIVE COMPENSATION.

The following table sets forth information concerning the compensation received by Mr. Karl Arleth, Mr. Howard Cooper and Mr. Patrick Quinn:

Summary Compensation Table

		Annual Compensation			Long Term Compensation
					Awards		Payouts
Name & Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Compen- sation ($)	Restricted Stock awards	Securities Underlying Options SARs (#)	LTIP Payouts ($)	All Other Compensation
Karl F. Arleth CEO	2005 2004 2003	205,000 180,000 85,000	265,000 ⁽¹⁾ 80,000 ⁽²⁾ 0	17,250 16,800 0	0 0 0	0 300,000 410,338	0 0 0	0 0 0
H. Howard Cooper, Chairman (until February 2005) CEO (until May 2003)	2005 2004 2003	200,000 ⁽³⁾ 200,000 160,000	0 160,000 ⁽²⁾ 0	11,181 8,200 0	0 0 0	0 400,000 603,289	0 0 0	0 0 0
Patrick A. Quinn CFO	2005 2004	0 0	0 0	192,910⁽⁴⁾ 111,647⁽⁴⁾	441,000 ⁽⁵⁾ 0	0 0	0 0	0 0

(1) $60,000 of Mr. Arleth’s bonus was paid in respect of performance during 2004 and $205,000 was in respect of performance during 2005.

(2) Bonus paid for 2003 performance.

(3) Mr. Cooper resigned as Chairman in February 2005 and later resigned as a director in October 2005. Amounts paid to Mr. Cooper in 2005 included his service as executive chairman in January and February 2005 and in respect of negotiated severance payments during the balance of 2005.

(4) Mr. Quinn has rendered services to the Company as its Chief Financial Officer on a contract basis. Amounts shown above were paid to Mr. Quinn’s firm, Quinn & Associates, P.C. in respect of Mr. Quinn’s services and for services of other employees of Quinn & Associates, P.C.

(5) Mr. Quinn was awarded 140,000 restricted shares on April 5, 2005. The value of shares held by Mr. Quinn at December 31, 2005 was $590,000.

TETON ENERGY CORPORATION

Stock Options

Options/SARs Grants During Last Fiscal Year

There were no options granted to the Company’s named executive officers during the year ended December 31, 2005.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Value

Number of

Securities

Value of

Acquired

Underlying

Unexercised

Value

Unexercised

In-the-money

Name

Exercise

Realized

Options

Karl F. Arleth

710,338

1,683,018

Howard Cooper

1,003,289

2,379,959

Employee Pension, Profit Sharing or Other Retirement Plans

During 2005, the Company established a Simple IRA, allowing for the deferral of employee income. The plan provides for the Company to match employee contributions up to 3% of gross wages. For the year ended December 31, 2005 Company contributed $3,467 to such plan.

Compensation of Directors

The Company pays its outside directors an annual retainer of $24,000, payable quarterly. In addition, for the first and second quarters of 2005 the directors received stock valued at $2,500 for each meeting board meeting attended, and stock valued at $1,000 for each teleconference. With the termination of the 2003 Employee Stock Option Plan and the 2004 Non-Employee Stock Compensation Plan, directors were no longer compensated in stock for meeting attendance or teleconferences, effective as of July 1, 2005.

Effective January 1, 2006, outside directors will be paid an annual retainer of $32,000, payable quarterly. In addition, members of the board or directors will be eligible to participate in the Company’s 2005 Long Term Incentive Plan.

During 2005, the directors received the following compensation based on retainers and attendance at board meetings: Mr. Connor, Mr. Conroy and Mr. Woodcock each received a retainer of $24,000 and Mr. White received a retainer of $6,000. Mr. Connor and Mr. Conroy each received $21,000 in stock for attendance at board meetings and participation in teleconferences and Mr. Woodcock received $22,300. In addition, during 2005, Mr. Woodcock, as Chairman, was awarded 120,000 shares of restricted stock, which vest in equal tranches each year over a three-year period beginning January 1, 2006. Additionally, since Mr. White was not a member of the Board when the LTIP grants were awarded in July 2005, he was awarded 25,000 shares which vest in equal tranches over a three-year period.

TETON ENERGY CORPORATION

Employment Contracts

Mr. Arleth, President and Chief Executive Officer, signed an employment agreement on May 1, 2003. The agreement is for a three-year term, with an initial salary of $10,000 per month. Mr. Arleth’s salary has been increased each year since the initial agreement, and, effective January 1, 2006, his salary under his employment agreement will be $20,833 per month. Under the terms of the agreement, Mr. Arleth is entitled to 24 months severance pay in the event of a change of position or control of the Company.

TETON ENERGY CORPORATION

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

The following table sets forth, as of December 31, 2005, the number of and percent of our common stock beneficially owned by persons or groups known by us to own beneficially 5% or more of our common stock:

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class

H. Howard Cooper	1,388,910 (1)	10.93%
2135 Burgess Road
Steamboat Springs, Colorado 80487

Karl F. Arleth	891,745 (2)	7.34%
410 17^th Street, Suite 1850
Denver, Colorado 80202

James J. Woodcock	618,566 (3)	5.23%
2404 Commerce Drive
Midland, TX 79702

Parties affiliated with PGR Partners, LLC	650,000 (4)	5.74%
730 17^th Sreet, Suite 410
Denver, Colorado 80202

Sound Energy Partners	643,400 (5)	5.68%
354 Pequot Avenue
Southport, Connecticut 06890

ATEC/Apollo	619,922 (6)	5.44%
1577 Ogden Street, Suite 300
Denver, CO 80218

(1) Includes (i) 10,621 shares of common stock, (ii) 375,000 shares underlying warrants, with an exercise price of $3.24, (iii) 603,289 shares underlying options exercisable at $3.48 per share and (iv) 400,000 shares underlying options exercisable at $3.60 per share.

(2) Includes (i) 75,850 shares of common stock, (ii) 105,557 shares underlying warrants, with exercise prices ranging from $3.24 per share to $4.92 per share, (iii) 410,338 shares underlying options exercisable at $3.48 per share, and (iv) 300,000 shares underlying options exercisable at $3.60 per share.

(3) Includes (i) 115,828 shares of common stock, (ii) 92,590 shares underlying warrants, with exercise prices ranging from $3.24 to $4.92 per share, (iii) 210,148 shares underlying options exercisable at $3.48 per share, and (iv) 200,000 shares underlying options exercisable at $3.60 per share.

TETON ENERGY CORPORATION

(4) Includes (i) 650,000 shares of common stock owned directly. 450,000 shares (as well as 200,000 warrants, which warrants were subsequently exercised) were issued directly to five entities controlled by individuals who are affiliated with PGR Partners, LLC and involved in the sale of the 25% membership interest in Piceance Gas Resources, LLC, which membership interest constituted our interest in the Piceance Basin until the fee owner of the land on which Piceance LLC’s oil and gas rights and leases are located consented to transfer the interest directly to each of the members.

(5) According to a Schedule 13G filed with the Securities and Exchange Commission by Sound Energy Partners, Inc., dated February 9, 2006 and effective as of December 31, 2005, Sound Energy Partners, Inc., a registered investment advisor, has shared power to vote or to direct the vote with respect to 643,400 shares of the Company’s common stock.

(6) Includes (i) 436,485 shares of common stock, and (ii) 183,437 shares underlying warrants, with an exercise price of $1.75. The shares and warrants were issued to nine individuals who are affiliated with ATEC/Apollo as part of the consideration for the purchase of the DJ Basin acreage.

The following table sets forth, as of December 31, 2005, the number of and percent of our common stock beneficially owned by (a) all directors and nominees, naming them, (b) the named executive officers, and (c) our directors and executive officers as a group, without naming them:

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class

Karl F. Arleth	891,745 (1)	7.34%
410 17^th Street, Suite 1850
Denver, Colorado 80202

James J. Woodcock	618,566 (2)	5.23%
2404 Commerce Drive
Midland, TX 79702

John T. Connor, Jr.	373,718 (3)	3.25%
410 17^th Street, Suite 1850
Denver, Colorado 80202

Thomas F. Conroy	161,031 (4)	1.41%
3825 S. Colorado Blvd.
Denver, CO 80110

Patrick A. Quinn	100,000 (5)	0.88%
700 17^th Street, Suite 1750
Denver, Colorado 80202

William K. White	15,000 (6)	0.13%
410 17^th Street, Suite 1850
Denver, Colorado 80202

All executive officers and
Directors as a group (6 persons)	2,160,060	18.24%

TETON ENERGY CORPORATION

(1) Includes (i) 75,850 shares of common stock, (ii) 105,557 shares underlying warrants, with exercise prices ranging from $3.24 per share to $4.92 per share, (iii) 410,338 shares underlying options exercisable at $3.48 per share, and (iv) 300,000 shares underlying options exercisable at $3.60 per share.

(2) Includes (i) 115,828 shares of common stock, (ii) 92,590 shares underlying warrants, with exercise prices ranging from $3.24 to $4.92 per share, (iii) 210,148 shares underlying options exercisable at $3.48 per share, and (iv) 200,000 shares underlying options exercisable at $3.60 per share.

(3) Includes (i) 183,554 shares of common stock owned indirectly, (ii) 15,164 shares of common stock owned directly, (iii) 100,000 shares of common stock underlying options exercisable at $3.71 per share and (iv) 75,000 shares of common stock underlying options exercisable at $3.60 per share.

(4) Includes (i) 31,261 shares of common stock, (ii) 26,112 shares underlying warrants, with exercise prices ranging from $3.24 to $6.00, (iii) 28,658 shares underlying options exercisable at $3.48 per share and (iv) 75,000 shares underlying options exercisable at $3.60 per share.

(5) Includes 100,000 restricted shares of common stock which are held subject to a restricted stock agreement.

(6) Includes 15,000 shares of common stock.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Transactions Involving Mr. Arleth

Mr. Arleth, President and Chief Executive Officer, signed an employment agreement on May 1, 2003. The agreement is for a three-year term, with an initial salary of $10,000 per month. Mr. Arleth’s salary has been increased each year since the initial agreement, and, effective January 1, 2006, his salary under his employment agreement will be $20,833 per month. Under the terms of the agreement, Mr. Arleth is entitled to 24 months severance pay in the event of a change of position or control of the Company.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Audit and Non-Audit Fees

Aggregate fees for professional services rendered for the Company by Ehrhardt Keefe Steiner & Hottman PC as of or for the two fiscal years ended December 31, 2005 and 2004 are set forth below:

	Fiscal Year 2005		Fiscal Year 2004

Audit Fees	$	101,111	$	74,053
Audit-Related Fees	16,034		40,508
Tax Fees	9,775		8,550
Total	$	126,920	$	123,111

TETON ENERGY CORPORATION

Audit Fees Aggregate fees for professional services rendered by Ehrhardt Keefe Steiner & Hottman PC in connection with its audit of our consolidated financial statements for the fiscal years 2005 and 2004 and the quarterly reviews of our financial statements included in Forms 10-Q.

Audit-Related Fees These were primarily related to S-3, S-8, SB-2 and SB-2/A filings for the registration of our stock, and review of our 2004 proxy statement.

Tax Fees These were related to tax compliance and related tax services.

Ehrhardt Keefe Steiner & Hottman PC rendered no professional services to us in connection with the design and implementation of financial information systems in fiscal year 2005 and 2004.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors

The Audit Committee pre-approves all audit and non-audit services provided by the independent auditors prior to the engagement of the independent auditors with respect to such services. The Chairman of the Audit Committee has been delegated the authority by the Committee to pre-approve interim services by the independent auditors other than the annual exam. The Chairman must report all such pre-approvals to the entire Audit Committee at the next committee meeting.

TETON ENERGY CORPORATION

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

Exhibits.

Exhibit No.		Description

3.1.1		Certificate of Incorporation of EQ Resources Ltd incorporated by reference to Exhibit 2.1.1 of Teton's Form 10-SB, filed July 3, 2001.

3.1.2		Certificate of Domestication of EQ Resources Ltd incorporated by reference to Exhibit 2.1.2 of Teton's Form 10-SB, filed July 3, 2001.

3.1.3		Articles of Merger of EQ Resources Ltd. and American-Tyumen Exploration Company incorporated by reference to Exhibit 2.1.3 of Teton's Form 10-SB, filed July 3, 2001.

3.1.4		Certificate of Amendment of Teton Petroleum Company incorporated by reference to Exhibit 2.1.4 of Teton's Form 10-SB, filed July 3, 2001.

3.1.5		Certificate of Amendment of Teton Petroleum Company incorporated by reference to Exhibit 2.1.5 of Teton's Form 10-SB, filed July 3, 2001.

3.1.6		Certificate of Designation for Series A Convertible Preferred Stock, incorporated by reference to Exhibit 3.1.6 of Teton's Form SB-2, filed January 27, 2004.

3.1.7		Certificate Designations, Preferences and Rights of the Terms of the Series C Preferred Stock, incorporated by reference to Exhibit 3.1 of Teton’s 8-K filed on June 8, 2005.

3.1.8		Certificate of Amendment to Certificate of Incorporation, dated June 28, 2005, incorporated by reference to Exhibit 10.1 of Teton’s Form 10-Q filed on August 15, 2005.

3.2		Bylaws, as amended, of Teton Petroleum Company incorporated by reference to Exhibit 3.2 of Teton’s Form 10-QSB, filed August 20, 2002.

4.1		Rights Agreement between Teton and Computershare Investors Services, LLC, dated June 3, 2005, incorporated by reference to Exhibit 4.1 of Teton’s Form 8-K filed on June 8, 2005.

10.1		Consulting Agreement dated March 1, 2005, between Teton Petroleum Company and H. Howard Cooper, incorporated by reference to Exhibit 10.1 of Teton’s Form 10-K filed March 31, 2005.

10.2		Employment Agreement, dated May 1, 2002, between Teton Petroleum Company and H. Howard Cooper, incorporated by reference to Exhibit 10.1.1 of Teton’s Form 10-K filed March 31, 2005.

10.3		Employment Agreement, dated May 1, 2003, between Teton Petroleum Company and Karl F. Arleth, incorporated by reference to Exhibit 10.3 of Teton’s Form 10-K filed March 31, 2005.

TETON ENERGY CORPORATION


10.4	2003 Employee Stock Option Plan, incorporated by reference to Exhibit 10.3 of Teton’s Form 10-K filed March 31, 2005.

10.5	2004 Non-employee Stock Compensation Plan incorporated by reference to Appendix B to our Proxy Statement filed on June 14, 2004.

10.6	Binding Letter of Intent dated December 17, incorporated by reference to Exhibit 10.6 of Teton’s Form 10-K filed March 31, 2005.

10.7	First Amendment to Purchase and Sale Agreement Niobrara Shallow Gas Project, dated January 2005, incorporated by reference to Exhibit 10.1 of Teton’s Form 10-Q filed May 16, 2005.

10.8	Purchase and Sale Agreement Niobrara Shallow Gas Project, dated April 13, 2005, incorporated by reference to Exhibit 10.2 of Teton’s Form 10-Q filed May 16, 2005.

10.9	Membership Interest Purchase Agreement between PGR Partners, LLC and Teton Petroleum Company, dated February 15, 2005, incorporated by reference to Exhibit 10.3 of Teton’s Form 10-Q filed May 16, 2005.

10.10	Confirmation of Grant of Stock Option, dated as of May 23, 2005, incorporated by reference to Exhibit 10.1 of Teton’s Form 10-Q filed November 14, 2005.

10.11	Confirmation of Grant of Stock Option, dated as of May 23, 2005, incorporated by reference to Exhibit 10.2 of Teton’s Form 10-Q filed November 14, 2005.

10.12	Confirmation of Grant of Stock Option, dated as of April 9, 2003, incorporated by reference to Exhibit 10.3 of Teton’s Form 10-Q filed November 14, 2005.

10.13	Confirmation of Grant of Stock Option, dated March 31, 2004, incorporated by reference to Exhibit 10.4 of Teton’s Form 10-Q filed November 14, 2005.

10.14	Form of 2005 Long-Term Incentive Plan 2005 Performance Share Unit Award Agreement, Employees and Directors, incorporated by reference to Exhibit 10.5 of Teton’s Form 10-Q filed November 14, 2005.

10.15	Form of 2005 Long-Term Incentive Plan 2005 Performance Share Unit Award Agreement, Patrick A. Quinn, incorporated by reference to Exhibit 10.6 of Teton’s Form 10-Q filed November 14, 2005.

10.16	Form of Stock Option Agreement Between Teton Energy Corporation and Howard Cooper, incorporated by reference to Exhibit 10.7 of Teton’s Form 10-Q filed November 14, 2005.

10.17	Letter Agreement dated as of October 6, 2005, between H. Howard Cooper and Teton Energy Corporation, incorporated by reference to Exhibit 10.8 of Teton’s Form 10-Q filed November 14, 2005.

10.18	Acreage Earning Agreement between Teton and Noble Energy, Inc., dated December 31, 2005, filed herewith.

10.19	First Amendment to Acreage Earning Agreement between Teton and Noble Energy, Inc., dated December 31, 2005, filed herewith.

TETON ENERGY CORPORATION


14.1	Code of Ethics and Business Conduct, incorporated by reference to Exhibit 14.1 of Teton’s 10-K filed on March 31, 2005

21.1	List of Subsidiaries, incorporated by reference Exhibit 21.1 of Teton’s Form 10-K filed on March 31, 2005.

23.1	Consent of independent registered accounting firm.

31.1	Certification by Chief Executive Officer pursuant to Sarbanes-Oxley Section 302, filed.

31.2	Certification by Chief Financial Officer pursuant to Sarbanes-Oxley Section 302, filed herewith.

32.1	Certification by Chief Executive Officer pursuant to 18 U.S. C. Section 1350, filed herewith.

32.2	Certification by Chief Financial Officer pursuant to 18 U.S. C. Section 1350, filed herewith.

99. 1	Audit Committee Charter incorporated by reference to Exhibit 99.4 of our Form 10-KSB/A filed on April 21, 2004.

TETON ENERGY CORPORATION

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.


	TETON ENERGY CORPORATION

	By:	/s/ Karl F. Arleth
		Karl. F. Arleth, Chief Executive Officer Dated: March 9, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date


/s/ James J. Woodcock	Chairman and Director	March 9, 2006
James J. Woodcock

/s/ Karl F. Arleth	President and CEO	March 9, 2006
Karl F. Arleth	(principal executive officer)

/s/ Thomas F. Conroy	Director	March 9, 2006
Thomas F. Conroy

/s/ John Connor	Director	March 9, 2006
John Connor

/s/ William K. White	Director	March 9, 2006
William K. White

/s/ Patrick A. Quinn	Chief Financial Officer	March 9, 2006
Patrick A. Quinn	(principal financial officer)