U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q/A

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2006

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to           

Commission file number: 001-31679

TETON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

(303) 565-4600

(Registrant’s telephone number, including area code)

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 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). 

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 May 11, 2006, 12,061,902 shares of the issuer’s common stock were outstanding.

EXPLANATORY NOTE

This Form 10-Q/A is being filed to amend our quarterly report on Form 10-Q originally filed on May 11, 2006, to amend two minor typographical errors in our financial statements as a result of the Edgarization process and one other minor typographical error in the notes to our financial statements.  The typographical errors do not affect the previous consolidated results reported on May 11, 2006.  There are no other changes and all other information included in the original on Form 10-Q, as filed on May 11, 2006, remains unchanged.

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TETON ENERGY CORPORATION

Table of Contents

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PART I. FINANCIAL INFORMATION

TETON ENERGY CORPORATION

Consolidated Balance Sheets

See notes to unaudited consolidated financial statements.

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TETON ENERGY CORPORATION

Unaudited Consolidated Statements of Operations and Comprehensive Loss

See notes to unaudited consolidated financial statements.

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TETON ENERGY CORPORATION

Unaudited Consolidated Statements of Cash Flows

See notes to unaudited consolidated financial statements.

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TETON ENERGY CORPORATION

Notes to Unaudited Consolidated Financial Statements

Note 1 — Organization and Summary of Significant Accounting Policies

Organization

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.

Interim Reporting

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), they do not necessarily include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of March 31, 2006, the results of operations for the three months ended March 31, 2005, and 2006, and cash flows for the three months ended March 31, 2005, and 2006. Operating results for the three months ended March 31, 2006, are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil and other factors. For a more complete understanding of our operations, financial position and accounting policies, these consolidated unaudited financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2005, previously filed with the SEC.

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of natural gas and oil reserves used in calculating depletion, the amount of expected future cash flows used in determining possible impairments of oil and gas properties, and the amount of future capital costs used in such calculations. Assumptions, judgments, and estimates also are required in determining future abandonment obligations, impairments of undeveloped properties, valuing deferred tax assets, and estimating fair values of derivative instruments.

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly owned and majority-owned subsidiaries. All inter-company profits, transactions, and balances have been eliminated. As is common in the oil and gas industry, we use pro rata consolidation for investments in partnerships and, under certain circumstances, limited liability companies (“LLC”).  In making such determination the Company will review the LLC operating agreement to determine if the characteristics of the LLC are more like a corporation or more like a partnership.

On February 15, 2005, we signed a membership interest purchase agreement with PGR Partners, LLC whereby we acquired 25% of the membership interest in a limited liability company (“Piceance LLC”) that owned certain oil and gas rights and leasehold assets covering approximately 6,300 acres in the Piceance Basin in western Colorado.  We accounted for our investment in Piceance LLC using pro rata consolidation.  During the first quarter of 2006, the members of Piceance LLC applied to and received the consent of the fee owner of the land on which Piceance LLC’s oil

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and gas rights and leases are located for Piceance LLC to transfer the underlying interest directly to each of the members.  As a result, on February 28, 2006, our 25% interest in the oil and gas rights and leases were transferred directly to Teton Piceance LLC, a wholly owned subsidiary of the Company.

As of March 31, 2006, we currently have no investments in partnerships or LLCs that would require us to use pro rata consolidation.

Sale of Oil & Gas Properties

Effective December 31, 2005, we 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 our DJ Basin acreage after payment of $3,000,000 cash and after drilling 20 wells by March 1, 2007 at no cost to us.  During that time, we will receive 25% of any revenues derived from the first 20 wells.  After completion of the first 20 wells, we will split with Noble all costs associated with future drilling according to each party’s working interest percentage.

We have recorded the entire $3,000,000 (including $300,000, which was reflected as a deposit at December 31, 2005) as a reduction of the investment in our DJ Basin property during the quarter ended March 31, 2006.

Revenue Recognition

Oil and natural gas revenue is recognized monthly based on production and delivery. We follow the “sales method” of accounting for our natural gas and crude oil revenue, so that we recognize sales revenue on all natural gas or crude oil sold to our purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Processing costs for natural gas that are paid in-kind are deducted from our revenues.

The volume of natural gas sold may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Natural gas imbalances can arise on properties for which two or more owners have the right to take production “in-kind.” In a typical gas balancing arrangement, each owner is entitled to an agreed-upon percentage of a property’s total production; however, at any given time, the amount of natural gas sold by each owner may differ from its allowable percentage. Two principal accounting practices have evolved to account for natural gas imbalances. These methods differ as to whether revenue is recognized based on the actual sale of natural gas (sales method) or an owner’s entitled share of the current period’s production (entitlement method). We have elected to use the sales method. If we used the entitlement method, our reported revenues may have been materially different.

At March 31, 2006, the liabilities in respect of gas balancing arrangements were immaterial.

Successful Efforts Method of Accounting

We account for our crude oil exploration and natural gas 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 oil and gas 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 the proper classification of wells designated as developmental or exploratory that 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 oil and gas 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 properly to account

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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 oil and gas 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 the Company is entering a new exploratory area in an effort to find an oil and gas 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.

Note 2 — Earnings per Share

Basic earnings per common share (“EPS”) is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 11,622,229 and 9,398,657 for the first quarter 2006 and 2005, respectively. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock. All potential dilutive securities have an anti-dilutive effect on earnings (loss) per share and accordingly, basic and dilutive weighted average shares are the same.

Note 3 — Stockholders’ Equity

Our authorized capital stock consists of 250,000,000 shares of common stock, $.001 par value per share and 25,000,000 shares of preferred stock, $.001 par value per share.

During the three months ended March 31, 2006, 588,891 warrants were exercised, purchasing an equivalent of number of common shares of the Company for net proceeds to the Company of $2,710,892.

In connection with the resignation of our former Chief Financial Officer effective March 31, 2006, 50,000 restricted shares of common stock were returned to us as an agreed-upon reduction in service fees charged. The return of such shares had been recorded as a reduction in accounting fees totaling $157,500 at March 31, 2006.

On June 2, 2005, our Board of Directors 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 our 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.

Note 4 — Stock-based Compensation

At March 31, 2006, we had several stock-based compensation plans, which are more fully described in Note 8 in our Annual Report on Form 10-K for the year ended 2005.

Prior to 2006, we accounted for those plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, as permitted by SFAS No. 123. Effective January 1, 2006, we adopted Statement of Financial Accounting Standard 123R Share-Based Payment (“SFAS 123R”) to all employee awards granted, modified, or settled after January 1, 2006. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. It also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those

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equity instruments.  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 were adopted by the Company effective January 1, 2006, using the modified prospective application method.

APB 25 did not require any compensation expense to be recorded in the financial statements if the exercise price of the award was not less than the market price on the date of grant.  Prior to July 2005, the Company issued only stock options and since all options granted by the Company had exercise prices equal to or greater than the market price on the date of the grant, no compensation expense was recognized for stock option grants prior to January 1, 2006.

Awards under our 2003 Employee Stock Compensation Plan vest in periodic installments after their grant and expire 10 years from grant date. Therefore, the cost related to stock-based employee compensation included in the determination of net income in 2005 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS 123. Awards under our 2005 Long-term Incentive Plan (“LTIP”) vest upon the attainment of one, two, and three year performance milestones. During the first quarter of 2005, we did not issue any stock-based awards under any of our stock-based compensation plans.

In 2006, a portion of certain stock options previously granted under the 2003 Plan will vest in the second quarter of 2006 and a pro rata portion of the anticipated total expense of that grant or $9,863 has been accrued during the three-month period ending March 31, 2006, to account for the pro rata portion attributable to the first quarter of 2006.  The initial tranche of that grant is anticipated to vest in 2Q06. These options are exercisable at $3.11 per share and vest over a three-year period, assuming the employees remain in our employ.  These stock options were valued at $118,529 on the grant date using the Black-Scholes option-pricing model with the following assumptions: volatility of 109.46%, a risk-free rate of 4%, zero dividend payments and a life of 10 years. Vested and unvested options outstanding under the Plan at March 31, 2006, are for 2,875,334 shares with exercise prices ranging from $3.11 to $3.71 per share.

For the quarter ended March 31, 2005, there were no outstanding unvested stock options ad accordingly no pro forma stock compensation existed for the quarter ended March 31, 2005.

A summary of stock option activity under our stock-based compensation plans for the three months ended March 31, 2006 is summarized below:

There were no options granted or exercised during the three months ended March 31, 2006.  As of March 31, 2006, the total unrecognized compensation cost related to non-vested options was $88,767, which is expected to be recognized over a weighed average period of approximately 27 months or 6.75 remaining quarters.

On June 28, 2005, the Company’s shareholders approved a stock-based long-term incentive plan (the “LTIP”) that permits the grant of unvested share awards, grants, options, performance share units, and share equivalents to employees, directors, consultants and vendors as directed by the Compensation Committee of the Board of Directors, with management recommendations regarding consultants, vendors, and non-executive employees.

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Grants were made in the third quarter of 2005 (the “2005 Grants”) and the first quarter of 2006 (the “2006 Grants”), each of which vest over a one, two, and three year performance period assuming specified goals are achieved. The number of shares that are finally awarded to LTIP participants is both fixed and variable.  It is fixed as it is based in part upon being in the Company’s service at the time of vesting and is variable because achievement of a combination of performance-related objectives as determined by the Compensation Committee of the Board of Directors is mandatory for vesting. Performance objectives established by the Compensation Committee include: reserve and production growth, expense management, stock performance, management efficiency and effectiveness, and completion of acquisitions.

The 2005 Grants totaled 400,000 performance share units (each unit equivalent to one share of common stock, assuming vesting) in respect of the target or base objectives and 800,000 performance share units in respect of stretch objectives.  The 2005 Grants called for vesting of 20% in 2005, 30% in 2006 and 50% in 2007, provided the milestones are achieved. The number of shares finally awarded will range from zero shares, if the minimum criteria are not met, to 200% of the target award if all criteria are met at the “stretch goal” level, each year. The calculation is based upon a weighted average calculation using the weighting percentages specified by the Board of Directors. Valuation of the 2005 Grants was $4.88 per share, based upon the closing price on the date of the grant, July 26, 2005. No performance grant shares vested in 2005 as outside directors determined that the minimum targets were not achieved on a weighted average basis. Of the 400,000 performance share units awarded in respect of the base case 2005 Grant, 82,500 performance share units were forfeited because of early Terminations, as defined in the LTIP.

In December 2005, grants of 195,000 restricted shares were made, which vest equally over 3 years, beginning January 1, 2006, and are based solely on service. These grants were valued at $6.06 per share, the closing price on the date of the grant. These shares will be issued only upon satisfaction of the vesting conditions.

The fair value of restricted stock issued pursuant to the Company’s LTIP is determined based on the market value of our common stock on the grant date.  A summary of the status of our restricted stock activity granted under our LTIP for the three months ended March 31, 2006, is summarized below:

The 2006 Grants of performance share unit grants were awarded by the Compensation Committee of the Board of Directors during the first quarter of 2006. The 2006 Grants reserved 1,250,000 performance share units in respect of base performance and 2,500,000 in respect to achievement of stretch objectives.  Each performance share unit is equivalent to one share of common stock, assuming vesting, are performance share units are performance plus service based, and vest over a one, two, and three year period (20% in 2006, 30% in 2007 and 50% in 2008, respectively), assuming both performance targets and service requirements are met. These grants are valued at $6.90, the closing price of the Company’s stock as reported by the American Stock Exchange on March 17, 2006, the date of the grant. The range of the grants which vest are from 0 to 200%, based upon relative achievement of the goals. To date, not all performance share units reserved have been awarded. For the first quarter, expense was not recognized for shares reserved for anticipated new hires (including hires after March 31, 2006) and consultants, as well as planned Terminations, as defined in the LTIP. Thus, 441,400 of 1,250,000 performance share units authorized in respect of base targets were not recognized as expense in the quarter ended March 31, 2006.

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A summary of the status of performance share units granted under our LTIP as of March 31, 2006, and changes during the three months ended March 31, 2006, are presented below:

Due to the variable number of shares that may be issued under the LTIP, we reevaluate the LTIP expectations on a quarterly basis and adjust the number of shares to be awarded based upon our results at the time of reevaluation and the expectations for change in performance as compared to the goals that must be achieved. Adjustments to the number of shares expected to be awarded, and the corresponding compensation expense, are made on a cumulative basis at the date of adjustment based upon the probable number of shares to be awarded.

Compensation cost for both restricted shares and performance share units is calculated by taking the pro-rata portion of the number of shares expected to vest in the current fiscal year multiplied by the fair-value price on the date of the grant and amounted to $479,160 for the quarter ended March 31, 2006. During the three months ended March 31, 2005, we did not award any restricted stock or performance share units under the LTIP (which had not yet been authorized by our Shareholders), and  accordingly, no equivalent expense was charged to earnings.

Note 5 — Commitments and Contingencies

Mr. Arleth, our 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 change in control of the Company.  The agreement contains an evergreen provision, which automatically extends the term of Mr. Arleth’s agreement for a two-year period if the agreement is not terminated by notice by either party at least 60 days prior to the end of the stated term.

We have entered into a three-year lease for office space, which expires in April 30, 2009.  Contractual commitments under this lease are $78,142 for 2006, $88,730 for 2007, $78,930 for 2008, and $23,043 for 2009.

During 2005, we established a Simple IRA plan, allowing for the deferral of employee income.  The plan provides for us to match employee contributions up to 3% of gross awards.  For the quarter ended March 31, 2006, we contributed $6,245 to such plan.

Note 6 — Asset Retirement Obligations

We have applied the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.”  For the quarter ending March 31, 2006, we recorded $3,895 as the fair value of our 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.

Note 7 — Derivative Instrument and Hedging Activities

Currently we do not use derivative financial instruments.

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Note 8 — Subsequent Events

On May 5, 2006, we closed a previously announced definitive agreement with American Oil and Gas, Inc. (“American”) to acquire a 25% working interest in approximately 59,000 net acres in the Williston Basin located in North Dakota.

In addition to our 25% interest, we have two partners in the acreage: American, which has a 50% working interest in the acreage, and Evertson Operating Company, which has a 25% interest.  Current plans call for the parties to drill two multi-lateral horizontal wells in 2006 to test the acreage.

Per the terms of the agreement, the Company paid American approximately $2.47 million in cash at closing and will pay an additional approximately $3.7 million of American’s 50% share for drilling and completion of the two planned wells through June 1, 2007. Any portion of the $3.7 million not expended for drilling and completion by June 1, 2007, will be paid to American on that date.  In addition, we are also obligated to pay costs in respect of our own 25% share of drilling and completion costs of such wells during the same time period.

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

FORWARD-LOOKING STATEMENTS

With the exception of historical matters, the matters discussed herein are forward-looking statements that involve risks and uncertainties. Forward-looking statements include, but are not limited to, statements concerning anticipated trends in revenues, and may include words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimate,” “projected,” “intends to,” or similar expressions, which are intended to identify “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Our actual results could differ materially from the results discussed in such forward-looking statements. There is absolutely no assurance that we will achieve the results expressed or implied in forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, our ability successfully to implement our strategy to acquire additional oil and gas properties and our ability successfully to manage and operate our newly acquired oil and gas properties or any properties subsequently acquired by us as well as those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2005 under the subsection “Caution Forward-Looking Statements” in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and “Risk Related to our Business” in our Registration Statement on Form S-3 filed with the Securities and Exchange Commission on October 17, 2005, on Form S-3 and Form S-4, each of which was filed with the Securities and Exchange Commission on March 15, 2006, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Management Discussion and Analysis

Overview

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.

Accomplishments and Highlights, Quarter Ended March 31, 2006

Our current operations are located in the Rocky Mountain Region of the United States.

Financial and operational highlights for the quarter ended March 31, 2006 include the following:

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•                  Our revenue from the sale of natural gas was $290,249, which is based on the sale of 45,582 mcf of natural gas net to the Company.  Our net loss increased from $679,995 ($.07 per share) to $1,262,625 ($.11 per share).

•                  We participated in the drilling of two wells to total depth on its acreage in the Piceance Basin of Colorado and the completion of two wells that were originally drilled in 2005. (In addition, two additional wells carried over from 2005 were completed during the first week of April.)  Work continues to complete the remaining 3 wells carried over from 2005 plus the two wells drilled in the first quarter of 2006.

•                  We executed an acreage earning agreement in respect of our DJ Basin acreage for $3,000,000 with Noble Energy, Inc. (“Noble”).  The salient terms of the agreement provide that Noble will earn into 75% of our DJ Basin acreage upon the drilling and completion of 20 wells by March 2007.  We are being carried by Noble on the costs associated with the first 20 wells. Noble, which is now the operator, has begun the exploration program and the development of a plan for drilling development of the acreage.  We have recorded the transaction as a sale for purposes of our statement of cash flows and a reduction in unproved reserves for purposes of our balance sheet.

•                  We negotiated an agreement with American Oil and Gas, Inc., which is discussed in further detail below.

During the first quarter of 2006, we continued our efforts to focus on the Rocky Mountain region of the United States.  To that end, we and our partner Noble Energy Corp. began an exploration program on over 192,000 acres in the eastern DJ Basin.  We also continued drilling operations in the Piceance Basin by drilling two and completing two natural gas wells, which wells were brought onto production.

Anticipated & Completed Key Second Quarter Items

On April 11, 2006, we announced that we signed a definitive agreement with American Oil and Gas, Inc. (“American”) to acquire a 25% working interest in approximately 45,000 net acres in the Williston Basin located in North Dakota.  The transaction closed at the completion of due diligence on May 5, 2006. Total acreage increased to approximately 59,000 net acres as American acquired additional acreage between the transaction’s announcement and closing. The additional acreage increased our cost to approximately $6.17 million, with $2.47 million due at closing and the remainder due as drilling progresses, as we carry American on its drilling costs up to the $3.7 million, but any unused carry is due to them on June 1, 2007.  Our obligation to carry American between closing and June 1, 2007, is in addition to our obligation to fund the costs associated with our own working interest during the same timeframe.

We plan to consider and pursue additional acquisitions as appropriate based on our business plan.  As a result, we may incur due diligence and legal expenses, which will be capitalized if we successfully complete an acquisition.  If an acquisition is not successful, such costs will be included in our general and administrative expenses in the year in which such expenses are incurred.  In the first quarter of 2006, we devoted significant internal resources to evaluating and capturing acquisitions while also utilizing the services of outside technical, legal and accounting consultants. We also hired a full-time Vice President of Production.

Results of Operations for the Three Months Ended March 31, 2006

We had a net loss for the three months ended March 31, 2006, of $1,262,625, which is $607,018 more than the net loss from continuing operations for the same period in 2005.  As described in further detail below, the increased loss was due primarily to accruals of non-cash compensation charges.

In the three months ended in March 31, 2006, oil and gas production net to our interest totaled 45,582 mcf resulting in $290,249 in oil and gas sales, at an average price of $6.37 for the quarter. The price we received is net of fuel, gathering, transportation, and marketing fees totaling $41,042 ($.90 per mcf). There were no comparative revenues in respect of the three months ended March 31, 2005, as we had not yet commenced operations.

Lease operating expenses for the period ended March 31, 2006, were $33,788 and production taxes were $8,018 (or a total of 14% of revenues) net to us resulting in operating income from oil and gas activities of $248,443 before depreciation and depletion, exploration costs, general and administrative expenses, and other income.  There were no comparative expenses during the corresponding period ended March 31, 2005, as we had not yet commenced formal operations.

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During the first quarter, general and administrative expense increased from $691,997 during 2005 to $1,342,803 for 2006.  Significant changes in general and administrative expenses for the three months ended March 31, 2006, compared to 2005 include:

•                  Compensation expense increased approximately $665,000, which increase was due primarily to non-cash compensation accruals of stock-based grants as a result of the implementation of our long-term incentive plan and our adoption of Statement of Financial Accounting Standard 123R Share-Based Payment, effective as of January 1, 2006.

•                  Legal, accounting, and compliance costs increased by approximately $100,000 from the prior year period in 2005 as a result of increased costs associated with the preparation and filing of two registration statements, and related expenses.

•                  Shareholder and investor relations costs increased by approximately $40,000 from the prior year period due to increased activity associated with our having been invited to present at more industry and investor conferences relative to the prior period.

•                  Board of Directors expenses increased by approximately $15,000 from the prior year period, due to the addition of an outside director.

During the three-month period ended March 31, 2006, certain general and administrative expenses were lower than in the prior year three-month period:

•                  Travel expenses were reduced by approximately $50,000 as a result of our continued focus on managing and pursuing opportunities in the Rocky Mountains.

•                  Accounting fees were approximately $150,000 lower from the prior period as a result of the partial reduction of a 2005 stock grant for services in respect of our contract CFO, who resigned from that position effective March 31, 2006.

•                  Insurance-related costs were approximately $13,000 lower from the prior year period as a result of lower D&O premiums coupled with reduced premiums as a result of the closing of all satellite offices.

During the first quarter of 2006, we incurred $140,516 in exploration expenses, primarily on its DJ Basin properties, relating to delay rentals and geological and geophysical expenses.

Other income in 2006 includes interest income from the cash balances maintained.

Liquidity and Capital Resources

We had cash and cash equivalents of $9,538,669 at March 31, 2006, and a working capital surplus of $7,578,990.

We currently estimate that our cash commitment for Q2 through Q4 of 2006 will be approximately $17.5 million. Such commitment includes our proportionate costs associated with the drilling of up to 20 total wells (depending on rig availability and other factors) and our proportionate costs relative to the construction of an access road on the Piceance Basin acreage. We also anticipate that we could incur potential additional expenditures relating to gathering systems on our DJ Basin acreage, as drilling results become known.  Also included in the $17.5 million budget are our current expectations in respect of our commitment in the development of the recently announced Williston Basin property acquisition.

We anticipate that we will utilize working capital generated from our ongoing operations in the Piceance Basin to meet some of our 2006 commitments.  In addition, in March 2006, we filed S-3 and S-4 shelf registration statements for $50 million each in financing capacity, or a total of $100 million, which registration statements have been declared effective by the SEC. We may also receive proceeds from the exercise of outstanding warrants as we did during the quarter ended March 31, 2006. At May 1, 2006, warrants to purchase 1,100,721 shares of common stock were outstanding. These warrants have a weighted average exercise price of $3.50 per share and expire between July 2006 and December 2012.  Warrants that are in the money and that are due to expire in 2006 may be exercised and could provide additional liquidity

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during 2006; however we cannot reasonably estimate the proceeds that may be received by virtue of the exercise of the warrants during the balance of 2006. Finally, we are in discussions with certain banks for the establishment of a senior debt facility. Any or all of these facilities may be available to fund any necessary additional needs.

If we are unable to borrow funds on acceptable terms, we may raise funds through additional equity offerings in order to meet our future capital needs.

There are no assurances that we will be successful in raising capital from either the debt or equity markets.

Sources and Uses of Funds

Historically, our primary source of liquidity has been cash provided by equity offerings. These offerings may continue to play an important role in financing our business. In addition, we will seek to establish a borrowing facility with one or more banks, most likely in the form of a revolving line of credit that could be used for development, drilling and other capital expenditures.

Cash Flows and Capital Expenditures

During the three months ended March 31, 2006, we used $908,561 of cash in our operating activities.  This amount compares to $604,019 used in our operating activities during the three-month period in 2005. The increase of $304,542 was due to increased operating activity as well as a payment made to the U.S. Trade and Development Agency in respect of the repayment of a grant associated with our discontinued Russian operations.

During three months ended March 31, 2006 we received cash of $2,700,000 in connection with the entering into the Acreage Earning Agreement with Noble involving our DJ Basin acreage.  In addition, we spent $2,027,957 on drilling and completion operations in the Piceance Basin.

During three months ended March 31, 2006, holders of 588,891 warrants exercised these warrants and purchased an equivalent number of common shares of the Company for net proceeds to the Company of $2,710,892.

Income Taxes, Net Operating Losses and Tax Credits

Since our inception, we have generated a net operating loss (“NOL”) carryforward for U.S. income tax purposes.  Such NOL is subject to U.S. Internal Revenue Code Section 382 limitations.  For losses incurred prior to 2004, utilization of the NOL is limited to approximately $900,000 per annum.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are 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 us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in the Notes to our consolidated financial statements. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

Reserve Estimates

Estimates of oil and gas 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

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accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretations and judgment. Estimates of economically recoverable oil and gas 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 oil and gas 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 the extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of oil and gas 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 our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Oil and Gas Properties

We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in their carrying value. We estimate the expected future cash flows of our developed proved properties and compare such future cash flows to the carrying values of the proved properties to determine if the carrying value is recoverable. If the carrying value exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of the oil and gas properties to their fair value. The factors used to determine fair value include, without limitation, 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 oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the carrying values associated with oil and gas properties.

Pro Rata Consolidation

As is common in the oil and gas industry, we use pro rata consolidation for our investment in partnerships and, under certain circumstances, limited liability companies (“LLC”).  In making such determination we will review the LLC operating agreement to determine if the characteristics of the LLC are more like a corporation or more like a partnership.

Stock Compensation

Effective January 1, 2006, we adopted the provisions of SFAS 123R to account for stock based compensation. Previously, we accounted for this compensation under the provisions of APB 25. Under APB 25, stock options did not result in any charge to earnings if the exercise price on the date of grant equaled or exceeded fair value (market price) on the grant date. Stock grants were charged to earnings on the vesting date based upon the market price of the stock on the date of the grant.

Under SFAS 123R, accounting for stock grants has not changed materially. We now accrue for anticipated vesting of stock grants in interim reporting periods based upon our best estimates at the time of the interim period of the conditions and criteria under which the options will vest. These conditions and criteria include service through the vesting date, announced future terminations, performance criteria based upon most recent forecasts and market conditions where appropriate. Market conditions are not a significant portion of the criteria. The estimates used are subjective and based upon managements judgment and may change over time as experience emerges. Changes to the interim accruals due to changes in the estimates of the conditions and criteria are recorded in the period in which the estimate changes occur.

We recorded current compensation of $479,160 based on management’s current assessments of satisfaction of performance and service conditions for these awards during the quarter ended March 31, 2006.  The performance assessment is scored based on an evaluation of the degree of progress made in achieving each of threshold, base, and stretch objectives established by the Compensation Committee of our Board of Directors by yearend.  Our compensation expense will increase or decrease in subsequent quarters based on management’s progress toward the achievement of these objectives.  Improved performance during the subsequent quarters of the year will increase compensation expense in those quarters whereas diminished performance will reduce compensation expense in subsequent quarters.

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Under SFAS 123R, our accounting for stock options has changed materially. We now amortize the unvested portion of stock option grants over the vesting period at the fair value of the option, as described in Note 4 to the financial statements. At March 31, 2006, there were 45,000 option grants unvested.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the exposure to loss resulting from changes in interest rates, foreign currency exchange rates, commodity prices, and equity prices.  To the extent we borrow or finance our activities we will be exposed to interest rate risk, which is sensitive to many factors, including governmental monetary and tax policies, domestic and international economic and political considerations and other factors that are beyond our control.

We have no current borrowings.

We do not have and currently have no plans to enter into any derivative financial instruments for hedging or speculative purposes.

ITEM 4. CONTROLS AND PROCEDURES

Our management, with the participation of our Chief Executive Officer and interim Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this Quarterly Report on Form 10-Q/A.  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 interim 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 is recorded, processed, summarized, and reported on a timely basis.

Changes in Internal Control over Financial Reporting

No change.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The securities described below represent our securities that we sold for the period commencing January 1, 2006, and ending March 31, 2006, which were not registered under the Securities Act of 1933, as amended, and which were issued by us pursuant to exemptions under the Securities Act. Underwriters were involved in none of these transactions.

During the first quarter, 588,891 warrants were exercised, purchasing common shares of the Company for net proceeds to the Company of $2,710,892. Shares purchased through the warrant exercises are covered under a registration statement at the time of resale.  The registration statement covering such resales was filed on October 17, 2005, (Registration No.: 333-129038), and declared effective by the SEC on November 10, 2005.

ISSUANCES OF STOCK FOR SERVICES OR IN SATISFACTION OF OBLIGATIONS

None issued. We recorded a reduction to service fees in the amount of $157,500 in connection with the resignation of our former Chief Financial Officer effective March 31, 2006.  Of the previously granted 140,000 restricted shares of common stock, 50,000 shares were returned to us as an agreed upon reduction in service fees charged to us by Quinn & Associates, P.C.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS:

Exhibits

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SIGNATURES

Pursuant to the requirements of the Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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