U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2007

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

For the transition period from           to

TETON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE		84-1482290
(State or other jurisdiction of		(IRS Employer
incorporation or organization)		Identification No.)
410 17th Street — Suite 1850
Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(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 þ 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). (Check one):

Large accelerated filer o      Accelerated filer o      Non-accelerated filer þ

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

As of May 9, 2007, 16,123,047 shares of the issuer’s common stock were outstanding.

 

 

TETON ENERGY CORPORATION AND SUBSIDIARIES

Table of Contents

				Page
PART I. FINANCIAL INFORMATION
Item 1.		Unaudited Consolidated Financial Statements
		Consolidated Balance Sheets March 31, 2007 (Unaudited) and December 31, 2006		3
		Consolidated Statements of Operations and Comprehensive Loss Three months ended March 31, 2007 and 2006		4
		Consolidated Statements of Cash Flows Three months ended March 31, 2007 and 2006		5
		Notes to Unaudited Consolidated Financial Statements		7
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3.		Quantitative and Qualitative Disclosures about Market Risk		18
Item 4.		Controls and Procedures		19
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings		20
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		20
Item 3.		Defaults Upon Senior Securities		20
Item 4.		Submission of Matters to a Vote of Security Holders		20
Item 5.		Other Information		20
Item 6.		Exhibits		21
SIGNATURES				22
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

Part 1. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

TETON ENERGY CORPORATION AND SUBSIDIARIES

		March 31,
		2007				December 31,
		(Unaudited)				2006
Assets
Current assets
Cash and cash equivalents		$	1,246,325			$	4,324,784
Trade accounts receivable			315,736				860,070
Advances to operator			—				401,491
Tubular inventory			148,628				148,628
Fair value of derivatives			309,981				402,867
Prepaid expenses and other assets			110,491				142,163
Total current assets			2,131,161				6,280,003
Non-current assets
Oil and gas properties (using successful efforts method of accounting)
Proved			11,713,723				11,635,699
Producing facilities			2,165,625				690,244
Unproved			13,967,553				13,959,480
Wells in progress			13,646,687				8,492,150
Facilities in progress			1,851,440				1,363,644
Land			300,000				300,000
Fixed assets			247,797				242,691
Total property and equipment			43,892,825				36,683,908
Less accumulated depreciation and depletion			(2,459,155	)			(1,911,889	)
Net property and equipment			41,433,670				34,772,019
Debt issuance costs—net			194,606				191,685
Total non-current assets			41,628,276				34,963,704
Total assets		$	43,759,437			$	41,243,707
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable		$	4,178,263			$	1,506,873
Accrued liabilities			2,943,727				4,195,674
Accrued payroll and severance			153,863				890,877
Accrued franchise taxes payable			75,244				30,518
Accrued purchase consideration			463,074				775,054
Total current liabilities			7,814,171				7,398,996
Long — term liabilities
Long — term debt			1,000,000				—
Asset retirement obligations			197,613				78,115
Other			59,214				—
Total long — term liabilities			1,256,827				78,115
Commitments
Stockholders’ equity
Common stock, $0.001 par value, 250,000,000 shares authorized, 16,123,047 and 15,180,649 shares issued and outstanding at March 31, 2007 and December 31, 2006, respectively			16,123				15,180
Additional paid—in capital			62,664,650				60,836,839
Stock—based compensation			4,032,807				3,138,772
Accumulated deficit			(32,025,141	)			(30,224,195	)
Total stockholders’ equity			34,688,439				33,766,596
Total liabilities and stockholders’ equity		$	43,759,437			$	41,243,707

See notes to unaudited consolidated financial statements

TETON ENERGY CORPORATION AND SUBSIDIARIES

		For the Three Months Ended
		March 31,
		2007				2006
Oil and gas sales		$	1,068,341			$	290,249
Cost of sales and expenses:
Lease operating expense			42,893				33,788
Production taxes			64,000				8,018
General and administrative			1,879,348				1,342,803
Depreciation, depletion and amortization			547,266				95,766
Accretion expense from asset retirement obligations			7,607				—
Exploration expense			306,134				140,516
Total cost of sales and expenses			2,847,248				1,620,891
Loss from operations			(1,778,907	)			(1,330,642	)
Other income (expense):
Realized gain on derivative contract			54,900				—
Unrealized derivative loss			(92,886	)			—
Interest income			28,981				68,017
Interest expense			(13,034	)			—
Total other income (expense)			(22,039	)			68,017
Net loss applicable to common shares		$	(1,800,946	)		$	(1,262,625	)
Basic and diluted weighted average common shares outstanding			15,599,815				11,622,229
Basic and diluted loss per common share		$	(0.12	)		$	(0.11	)

See notes to unaudited consolidated financial statements.

TETON ENERGY CORPORATION AND SUBSIDIARIES

		For the Three Months Ended
		March 31,
		2007				2006
Cash flows from operating activities
Net loss		$	(1,800,946	)		$	(1,262,625	)
Adjustments to reconcile net loss to net cash used in operating activities
Depreciation and depletion			547,266				95,766
Debt issuance cost amortization			13,034				—
Accretion expense from asset retirement obligations			7,607				—
Accrued stock based compensation — net of stock returned			894,035				331,523
Unrealized derivative loss			92,886				—
Changes in assets and liabilities
Discontinued operations			—				(255,000	)
Trade accounts receivable			544,334				155,116
Prepaid expenses and other current assets			31,672				90,280
Accounts payable and accrued liabilities			151,181				(11,988	)
Accrued payroll and severance and franchise taxes payable			(692,288	)			(51,633	)
Other liabilities			59,214				—
			1,648,941				354,064
Net cash used in operating activities			(152,005	)			(908,561	)
Cash flows from investing activities
Proceeds from sale of oil and gas properties			—				2,700,000
Purchase of fixed assets			(5,106	)			—
Development of oil and gas properties			(5,734,147	)			(2,027,957	)
Net cash used in investing activities			(5,739,253	)			672,043
Cash flows from financing activities
Proceeds from exercise of warrants and issuance of stock, net of issue costs of $0 and $0, respectively			1,828,754				2,710,892
Borrowings from credit facility			1,000,000				—
Debt issuance costs from bank debt			(15,955	)			—
Net cash provided by financing activities			2,812,799				2,710,892
Net increase (decrease) in cash and cash equivalents			(3,078,459	)			2,474,374
Cash and cash equivalents — beginning of year			4,324,784				7,064,295
Cash and cash equivalents — end of period		$	1,246,325			$	9,538,669

See notes to unaudited consolidated financial statements.

TETON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows — continued
(Unaudited)

		For the Three Months Ended
		March 31,
		2007				2006
Supplemental disclosure of non-cash activity:
Accrued stock — based compensation		$	894,035			$	489,023
Reduction in accounting service fees			—				(157,500	)
Deposit applied to oil and gas properties — Note 1			—				300,000
Capital expenditures included in accounts payable and accrued liabilities			6,603,208				1,512,265
Asset retirement obligation associated with oil and gas properties			111,891				—
Unrealized derivative loss			92,886				—

See notes to unaudited consolidated financial statements.

Notes to Consolidated Financial Statements

(Unaudited)

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. Our current operations are focused in three basins in the Rocky Mountain region of the United States.

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, 2007, the results of operations for the three months ended March 31, 2007 and 2006, and cash flows for the three months ended March 31, 2007 and 2006. 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, 2006, previously filed with the SEC on March 19, 2007.

In the course of preparing the consolidated financial statements, our 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 proved and unproved properties, the amount of accrued capital expenditures used in such calculations, future abandonment obligations and non-cash stock-based compensation expense related to the Company’s Long Term Incentive Plan.

Principles of Consolidation

The consolidated financial statements include the accounts of all of our wholly owned subsidiaries. All inter-company profits, transactions, and balances have been eliminated.

Inventory — Tubular

Tubular inventory consists primarily of tubular pipe and casing used in our operations and is stated at the lower of average cost or market value.

Sale of Oil and Gas Properties

Effective December 31, 2005, the Company entered into an Acreage Earning Agreement (the “Earning Agreement”) with Noble Energy, Inc. (“Noble”), which closed on January 27, 2006. Under the terms of the Earning Agreement, Noble would earn a 75% working interest in Teton’s Denver-Julesburg (“DJ”) Basin acreage in all acreage within the Area of Mutual Interest (“AMI”) after payment of the $3,000,000 and after drilling twenty wells by March 1, 2007 at no cost to Teton. Noble paid the Company $3,000,000 under the Earning Agreement and the Company 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 its DJ Basin property. Teton receives 25% of any net revenues derived from the drilling and completion of the first 20 wells. After completion of the first 20 wells,

Notes to Consolidated Financial Statements—Continued

(Unaudited)

the Earning Agreement provides that Teton and Noble will split all costs associated with future drilling and related facilities according to each party’s working interest percentage.

On December 21, 2006, the Company received notification from Noble that the first 20 wells had been drilled and completed for the DJ Basin Niobrara pilot project. Therefore, pursuant to the Earning Agreement, Noble earned 75% of all acreage within the AMI. Teton’s interests in the oil and gas rights and leases are recorded directly to Teton DJ Basin LLC, a wholly owned subsidiary of the Company.

Purchase of Oil and Gas Properties

On May 5, 2006, we closed a definitive agreement with American Oil and Gas, Inc. (“American”) acquiring a 25% working interest in approximately 59,000 net acres in the Williston Basin located in North Dakota for a total purchase price of approximately $6.17 million.

Per the terms of the agreement, we paid American approximately $2.47 million in cash at closing and additionally agreed to pay approximately $3.7 million in respect 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 to our obligation to fund America’s share, we are also obligated to pay costs in respect of our own 25% share of drilling and completion costs of such wells. As of March 31, 2007, we have paid to American approximately $3.3 million of the initial obligation of $3.7 million resulting in a remaining accrued purchase consideration of $463,074.

In addition to our 25% working interest, we have two partners in the acreage: American, which has a 50% working interest in the acreage, and Evertson Energy Company (“Evertson”) who is the operator and has a 25% working interest. Evertson began drilling one multi-lateral horizontal well, the Champion 1-25H on September 25, 2006. This well is currently being tested for commerciality.

Debt Issuance Costs

Debt issuance costs are amortized to interest expense over the life of the related credit facility using the effective interest method. The Credit Facility currently in place has a term of 48 months maturing June 15, 2010. See Note 3 — Long-Term Debt.

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. When this occurs, a gas imbalance is deemed to exist. 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 future reported revenues may be materially different than those reported under the sales method.

At March 31, 2007, there were no gas imbalances in respect of our oil and gas operations.

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, 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

Notes to Consolidated Financial Statements—Continued

(Unaudited)

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. In this case an allocation of costs to the exploratory and development segments is required. 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 expense when incurred. In addition, in the event that wells do not produce economic quantities of oil and or gas an impairment event may occur and part or all of the costs capitalized at that point in time would be expensed.

Reclassification

Certain amounts in the 2006 financial statements have been reclassified to conform to the 2007 presentation.

Income Taxes

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“FIN 48”). The interpretation creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition of certain tax positions.

The Company adopted the provisions of FIN 48 on January 1, 2007. The adoption of this accounting principle did not have an effect on the Company’s financial statements as of March 31, 2007.

Recently Issued Accounting Pronouncements

In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS 157”). The adoption of SFAS 157 is not expected to have a material impact on the Company’s consolidated financial position or results of operations. However, additional disclosures may be required about the information used to develop certain fair value measurements. SFAS 157 establishes a single authoritative definition of fair value, sets out a framework for measuring fair value and requires additional disclosures about fair value measurements. This Standard requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy. SFAS 157 does not require any new fair value measurements, but will remove inconsistencies in fair value measurements between various accounting pronouncements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. This statement is effective beginning January 1, 2008 and we are evaluating this pronouncement.

Note 2 — Earnings per Share

Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. 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. As of March 31, 2007 a total of 4,592,150 shares of dilutable securities have been excluded from the calculation of EPS as the effect of including these securities would be anti-dilutive.

Notes to Consolidated Financial Statements—Continued
(Unaudited)

Note 3 — Long-Term Debt

Long—term debt consisted of the following at March 31, 2007 and December 31, 2006 as follows:

		March 31, 2007				December 31, 2006
Credit Facility		$	1,000,000			$	—

On June 15, 2006, the Company entered into a $50 million revolving credit facility (the “Credit Facility”) with BNP Paribas as administrative agent, sole lead arranger, and sole book runner. The Credit Facility matures on June 15, 2010. As of March 31, 2007, the Company advanced $1.0 million of its Credit Facility. As of May 10, 2007, the Company advanced an additional $3.0 million for a total outstanding balance of $4.0 million under its Credit Facility.

The Credit Facility provides for as much as $50 million in borrowing capacity, depending upon a number of factors, such as the projected value of our proven oil and gas assets. The borrowing base for the Credit Facility at any time will be the loan value assigned to the proved reserves attributable to our subsidiaries’ direct or indirect oil and gas interests. The Credit Facility has an initial borrowing base of $3.0 million, and this borrowing base was increased to $6.0 million on March 12, 2007. The borrowing base will be redetermined on a semi-annual basis, based upon an engineering report delivered by us from an approved petroleum engineer. The Credit Facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit.

Under the Credit Facility, each loan bears interest at a Eurodollar rate or a base rate, as requested by us, plus an additional margin based on the amount of our total outstanding borrowings relative to the total borrowing base. The Eurodollar rate is based on the London Interbank Offered Rate. The base rate is the higher of the Prime Rate or the Federal Funds Rate plus one-half of one percent. In addition, under the terms of the Credit Facility, we are required to pay a commitment fee based on the average daily amount of the unused amount of the commitment of each lender. This fee accrues at a rate of 0.50% per annum and is paid quarterly in arrears on the last day of March, June, September, and December of each year and on the date on which the Credit Facility is terminated. Loans made under the Credit Facility are secured by a first mortgage against the Company’s properties, a pledge of the equity of our subsidiaries and a guaranty by those same subsidiaries.

Costs were incurred in connection with our Credit Facility and are considered part of our debt issuance costs and are included in our non-current assets. The remaining unamortized debt issuance costs at March 31, 2007 were $194,606. Those debt issuance costs are amortized to interest expense over the life of the related credit facility using the effective interest method.

The Credit Facility contains customary affirmative and negative covenants such as minimum/maximum ratios for liquidity and leverage. Under the terms of the Credit Facility, certain covenants are not immediately effective and are phased in beginning at the end of the first quarter of 2007 and are then gradually phased-in over the first three quarters of 2007. On May 11, 2007 the Company entered into a placement agreement with a broker/dealer pursuant to which this broker/dealer will raise $7.0 million of 8% Senior Subordinated Convertible Unsecured Notes on a best efforts basis. See Note 8 — Subsequent Events.

The Company amended its Credit Facility on May 14, 2007. The Second Amendment provides for the total debt to EBITDAX (Earnings Before Interest, Taxes, Depreciation And Amortization And Exploration) ratio to be effective September 30, 2007.

The $1.0 million outstanding on the Credit Facility as of March 31, 2007 and the $3.0 million that was subsequently drawn are both due on June 15, 2010. The 8% Senior Subordinated Unsecured Notes are due May 15, 2008.

Note 4 — Stockholders’ Equity

Our authorized capital stock consists of 250,000,000 shares of common stock, $.001 par value per share (the “Common Stock”) and 25,000,000 shares of preferred stock, $.001 par value per share (the “Preferred Stock”).

During the three months ended March 31, 2007, holders of the Company’s Common Stock options exercised 510,880 options, and purchased an equivalent number of the Company’s Common Stock. The Company collected proceeds of $1,828,754 during the first quarter of 2007 in respect to the exercise of these stock options. See Note 5 — Stock-based Compensation for additional information on stock options.

During the three months ended March 31, 2007, the Company issued 426,518 restricted shares which were awarded to directors, officers and employees under the 2005 LTIP plan for 2006 year milestone achievements. In addition, the Company issued 70,001 restricted shares of common stock that vested during the year ended December 31, 2006. See Note 5 — Stock-based Compensation for additional information on restricted Common Stock.

In connection with the resignation of our former contract 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.

Notes to Consolidated Financial Statements—Continued
(Unaudited)

In respect to warrants, the following table presents the activity for warrants outstanding for the three months ended March 31, 2007:

						Weighted
						Average
						Exercise
		Shares				Price
Outstanding — December 31, 2006			867,819			$	3.14
Granted			—				—
Exercised			—				—
Forfeited/canceled			—				—
Outstanding — March 31, 2007			867,819			$	3.14

The following table presents the composition of warrants outstanding and exercisable as of March 31, 2007:

Range of Exercise Prices		Number				Price*				Life*
$1.75 - $3.24			861,819			$	3.13				4.3
$3.48 - $4.35			6,000				3.81				1.3
Total shares outstanding and exercisable			867,819			$	3.14				4.3

Note 5 — Stock-based Compensation

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 certain Company employees and directors which vest during each of 2005, 2006 and 2007 provided the Company meets certain performance targets as established by the Committee. The vesting of the performance share units into common stock is conditioned on the participants’ remaining employed by the Company at each measurement date and will vest over one, two and three year periods. The performance share units will vest into common stock on a sliding scale from 50% to 200%, depending on the performance levels achieved by the Company. No LTIP shares were earned for the 2005 year as the objectives established by the Compensation Committee were not met.

During 2006, the Compensation Committee reserved 2,500,000 performance share units under the LTIP to executives, directors, certain employees and consultants which vest during each of 2006, 2007 and 2008 provided the Company meets certain performance targets as established by the Committee. The vesting of the performance share units into common stock is conditioned on the participants’ remaining employed by the Company at each measurement date and will vest over one, two and three year periods. The performance share units will vest into common stock on a sliding scale from 50% to 200%, depending on the performance levels achieved by the Company. On March 13, 2007, based on the achievement of a 150% composite index for grants reserved for 2006, 291,750 shares were earned and awarded to directors, employees and consultants.

A summary of the stock-based compensation expense recognized in the results of operations is set forth below:

		Three Months Ended March 31,
		2007				2006
LTIP performance share units — directors, employees and consultants		$	741,179			$	380,685
Restricted common stock — directors, employees and consultants			148,473				98,475
Stock options			4,383				9,863
Total		$	894,035			$	489,023

Notes to Consolidated Financial Statements—Continued
(Unaudited)

Each of the component categories of stock-based compensation is described more fully below.

Stock Options

We granted 45,000 stock options during 2006 under the 2003 Employee Stock Option Plan. These options are exercisable at $3.11 per share and vest over a three-year period, assuming the employees remain in our employ. As of March 31, 2007, we estimated the unrecognized value of the stock options at $21,916 using the Black-Scholes option-pricing model with the following assumptions: volatility of 109.46%, a risk-free rate of approximately 4%, zero dividend payments and a life of 10 years. As of March 31, 2007, there were 10,033 unvested stock options outstanding, and the total unrecognized compensation cost adjusted for estimated forfeitures related to non-vested options was $21,916, which is expected to be recognized over the remaining service period of 15 months.

A summary of stock option activity for the three months ended March 31, 2007 is set forth below:

										Weighted
										Average
						Weighted				Remaining				Aggregate
		Number				Average				Contractual				Intrinsic
		Outstanding				Exercise Price				Term				Value
										(in years)
Outstanding at December 31, 2006			2,088,545			$	3.56
Granted			—			$	—
Exercised			(510,880	)		$	3.58
Forfeited/expired			—			$	—
Outstanding at March 31, 2007			1,577,665			$	3.55				5.91			$	2,148,373
Exercisable at March 31, 2007			1,564,332			$	3.55				5.91			$	2,124,373

Long Term Incentive Plan

On June 28, 2005, the Company’s shareholders approved a long-term incentive plan (the “LTIP”) that permits the grant of stock options, stock appreciation rights, performance share units, and restricted share units 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.

The Compensation Committee establishes a pool (“Pool”) of Performance Share Units (“Units”) under the LTIP each year (each year becoming a “Grant Year”), subject to limits set forth in the LTIP, and allocates the pool to officers, directors, employees and consultants, and grants units (“Grants”) to individual participants. The Grants vest over a period of time, typically over a three-year period. In addition to vesting based on a participant’s continued employment with or service to the Company over the period of a Grant, the Units must be earned based on achieving performance goals set forth by the Compensation Committee. The Compensation Committee designates performance levels as “Threshold,” “Base,” and “Stretch.” If the Company achieves 100% of the Base level of performance, 100% of the Units vesting in that year will be earned. If the Company achieves the Threshold level of performance, 50% of the Units will be earned. If the Company achieves the Stretch level of performance, 200% of the Units will be earned. If the Threshold performance is not achieved, no Units are earned. Units may not be earned above the 200% Stretch level. Once the Units are vested and earned, they are released to the participants as common stock.

The value of each Unit is measured and determined based on the value of the Company’s common stock at the date the Unit is granted. Annual compensation expense is calculated based upon the number of Units vested and earned each year. Each quarter the Company estimates the level of performance expected to be achieved by year-end and records an estimated expense accordingly.

During the third quarter of 2005 (the “2005 Grant Year”) the Compensation Committee established a Pool of 400,000 Base Units and 800,000 Stretch Units (the “2005 Grants”). During 2005, grants of 372,500 Base Unit awards were made. The Units vest in three tranches (20% in 2005, 30% in 2006 and 50% in 2007), provided the goals set forth by the Compensation Committee are met. The performance goals are based upon attaining specific objectives, including: (a) achieving certain levels of oil and gas reserves in each year of the grant, (b) achieving a certain level of oil and gas production in each year of the grant, (c) achieving a certain level of stock price performance in each year of the Grant, (d) maintaining finding and development costs within certain ranges during each year of the grant and (e) management’s

Notes to Consolidated Financial Statements—Continued
(Unaudited)

efficiency and effectiveness in its operations. On March 13, 2007, based on the achievement of a 126.54% composite index in respect of the milestones established for 2006 under the 2005 Grants, 134,768 shares were earned and awarded, to directors, employees and consultants.

In December 2005, the Compensation Committee reserved for 2006 (the “2006 Grant Year”) 1,000,000 Base Units and 2,000,000 Stretch Units (the “2006 Grants”). In March 2006, the Compensation Committee increased the Pool of Base Units being reserved to 1,250,000 and Stretch Units to 2,500,000 to accommodate anticipated executive hires. At December 31, 2006, a total of 984,625 Base Units and 1,969,250 Stretch Units had been granted, but not yet earned or vested. The remainder of Units in the 2006 Pool reverted to shares deemed available for future issuance, consistent with the terms of the LTIP.

The 2006 Grants vest in three tranches (20% in 2006, 30% in 2007 and 50% in 2008), provided the goals set forth by the Compensation Committee are met. The performance objectives established by the Compensation Committee for the 2006 Grants are based on the (a) value of completed acquisitions in each year of the Grant relative to the Company’s market capitalization at the end of the previous calendar year, (b) stock price performance relative to an index of comparable companies over the period of the Grant established by an independent third party, and (c) management’s efficiency and effectiveness in its operations. These objectives represent 100% of the goals for senior executives of the Company and varying but lesser percentages for other employees, whose vesting includes a combination of individual, team, and corporate objectives in each year of the 2006 Grant. On March 13, 2007, based on the achievement of a 150% composite index for the 2006 Grants under the 2006 Grant Year, 291,750 shares were earned and awarded to directors, employees and consultants.

A summary of the Performance Units as for the three months ended March 31, 2007 is set forth below:

		2005 Grant Year								2006 Grant Year								Total
						Weighted								Weighted								Weighted
						Average								Average								Average
		Base				Grant				Base				Grant				Base				Grant
		Performance				Date Fair				Performance				Date Fair				Performance				Date Fair
		Share Units				Value				Share Units				Value				Share Units				Value
Total pool			400,000								1,250,000								1,650,000
Grants outstanding at beginning of year			177,500			$	4.95				778,000			$	6.71				955,500			$	6.38
Grants during the period			—			$	—				—			$	—				—			$	—
Vested and released			—			$	—				—			$	—				—			$	—
Forfeited/cancelled			—			$	—				—			$	—				—			$	—
Outstanding at end of period			177,500			$	4.95				778,000			$	6.71				955,500			$	6.38

Restricted Common Stock

In December 2005, grants of 195,000 restricted shares were made pursuant to the Company’s LTIP, which vest equally over 3 years, beginning January 1, 2006, based solely on service and continued employment throughout the vesting period. Of the 195,000 restricted shares, 65,001 shares vested in 2006. An additional 69,000 share grants were made during the 2006 year of which 64,000 vest over three years and 5,000 vested immediately. In the three months ended March 31, 2007, 55,000 shares grants were made which vest over three years. Compensation expense was recorded for the three months ended March 31, 2007 and 2006 based on the market value of the common stock on the date of the grant, recorded over the related service period.

Notes to Consolidated Financial Statements—Continued
(Unaudited)

A summary of the status of restricted stock activity granted under our LTIP for the three month period ended March 31, 2007, is set forth below:

						Weighted
						Average
		Restricted				Grant-Date
		Stock				Fair Value
Non-vested at December 31, 2006			193,999			$	5.98
Granted			55,000			$	5.11
Vested			—			$	—
Forfeited			—			$	—
Non-vested at March 31, 2007			248,999			$	5.78

Note 6 — Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells and removal of equipment and facilities from leased acreage, in accordance with applicable state and federal laws. The Company determines asset retirement obligations by calculating the present value of estimated cash flows related to future abandonment obligations. The following table provides a reconciliation of the Company’s asset retirement obligations for the three months ended March 31, 2007:

		March 31, 2007
Asset retirement obligation December 31, 2006		$	78,115
Additional liabilities incurred			22,766
Revisions in estimated cash flows			89,125
Accretion expense			7,607
Asset retirement obligation, March 31, 2007		$	197,613

Note 7 — Commitments

On February 1, 2007, the Company executed an employment agreement with Dominic J. Bazile II to become the Company’s Executive Vice President and Chief Operating Officer. The employment agreement provides for an initial salary for Mr. Bazile of $225,000 per year. Under the terms of the employment agreement, Mr. Bazile is entitled to 12 months severance pay in the event of a change of position or change in control of the Company or if his employment is terminated without cause. The employment agreement contains an evergreen provision, which automatically extends the term of Mr. Bazile’s employ for a two-year period if the agreement is not terminated by notice by either party during 60 days prior to the end of the initial stated term which is two years. In addition, Mr. Bazile’s contract employment agreement has an indemnification agreement.

We have entered into a three-year lease for office space, which expires in April 30, 2009. Contractual commitments under this lease are approximately $92,000 for the remainder of 2007, $129,000 for 2008, and $44,000 for 2009.

During 2006, 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 three months ended March 31, 2007, we contributed $16,649 to this plan.

Note 8 — Subsequent Events

On May 11, 2007, the Company entered into a placement agent agreement with a broker/dealer pursuant to which the broker/dealer agrees to act as exclusive placement agent on a “best efforts basis” in connection with a raise by the Company of up to (i) $7,000,000 principal amount of convertible 8% Senior Subordinates Unsecured Notes (the “Notes”) and 2,450,000 Common Stock Purchase Warrants, each to purchase one share of the Company’s Common Stock at $5.00 per Share. As of this date hereof, the Company has received executed subscription amounts for $5,600,000 principal amount of the Notes. In addition, the notes have a conversion price of $5.00 per share.

The Company’s Compensation Committee has revised its cash bonus plan for management and other employees. The revised plan establishes minimum EBITDAX thresholds that must be met in order for cash bonuses to be earned.

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 to successfully implement our strategy to acquire additional oil and gas properties and our ability to successfully 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, 2006, under the subsection “Forward-Looking Statements” in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section, 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, 2007

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

Financial and operational highlights for the three months ended March 31, 2007 include the following:

	•		Our net loss increased to $1,800,946 ($0.12 per share) for the three month period ended March 31, 2007 from $1,262,625 ($0.11 per share) for the same period in 2006. The increase in net loss of $538,321 is mainly attributable to increased general and administrative expenses, higher exploration expenses, higher depletion expense, offset by higher sales of gas in the Piceance Basin of Colorado during 2007.
	•		Our revenue from the sale of natural gas and oil increased to $1,068,341, which is based on the sale of 202,887 mcf equivalent of natural gas at an average price of $5.27 per mcf equivalent after a total deduction of $129,382 ($0.64 per mcf) for gathering, fuel, transportation and marketing expenses, net to the Company. Included in our oil and gas sales, our net revenue from the sale of test oil produced and sold from the Champion 1-25H well in the Williston Basin totaled approximately $36,000 and natural gas sales from the DJ Basin totaled approximately $12,000.
	•		We participated in the drilling of eight development wells in the current quarter to total depth on our acreage in the Piceance Basin of Colorado.
	•		We participated with Noble Energy Inc. in the construction of gas gathering systems in our Area of Mutual (AMI) interest in the DJ basin. In addition, Noble connected a total of 7 wells to sales during the quarter, as part of the pilot project to test the commercial viability of the wells that were drilled by Noble during 2006.
	•		The Company invested $5,734,147 in capital expenditures as further described below.

Results of Operations for the Three Months Ended March 31, 2007

We had a net loss for the three months ended March 31, 2007, of $1,800,946, which is $538,321 more than the net loss from for the same period in 2006. The increased net loss was primarily due to an increase in non-cash stock-based compensation of $405,012, included in general and administrative expense, for the three months ended March 31, 2007 compared to the same period in 2006. We also experienced higher oil and gas sales, lease operating expenses, other general and administrative expenses, depreciation and depletion expenses, exploration expenses and other expenses in the three months ended March 31, 2007

than in the same period in 2006, as discussed below.

During the three months ended in March 31, 2007, oil and gas sales net to our interest totaled 202,887 mcf equivalent resulting in $1,068,341 in oil and gas sales, at an average price of $5.27 per mcf equivalent after a total deduction of $129,382 ($0.64 per mcf equivalent) for gathering, fuel, transportation and marketing expenses. During the three months ended in March 31, 2006, oil and gas sales net to our interest totaled 45,582 mcf resulting in $290,249 in oil and gas sales, at an average price of $6.37 per mcf after a total deduction of $41,042 ($0.92 per mcf ) for gathering, fuel, transportation and marketing expenses. The higher oil and gas sales are due to 20 wells on production in the Piceance Basin, 7 wells on production in the DJ Basin, and from the sale of test oil from the Champion 1-25H well in the Williston Basin in the first quarter of 2007 as compared to 3 wells on production in the Piceance Basin in the same period in 2006.

Lease operating expenses and production taxes for the three-month period ended March 31, 2007, were $42,893 and $64,000, respectively (totaling $106,893, or 10% of revenues and $0.53 per mcf equivalent). Lease operating expense and production taxes for the three-month period ended March 31, 2006, were $33,788 and $8,018, respectively (totaling $41,806, or 14 % of revenues and $0.92 per mcf). The increase in lease operating expenses and production taxes in 2007 of $65,087 or 156% as compared to 2006 resulted primarily from the increase in the number of producing wells in 2007 as compared to 2006.

During the three months ended March 31, 2007, general and administrative expense of $1,879,348 increased $536,545 from $1,342,803 for the comparable period in 2006. Significant increases in general and administrative expenses for the three months ended March 31, 2007, compared to 2006 include the following that are mainly a result of the growth in the Company’s operations, employees and achievements:

	•		Non-cash stock-based compensation expense increased by $405,012 as a result of the increase in the number of employees and estimated achievement of performance objectives, as defined in the Company’s 2005 LTIP, during the period as compared to the comparable period in 2006.
	•		Cash compensation increased by $73,358 due to the increase in the number of employees in 2007 as compared to 2006.
	•		Fees for accounting services increased by $110,190, as a result of a one-time credit recorded in the first quarter of 2006 of $157,500 associated with the return of 50,000 shares of our Common Stock from our former contract Chief Financial Officer during that period.

During the three months ended March 31, 2007, exploration expenses increased $165,618 from 2006 as a result of expenses incurred for seismic projects on our DJ Basin properties as well as increased exploration activities associated with our future growth plans.

Depreciation and depletion expense increased $451,500 for the three months ended March 31, 2007 from the same period in 2006 primarily due to the higher gas sales volumes in 2007 compared to 2006.

In addition, other income (expense) of $(22,039) and $68,017 in the first quarter of 2007 and 2006, respectively, equates to a $90,056 increase in expense, net, for the first quarter of 2007 as compared to the same period in 2006. During the first quarter of 2007 we recorded $92,886 of unrealized losses on derivative contracts. There were no derivative contracts in place during the first quarter of 2006. Also included in the first quarter of 2007 (that was not included in the first quarter of 2006) is $13,034 in respect to debt issuance cost amortization, and a realized gain on derivative contracts of $54,900. Other income in 2006 only included interest income earned on cash balances maintained and these cash balances were higher during the first quarter of 2006, also resulting in a reduction of $39,036 in interest income during 2007 as compared to 2006.

Anticipated and Completed Key First Quarter Items

We plan to consider and pursue additional acquisitions as appropriate based on our business plan as well as to continue to evaluate our Williston Basin and DJ Basin acreage positions. As a result, we will incur additional exploration expenses to evaluate the acreage positions and in respect to additional acquisitions we may incur due diligence and legal expenses, which will be capitalized only if we successfully complete an acquisition. If an acquisition is not successful, we will

include those costs in our general and administrative expenses in the period in which such expenses are incurred.

Liquidity and Capital Resources

As of March 31, 2007 we had cash and cash equivalents of $1,246,325 and a working capital deficit of $(5,683,010). On May 11, 2007 we entered into a placement agreement with a broker/dealer pursuant to which this broker/dealer will raise $7.0 million of 8% Senior Subordinated Convertible Unsecured Notes on a best efforts basis. In addition, we are also considering monetization of partial or full ownership of selected oil and gas assets to fund our capital program.

We currently estimate the cost of our Piceance development program to be approximately $20.4 million for the year ending December 31, 2007. In addition, we are planning on additional development projects in the DJ Basin, conditioned on our evaluation of performance of the first test wells that would increase our overall 2007 development plan by as much as $6.9 million, including seismic, gathering lines and development drilling and completion/facility costs. In addition, our 2007 capital budget could be substantially increased if: (1) Berry, as operator for the Piceance play, increases the drilling program, (2) Noble, as operator for the DJ Basin play, increases the drilling program, and (3) Evertson, as operator for the Williston Basin, increases the drilling program. We have experienced higher costs of drilling Piceance Basin wells during the last two quarters and if this trend continues our capital requirements could increase as well.

We anticipate that we will utilize working capital generated from our ongoing operations to meet some of our 2007 commitments. In addition, in March 2006, we filed S-3 and S-4 shelf registration statements for $50 million each in financing capacity, which registration statements have been declared effective by the SEC. Our capacity remaining on the S-3 registration is $39 million as a result of our public offering of common stock of $10.8 million during 2006. We have not utilized any of our $50 million S-4 shelf registration.

We also may continue to receive proceeds from the exercise of outstanding warrants and/or options as we did during the year ended December 31, 2006. During the quarter ended March 31, 2007, we received $1,828,754 in respect to options that were exercised during the period. As of March 31, 2007 warrants to purchase 867,819 shares of common stock were outstanding. These warrants have a weighted average exercise price of $3.14 per share and expire between April 2008 and December 2012. As of March 31, 2007, options to purchase 1,577,665 shares of common stock were outstanding. These options have a weighted average exercise price of $3.55 per share and expire between July 2007 and May 2015.

In June 2006, we established a $50 million revolving credit facility with BNP Paribas (the “Credit Facility”). The Credit Facility had an initial borrowing base of $3.0 million, which was increased to $6.0 million on March 12, 2007. The Credit Facility matures on June 15, 2010. The Credit Facility provides for as much as $50.0 million in borrowing capacity, depending upon a number of factors, such as the projected value of our proven oil and gas assets. The borrowing base for the Credit Facility at any time will be the loan value assigned to the proved reserves attributable to our subsidiaries’ direct or indirect oil and gas interests. The borrowing base is redetermined on a semi-annual basis, based upon an engineering report delivered by us from an approved petroleum engineer. The Credit Facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. As of May 10, 2007, we have advanced a total of $4.0 million from the Credit Facility. On May 14, 2007, the Company amended the Credit Facility whereby the total debt to EBITDAX covenant is effective September 30, 2007.

We expect that the combination of our current cash balances, the proceeds of up to $7.0 million from the Notes and the monetization of portions or all of selected oil and gas assets referred to above, amounts available from existing and anticipated increases in our Credit Facility, proceeds from the exercise of warrants and options, and the use of our S-3 and S-4 shelf registrations will provide us with adequate resources to meet our capital needs for 2007.

There can be no assurances that we will be successful in raising capital sufficient to fund the above-referenced capital plan from either the debt or equity markets and or from asset monetization in the future or increasing our current borrowing base from the Credit Facility.

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. Cash raised from third parties or generated through operations will be used for additional acquisitions or in connection with drilling programs associated with our current properties.

Cash Flows and Capital Expenditures

Operating activities

During the three months ended March 31, 2007, we used $152,005 in operating activities. This amount compares to $908,561 used in our operating activities during the same period in 2006. The decrease of net cash used in our operating activities of $756,556 was primarily due to a $778,092 increase in our oil and gas sales in the first quarter of 2007 as compared to 2006 partially offset by higher expenses. Our net loss increased by $538,321 in the first quarter of 2007 as compared to the same period in 2006, however non-cash charges for depreciation, depletion and amortization increased by $464,534 and non-cash charges for accrued stock-based compensation increased by $562,512 during the same period as compared to the first quarter of 2006. In addition our cash used in operating activities decreased in the first quarter of 2007 due to accelerated collections of trade accounts receivable of $339,518 as compared to the same period in 2006. During the first quarter of 2006 we used $255,000 in respect to discontinued operations, and we did not use any cash for discontinued operations during 2007. Cash used in operating activities increased by $640,655 in 2007 in respect to accrued franchise tax and payroll accruals.

Investing activities

We incurred capital costs of $5,734,325 and $2,027,957 for the quarters ended March 31, 2007 and 2006, respectively. During the 2007 period, we incurred capital costs in respect to both our drilling activities of $4,458,591 and facilities costs of $1,280,740. During the 2006 period we incurred capital costs both in respect to drilling activities of $2,024,219 and facilities costs of $3,738. As of March 31, 2007, we had 15 Piceance Basin wells and 2 Bakken play wells in progress compared to 12 Piceance wells in progress as of March 31, 2006. Our development costs have also increased for the three months ended March 31, 2007 as compared to the same period in 2006 which is attributed to higher costs associated with the Piceance Basin drilling program.

During the three months ended March 31, 2006, we received cash of $2,700,000 in connection with Acreage Earning Agreement with Noble in respect to our DJ Basin acreage.

Financing activities

During three months ended March 31, 2007, holders of 510,880 options exercised these options and purchased an equivalent number of common shares of the Company for net proceeds to us of $1,858,754. During three months ended March 31, 2006, holders of 588,891 options exercised these options and purchased an equivalent number of common shares of the Company for net proceeds to us of $2,710,892. During the three months ended March 31, 2007, we drew $1.0 million down on our Senior Credit facility with BNP Paribas.

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 2006, utilization of the NOL is limited to approximately $900,000 per annum.

Critical Accounting Policies

Our Critical Accounting Policies and Estimates are included in our Form 10-K for the year ended December 31, 2006 filed with the SEC on March 19, 2007. There have been no changes to our accounting policies during the quarter ended March 31, 2007.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on our 2006 production, our income before income taxes for 2006 would have moved up or down approximately $69,000 for every $0.10 change in natural gas prices.

We have begun entering into derivative contracts to manage our exposure to oil and natural gas price volatility. To date, our derivative contracts have been costless collars, although we evaluate other forms of derivative instruments as well.

On October 24, 2006, we entered into certain ISDA agreements with BNP Paribas to allow us to hedge our commodity pricing risk relative to our future oil and gas production. In addition, we have a company hedging policy in place, if

necessary, to protect a portion of our production against future pricing fluctuations. Although we have not yet hedged any of our future production beyond December 31, 2007, we will consider this strategy for oil and gas production and future acquisitions.

Our outstanding hedges as of March 31, 2007 are summarized below:

Monthly Volume

CIG

Period

(MMBtu)

Floor/Ceiling

Commodity

Natural Gas

04/2007

30,000

$

6.00/$7.25

Natural Gas

05/2007

30,000

$

6.00/$7.25

Natural Gas

06/2007

30,000

$

6.00/$7.25

Natural Gas

07/2007

30,000

$

6.00/$7.25

Natural Gas

08/2007

30,000

$

6.00/$7.25

Natural Gas

09/2007

30,000

$

6.00/$7.25

Natural Gas

10/2007

30,000

$

6.00/$7.25

Natural Gas

11/2007

30,000

$

6.00/$7.25

Natural Gas

12/2007

30,000

$

6.00/$7.25

The collared hedges shown above have the effect of providing a protective floor while allowing us to share in upward pricing movements. Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. For the 2007 natural gas contracts listed above, a hypothetical $0.10 change in the CIG price above the ceiling price or below the floor price applied to the notional amounts would cause a change in the gain (loss) on hedging activities of $27,000. The Company plans to continue to enter into derivative contracts to decrease exposure to commodity price decreases.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses depending on market dynamics. This forward-looking information provides indicators of how we view and manage (or anticipate managing) our ongoing market risk exposures.

Interest Rate Risk

At March 31, 2007, we had $1.0 million outstanding on our Credit Facility. Under the Credit Facility, each loan bears interest at a Eurodollar rate or a base rate, as requested by us, plus an additional margin based on the amount of our total outstanding borrowings relative to the total borrowing base. The Eurodollar rate is based on the London Interbank Offered Rate (“LIBOR”). The base rate is the higher of the Prime Rate or the Federal Funds Rate plus one-half of one percent. In addition, under the terms of the Credit Facility, we are required to pay a commitment fee based on the average daily amount of the unused amount of the commitment of each lender. This fee accrues at a rate of 0.50% per annum and is paid quarterly in arrears on the last day of March, June, September, and December of each year and on the date on which the Credit Facility is terminated. Assuming that we were to draw down on the entire $6 million currently available to us under our credit facility, a one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate would result in additional interest expense to us of approximately $15,000 per quarter.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and 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. 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 is recorded, processed, summarized and reported on a timely basis.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended March 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

There have been no material changes from risk factors previously disclosed in the registrant’s Form 10-K for the year ended December 31, 2006.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

On May 3, 2007 the Company held its annual Shareholder Meeting.

The following table outlines the results of the shareholder voting in respect to the proposals included on the Company’s Definitive Proxy filed with the SEC on March 19, 2007:

Proposal		Vote Type			Voted				Voted (%)
No. 1 Election of Directors
Karl F. Arleth		For			10,382,552				77.41
		Withheld			3,029,580				22.59
Robert F. Bailey		For			12,536,307				93.47
		Withheld			875,825				6.53
John T. Connor Jr.		For			10,372,940				77.34
		Withheld			3,039,192				22.66
Thomas F. Conroy		For			10,276,083				76.62
		Withheld			3,136,049				23.38
William K. White		For			10,360,909				77.25
		Withheld			3,051,223				22.75
James J. Woodcock		For			10,465,297				78.03
		Withheld			2,946,835				21.97
No. 2 Notification of Appointment of Auditors
Auditors		For			13,149,735				98.04
		Withheld			50,920				0.38
		Abstain			211,477				1.58

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS:

31.1

Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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.