UNITED STATES
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 quarterly period ended March 31, 2008

o		TRANSITION REPORT PURSUANT TO 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		(I.R.S. employer
incorporation or organization)		identification no.)

410 Seventeenth Street, Suite 1850, Denver, Colorado (Address of principal executive offices)		80202 (Zip code)

(303) 565-4600
(Registrant’s telephone number, including area code)
NONE
(Former name, former address, and former fiscal year, if changed since last report)

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 period 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 checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class		Outstanding as of May 1, 2008
Common stock, $.001 par value		20,973,674

 

 

TETON ENERGY CORPORATION
FORM 10-Q
TABLE OF CONTENTS

		Page
PART I. Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheet as of March 31, 2008 (Unaudited) and December 31, 2007		2
Consolidated Statement of Operations for the Three Months Ended March 31, 2008 and 2007 (Unaudited)		3
Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2008 and 2007 (Unaudited)		4
Notes to Consolidated Financial Statements (Unaudited)		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		12
Item 3. Quantitative and Qualitative Disclosures About Market Risk		20
Item 4. Controls and Procedures		21
PART II. Other Information:
Item 1. Legal Proceedings		21
Item 1A. Risk Factors		21
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		21
Item 3. Defaults Upon Senior Securities		21
Item 4. Submission of Matters to a Vote of Security Holders		21
Item 5. Other Information		21
Item 6. Exhibits		22
Signatures		23
Exhibit 31.1
Exhibit 31.2
Exhibit 32

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TETON ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET
($ amounts in thousands )

		March 31, 2008				December 31, 2007
		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	6,775			$	24,616
Trade accounts receivable			4,161				2,686
Advances to operator			575				—
Tubular inventory			149				149
Prepaid expenses and other assets			222				131
Deferred debt issuance costs – net			740				1,419
Total current assets			12,622				29,001
Oil and gas properties, successful efforts method:
Proved			39,001				35,708
Unproved			14,293				13,411
Wells and facilities in progress			4,730				3,230
Land			153				153
Fixed assets			380				332
Total property and equipment			58,557				52,834
Less accumulated depreciation and depletion			(5,881	)			(3,695	)
Net property and equipment			52,676				49,139
Fair value of oil and gas derivative contracts			533				—
Deferred debt issuance costs – net			149				159
Total assets		$	65,980			$	78,299
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	807			$	400
Accrued liabilities			4,498				7,833
Accrued payroll			708				902
8% senior subordinated convertible notes, net of discount of $3,845 and $7,370 at March 31, 2008 and December 31, 2007 respectively			5,155				1,630
Fair value of oil and gas derivative contracts			2,175				455
Derivative contract liabilities			8,697				9,522
Total current liabilities			22,040				20,742
Long-term liabilities:
Long-term debt — senior secured bank debt			—				8,000
Asset retirement obligations			619				529
Total liabilities			22,659				29,271
Commitments and contingencies (see Note 10)
Stockholders’ equity:
Preferred stock, $.001 par value; 25,000,000 shares authorized; none outstanding as of March 31, 2008 and December 31, 2007			—				—
Common stock, $.001 par value; 250,000,000 shares authorized; 17,975,721 and 17,652,889 shares issued and outstanding as of March 31, 2008 and December 31, 2007, respectively			18				18
Additional paid-in capital			79,373				76,857
Accumulated deficit			(36,070	)			(27,847	)
Total stockholders’ equity			43,321				49,028
Total liabilities and stockholders’ equity		$	65,980			$	78,299

The accompanying notes are an integral part of the consolidated financial statements.

TETON ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS
($ amounts in thousands except share and per share data)
(Unaudited)

		Three Months Ended
		March 31,				March 31,
		2008				2007
Operating revenues:
Oil and gas sales		$	3,640			$	1,198
Operating expenses:
Lease operating expense			350				43
Transportation expense			123				129
Production taxes			202				64
Exploration expense			326				306
General and administrative			3,819				1,879
Depreciation, depletion and accretion expense			2,198				555
Total operating expenses			7,018				2,976
Operating income (loss)			(3,378	)			(1,778	)
Other income (expense):
Realized gain (loss) on oil and gas derivative contracts			(220	)			55
Unrealized (loss) on oil and gas derivative contracts			(1,233	)			(93	)
Gain on derivative contract liabilities			825				—
Interest income			129				29
Interest expense			(4,346	)			(13	)
Total other income (expense)			(4,845	)			(22	)
Net income (loss)		$	(8,223	)		$	(1,800	)
Basic income (loss) per common share		$	(0.46	)		$	(0.12	)
Fully diluted income (loss) per common share		$	(0.46	)		$	(0.12	)
Basic weighted-average common shares outstanding			17,772,955				15,599,815
Fully diluted weighted-average common shares outstanding			17,772,955				15,599,815

The accompanying notes are an integral part of the consolidated financial statements.

TETON ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
($ amounts in thousands of dollars)
(Unaudited)

		Three Months Ended
		March 31,				March 31,
		2008				2007
Operating activities:
Net income (loss)		$	(8,223	)		$	(1,800	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and accretion			2,198				555
Amortization of debt issuance costs			689				13
Amortization of debt discount			3,525				—
Stock-based compensation expense, exclusive of cash withheld for payroll taxes of $329 and $0, respectively			1,450				894
Non-cash (gain) on derivative contract liabilities			(825	)			—
Unrealized loss – oil and gas derivative contracts			1,233				93
Changes in current assets and liabilities:
Trade accounts receivable			(1,475	)			544
Advances to operator			(575	)			—
Prepaid expenses and other current assets			(91	)			32
Accounts payable and accrued liabilities			(412	)			210
Accrued payroll			(194	)			(692	)
Net cash used in operating activities			(2,700	)			(151	)
Investing activities:
Acquisition of corporate fixed assets			(49	)			(5	)
Development of oil and gas properties			(8,070	)			(5,734	)
Net cash used in investing activities			(8,119	)			(5,739	)
Financing activities:
Proceeds from exercise of options/warrants			978				1,829
Net borrowings (repayments) on senior bank credit facility			(8,000	)			1,000
Debt issuance costs			—				(16	)
Net cash provided by (used in) financing activities			(7,022	)			2,813
Increase (decrease) in cash and cash equivalents			(17,841	)			(3,077	)
Cash and cash equivalents – beginning of period			24,616				4,325
Cash and cash equivalents – end of period		$	6,775			$	1,248
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest, net of amounts capitalized		$	170			$	—
Capitalized interest		$	77			$	—
Capital expenditures included in accounts payable and accrued liabilities		$	3,108			$	6,603
Stock-based compensation expense included in capital expenditures		$	88			$	—
Asset retirement obligation additions and revisions associated with oil and gas properties		$	77			$	112

The accompanying notes are an integral part of the consolidated financial statements.

TETON ENERGY CORPORATION

(Unaudited)

1.		General
		Basis of Presentation
		The accompanying unaudited interim consolidated financial statements were prepared by Teton Energy Corporation (“Teton” or the “Company”) pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in the annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted as allowed by such rules and regulations. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year.
		Certain amounts in the 2007 financial statements were reclassified to conform to the 2008 unaudited consolidated financial statement presentation, including, but not limited to, presenting revenues on a gross basis before gathering and transportation expenses which are now included in transportation expense on the Consolidated Statement of Operations.
		The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”), and are supplemented throughout the notes to this quarterly report on Form 10-Q.
		The interim consolidated financial statements presented should be read in conjunction with the financial statements and notes thereto for the year ended December 31, 2007 included in the 2007 Form 10-K filed with the SEC.
		Recently adopted accounting pronouncements
		On January 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) related to financial assets and liabilities, which primarily affect the valuation of our derivative contracts (see Note 4).  In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.  Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis.   The adoption of FAS 157 did not have a material effect on our financial condition or results of operations. We are still in the process of evaluating this standard with respect to its effect on nonfinancial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.
		On January 1, 2008, we adopted the provision of SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”) which permits an entity to measure certain financial assets and financial liabilities at fair value. 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. The adoption of SFAS No. 159 did not have a material effect on our financial condition or results of operations as we did not make any such elections under this fair value option.
		New accounting pronouncements
		In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. SFAS No. 141R requires the acquiring Company to measure almost all assets acquired and liabilities assumed in the acquisition at fair value as of the acquisition date. SFAS No. 141R is effective for fiscal years beginning on or after December 15, 2008 (fiscal 2009 for the Company) and should be applied prospectively with the exception of income taxes which should be applied retrospectively for all business combinations. Early adoption is prohibited. The Company is in the process of evaluating the impacts, if any, of adopting this pronouncement.

		In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” (“SFAS No. 161), an amendment to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 161 requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This Statement will be effective for the Company’s interim and annual financial statements beginning in fiscal year 2010. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. The Company is in the process of evaluating the impacts, if any, of adopting this pronouncement.
2.		Earnings per share of common stock
		Basic income (loss) per common share is computed by dividing net income (loss) by the weighted average number of basic common shares outstanding during each period. The shares represented by vested restricted stock and vested performance share units under the Company’s 2005 Long Term Incentive Plan (see Note 8) are considered issued and outstanding at March 31, 2008 and 2007, respectively, and are included in the calculation of the weighted average basic common shares outstanding. Diluted income (loss) per common share reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock.
		The following is the calculation of basic and fully diluted weighted average shares outstanding and earnings per share of common stock for the periods indicated:

		Three Months Ended
		March 31,				March 31,
		2008				2007
Net income (loss)		$	(8,223	)		$	(1,800	)
Weighted average common shares outstanding – basic			17,772,955				15,599,815
Dilution effect of restricted stock, performance share units, stock options and warrants			—				—
Weighted average common shares outstanding —fully diluted			17,772,955				15,599,815
Earnings (loss) per share of common stock:
Basic		$	(0.46	)		$	(0.12	)
Fully diluted		$	(0.46	)		$	(0.12	)

The following options, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:

		Three Months Ended
		March 31,				March 31,
		2008				2007
Convertible Notes			1,800,000				—
Warrants			4,642,098				867,819
Stock Options			368,305				1,577,665
LTIP Performance Units			448,464				1,911,000
Restricted Common Stock			21,108				235,666
Total			7,279,975				4,592,150

3.		Oil and Gas Properties
		Impairment of Long-Lived Assets
		The Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If upon review the sum of the estimated undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value.

		Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties including undeveloped leaseholds. The Company has not incurred any impairment expense during the three months ended March 31, 2008 or 2007.
		Subsequent Event
		On April 2, 2008, the Company completed the purchase of reserves, production and certain oil and gas properties in the Central Kansas Uplift of Kansas from Shelby Resources, LLC, a private oil and gas company and a group of approximately 14 other working interest owners, collectively (“Sellers”) for approximately $53.4 million before closing adjustments. Terms also include warrant coverage of 625,000 shares at a $6.00 strike price with a two-year term. The effective date of the transaction is March 1, 2008.
		The purchase price was funded with $40.1 million of cash and borrowing capacity available under Teton’s revolving credit facility with JPMorgan and $13.3 million of Teton common stock, or 2,746,124 common shares. Effective April 2, 2008, Teton amended its bank credit facility with JPMorgan, increasing the total facility from $50 million to $150 million. The available borrowing base under Teton’s bank credit facility was increased from $10 million to $50 million as a result of the combination of the added reserves from this transaction, ongoing drilling programs and new hedging positions. The Company has hedged 80 percent of the oil proved developed producing (“PDP”) production and 80 percent of the natural gas PDP production related to this transaction for five years through a series of costless collars in order to lock in base case economics associated with the acquisition (see Note 10).
		Suspended Well Costs
		The company had no exploratory well costs that had been suspended for a period of one year or more as of March 31, 2008 or 2007.
		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 related equipment and facilities, in accordance with applicable state and federal laws. The following table provides a reconciliation of the Company’s asset retirement obligations:

		Three Months Ended
		March 31, 2008
Asset retirement obligation – beginning of period		$	529
Additional liabilities incurred			77
Revisions in estimated cash flows			—
Accretion expense			13
Asset retirement obligation – end of period		$	619

		4.   Fair Value of Financial Instruments
		Effective January 1, 2008, we adopted the provisions of SFAS No. 157, Fair Value measurements, for all financial instruments. The valuation techniques required by SFAS No. 157 are based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent resources, while unobservable inputs reflect our market assumptions. The standard established the following fair value hierarchy:
		Level 1 — Quoted prices for identical assets or liabilities in active markets.
		Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.

		Level 3 — Significant inputs to the valuation model are unobservable.
		The following describes the valuation methodologies we use to measure financial instruments at fair value.
		Debt and Equity Securities
		The recorded value of the Company’s long-term debt approximates its fair value as it bears interest at a floating rate. The Company’s 8% senior subordinated convertible notes (“Convertible Notes”) are recorded at amortized cost as discussed in Note 5 below.
		Derivative Instruments
		The Company uses derivative financial instruments to mitigate exposures to oil and gas production cash-flow risks caused by fluctuating commodity prices. All derivatives are initially, and subsequently, measured at estimated fair value and recorded as liabilities or assets on the balance sheet. For oil and gas derivative contracts that do not qualify as cash flow hedges, changes in the estimated fair value of the contracts are recorded as unrealized gains and losses under the other income and expense caption in the consolidated statement of operations. When oil and gas derivative contracts are settled, the Company recognizes realized gains and losses under the other income and expense caption in its consolidated statement of operations. At March 31, 2008, the Company did not have any derivative contracts that qualify as cash flow hedges.
		Included in the Company’s derivative contracts in place at March 31, 2008 are fixed rate swap arrangements for the sale of oil and natural gas which are valued using Level 1 exchange traded prices. Derivative assets and liabilities included in Level 2 primarily represent hedge contracts, valued using the Black-Scholes-Merton valuation technique, in place through 2013 for a total of approximately 566,189 Bbls of oil production and 2,525,995 MMbtu of natural gas production.
		The Company also uses various types of financing arrangements to fund its business capital requirements, including convertible debt and other financial instruments indexed to the market price of the Company’s common stock. We evaluate these contracts to determine whether derivative features embedded in host contracts require bifurcation and fair value measurement or, in the case of free-standing derivatives (principally warrants) whether certain conditions for equity classification have been achieved. In instances where derivative financial instruments require liability classification, the Company initially and subsequently measures such instruments at estimated fair value using Level 2 inputs. Accordingly, the Company adjusts the estimated fair value of these derivative components at each reporting period through a charge to earnings until such time as the instruments are exercised, expire or are permitted to be classified in stockholders’ equity.
		As of March 31, 2008, the fair value of financing warrants included as a component of current liabilities consisted of warrants to purchase 3,600,000 shares of the Company’s common stock that do not achieve all of the requisite conditions for equity classification. These free-standing derivative financial instruments arose in connection with the Company’s financing transaction in May 2007 which consisted of the $9.0 million Convertible Notes and warrants to purchase 3,600,000 shares of the Company’s common stock at a $5.00 strike price for a period of five years (the “Warrants”) as more fully discussed in Note 5.

The following table summarizes our assets and liabilities measured at fair value on a recurring basis at March 31, 2008.

		Level 1				Level 2				Level 3				Total
Assets:
Oil and gas derivative contracts		$	—			$	533			$	—			$	533
Liabilities:
Oil and gas derivative contracts		$	839			$	1,336			$	—			$	2,175
Derivative contracts — Warrants			—				8,697								8,697
		$	839			$	10,033			$	—			$	10,872

5.		8% Senior Subordinated Convertible Notes
		On May 16, 2007, the Company closed on a financing consisting of $9.0 million face value of 8% Senior Subordinated Convertible Notes due May 16, 2008, which included Warrants to purchase 3,600,000 shares of the Company’s common stock at a $5.00 strike price for a period of five years. The Warrants include a cashless exercise feature. Net proceeds from the sale of the Convertible Notes and Warrants amounted to $8.3 million after fees and expenses. The Convertible Notes bear interest at 8% per annum which is payable on a quarterly basis on July 1, October 1, January 1, and April 1, beginning July 1, 2007, either in cash or common stock at the Company’s option. The Convertible Notes were initially convertible into common stock at a conversion price of $5.00 per share subject to adjustment at maturity to a then market-indexed rate. The conversion feature also provided full-ratchet anti-dilution protection in the event of sales of shares or other share-indexed instruments below the conversion price. The Convertible Notes are unsecured but provide for penalties in the event of default. In addition, on May 18, 2007, the Company issued to the placement agent for this offering warrants to purchase 360,000 shares of the Company’s common stock at a $5.00 strike price with a term of five years.
		On June 28, 2007, the Company amended the Convertible Notes with the holders to, among other things, change the conversion terms at maturity from a variable conversion price to a fixed $5.00 conversion price as the floor at maturity and to modify the anti-dilution protections to fix the $5.00 price as the floor. While the amendment did not give rise to an extinguishment of the original Convertible Notes, the Company concluded that the Convertible Notes met the Conventional Convertible Debt Exemption criteria which provides for classification of the compound embedded derivative in stockholders’ equity. In addition, the removal of the variable conversion price resulted in reclassification of the placement agents’ warrants and certain other warrants to stockholders’ equity. The Warrants continue to require classification as derivative contract liabilities in the Company’s consolidated balance sheet. As a result of the amendment, the principal amount of the Convertible Notes is convertible into 1.8 million shares of the Company’s common stock.
		Accounting for the reclassifications in accordance with EITF 06-7 resulted in the Company adjusting the compound embedded derivative, warrants issued to placement agents and certain other warrants to estimated fair value on the amendment date and reclassifying the adjusted balances to stockholders’ equity without any adjustment to the carrying value or amortization of the host debt instrument.
		The $9.0 million debt component of the Convertible Notes was initially recorded net of debt issuance discount of $9.0 million. The debt issuance discount is being amortized to interest expense over the one year life of the Convertible Notes using the effective interest method. The Company recorded $3.5 million of debt issuance discount amortization during the three months ended March 31, 2008. The remaining debt issuance discount of $3.8 million will be amortized to interest expense during the second quarter of 2008.
		Deferred debt issuance costs of $740 associated with the Convertible Notes are included in current assets as of March 31, 2008 and will be amortized to interest expense using the effective interest method during the second quarter of 2008. The Company recorded $679 of amortization during the three months ended March 31, 2008.

6.		Senior Bank Facility
		On June 15, 2006, the Company entered into a $50.0 million senior revolving credit facility (the “Credit Facility”) with BNP Paribas. The original maturity date of the Credit Facility was June 15, 2010. The Credit Facility had an initial borrowing base of $3.0 million. The borrowing base was increased to $6.0 million on March 12, 2007, and further increased to $10.0 million on July 19, 2007.
		On August 9, 2007, the Company entered into an amended and restated $50.0 million revolving credit facility with JPMorgan Chase, as administrative agent. JPMorgan Chase assumed the Company’s previous Credit Facility with BNP Paribas. The amended Credit Facility originally was scheduled to mature on August 9, 2011. On April 2, 2008, the Company again amended its Credit Facility (“the Amended Credit Facility”) to a $150 million revolving credit facility ($50 million borrowing base). There will be a re-determination of the borrowing base and conforming borrowing base on August 1, 2008 and November 1, 2008.
		Under the Amended Credit Facility, each loan bears interest at a Eurodollar rate (London Interbank Offered Rate, or LIBOR) plus applicable margins of 1.25% to 3.0% or a base rate (the higher of the Prime Rate or the Federal Funds Rate plus 0.5%) plus applicable margins of 0% to 1.5%, as requested by the Company. The Company is also required to pay a commitment fee of 0.375% or 0.5% per annum, based on the daily average unused amount of the commitment. Loans made under the Amended Credit Facility are secured primarily by a first mortgage against the Company’s oil and gas assets and by a pledge of the Company’s equity interests in its subsidiaries and a guaranty by its subsidiaries. The Amended Credit Facility contains customary affirmative and negative covenants such as minimum/maximum ratios for liquidity and leverage.
		On February 11, 2008, the Company repaid the entire $8.0 million balance outstanding under the Credit Facility. The balance outstanding on March 31, 2008 was $0. For the three months ended March 31, 2008, interest expense with respect to the above credit lines totaled $247 and capitalized interest totaled $77.
7.		Stockholders’ Equity
		Warrants
		The following table presents the composition of warrants outstanding and exercisable as of March 31, 2008:

										Weighted
										Average
										Remaining
Range of Exercise Prices							Number			Contractual Life
										(years)
		$	1.75				60,748				0.0
		$	3.24				497,489				3.2
		$	3.48				3,700				0.2
		$	4.35				2,300				0.6
		$	5.00				3,960,000				4.1
		$	6.06				414,547				4.3
Total warrants outstanding and exercisable							4,938,784				4.1

		Subsequent Event
		On April 2, 2008, in conjunction with the purchase of production, reserves and certain oil and gas producing properties in the Central Kansas Uplift, the Company issued 625,000 Warrants to acquire shares of Teton Common Stock. Each Warrant is exercisable on or after July 2, 2008 at an exercise price of $6.00 per share, and expires on April 1, 2010. The Company evaluated these instruments in accordance with SFAS No. 133 and EITF 00-19 and determined, based on the facts and circumstances, that these instruments qualify for classification in stockholders’ equity.

8.		Stock-Based Compensation
		During 2008, 2,777,500 performance share units were granted to Participants, pursuant to the 2005 Long Term Incentive Plan (“LTIP”) by the Compensation Committee (the “2008 Grants”). The 2008 Grants vest in three tranches, provided the goals set forth by the Compensation Committee are met. The performance measure under this Award is based on increases in the Company’s net asset value per share. The grants vest at 20%, 30% and 50% when the net asset value per share of the Company increases by 40%, 100% and 200%, respectively, from a base level set by the Compensation Committee as of December 31, 2007. An additional 207,250 shares of restricted common stock, granted pursuant to the Company’s LTIP, were awarded during the three months ended March 31, 2008. These shares vest over three years based solely on service.
		Compensation expense is recorded at fair value based on the market price of the Company’s common stock at the date of grant and is recognized over the related service period. During the three months ended March 31, 2008, the Company recorded $1.6 million, as a component of general and administrative expense, for stock-based compensation expense applicable to the vesting of LTIP performance-vesting and restricted stock grants. The Company expects to recognize approximately an additional $7.0 million during the twelve months ending December 31, 2008 related to the LTIP performance-vesting and restricted stock grants outstanding at March 31, 2008.
9.		Income Taxes
		For each of the three months ended March 31, 2008 and 2007, the current and deferred provision for income taxes was $0.
		At December 31, 2007, the Company had net operating loss carryforwards (“NOLs”), for federal income tax purposes, of approximately $32.5 million. These NOLs, if not utilized to reduce taxable income in future periods, will expire in various amounts from 2018 through 2027. Approximately $5.8 million of such NOLs is subject to U.S. Internal Revenue Code Section 382 limitations. As a result of these limitations, utilization of this portion of the NOLs is limited to approximately $3.6 million and $2.2 million for the years ending December 31, 2008 and 2009, respectively plus any loss attributable to any built-in gain on assets sold within five years of the ownership change.
		On January 1, 2007, the Company adopted the provisions of FIN 48, which requires that the Company recognize in its consolidated financial statements only those tax positions that are “more-likely-than-not” of being sustained as of the adoption date, based on the technical merits of the position. As a result of the implementation of FIN 48, the Company performed a comprehensive review of its material tax positions in accordance with recognition and measurement standards established by FIN 48. We have no accrued interest or penalties related to uncertain tax positions as of March 31, 2008.
10.		Commitments and Contingencies
		To mitigate a portion of the potential exposure to adverse market changes in the prices of oil and natural gas, the Company has entered into various derivative contracts. Our outstanding commodity hedges as of March 31, 2008 are summarized below:

Type of Contract		Remaining Volume				Fixed Price (1)		Price Index (2)		Contract Period
Oil Fixed Price Swap			16,500			$80.70		WTI		11/01/07-12/31/08
Oil Costless Collar			15,150			$101.40 Floor/$106.00 Ceiling		WTI		04/01/08-04/30/08
Oil Costless Collar			107,895			$95.80 Floor/$103.00 Ceiling		WTI		05/01/08-12/31/08
Oil Costless Collar			443,144			$90.00 Floor/$104.00 Ceiling		WTI		01/01/09-04/30/13
Total Bbl			582,689
Natural Gas Fixed Price Swap			210,000			$5.78		CIGRM		08/01/07-10/31/08
Natural Gas Costless Collar			612,000			$6.00 Floor/$7.10 Ceiling		CIGRM		02/01/08-01/31/09
Natural Gas Costless Collar			1,652,573			$6.50 Floor/$7.75 Ceiling		CIGRM		02/01/09-04/30/13
Natural Gas Costless Collar			261,422			$9.10 Floor/$9.75 Ceiling		NYMEX		05/01/08-04/30/13
Total MMBtu			2,735,995

On April 30, 2008, the Company entered into a lease agreement for new office space in Denver beginning September 1, 2008 for a period of 69 months. Rental payments, before expenses, under the lease is $65,000 for the remainder of 2008, $236,000 for 2009 and $1,240,000 thereafter. After September 1, 2008, the Company has no further obligations under its current lease agreement.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The terms “Teton”, “Company”, “we”, “our” and “us” refer to Teton Energy Corporation and its subsidiaries, as a consolidated entity, unless the context suggests otherwise.

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains both historical and “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements, written, oral or otherwise made, represent the Company’s expectation or belief concerning future events. All statements, other than statements of historical fact, are or may be forward-looking statements. For example, statements concerning projections, predictions, expectations, estimates or forecasts, and statements that describe our objectives, future performance, plans or goals are, or may be, forward-looking statements. These forward-looking statements reflect management’s current expectations concerning future results and events and can generally be identified by the use of words such as “may,” “will,” “should,” “could,” “would,” “likely,” “predict,” “potential,” “continue,” “future,” “estimate,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “foresee,” and other similar words or phrases, as well as statements in the future tense.

Forward-looking statements involve known and unknown risks, uncertainties, assumptions, and other important factors that may cause our actual results, performance, or achievements to be different from any future results, performance and achievements expressed or implied by these statements. The following important risks and uncertainties could affect our future results, causing those results to differ materially from those expressed in our forward-looking statements:

	•		General economic and political conditions, including governmental energy policies, tax rates or policies and inflation rates;
	•		The market price of, and demand for, oil and natural gas;
	•		Our ability to service current and future indebtedness;
	•		Our success in completing development and exploration activities;
	•		Reliance on outside operating companies for drilling and development of our oil and gas properties;
	•		Expansion and other development trends of the oil and gas industry;
	•		Acquisitions and other business opportunities that may be presented to and pursued by us;
	•		Our ability to integrate our acquisitions into our company structure;
	•		Changes in laws and regulations; and
	•		Other Risk Factors described in Item 1A of this Quarterly Report on Form 10-Q, and in our Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 13, 2008 (the “2007 Form 10-K”).

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors, including unknown or unpredictable ones could also have material adverse effects on our future results.

The following discussion should be read in conjunction with Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – included in our 2007 Form 10-K.

Overview and Strategy

We are an independent energy company engaged primarily in the development, production and marketing of oil and natural gas in North America. Our current operations are focused in four basins in the Rocky Mountain region of the United States: the Piceance, DJ, Williston and Big Horn Basins. Subsequent to the first quarter of 2008, we acquired producing properties and acreage in Central Kansas.

Teton Energy was formed in November 1996 and is incorporated in the State of Delaware. Our common shares are publicly traded on the American Stock Exchange under the symbol “TEC.”

Our principal executive offices are located at 410 Seventeenth Street, Suite 1850, Denver, CO 80202, and our telephone number is (303) 565-4600. Our web site is www.teton-energy.com.

Our objective is to increase stockholder value by pursuing our corporate strategy of:

	•		economically growing reserves and production, by acquiring under-valued properties with reasonable risk-reward potential and by participating in, or actively conducting, drilling operations in order further to exploit our existing properties;
	•		seeking high-quality exploration and development projects with potential for providing operated, long-term drilling inventories; and
	•		selectively pursuing strategic acquisitions that may expand or complement our existing operations.

The pursuit of our strategy includes the following key elements:

Pursue Attractive Reserve and Leasehold Acquisitions

To date, acquisitions have been critical in establishing our asset base. We believe that we are well positioned, given our initial success in identifying and quickly closing on attractive opportunities in the Piceance, DJ, Williston and Big Horn Basins, and our recent acquisition in the Central Kansas Uplift, to effect opportunistic acquisitions that can provide upside potential, including long-term drilling inventories and undeveloped leasehold positions with attractive return characteristics. Our focus is to acquire assets that provide the opportunity for developmental drilling and/or the drilling of extensional step-out wells, which we believe will provide us with significant upside potential while not exposing us to the risks associated with drilling new field wildcat wells in frontier basins. On April 2, 2008, we acquired the Central Kansas Uplift properties, which included an additional 50 producing wells (see further discussion below).

Drive Growth through Drilling

We plan to supplement our long-term reserve and production growth through drilling operations. In 2007, we participated in the drilling of 41 gross wells in connection with our Piceance Basin project where we have a 12.5% non-operated working interest, 81 gross wells in the DJ Basin under the Noble Earning Agreement where we have a 25% non-operated working interest in the AMI and 3 gross wells in the Williston Basin (in one gross well, we have a 25% non-operated working interest and, in the other two gross wells, a 5.95% and 1.56% non-operated working interest). In 2008, we anticipate that we will participate in the drilling of 52 gross wells in the Berry Petroleum Company (“Berry”) operated properties in the Piceance Basin, in the drilling of 163 gross wells in the Noble-operated properties in the Teton – Noble AMI, and in the drilling of 4 gross wells in the Evertson-operated properties in the Williston Basin.  During 2008 we also anticipate that we will drill 50 gross wells on properties operated by us, including 17 gross wells in the DJ Basin (Frenchman Creek, South Frenchman Creek and Washco), 4 gross wells in the Big Horn Basin properties and 29 gross wells in the newly acquired Central Kansas Uplift properties (see further discussion below).

Maximize Operational Control

It is strategically important to our future growth and maturation as an independent exploration and production company to be able to serve as operator of our properties when possible in order to be able to exert greater control over costs and timing in and the manner of our exploration, development, and production activities. In 2007, we acquired 499,904 gross acres (413,786 net) in the DJ Basin Washco properties, including about 1.0 MMcfed of production, 111,872 gross acres (109,688 net) in the DJ Basin South Frenchman Creek properties, 28,204 gross acres (11,689 net) in the DJ Basin Frenchman Creek properties and 16,417 gross acres (15,132 net) in the Big Horn Basin properties, all of which are properties operated by us. On April 2, 2008, we acquired an additional 48,100 gross acres (31,650 net) in the Central Kansas Uplift, all of which is also operated by us (see further discussion below) as well as an additional 6,383 gross (4,519 net) acreas in the Big Horn Basin in 2008.

Operate Efficiently and Effectively, and Maximize Economies of Scale Where Practical

Our objective is to generate profitable growth and high returns for our stockholders, and we expect that our unit cost structure will benefit from economies of scale as we grow and from our continuing cost management initiatives. As we manage our growth, we are actively focusing on reducing lease operating expenses and finding and development costs. In addition, our acquisition efforts are geared toward pursuing opportunities that fit well within existing operations, in areas where we are establishing new operations or in areas where we believe that a base of existing production will produce an adequate foundation for economies of scale.

Pursuit of Selective Complementary Acquisitions

We seek to acquire long-lived producing properties with a high degree of operating control, or oil and gas concerns that enjoy good business reputations and that offer economical opportunities to increase our natural gas and crude oil reserves.

On April 2, 2008, we completed the purchase of reserves, production and certain oil and gas properties in the Central Kansas Uplift of Kansas from Shelby Resources, LLC, a private oil and gas company and a group of approximately 14 other working interest owners, collectively (“Sellers”) for approximately $53.4 million before closing adjustments. Terms also include warrant coverage of 625,000 shares at a $6.00 strike price with a two-year term. The effective date of the transaction is March 1, 2008.

The purchase price was funded with $40.1 million of cash and $13.3 million of Teton common stock, or 2,746,124 common shares. Effective April 2, 2008, we amended our bank credit facility with JPMorgan, increasing the total facility from $50 million to $150 million. The available borrowing base under our bank credit facility was increased from $10 million to $50 million as a result of the combination of the added reserves from this transaction, ongoing drilling programs and new hedging positions. We have hedged 80 percent of the oil proved developed producing (“PDP”) production and 80 percent of the natural gas PDP production related to this transaction for five years through a series of costless collars in order to lock in base case economics associated with the acquisition.

Following are summary comments of our performance in several key areas during the three month period ended March 31, 2008 (Dollar amounts in thousandss, except amounts per unit of production):

Net income (loss)

Our net loss increased from $1,800 (or $0.12 per share) for the three months ended March 31, 2007, to $8,223 (or $0.46 per share) for the three months ended March 31, 2008. The increase in net loss of $6,423 is due largely to an increase in general and administrative expenses (largely due to an increase in non-cash compensation of $900) and an increase in non-cash interest expense related to the amortization of deferred debt discount and issuance costs of $4,200, and less significantly to an increase in lease operating and related production expenses (due primarily to increased production and production in new locations with per unit LOE that is slightly higher). These increases in operating and interest expenses were slightly offset by a 204% increase in oil and gas revenues, from $1,198 in the first quarter of 2007 to $3,640 in the first quarter of 2008.

Production

Production increased to 422,255 Mcfe for the three months ended March 31, 2008, compared to 202,887 Mcfe for the same prior year period. This increase does not include any impact from the Company’s acquisition of producing properties in Central Kansas. The Company will begin recognizing its share of production and related sales from the area in April of 2008.

Piceance. Net production in the area increased to 263,562Mcfe for the three months ended March 31, 2008, compared to 196,489 Mcfe for the same prior year period. The increase is due primarily to an increase in producing well count, offset slightly by the normal production decline of existing wells and more so by the fact that we sold half of our 25% working interest in the Piceance Basin non-operated properties for $36.7 million in cash, including purchase price adjustments, and oil and gas properties and related production values at $4.7 million in the fourth quarter 2007. Four new wells came on-line during March 2008 bringing the total producing well count to 57 wells as of March 31, 2008 with 17 additional wells waiting on completion. As of March 31, 2007 there were 20 producing wells in the area.

Teton Noble AMI. As of March 31, 2008, there were 78 gross producing non-operated wells in the DJ Noble area of the DJ Basin with an additional 15 waiting on completion. This producing well count is compared to seven producing wells as of the same prior year period. Production increased from 2,360 Mcfe for the three months ended March 31, 2007 to 54,788 Mcfe for the three months ended March 31, 2008. Noble commenced its 2008 drilling program on March 23, 2008, and we have been informed by the operator that it intends to drill approximately 163 gross wells, 40 net to our interest, during 2008.

Washco. As of March 31, 2008, there were 27 gross productive wells in the Washco area of the DJ Basin, operated by the Company, that produced a total of 93,991 Mcfe during the three months ended March 31, 2008. The Company recognized its first production in the area during the fourth quarter of 2007.

Williston. For the three months ended March 31, 2008, production in the area was 9,914 Mcfe as compared to 4,038 Mcfe during the same prior year period. We participated in the drilling of two Bakken test wells and a Red River test well in the Williston Basin of North Dakota in the year ended December 31, 2007. In April 2008, the Company received a proposal, from the operator, to drill a vertical well targeted to test the Stonewall, Red River and Winnipeg formations at an estimated gross cost of $3.8 million.

Oil and Gas Sales

Oil and gas sales increased 204% from $1,198 for the three months ended March 31, 2007 to $3,640 for the three months ended March 31, 2008. The increase in total revenue is due to both increased production volumes, as discussed above by operating area, and an increase in the average price per Mcfe. The average price per Mcfe increased $2.72 per Mcfe, from $5.90 to $8.62 per Mcfe. The increase in price per Mcfe is largely impacted by an increase in oil volumes as a percentage of total volumes as well as higher average spot prices.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of liquidity have been cash provided by equity offerings and borrowings under our bank credit facility. In the past, these sources have been sufficient to meet the needs of the business. As a result of our developmental drilling program in 2007, the continued development drilling in 2008 and the additional producing well count added from the April 2, 2008 acquisition in the Central Kansas Uplift, we expect that cash flow from operating activities will begin to contribute more significantly to our cash requirements for the remainder of 2008 and for the foreseeable future thereafter. We believe that cash on hand, amounts available under our $150 million credit facility($50 million borrowing base) at March 31, 2008, together with anticipated net cash provided by operating activities during 2008, will provide us with sufficient funds to develop new reserves, maintain our current facilities and complete our current capital expenditure program through 2008. Depending on the timing and amount of future projects, we may be required to seek additional sources of capital. While we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.

We may also receive proceeds from the exercise of outstanding warrants and/or options as we did during previous years. At March 31, 2008 warrants to purchase 4,938,784 shares of common stock were outstanding. These warrants have a weighted average exercise price of $4.87 per share and expire between April 2008 and December 2012. At March 31, 2008, options to purchase 1,415,844 shares of common stock were outstanding. These options have a weighted average exercise price of $3.55 per share and expire between April 2013 and May 2015. During the first quarter 2008, we received proceeds of approximately $978 from the exercise of warrants.

Credit Facility

On August 9, 2007, the $50 million revolving credit facility with BNP Paribas (the “Credit Facility”) was replaced by an amended and restated Credit Facility with JP Morgan Chase Bank, N.A. The amended and restated Credit Facility had an initial borrowing capacity of $50 million, and was amended on April 2, 2008 to a $150 million revolving credit facility ($50 million borrowing base) as a result of the additional reserves related to the acquisition of the Central Kansas Uplift properties previously discussed.

The following table provides information about our financial position (amounts in thousands, except ratios):

		March 31,				December 31,
		2008				2007
Financial Position Summary
Cash and cash equivalents		$	6,775			$	24,616
Working capital		$	(9,418	)		$	8,259
Debt outstanding		$	5,155			$	9,630
Stockholders’ equity		$	43,321			$	49,028
Ratios
Long-term debt to total capital ratio			0.0	%			14.0	%
Total debt to equity ratio			11.9	%			19.6	%

During the three months ended March 31, 2008, we had negative working capital of $9,418, due primarily to a decrease in cash and cash equivalents related to the pay-off of the $8.0 million Senior Secured Bank debt during the first quarter of 2008, cash expenditures primarily for our share of drilling and completion expenses in the non-operated properties of the Piceance, the increase in the balance sheet amount of the 8% convertible notes due to amortization of the original issue discount during the first quarter of $3.5 million, and the increase in the liability related to oil and gas derivatives.

Cash Flows and Capital Requirements

The following table summarizes our cash flows for the periods indicated:

		Three months ended March 31,
		2008				2007
Cash provided by (used in):
Operating Activities		$	(2,700	)		$	(151	)
Investing Activities			(8,119	)			(5,739	)
Financing Activities			(7,022	)			2,813
Net change in cash		$	(17,841	)		$	(3,077	)

During the three months ended March 31, 2008, net cash used in operating activities was $2,700 as compared to $151 during the same prior year period. Our net loss increased by $6,423 in the first quarter of 2008 as compared to the first quarter of 2007. This increase in net loss was somewhat offset by an increase in non-cash charges related to depreciation, depletion and amortization of $1,643, amortization of deferred debt discount and issuance costs of $4,200 and non-cash compensation of $556.

During the three months ended March 31, 2008, net cash used in investing activities was $8,119 as compared to $5,739 in the same prior year period. Cash expenditures during the three month period relate largely to continued development of the Piceance Basin Play and Teton-Noble AMI and were funded primarily by cash on hand.

During the three months ended March 31, 2008 net cash used in financing activities was $7,022 as compared to net cash provided by financing activities of $2,813 in the same prior year period. During the three months ended March 31, 2008, we repaid the $8.0 million outstanding as of December 31, 2007 under our senior bank credit facility. This net repayment was offset slightly by funds received from the exercise of warrants during the period.

Our capital budget for 2008 of $43 million includes planned drilling in the Piceance, DJ and Williston Basins and the Central Kansas Uplift. Of that amount approximately $8.7 million had been accrued or expended at March 31, 2008 primarily for our share of drilling and completion expenses in the non-operated properties of the Piceance. Additionally, we are planning to drill four wells in the Big Horn Basin that are not currently included in the 2008 budget. The amounts to be included for those properties will be determined when we have added a partner to the operation. Our planned 2008 development and exploration expenses could also increase if any of the operations associated with our properties experience cost overruns, or if: (1) Berry, as operator for the Piceance Basin play, increases the drilling program, (2) Noble, as operator for the Teton-Noble AMI play, increase the drilling program, or (3) Evertson, as operator for the Williston Basin play, increases the drilling program.

Contractual Obligations

We have a Company hedging policy in place, to protect a portion of our production against future pricing fluctuations. Our outstanding hedges as of March 31, 2008 are summarized below:

Type of Contract		Remaining Volume				Fixed Price (1)		Price Index (2)		Contract Period
Oil Fixed Price Swap			16,500			$80.70		WTI		11/01/07-12/31/08
Oil Costless Collar			15,150			$101.40 Floor/$106.00 Ceiling		WTI		04/01/08-04/30/08
Oil Costless Collar			107,895			$95.80 Floor/$103.00 Ceiling		WTI		05/01/08-12/31/08
Oil Costless Collar			443,144			$90.00 Floor/$104.00 Ceiling		WTI		01/01/09-04/30/13
Total Bbl			582,689
Natural Gas Fixed Price Swap			210,000			$5.78		CIGRM		08/01/07-10/31/08
Natural Gas Costless Collar			612,000			$6.00 Floor/$7.10 Ceiling		CIGRM		02/01/08-01/31/09
Natural Gas Costless Collar			1,652,573			$6.50 Floor/$7.75 Ceiling		CIGRM		02/01/09-04/30/13
Natural Gas Costless Collar			261,422			$9.10 Floor/$9.75 Ceiling		NYMEX		05/01/08-04/30/13
Total MMBtu			2,735,995

The collared hedges shown above have the effect of providing a protective floor while allowing us to share in upward pricing movements to a fixed point. Consequently, while these hedges are designed to decrease our exposure to price decreases while allowing us to share in some upside potential of price increases, they also have the effect of limiting the benefit of price increases beyond the ceiling. For the natural gas contracts listed above, a $0.10 hypothetical change in the CIGRM or NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause a change in the unrealized gain or loss on hedging activities in 2008 of $274. For the oil contracts listed above, a $1.00 hypothetical change in the WTI price above the ceiling price or below the floor price applies to the notional amounts would cause a change in the unrealized gain or loss on hedging activities in 2008 or $583. The Company plans to continue to evaluate the possibility of entering into derivative contracts, as prices change and additional volumes become available in the future, to decrease exposure to commodity price volatility.

Off Balance Sheet Arrangements

We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Quarterly Report on Form 10-Q.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

On January 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) related to financial assets and liabilities, which primarily affects the valuation of our derivative contracts (see Note 4 to the Notes to the Consolidated Financial Statements included in this Form 10-Q). In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The adoption of FAS 157 did not have a material effect on our financial condition or results of operations. We are still in the process of evaluating this standard with respect to its effect on nonfinancial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

On January 1, 2008, we adopted the provision of SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”) which permits an entity to measure certain financial assets and financial liabilities at fair value. 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. The adoption of SFAS No. 159 had no effect on our financial condition or results of operations as we did not make any such elections under this fair value option.

New accounting pronouncements

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. SFAS No. 141R requires the acquiring Company to measure almost all assets acquired and liabilities assumed in the acquisition at fair value as of the acquisition date. SFAS No. 141R is effective for fiscal years beginning on or after December 15, 2008 (fiscal 2009 for the Company) and should be applied prospectively with the exception of income taxes which should be applied retrospectively for all business combinations. Early adoption is prohibited. We are in the process of evaluating the impacts, if any, of adopting this pronouncement.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008 (fiscal 2009 for the Company). We are in the process of evaluating the impacts, if any, of adopting this pronouncement, but currently does not believe it will apply to the Company.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” (“SFAS No. 161), an amendment to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 161 requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This Statement will be effective for our interim and annual financial statements beginning in fiscal year 2010. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We are in the process of evaluating the impacts, if any, of adopting this pronouncement.

FAIR VALUE MEASUREMENT

Effective January 1, 2008, we adopted the provisions of SFAS No. 157, for all financial instruments. The valuation techniques required by SFAS No. 157 are based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent resources, while unobservable inputs reflect our market assumptions. The standard established the following fair value hierarchy:

Level 1 — Quoted prices for identical assets or liabilities in active markets.

Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.

Level 3 — Significant inputs to the valuation model are unobservable.

The following describes the valuation methodologies we use to measure financial instruments at fair value.

Debt and Equity Securities

The recorded value of our long-term debt approximates its fair value as it bears interest at a floating rate. Our derivative financial instruments are recorded at estimated fair value as described above. Our 8% senior subordinated convertible notes (“Convertible Notes”) are recorded at amortized cost.

Derivative Instruments

We use derivative financial instruments to mitigate exposures to oil and gas production cash-flow risks caused by fluctuating commodity prices. All derivatives are initially, and subsequently, measured at estimated fair value and recorded as liabilities or assets on the balance sheet. For oil and gas derivative contracts that do not qualify as cash flow hedges, changes in the estimated fair value of the contracts are recorded as unrealized gains and losses under the other income and expense caption in the consolidated statement of operations. When oil and gas derivative contracts are settled, we recognize realized gains and losses under the other income and expense caption in our consolidated statement of operations.

Included in the our derivative contracts in place at March 31, 2008 are fixed rate swap arrangements for the sale of oil and natural gas which are valued using Level 1 exchange traded prices. Derivative assets and liabilities included in Level 2 primarily represent collared hedge contracts in place through 2013 which are valued using the Black-Scholes-Merton Pricing Model, or a similar model.

We also use various types of financing arrangements to fund our business capital requirements, including convertible debt and other financial instruments indexed to the market price of the our common stock. We evaluate these contracts to determine whether derivative features embedded in host contracts require bifurcation and fair value measurement or, in the case of free-standing derivatives (principally warrants) whether certain conditions for equity classification have been achieved. In instances where derivative financial instruments require liability classification, the Company initially and subsequently measures such instruments at estimated fair value using Level 2 inputs in the Black-Scholes-Merton Pricing Model. Accordingly, we adjust the estimated fair value of these derivative components at each reporting period through a charge to earnings until such time as the instruments are exercised, expire or are permitted to be classified in stockholders’ equity.

RESULTS OF OPERATIONS

Three months ended March 31, 2008 compared to the three months ended March 31, 2007

Sales volume and price comparisons

		Three months ended March 31,
		2008								2007
		Volume				Average Price (1)				Volume				Average Price (1)
Product:
Gas (Mcf)			338,189			$	7.25				192,045			$	5.75
Oil (Bbls)			14,011			$	84.91				1,807			$	52.17
Mcfe			422,255			$	8.62				202,887			$	5.90

For the three months ended March 31, 2008, we had net loss from continuing operations of $8,223 as compared to $1,800 in the same prior year period. Factors contributing to the $6,423 increase in net loss include the following:

Oil and gas production for the three months ended March 31, 2007 increased 108% to 422,255 Mcfe as compared to 202,887 Mcfe in the same prior year period. The increase in production is largely attributed to increased production in the Piceance Basin play, the Teton — Noble AMI and the Washco operating area. Production in the Piceance increased to 263,562 Mcfe for the three months ended March 31, 2008 as compared to 196,489 Mcfe for the same prior year period. The increase is due primarily to an increase in producing well count, offset slightly by the normal production decline of existing wells and more so by the fact that we sold half of our 25% working interest in the Piceance Basin non-operated properties for $36.7 million in cash, including purchase price adjustments, and oil and gas properties and related production values at $4.7 million in the fourth quarter 2007. Production in the Teton — Noble AMI increased from 2,360 Mcfe for the three months ended March 31, 2007 to 54,788 Mcfe for the three months ended March 31, 2008, due to increased drilling activity. Washco production for the three months ended March 31, 2008 was 93,991 Mcfe. We recognized our first production in the area during the fourth quarter of 2007.

Oil and gas sales increased 204% from $1,198 for the three months ended March 31, 2007 to $3,640 for the three months ended March 31, 2008. The increase in total revenue is due to both increased production volumes, as discussed above by operating area, and an increase in the average price per Mcfe. The average price per Mcfe increased $2.72 per Mcfe, from $5.90 to $8.62 per Mcfe. More typical winter weather and lower average natural gas storage volumes combined to produce higher average first quarter prices for natural gas in 2008 compared to 2007.

Oil and gas production expenses

		Three Months Ended March 31,
		2008				2007
		(in dollars per Mcfe)
Average price		$	8.62			$	5.90
Production costs			1.12				0.85
Production taxes			0.48				0.32
Total operating costs			1.60				1.17
Cash gross margin		$	7.02			$	4.73
Cash gross margin percentage			81	%			80	%

Our production costs (lease operating expenses, transportation costs and production taxes) for the three month ended March 31, 2008 increased $439, due primarily to increased production discussed above.

General and administrative expenses increased $1,940, from $1,879 to $3,819 for the three months ended March 31, 2008. The increase is due primarily to an increase in compensation expense of $1,200 related to (1) cash compensation related to additional headcount over the same prior year period ($300) and (2) the increase in non-cash compensation charges for presumed vesting of the performance share LTIP awards ($900), an increase in professional fees of $540 related to Sarbanes Oxley and financial consultant work performed in the first quarter of 2008, an increase of $90 for office rent and related expenses due to the additional headcount, and office space and an increase in corporate communications of $130 resulting from additional attendance at conferences during the three months ended March 31, 2008. There were no other individually significant increases or decreases.

Depletion and depreciation expense increased from $555 for the three months ended March 31, 2007 to $2,198 for the three months ended March 31, 2008. This increase is due primarily to the increased production and higher capital costs over the same prior year period.

During the three months ended March 31, 2008, we recorded a net unrealized loss on derivative contracts of $408. The loss represents marking the derivative contracts to market at March 31, 2008, based on the future expected prices of the related commodities (see discussion on fair value measurement above).

Interest expense for the three months ended March 31, 2008 was $4,346 and included $3,525 and $679 of amortization of debt issuance discount and costs, respectively related to the 8% Senior Subordinated Convertible Notes. The remaining debt issuance discount and issuance costs of $3,845 and $740, respectively will be recognized during the second quarter of 2008.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 nature 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.

Commodity 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 commodity prices have been volatile and unpredictable for several years. The prices we receive for our production depend on numerous factors beyond our control. Based on our production for the three months ended March 31, 2008, our income before income taxes for the period would have moved up or down approximately $8 for every $1.00 change in oil prices and $12 for every $0.10 change in natural gas prices.

We have entered into derivative contracts to manage our exposure to oil and natural gas price volatility. We have a Company hedging policy in place to protect a portion of our production against future pricing fluctuations. Refer to contractual obligations above for a breakout of our outstanding hedge positions at March 31, 2008.

Interest Rate Risk

At March 31, 2007, we had $0 outstanding on our Credit Facility. Under the Amended Credit Facility, each loan bears interest at a Eurodollar rate (London Interbank Offered Rate, or LIBOR) plus applicable margins of 1.25% to 3.0% or a base rate (the higher of the Prime Rate or the Federal Funds Rate plus 0.5%) plus applicable margins of 0% to 1.5%, as requested by the Company. The Company is also required to pay a commitment fee of 0.375% or 0.5% per annum, based on the average daily amount of the unused amount of the commitment. Assuming that we were to draw down on the entire $10 million available to us under our Credit Facility, at March 31, 2008, a one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate would result in an additional interest expense to us of approximately $25 per quarter.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that as of March 31, 2008, our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

There has been no change in our internal control over financial reporting that occurred during the quarter ended March 31, 2008 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

We are not a party to any legal proceedings.

ITEM 1A. RISK FACTORS

There were no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2007 Annual Report on Form 10-K filed with the Securities and Exchange Commission, on March 13, 2008.

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.

No matters were submitted to a vote of our security holders during the first quarter of 2008.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS

The following exhibits are filed as part of this report:

Exhibit Number and Description:

3.1.1		Certificate of Incorporation of EQ Resources Ltd incorporated by reference to Exhibit 2.1.1 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.2		Certificate of Domestication of EQ Resources Ltd incorporated by reference to Exhibit 2.1.2 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.3		Articles of Merger of EQ Resources Ltd. and American-Tyumen Exploration Company incorporated by reference to Exhibit 2.1.3 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.4		Certificate of Amendment of Teton Petroleum Company incorporated by reference to Exhibit 2.1.4 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.5		Certificate of Amendment of Teton Petroleum Company incorporated by reference to Exhibit 2.1.5 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.6		Certificate of Amendment to Certificate of Incorporation, dated June 28, 2005, incorporated by reference to Exhibit 10.1 of Teton’s Form 10-Q filed on August 15, 2005.
3.2		Bylaws, as amended, of Teton Petroleum Company incorporated by reference to Exhibit 3.2 of Teton’s Form 10-QSB, filed August 20, 2002.
4.1		Form of Senior Subordinated Convertible Note in connection with Teton’s May 2007 financing, incorporated by reference to Exhibit 4.1 of Teton’s Form 10-Q filed on August 14, 2007.
4.2		Form of Common Stock Purchase Warrant issued to investors in connection with Teton’s May 2007 financing, incorporated by reference to Exhibit 4.2 of Teton’s Form 10-Q filed on August 14, 2007.
4.3		Form of Common Stock Purchase Warrant issued to investors and placement agents in connection with Teton’s July 2007 financing, incorporated by reference to Exhibit 4.3 of Teton’s Form 10-Q filed on August 14, 2007.
10.1		Advisory Services Agreement dated as of July 1, 2007, between Teton and Commonwealth Associates, L.P., incorporated by reference to Exhibit 10.4 to Teton’s Registration Statement on Form S-3/A (File No. 333-145164), filed September 18, 2007.
10.2		Purchase, Sale and Exploration Agreement dated March 24, 2008, entered into on March 28, 2008 by and between, Teton Energy Corporation and Shelby Resources LLC, incorporate by reference to Exhibit 10.1 of Teton’s Form 8-K filed April 3, 2008.
10.3		Form of Registration Rights Agreement in connection with the issuances of the shares of Common Stock and the Warrants, in connection with the Purchase, Sale and Exploration Agreement dated March 24, 2008 by and between, Teton Energy Corporation and Shelby Resources LLC, incorporated by reference to Exhibit 10.2 of Teton’s Form 8-K filed April 3, 2008.
10.4		Form of Teton Energy Corporation Common Stock Purchase Warrant issued in connection with the Purchase, Sale and Exploration Agreement dated March 24, 2008 by and between, Teton Energy Corporation and Shelby Resources LLC, incorporated by reference to Exhibit 10.3 of Teton’s Form 8-K filed April 3, 2008.
10.5		Second Amended and Restated Credit Agreement dated as of April 2, 2008 among Teton Energy Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto, incorporated by reference to Exhibit 10.4 of Teton’s Form 8-K filed April 3, 2008.
31.1		Certification by Chief Executive Officer pursuant to Sarbanes-Oxley Section 302, filed herewith.
31.2		Certification by Chief Financial Officer pursuant to Sarbanes-Oxley Section 302, filed herewith.
32		Certification by Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, filed herewith.

SIGNATURES

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

EXHIBIT INDEX

Exhibit Number				Description
3.1.1				Certificate of Incorporation of EQ Resources Ltd incorporated by reference to Exhibit 2.1.1 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.2				Certificate of Domestication of EQ Resources Ltd incorporated by reference to Exhibit 2.1.2 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.3				Articles of Merger of EQ Resources Ltd. and American-Tyumen Exploration Company incorporated by reference to Exhibit 2.1.3 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.4				Certificate of Amendment of Teton Petroleum Company incorporated by reference to Exhibit 2.1.4 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.5				Certificate of Amendment of Teton Petroleum Company incorporated by reference to Exhibit 2.1.5 of Teton’s Form 10-SB (File No. 000-31170), filed July 3, 2001.
3.1.6				Certificate of Amendment to Certificate of Incorporation, dated June 28, 2005, incorporated by reference to Exhibit 10.1 of Teton’s Form 10-Q filed on August 15, 2005.
3.2				Bylaws, as amended, of Teton Petroleum Company incorporated by reference to Exhibit 3.2 of Teton’s Form 10-QSB, filed August 20, 2002.
4.1				Form of Senior Subordinated Convertible Note in connection with Teton’s May 2007 financing, incorporated by reference to Exhibit 4.1 of Teton’s Form 10-Q filed on August 14, 2007.
4.2				Form of Common Stock Purchase Warrant issued to investors in connection with Teton’s May 2007 financing, incorporated by reference to Exhibit 4.2 of Teton’s Form 10-Q filed on August 14, 2007.
4.3				Form of Common Stock Purchase Warrant issued to investors and placement agents in connection with Teton’s July 2007 financing, incorporated by reference to Exhibit 4.3 of Teton’s Form 10-Q filed on August 14, 2007.
10.1				Advisory Services Agreement dated as of July 1, 2007, between Teton and Commonwealth Associates, L.P., incorporated by reference to Exhibit 10.4 to Teton’s Registration Statement on Form S-3/A (File No. 333-145164), filed September 18, 2007.
10.2				Purchase, Sale and Exploration Agreement dated March 24, 2008, entered into on March 28, 2008 by and between, Teton Energy Corporation and Shelby Resources LLC, incorporate by reference to Exhibit 10.1 of Teton’s Form 8-K filed April 3, 2008.
10.3				Form of Registration Rights Agreement in connection with the issuances of the shares of Common Stock and the Warrants, in connection with the Purchase, Sale and Exploration Agreement dated March 24, 2008 by and between, Teton Energy Corporation and Shelby Resources LLC, incorporated by reference to Exhibit 10.2 of Teton’s Form 8-K filed April 3, 2008.
10.4				Form of Teton Energy Corporation Common Stock Purchase Warrant issued in connection with the Purchase, Sale and Exploration Agreement dated March 24, 2008 by and between, Teton Energy Corporation and Shelby Resources LLC, incorporated by reference to Exhibit 10.3 of Teton’s Form 8-K filed April 3, 2008.
10.5				Second Amended and Restated Credit Agreement dated as of April 2, 2008 among Teton Energy Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto, incorporated by reference to Exhibit 10.4 of Teton’s Form 8-K filed April 3, 2008.
31.1				Certification by Chief Executive Officer pursuant to Sarbanes-Oxley Section 302, filed herewith.
31.2				Certification by Chief Financial Officer pursuant to Sarbanes-Oxley Section 302, filed herewith.
32				Certification by Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, filed herewith.