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, 2009

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 incorporation or organization)		(I.R.S. employer identification no.)

600 17th Street, Suite 1600 North, 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 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 check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

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, 2009
Common stock, $.001 par value		23,944,646

 

 

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, 2009 (Unaudited) and December 31, 2008			2
Consolidated Statement of Operations for the Three Months Ended March 31, 2009 and 2008 (Unaudited)			3
Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2009 and 2008 (Unaudited)			4
Notes to Consolidated Financial Statements (Unaudited)			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
Item 3. Quantitative and Qualitative Disclosures About Market Risk			26
Item 4. Controls and Procedures			26
PART II. Other Information:
Item 1. Legal Proceedings			27
Item 1A. Risk Factors			27
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			28
Item 3. Defaults Upon Senior Securities			28
Item 4. Submission of Matters to a Vote of Security Holders			28
Item 5. Other Information			28
Item 6. Exhibits			28
Signatures			30
Exhibit 31.1
Exhibit 31.2
Exhibit 32

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TETON ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET
(000s except share)

		March 31, 2009				December 31, 2008
		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	360			$	—
Trade accounts receivable			1,570				4,176
Current assets held for sale (Note 4)			11,760				—
Tubular inventory			468				373
Fair value of oil and gas derivative contracts			4,665				5,217
Prepaid expenses and other assets			278				249
Deferred debt issuance costs — net			534				540
Total current assets			19,635				10,555
Oil and gas properties, successful efforts method:
Developed properties			50,184				94,529
Wells and facilities in progress			3,587				7,702
Undeveloped properties			18,276				22,005
Corporate and other assets			1,322				1,460
Total property and equipment			73,369				125,696
Less accumulated depreciation and depletion			(8,868	)			(18,317	)
Net property and equipment			64,501				107,379
Fair value of oil and gas derivatives contracts			3,667				6,991
Deferred debt issuance costs — net			1,770				1,933
Total assets			89,573				126,858
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable			1,864				1,915
Current liabilities held for sale (Note 4)			3,279				—
Accrued liabilities			1,391				6,272
Accrued payroll			199				202
Total current liabilities			6,733				8,389
Long-term liabilities:
Long-term debt — senior secured bank debt			30,742				29,650
Long-term debt - 10.75% Secured Convertible Debentures net of discount of $2,043 and $0, respectively			23,457				26,250
Asset retirement obligations			533				1,298
Total long-term liabilities			54,732				57,198
Total liabilities			61,465				65,587
Commitments and contingencies (see Note 11)
Stockholders’ equity:
Preferred stock, $.001 par value; 25,000,000 shares authorized; none outstanding			—				—
Common stock, $.001 par value; 250,000,000 shares authorized; 23,944,162 and 23,821,573 shares issued and outstanding as of March 31, 2009 and December 31, 2008, respectively			24				24
Additional paid-in capital			103,458				103,267
Accumulated deficit			(75,374	)			(42,020	)
Total stockholders’ equity			28,108				61,271
Total liabilities and stockholders’ equity			89,573				126,858

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

TETON ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS
(000s except share and per share data)
(Unaudited)

		Three Months Ended March 31,
		2009				2008
Operating revenues:
Oil and gas sales		$	1,791			$	1,304
Miscellaneous expense, net			(13	)			—
Total revenues			1,778				1,304
Operating expenses:
Lease operating expense			704				220
Workover expense			166				—
Transportation expense			250				2
Production taxes			142				81
Exploration expense			376				(38	)
General and administrative			1,890				3,819
Depreciation, depletion and accretion expense			1,507				962
Impairment expense			1,243				—
Total operating expenses			6,278				5,046
Operating income (loss)			(4,500	)			(3,742	)
Other income (expense):
Realized gain (loss) on oil and gas derivative contracts			3,765				(113	)
Unrealized loss on oil and gas derivative contracts			(3,875	)			(1,233	)
Gain on derivative contract liabilities			—				825
Gain on retirement of convertible debt			480				—
Interest expense, net			(1,306	)			(4,217	)
Total other income (expense)			(936	)			(4,738	)
Net loss before discontinued operations			(5,436	)			(8,480	)
Loss from discontinued operations			(30,083	)			257
Net loss applicable to common shares		$	(35,519	)		$	(8,223	)
Basic loss per common share before discontinued operations		$	(0.23	)		$	(0.48	)
Discontinued operations per share of common stock		$	(1.26	)		$	0.02
Basic loss per share of common stock		$	(1.49	)		$	(0.46	)
Fully diluted income (loss) per common share		$	(1.49	)		$	(0.46	)
Basic weighted-average common shares outstanding			23,899				17,773
Fully diluted weighted-average common shares outstanding			23,899				17,773

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

TETON ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(000s) (Unaudited)

		Three Months Ended March 31,
		2009				2008
Operating activities:
Net loss		$	(35,519	)		$	(8,223	)
Discontinued operations:
Loss on discontinued operations			403				(257	)
Loss on sale of discontinued operations			731				—
Impairment of discontinued operations			28,949				—
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and accretion			1,507				962
Impairment of oil and gas properties			1,243				—
Debt issuance cost amortization			169				689
Debt discount amortization			121				3,525
Stock-based compensation expense, exclusive of cash withheld for payroll taxes of $5 and $329, respectively			164				1,450
Non-cash loss on derivative contract liabilities			—				(825	)
Unrealized loss — oil and gas derivative contracts			3,875				1,233
Gain on retirement of 10.75% Convertible Debentures			(480	)			—
Changes in current assets and liabilities:
Trade accounts receivable			1,778				861
Advances to operator			—				(575	)
Prepaid expenses and other current assets			(124	)			(91	)
Accounts payable and accrued liabilities			(2,717	)			(1,255	)
Accrued payroll			(3	)			(194	)
Net cash provided by operating activities			97				(2,700	)
Investing activities:
Proceeds from sale of oil and gas properties			—				—
Acquisition of corporate fixed assets			(16	)			(49	)
Acquisition and development of oil and gas properties			(543	)			(8,070	)
Net cash used in investing activities			(559	)			(8,119	)
Financing activities:
Proceeds from exercise of options/warrants			—				978
Retirement of 10.75% Convertible Debentures			(270	)			—
Net borrowings from senior bank credit facility			1,092				(8,000	)
Net cash provided by financing activities			822				(7,022	)
Increase (decrease) in cash and cash equivalents			360				(17,841	)
Cash and cash equivalents — beginning of period			—				24,616
Cash and cash equivalents — end of period		$	360			$	6,775
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest, net of amounts capitalized		$	996			$	170
Capitalized interest		$	7			$	77
Reclassification of oil and gas properties, net to current assets held for sale		$	10,300			$	—
Reclassification of accrued liabilities to current liabilities held for sale		$	2,801			$	—
Capital expenditures included in accounts payable and accrued liabilities		$	2,090			$	3,108
Reclassification of ARO liabilities to current liabilities held for sale		$	478			$	77
ARO disposed of in sale of assets		$	295			$	—
Adoption of EITF 07-5 cumulative effect adjustment		$	2,164			$	—

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

TETON ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands except per share data)
(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.

On March 31, 2009 the Company sold its working interest in the Teton Noble AMI non-operated properties to Noble Energy, Inc., the operator. Additionally, the Company entered into a Purchase and Sale Agreement to sell its 12.5% working interest in its Piceance Basin properties on April 22, 2009. The sale is expected to close in May 2009. At March 31, 2009, the Piceance Basin properties are classified as held for sale. The results of operations and any loss on sale associated with the disposal of these two properties are classified as discontinued operations in the current year results. Certain amounts for the period ending March 31, 2008 have been reclassified to conform to the current year presentation, including, but not limited to, the reclassification of oil and gas revenues and operating expenses related to the operations in the Teton Noble AMI and Piceance Basin operations to discontinued 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, 2008 (the “2008 Form 10-K”), and are supplemented throughout the notes to this quarterly report on Form 10-Q.

The interim consolidated financial statements should be read in conjunction with the financial statements and notes thereto for the year ended December 31, 2008 included in the 2008 Form 10-K filed with the SEC.

Cash and cash equivalents

Cash and cash equivalents includes all cash balances and any highly liquid investments with an original maturity of 90 days or less. The Company uses excess cash on-hand to repay, to the extent possible, amounts outstanding under its line of credit, and minimize related interest expense, resulting in a cash balance of $360 and $0 at March 31, 2009 and December 31, 2008, respectively.

Accrued liabilities

At March 31, 2009 accrued liabilities consisted of $1.0 million of accrued interest payable related to the Company’s 10.75% Secured Convertible Debentures and interest on the balance outstanding on its line of credit, $134 of accrued production taxes related to oil and gas sales and franchise taxes and $253 million of accrued liabilities related to operations. At December 31, 2008 accrued liabilities consisted of $1.7 million of accrued interest payable related to the Company’s 10.75% Secured Convertible Debentures and interest on the balance outstanding on its line of credit, $856 of accrued production taxes related to oil and gas sales and $3.7 million of accrued liabilities related to operations. There are no other liabilities which are individually material for discussion.

Recently adopted accounting pronouncements

On January 1, 2009, the Company adopted the provisions of FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which deferred 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. The adoption of FSP FAS 157-2 did not have a material impact on the Company’s consolidated financial statements.

On January 1, 2009, the Company adopted the provisions of 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. The Company will apply the provisions of SFAS No. 141R to future acquisitions.

On January 1, 2009, the Company adopted the provisions of 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. The Company has applied the provisions of SFAS No. 161 and has included the required disclosures in this quarterly report on Form 10-Q.

On January 1, 2009, the Company adopted the provisions of FSP No. APB 14-1, “Accounting for Convertible Debt Instruments that May Be Settled in Cash upon Conversion (Including Partial Cash Settlement,)” (“FSP APB 14-1”). FSP APB 14-1 addresses the accounting for convertible debt securities that, upon conversion, may be settled by the issuer either fully or partially in cash. The adoption of APB 14-1 did not have a material impact on the Company’s financial position or results of operations.

On January 1, 2009, the Company adopted the provisions of FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 clarified that all outstanding unvested share-based payment awards that contain rights to non-forfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. The adoption of FSP EITF 03-6-1 did not have a material impact on the Company’s consolidated financial statements or results of operations.

On January 1, 2009, the Company adopted the provisions of EITF Issue No. 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own stock” (“EITF No. 07-5”). EITF No. 07-5 provides guidance for determining whether an equity-linked financial instrument (or embedded feature) is indexed to an entity’s own stock. EITF No. 07-5 applies to any freestanding financial instrument or embedded feature that has all of the characteristics of a derivative or freestanding instrument that is potentially settled in an entity’s own stock. To meet the definition of “indexed to own stock,” an instrument’s contingent exercise provisions must not be based on (a) an observable market, other than the market for the issuer’s stock (if applicable), or (b) an observable index, other than an index calculated or measured solely by reference to the issuer’s own operations, and the variables that could affect the settlement amount must be inputs to the fair value of a “fixed-for-fixed” forward or option on equity shares. The Company has evaluated the impact of adoption of EITF 07-5, see Note 6 for a discussion regarding the impact to the Company of adoption.

On January 1, 2009, the Company adopted the provisions of EITF 08-4, “Transition Guidance for Conforming Changes to Issue No. 98-5” (“EITF 08-4”). EITF 08-4 provides transition guidance with respect to conforming changes made to EITF 98-5, that result from EITF 00-27, “Application of Issue No. 98-5 to Certain Convertible Instruments,” and SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” The adoption of EITF 98-5 did not have a material impact on the Company’s consolidated financial statements or results of operations.

On January 1, 2009, the Company adopted the provisions of EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”). EITF 08-5 provides guidance for measuring liabilities issued with an attached third-party credit enhancement (such as a guarantee). It clarifies that the issuer of a liability with a third-party credit enhancement (such as a guarantee) should not include the effect of the credit enhancement in the fair value measurement of the liability. The adoption of EITF 08-5 did not have a material impact on the Company’s consolidated financial statements or results of operations.

New accounting pronouncements

In April 1, 2009, the FASB issued FSP 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP 141R-1). FSP 141R-1 amends and clarifies SFAS No. 141R to address application issues associated with initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP 141R-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company will apply the provisions of FSP 141R-1 to future acquisitions.

On April 9, 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. FSP SFAS 157-4 is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009. The Company does not expect the adoption of FSP 157-4 to have a material impact on the Company’s consolidated financial statements or results of operations.

On April 29, 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to require publicly-traded companies, as defined in APB Opinion No. 28, “Interim Financial Reporting,” to provide disclosures on the fair value of financial instruments in interim financial statements. FSP SFAS 107-1 and APB 28-1 are effective for interim periods ending after June 15, 2009. The Company does not expect the adoption of FSP SFAS 107-1 to have a material impact on the Company’s consolidated financial statements or results of operations.

2.

Going Concern

These unaudited interim consolidated financial statements have been prepared on a going concern basis which contemplates the realization of assets and the payment of liabilities in the ordinary course of business. Effective May 1, 2009, the group of banks which participate in the Amended Credit Facility will redetermine the Company’s borrowing base. The redetermination is expected to result in a borrowing base deficiency which, by contract, is due in equal monthly payments over three months. The Company does not currently have sufficient resources to fund its current working capital requirements and service its debt. The Company plans to obtain additional capital availability through alternative financing arrangements with third parties and the sale of assets to service its current working capital requirements. Additionally, management continues to re-examine all aspects of the Company’s business for areas of improvement and continues to focus on the Company’s fixed cost base to better align with operating levels and market demand. However, there is no assurance that the Company’s plans could be consummated on acceptable terms or at all. As a result, there is substantial doubt as to the ability of the Company to continue as a going concern. Should the Company be unable to continue as a going concern, it may be unable to realize the carrying value of its assets and to meet its liabilities as they become due. These unaudited interim consolidated financial statements do not include any adjustments for this uncertainty.

Our ability to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. The Company has engaged Barrier Advisors, Inc. to assist further in the evaluation of our strategic and financial alternatives. Until the possible completion of the financial and strategic alternatives process, our future remains uncertain and there can be no assurance that our efforts in this regard will be successful. See additional comments under Note 4 under the heading “dispositions.”

3.

Earnings per share of common stock

Basic loss per common share is computed by dividing net 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 9) are considered issued and outstanding at March 31, 2009 and 2008, respectively, and are included in the calculation of the weighted average basic common shares outstanding. Diluted loss per common share reflects the potential dilution that would occur if contracts to issue common stock were exercised or converted into common stock. For the periods ending March 31, 2009 and 2008, basic loss per common share and diluted loss per common share are the same as any potentially dilutive shares would be anti-dilutive to the periods.

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,
		2009				2008
Net loss before discontinued operations		$	(5,436	)		$	(8,480	)
Discontinued operations			(30,083	)			257
Net loss		$	(35,519	)		$	(8,223	)
Weighted average common shares outstanding — basic			23,898,747				17,772,955
Dilution effect of restricted stock, performance share units, options and warrants			—				—
Weighted average common shares outstanding — fully diluted			23,898,747				17,772,955
Earnings (loss) per share of common stock:
Basic loss before discontinued operations		$	(0.23	)		$	(0.48	)
Discontinued operations per share of common stock			(1.26	)			0.02
Basic loss per share of common stock		$	(1.49	)		$	(0.46	)
Fully diluted		$	(1.49	)		$	(0.46	)

Options to purchase 1,415,844 shares of common stock and 1,272,451 warrants to purchase common stock were outstanding during the first quarter of 2009 but were not included in the computation of diluted EPS because the exercise price was greater than the average market price of the common shares. Additionally, 2,136,800 unvested Performance Share Units, 207,435 unvested Restricted Share Units and 3,942,308 shares to be issued upon conversion of the Company’s 10.75% Debentures were excluded as the effect of these shares would have been anti-dilutive. The potentially dilutive shares are calculated using the treasury stock method, whereby a company uses the proceeds from the exercise or purchase of shares as well as the average unrecognized compensation to repurchase common stock at the average market price during the period. If the average market price during the period is less than the purchase or exercise price, the outstanding security will have an anti-dilutive effect on earnings per share. At March 31, 2009, the maximum number of shares that could potentially be included in the basic earnings per share calculation, if all shares above were exercised, purchased or converted is 8,995,835 shares.

For the period ended March 31, 2008, the maximum number of shares that could have potentially been included in basic earnings per share, if all shares were exercised, purchased or converted was 7,279,975 shares.

4.

Oil and Gas Properties

Dispositions

It is strategically important to the Company’s future growth and maturation as an independent exploration and production company to be able to serve as operator of the Company’s properties when possible in order to be able to exert greater control over costs and timing in, and the manner of, the Company’s exploration, development and production activities. As of March 31, 2009 the Company has five projects, four of which are operated by the Company. The Company’s strategic plan involves focusing on the development of the Company’s operated properties.

Noble AMI

On March 31, 2009, the Company closed on the sale of its 25 percent non-operated working interest position in the Noble AMI. The Company sold its interest, which also included the Company’s 50 percent operated working interest in its undeveloped Frenchman Creek acreage in eastern Colorado, to its operating partner and 75 percent working interest owner, Noble Energy, Inc. (“Noble”). The net sales price of $4.0 million was received in the form of forgiveness of all outstanding and future amounts owed to Noble by the Company, related to the development of the Teton—Noble AMI project of $4.4 million, net of revenue receivable of $400 for the same period.

The carrying value of the Company’s working interest in the Teton-Noble AMI and undeveloped Frenchmen Creek acreage was $4.4 million, and $281, respectively, at March 31, 2009. The loss on sale of $700 is reported in discontinued operations on the face of the financial statements.

Piceance

On April 22, 2009, the Company and Puckett Land Company (“Puckett”) entered into a Purchase and Sale Agreement, (“PSA”), for the sale of the Company’s 12.5 percent non-operated working interest position in the Piceance Basin for $10.3 million before closing adjustments. The closing, which is subject to completion of due diligence, is anticipated to occur on or before May 22, 2009, with an effective date of January 1, 2009.

In accordance with Generally Accepted Accounting Principles, the carrying value of the developed and undeveloped properties in the Piceance Basin was written down to the fair value of $10.3 million. The Company recognized a loss, which is included in discontinued operations on the face of the financial statements of $29.4 million comprised of the write-down of the Piceance Basin assets of $28.9 million and an operating loss for the three months ended March 31, 2009 of $427.

The assets and liabilities outstanding at March 31, 2009 related to the Piceance Basin properties are classified as held for sale on the face on the financial statements. The amounts included in current assets and liabilities for sale include the following:

		At March 31, 2009
Production receivable		$	1,460
Developed properties			14,135
Wells and facilities in progress			4,524
Undeveloped properties			1,029
Less accumulated depreciation and depletion			(9,388	)
Total current assets held for sale		$	11,760
Accrued liabilities		$	2,512
Asset retirment obligations			478
Production taxes payable			289
		$	3,279

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 incurred impairment expenses of $1,243 and $0 during the three months ended March 31, 2009 and 2008, respectively. The lack of industry activity and lower prices have had a negative effect on the value of the Company’s leasehold interests in all area, since the fourth quarter of 2008. See Note 5 for further discussion on the valuation of the Company’s impaired assets.

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, 2009 or 2008.

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, 2009
		(in thousands)
Asset retirement obligation — beginning of period		$	1,298
Accretion expense			8
Obligations sold or held for sale			(773	)
Asset retirement obligation — end of period		$	533

5.

Fair Value of Financial Instruments

Effective January 1, 2008, the Company 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 the Company’s 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 the Company used 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 Secured Convertible Notes (“Convertible Notes”) were negotiated instruments and are therefore recorded at fair value. The Company evaluated the Convertible Notes and determined that, upon adoption of EITF 07-5 on January 1, 2009, embedded conversion features existed which were required to be bifurcated and accounted for separately as a derivative instrument. See discussion below on the embedded conversion features.

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, 2009, the Company did not have any derivative contracts that qualify as cash flow hedges.

Derivative assets and liabilities included in Level 2 include fixed-rate swap arrangements for the sale of oil and natural gas hedge contracts, valued using the Black-Scholes-Merton valuation technique, in place through the third quarter of 2011 for a total of approximately 278,591 Bbls of oil production. During the three months ended March 31, 2009, the Company recognized a realized gain of $3,765 related to the first quarter hedging settlements and to the sale of its open positions for the fourth quarter of 2011 through April 2013. A loss of $3,875 is included under unrealized gains and losses under other income relating to the change in fair value of the open hedging positions.

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. The Company evaluates 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.

On April 2, 2008, in conjunction with the purchase of production and reserves related to 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 and therefore are not reported as a liability or measured at fair value on a recurring basis.

The Company adopted the provisions of EITF 07-5 on January 1, 2009. The Company evaluated its 10.75% Secured Convertible Debentures under the provisions of this EITF and determined that the embedded conversion features constitute embedded derivatives which are not linked to the equity of the Company. These embedded features, which include provisions to protect the investor in the event the Company issues stock dividends, goes through a subsequent rights offering or enters into a fundamental or change of control transaction, were valued using a probability weighted Black-Scholes-Merton valuation technique. The inputs to this model include significant unobservable inputs which require management’s judgment and are considered to be level 3 inputs within the meaning of FAS 157. As of March 31, 2009, the fair value of compound embedded derivative instruments was $0. The initial adoption was recorded as a debt discount and a cumulative effect of a change in accounting principle and recorded in retained earnings. The embedded derivative conversion features are re-measured at each reporting period with subsequent changes in the fair value being recorded under the other income and expense caption in the consolidated statement of operations.

Additionally, the Company has freestanding warrants which were evaluated and determined to meet the scope exceptions in SFAS No. 133. Accordingly, these warrants are not measured at fair value.

The following table summarizes Teton’s assets and liabilities measured at fair value on a recurring basis at March 31, 2009.

		Level 1				Level 2				Level 3				Total
Assets:
Oil and gas derivative contracts		$	—			$	8,332			$	—			$	8,332
Liabilities:
Embedded conversion features		$	—			$	—			$	—			$	—

As of March 31, 2009, the Company did not have any assets or liabilities measured at fair value on a recurring basis using level 3 inputs.

Assets Measured at Fair Value on a Non-Recurring Basis

The fair value of long-lived assets is determined using, to the extent possible, level 2 inputs which may include, third-party valuations of the PV10 value of reserves, and level 1 inputs, which may include, public information regarding the sales price of like assets in an orderly transaction between willing market participants. In the absence of available information, the Company uses significant unobservable level 3 inputs to assess the fair value of long-lived assets.

In accordance with the provisions of SFAS No. 144, long-lived assets held for sale are recorded at their fair value. As a result, an impairment charge of $28,949 was taken and is included in discontinued operations. The fair value of the assets held for sale was valued using level 1 inputs as the fair value pertains to the Purchase and Sale Agreement which is representative of the quoted price in an active market for the sale of these assets.

The Company’s undeveloped properties are subject to impairment under the provisions of SFAS No. 19. The recoverability of the carrying value of the properties is compared to the expected future cash flows, or the fair value of the asset. For the period ended March 31, 2009, the Company used level 2 and level 3 inputs to determine the fair value of its undeveloped properties. The current economic state and lack of market activity constitutes an inactive market under the provisions of SFAS No. 157. Accordingly, the Company applied judgment to adjust level 2 inputs, including Q4 2008 sales of similar assets and its knowledge of transactions between private companies, as current and relevant observable data is unavailable. As a result, an impairment of $837 and $406 was recorded related to the undeveloped properties in the Williston Basin and Central Kansas Uplift, respectively.

The following table summarizes the changes in value of Teton’s assets measured at fair value on a non-recurring basis at March 31, 2009.

		Change in Fair Value Measure Using
														Total
Description		Level 1				Level 2				Level 3				Losses
Long-lived assets held and used		$	—			$	—			$	(1,243	)		$	(1,243	)
Long-lived assets held for sale			(28,949	)			—				—				(28,949	)
		$	(28,949	)		$	—			$	(1,243	)		$	(30,192	)

6.

Convertible Notes

10.75% Secured Convertible Debentures

On June 18, 2008, the Company closed the private placement of $40 million aggregate principal amount of 10.75% Secured Convertible Debentures due on June 18, 2013 (the “Debentures”). The Debentures are convertible by the holders at a conversion rate of $6.50 per share and contain a two year no-call provision and a provisional call thereafter if the price of the underlying common stock of the Company exceeds the conversion price by 50%, or is $9.75, for any 20 trading days in a 30 trading-day period. If the holders convert into common stock, or the Debentures are called by the Company before the three-year anniversary of the original issuance date, the holders will be entitled to a payment in an amount equal to the present value of all interest that would have accrued if the principal amount had remained outstanding through such three-year anniversary. The Debentures are secured by a second lien on all assets in which the Company’s senior lender maintains a first lien.

The Debentures bear interest at a rate of 10.75% per year payable semiannually in arrears on July 1 and January 1 of each year beginning with July 1, 2008. The holders each had a 90-day put option, expiring September 18, 2008, whereby they elected to reduce their investment in the Debentures by a total of 25% of the face amount, or $10 million in the aggregate. The Company repaid the $10 million to its investors on September 18, 2008, reducing the total outstanding amount on the Debentures to $30 million.

The net proceeds from the issuance of the Debentures, after fees and related expenses (and excluding the 90-day 25% put options) were approximately $28 million. These funds were used to pay down the Company’s outstanding indebtedness on its revolving credit facility (see Note 7).

On September 19, 2008, the Company entered into the Secured Subordinated Convertible Debenture Indenture (the “Indenture”) with each of the Company’s subsidiary guarantors and the Bank of New York Mellon Trust Company, N.A., a national banking association (“Bank of New York” or the “Trustee”), and, in an exchange transaction on the same date, pursuant to the Purchase Agreement and the Indenture, the Company exchanged the Original Debentures for a Global Debenture in the amount of $30 million, which the Company deposited with the Depository Trust Company (“DTC”) and registered in the name of Cede & Co., as DTC’s nominee. Pursuant to the Indenture, Bank of New York is acting as Trustee with respect to the Global Debenture and the Company’s obligations thereunder. Initially, the Trustee is also serving as the paying agent, conversion agent and registrar with respect to the Indenture.

In connection with the Exchange and the closing of the Indenture, the Company entered into a letter agreement with each of the parties to the original Purchase Agreement, which amends and supplements the Purchase Agreement to, among other things, appoint Bank of New York as Representative, replacing Whitebox Advisors, LLC. The Company also entered into an amended and restated Intercreditor and Subordination Agreement with JPMorgan Chase and Bank of New York, and an amended and restated Subordinated Guaranty and Pledge Agreement, which reflect, among other things, the Exchange and the appointment of Bank of New York as successor in interest to Whitebox Advisors LLC as Representative and collateral agent.

On November 13, 2008, one of the investors, who held a $3.75 million investment in the Debentures, elected to convert, bringing the total outstanding amount on the Debentures to $26.25 million. The Company issued 576,924 shares of our common stock (based on the $6.50 stated conversion rate), 216,541 shares of the Company’s common stock related to the interest make-whole provision and paid $893 in cash related to accrued interest through the conversion date and for the remaining amount of the interest make-whole. On January 16, 2009, the Company retired an additional $750 of the Debentures for $270, in cash, bringing the total outstanding on the Debentures to $25.5 million.

Deferred debt issuance costs of $2,064 associated with the Convertible Notes are included in assets as of March 31, 2009 and will be amortized to interest expense over the life of the related Debenture. The Company recorded $159 and $0 of amortization of deferred debt issuance costs during the three months ended March 31, 2009 and 2008, respectively, related to the Notes.

The Company adopted the provisions of EITF 07-5 on January 1, 2009 (see Note 5) and as a result, recorded a debt discount related to the Debentures of $2,164. During the three months ended March 31, 2009, the Company recorded $121 of interest expense related to the amortization of the debt discount.

7.

Senior Bank Facility

On April 2, 2008, the Company amended its $50 million Credit Facility to a $150 million revolving credit facility (“the Amended Credit Facility”) with a $50 million borrowing base.

In connection with the privately placed 10.75% Secured Convertible Debenture, the borrowing base on the Company’s $150 million revolving credit facility was reduced from $50 million to $32.5 million. On August 1, 2008 the borrowing base was re-determined and increased to $34.5 million. Subsequently, on April 1, 2009, the borrowing base was reduced to $32.5 million related to the sale of hedge positions that were included in the value of the borrowing base. The Company’s total available borrowings under the Debentures and the Amended Credit Facility are $58.0 million as of March 31, 2009.

Under the Amended Credit Facility, at the option of the Company, each loan bears interest at a Eurodollar rate (London Interbank Offered Rate, or LIBOR) plus applicable margins of 1.25% to 2.25% or a base rate (the higher of the Prime Rate or the Federal Funds Rate plus 0.5%) plus applicable margins of 0% to .75%, determined on a sliding scale based on the percentage of total borrowing base in use. The Company is also required to pay a commitment fee of 0.375% to 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, by a pledge of the Company’s equity interests in its subsidiaries and by a guaranty by its subsidiaries. The Amended Credit Facility contains customary affirmative and negative covenants such as minimum/maximum ratios for liquidity and leverage.

Effective May 1, 2009, the group of banks which participate in the Amended Credit Facility will redetermine the Company’s borrowing base (results of the redetermination are expected to be communicated to the Company in mid-May). The redetermination is expected to result in a borrowing base deficiency which, by contract, is due in equal monthly payments over three months. The Company does not currently have sufficient resources to fund its current working capital requirements and service a borrowing base deficiency on its debt, and is negotiating with the bank group to extend the repayment period for any borrowing base deficiency that results from the redetermination. The Company plans to obtain additional capital availability through alternative financing arrangements with the bank or third parties and the sale of assets (see Note 4, Dispositions, for further discussion of pending sale of the Piceance assets for $10.3 million) to service its current working capital requirements, and its debt obligations. Additionally, management continues to re-examine all aspects of the Company’s business for areas of improvement and continues to focus on the Company’s fixed cost base to better align with operating levels and market demand. However, there is no assurance that the Company’s plans could be consummated on acceptable terms or at all. The amount of the bank borrowing base immediately subsequent to the redetermination cannot be estimated at this time. It is possible that it would exceed the amounts realized from the sale of assets, in which case the excess deficiency could become a current liability. These unaudited interim consolidated financial statements do not include any adjustments for these uncertainties.

The balance outstanding at March 31, 2009 was approximately $30.7 million. For the three months ended March 31, 2009, interest expense with respect to the above credit lines and the Convertible Notes described in Note 5 totaled $319 and $686, respectively, and capitalized interest totaled $7. During the three months ended March 31, 2008, interest expense related to the Company’s senior debt was $247 and capitalized interest was $77.

8.

Stockholders’ Equity

Warrants

The following table presents the composition of warrants outstanding and exercisable as of March 31, 2009. The weighted average exercise price of the outstanding warrants is $5.51.

						Weighted
						Average
						Remaining
Range of Exercise Prices		Number				Contractual Life
						(years)
$3.24			232,904				3.7
$6.00			625,000				1.0
$6.06			414,547				3.3
Total warrants outstanding and exercisable			1,272,451				2.3

9.

Stock-Based Compensation

During 2008, 2,659,214 performance share units, net of forfeitures, were granted to participants, pursuant to the 2005 Long Term Incentive Plan (“LTIP”) by the Compensation Committee of the Company’s Board of Directors (the “2008 Grants”). The 2008 Grants vest in three tranches, provided the goals set forth by the Compensation Committee are met. The performance measures under these Awards are 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 227,449 shares of restricted common stock, net of forfeitures, granted pursuant to the Company’s LTIP, were awarded during 2008 and the first quarter of 2009. 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, 2009, the Company recorded $169 for stock-based compensation expense applicable to the vesting of restricted stock grants. The Company expects to recognize approximately an additional $463 during the twelve months ending December 31, 2009 related to the restricted stock grants outstanding at March 31, 2009.

10.

Income Taxes

For each of the three months ended March 31, 2009 and 2008, the current and deferred provision for income taxes was $0.

At December 31, 2008, the Company had net operating loss carryforwards (“NOLs”), for federal income tax purposes, of approximately $59.5 million. These NOLs, if not utilized to reduce taxable income in future periods, will expire in various amounts from 2018 through 2028. Approximately $2.2 million of such NOL’s are subject to limitation under Section 382 of the Internal Revenue Code, all of which will free up in 2009. During 2008, the Company had no deductions from the exercise of nonqualified stock options. The Company has established a valuation allowance for deferred taxes equal to its entire net deferred tax assets as management currently believes that it is more likely than not that these losses will not be utilized.

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. The Company had no accrued interest or penalties related to uncertain tax positions as of March 31, 2009.

11.

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. The outstanding commodity hedges as of March 31, 2009 are summarized below:

Type of Contract

Remaining Volume

Fixed Price per Barrel

Price Index (1)

Remaining Period

Oil Costless Collar

105,049

$90.00 Floor/$104.00 Ceiling

WTI

04/01/09-12/31/09

Oil Costless Collar

106,876

$90.00 Floor/$104.00 Ceiling

WTI

01/01/10-12/31/10

Oil Costless Collar

66,666

$90.00 Floor/$104.00 Ceiling

WTI

01/01/11-09/30/11

Total Bbl

278,591

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. The start of the new lease agreement was delayed to November 1, 2008. Rental payments, before expenses, under the lease are $187 for the remainder of 2009, $269 for 2010 and an aggregate $971 thereafter, for the remaining 41 months of the agreement.

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

($ amounts in thousands, except amounts per unit of production)

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:

•

Our ability to execute our Feasibility Plan in order to sustain our ability to continue as a going concern;

•

Our ability to service current and future indebtedness and comply with the covenants related to the debt facilities;

•

General economic and political conditions, including governmental energy policies, tax rates or policies, inflation rates and constrained credit markets;

•

The market price of, and supply/demand balance for, oil and natural gas;

•

Our success in completing development and exploration activities, when and if we are able to resume those activities;

•

Reliance on outside operating companies for drilling and development of our non-operated 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; and

•

Changes in laws and regulations.

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 2008 Annual Report on Form 10-K.

Overview and Strategy

We are an independent oil and gas exploration and production company focused on the acquisition, exploration and development of North American properties. The Company’s current operations are concentrated in the prolific Midcontinent and Rocky Mountain regions of the U.S. We have leasehold interests in the Central Kansas Uplift, the eastern Denver-Julesburg Basin in Colorado, Kansas and Nebraska, the Williston Basin in North Dakota and the Big Horn Basin in Wyoming. At March 31, 2009, we also had operations in the Piceance Basin in western Colorado, but currently have a signed purchase and sale agreement to sell that property.

Teton was formed in November 1996 and is incorporated in the State of Delaware. Effective September 8, 2008, our common shares are publicly traded on the NASDAQ Capital Market LLC under the symbol “TEC.” Prior to September 8, 2008, our common shares were publicly traded on the American Stock Exchange under the symbol “TEC.”

Our principal executive offices are located at 600 17th Street, Suite 1600 North, Denver, CO 80202, and our telephone number is (303) 565-4600. Our web site is www.teton-energy.com.

Current Economic Conditions and Credit Crisis

Our long term plans have been, and will continue to be, to economically grow reserves and production, primarily by:

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

However, with the recent slowdown in the national economy, tightening of the credit and equity markets and depressed oil and gas commodity prices, we have evaluated our short-term objectives and the impact of these factors on our 2009 capital, operating and G&A budgets. In light of the current economic environment and its impact on our industry, our focus for 2009 is largely centered on production of our operated properties in the Central Kansas Uplift. Additionally, we are focusing our efforts on the execution of our Feasibility Plan (discussed below) in an attempt to solidify our position as a going concern. Refer to the heading “Liquidity and Capital Resources,” for further discussion on the impacts of current economic factors on our short-term strategic plans.

Following are summary comments of our performance in several key areas during the three month period ended March 31, 2009:

Net income (loss)

During the three month period ended March 31, 2009, we moved from a net loss before discontinued operations of $8,480 (or $0.48 per common share), and a net loss applicable to common shares of $8,223 (or $0.46 per common share), for the three months ended March 31, 2008 to a net loss before discontinued operations of $5,436 (or $0.23 per common share) and a net loss applicable to commons shares of $35,519 (or $1.49 per common share). The increase in net loss of $27,296 for the three month period is due largely to the loss on discontinued operations ($29,680 of which is loss or impairment on the Teton-Noble AMI and Piceance Basin assets sold or being sold, based on the sales price or expected sales price of each, and $403 of which is the ongoing loss on normal operations for those assets during the first quarter of 2009) and, to a lesser extent, to impairments charged to non-producing leaseholds in Williston ($838) and CKU ($405) related to lower current leasing prices in the areas due to lower commodity prices, and unrealized losses on oil and gas derivative contracts ($2,642). The increase in net loss was somewhat offset by lower general and administrative expenses ($1,929) and higher DD&A ($478), as well as realized gains on the oil and gas derivative contracts ($3,878) and lower interest expense ($2,911). See Results of Operations below for further discussion on G&A, derivative contracts and interest expense.

Production

During the three months ended March 31, 2009, average company-wide daily production increased 59%, to 7,382 Mcfed, as compared to average daily production of 4,640 Mcfed during the same prior year period. The fluctuations in production by major operating area are discussed below.

Central Kansas Uplift. On April 2, 2008, we completed the purchase of reserves, production and certain oil and gas properties in the Central Kansas Uplift (“CKU”), and we began recognizing our share of production from the 53 producing wells at that time (61 currently). Average daily production, net to the Company, from the area was 2,621 Mcfed for the three months ended March 31, 2009. The second quarter 2008 was our first production from the Central Kansas properties, so there were no production volumes included in the first quarter 2008 results.

At March 31, 2009, we had approximately 86% of the current oil production hedged, with contracts in place through September 30, 2011 on costless collars at a floor price of $90.00 per barrel of oil and a ceiling price of $104.00. At $90.00 per barrel of oil and today’s drilling costs, a typical well in the CKU project would generate an approximate 80% IRR.

Piceance. Average daily production, net to the Company, in the area was 3,100 Mcfed for the three months ended March 31, 2009 compared to 2,896 Mcfed for the same prior year period. The increase in production in the three months ended March 31, 2009, relates to the new wells put on production after the first quarter 2008. 52 gross wells were spud in 2008 and no new wells were started in 2009, with 30 of the 2008 new wells being hooked up prior to March 31, 2009, bringing the total producing well count to 95 with 20 wells still waiting on completion. The operator has informed us that they do not intend to drill additional wells in 2009.

On April 22, 2009, we signed a Purchase and Sale Agreement for the sale of our 12.5 percent non-operated working interest position in the Piceance Basin in western Colorado to Puckett Land Company for $10.3 million before closing date adjustments. The closing is anticipated to occur on or before May 22, 2009, with an effective date of January 1, 2009. The results of operations from January 1, 2009 through the closing date will be settled as an adjustment to the purchase price at closing. The sale was made as a part of our ongoing effort to sell the non-operated assets, to be more heavily weighted towards our own operations to be able to better control our pace of capital expenditures and to improve upon our liquidity.

In accordance with generally accepted accounting principles, we recorded an impairment expense on this property for the quarter ended March 31, 2009 of $28,949. The current world-wide economic conditions and credit crisis, coupled with low commodity prices for natural gas in the Rockies, resulted in a current market value of the assets that is lower than our book carrying value. At March 31, 2009, the carrying value of the Piceance developed and undeveloped properties exceeded the negotiated sales price of the assets, which resulted in the impairment expense.

Teton-Noble AMI. As of March 31, 2009, there were 124 producing wells in our non-operated properties in the Teton-Noble AMI in the DJ Basin. Production, net to the Company, increased to 783 Mcfed for the three months ended March 31, 2009, from 602 Mcfed for the same prior year period.

The results of these wells were disappointing for the amount of investment made. Gathering system problems and disappointing production volumes resulted in marginal economics for the project, and we had exercised our right to go non-consent during the fourth quarter 2008. We sold our 25 percent non-operated working interest position in the Teton-Noble AMI to Noble Energy Inc. (“Noble”) in exchange for the forgiveness of all outstanding and future amounts owed to Noble by Teton, related to the development of the project ($4.0 million after post-effective date adjustments). Included in the sale is the Company’s 50 percent operated working interest in its undeveloped Frenchman Creek acreage in eastern Colorado. The sale closed on March 31, 2009, with an effective date of February 1, 2009. At March 31, 2009, the carrying value of the Teton-Noble AMI developed and undeveloped properties exceeded the sales price of the assets, which resulted in a loss on the sale of $700.

Washco. As of March 31, 2009, there were 27 gross producing wells in our operated Washco area of the DJ Basin which produced an average of 763 Mcfed, net to the Company, during the three months ended March 31, 2009, increasing from 1,033 Mcfed for the same prior year period. We are currently seeking a partner to drill additional wells in the Washco area.

Williston. For the three months ended March 31, 2009, production, net to the Company, in the area averaged 115 Mcfed as compared to 109 Mcfed during the same prior year period. We hold an interest in 9 gross wells in the Williston Basin, including 7 producing Bakken wells and 2 Red River wells (one producing and one well in process).

On November 13, 2008, we and our partners spud the Viall #30-1 well to test the Stonewall, Red River and Winnipeg formations. Completion operations commenced on January 5, 2009. Testing of the Winnipeg formation did not indicate commercially viable production from that formation, but the Red River C and D formations tested positive for commercially viable reserves. The well is waiting on pipeline connection to a gas processing facility, expected in the summer 2009.

The first of four locations in the Bakken Shale play, subject to a participation agreement with Red Technology Alliance LLC (“RTA”) on Teton’s 88,472 gross acreage block, was originally expected to be spud in the first quarter of 2009. RTA has since been dissolved as an operating entity. We are currently seeking another partner to drill this prospect.

Oil and Gas Sales

Oil and gas sales increased 37%, from $1,304 for the three months ended March 31, 2008 to $1,791 for the three months ended March 31, 2009. The increase in revenue is due to moving the revenues related to the Teton-Noble AMI and the Piceance Basin assets into the line item loss from discontinued operations, since they have been sold or are assets held for sale, as discussed above by operating area. The average well head price per Mcfe decreased $6.86 per Mcfe, from $12.55 to $5.69 per Mcfe for the three months ended March 31, 2009, when compared to the prior year period. Average commodity prices have decreased significantly at the beginning of 2009, with crude oil trading approximately in the $30-50 per barrel range and natural gas trading in the $3.50-6.00 per Mcf range for NYMEX ($1.80-$4.65 per Mcf for CIG Rockies gas) during the first quarter of 2009, compared to oil trading at an average price of approximately $85 and CIG gas trading in an approximate range of $8.00-$9.00 during the first quarter of 2008. After moving the sales related to Teton-Noble AMI and Piceance assets into discontinued operations, the first quarter 2008 is heavily weighted towards the oil price on an Mcfe basis (one barrel of oil is converted to Mcfe by dividing by a factor of 6), However, as detailed in the tables below under Liquidity and Capital Resources, Contractual Obligations, Teton has approximately 86% of current oil production hedged at a floor price of $90.00 per barrel and, after closing the sale of the Piceance assets, expected for May 2009, will have minimal exposure to natural gas prices.

LIQUIDITY AND CAPITAL RESOURCES

Going Concern

Our consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates the realization of assets and the liquidation of liabilities in the normal course of business. We have incurred significant operating losses in the quarter ended March 31, 2009, attributable largely to impairment expenses on our non-operated properties, as well as a sudden and rapid decline in commodity prices in our industry. We have managed our liquidity during this time through a series of cost reduction initiatives and sales of assets. However, the global credit market crisis and depressed commodity prices have had a dramatic effect on our industry. In the second half of 2008, the increased turmoil in the overall credit markets, the volatility in the prices of oil and natural gas, the recession in the United States and Western Europe and the slowdown of economic growth in the rest of the world created a substantially more difficult business environment. The ability to execute capital markets transactions or sales of assets was extremely limited. Our liquidity position, as well as our operating performance, was negatively affected by these economic and industry conditions and by other financial and business factors, many of which are beyond our control. We do not believe it is likely that these adverse economic conditions, and their effect on the oil and gas industry, will improve significantly during 2009, notwithstanding the unprecedented intervention by governments in the United States and other countries in the global banking and financial systems.

Historically, our primary sources of liquidity have been cash provided by debt and equity offerings and borrowings under our bank credit facility. In the past, these sources have been sufficient to meet our business needs. The adverse developments in financial and credit markets during the fourth quarter of 2008 have continued into early 2009 and have made it very difficult and much more expensive to access capital markets. Although the credit markets tightened in the latter half of 2008, we believed at December 31, 2008 that the amounts available to us under our existing $150 million credit facility ($32.5 million borrowing base at March 31, 2009 — see additional comments below related to the redetermination of the bank borrowing base), together with the anticipated net cash provided by operating activities during 2009 and proceeds from potential sales of non-operated properties, would provide us with sufficient funds to maintain our current facilities and complete our limited capital expenditure program through 2009. In response to the lower commodity prices and continued constrained capital markets, our capital expenditure budget for 2009 will focus primarily on optimizing production in our operated properties in the Central Kansas Uplift (refer to discussion below under the heading Cash Flows and Capital Requirements), completion of the Viall #30-1 well drilled in the Williston Basin in 2008, and lease and seismic costs.

Depending on the timing and amounts of our capital projects and future developments in the capital markets, we will likely be required to seek additional sources of capital. However, due to the uncertain state of the current capital markets, we can provide no assurance that we would be able to secure additional financing if required, or as to the terms of any such additional financing, as securing additional financing would likely be much more difficult than it has been in the past, and, if secured, the terms would likely be more onerous. We had previously publicly stated our plans to sell non-operated properties as part of our current strategic plan, and we sold our non-operated Teton-Noble AMI assets in the DJ Basin (packaged with our undeveloped assets in Frenchmen Creek), with the transaction closing March 31, 2009. On April 22, 2009, we signed a purchase and sale agreement for the Piceance Basin assets.

Current developments in the capital markets include the reduction of lenders’ pricing decks (i.e., the commodity prices upon which lenders base their determinations of borrowing bases), which we expect will lead to a decrease of our borrowing base. With the significant declines in commodity prices since the summer of 2008, there has been a reduction of the price decks by the banks which participate in our Amended Credit Facility. Each individual bank determines its own pricing deck based on its analysis of various factors, including the general economy, current commodity prices and the specific bank’s expectations of future commodity prices. Consequently, a reduction of our borrowing base at the next redetermination, scheduled for May 1, 2009 (expected to be communicated to us in mid-May), is anticipated, and, although we do not yet know the amount of the reduction, nor can we reasonably estimate the amount, it is expected to be material. Any excess outstanding borrowings over the re-determined borrowing base (a “borrowing base deficiency”) could be required by the banks to be repaid in three equal installments on the last day of each month following the redetermination, and we do not have adequate funds available to repay a material borrowing base deficiency at this time. We have developed a “Feasibility Plan” designed to improve our current situation over a period of time, and that plan has been presented to the bank group for its consideration. The key elements of the plan include:

•

Asset sales — As noted above, the Teton-Noble AMI sale was closed on March 31, 2009, with an effective date of January 1, 2009, in exchange for the forgiveness of $4.0 million of payables to the buyer. Additionally, on April 22, 2009, we signed a purchase and sale agreement for the Piceance Basin assets, expected to close May 22, 2009 with an effective date of January 1, 2009, for a sales price of $10.3 million. All outstanding payables to the operator of the Piceance property will be netted against the sales price at closing, and the remaining balance of the sales price, estimated at $8-9 million, will be used to reduce the outstanding borrowings under the Amended Credit Facility.

•

Labor costs — We have reduced the number of our employees (both regular employees and ongoing contractors) by 42%. We expect that, as a result, we will experience positive effects on expenses and cash flow beginning in early May, after the severance benefits for most of those terminated expire. Salaries of all remaining employees were also reduced by 10%, the 410(K) plan was eliminated and our contribution to employee benefit plan premiums was reduced from 90-100% to 50%. All of those reductions were effective in early April 2009. The resultant annual reduction to G&A expenses is estimated at approximately $1.3 million. Additionally, we did not pay any bonuses in early 2009 for 2008 and have no intention of doing so in the future.

•

Delay in capital expenditures — We have evaluated our 2009 capital and drilling program through an analysis of each item on a discretionary vs nondiscretionary basis, and have significantly reduced the 2009 program by eliminating or reducing those items we believe to be discretionary. We estimate capital expenditures will be approximately $3.5 million in 2009, which is approximately $7 million less than our original projection. Additionally, we have renegotiated several supply/service items in the field and expect to realize savings on those items through the remainder of the year.

•

Crude oil hedges — The liquidation of our oil hedges would be a possible source of additional funds used to repay any remaining borrowing base deficiency. Due to the uncertain state of the oil and gas industry and the related volatility in commodity prices, there is no assurance that we would be able to complete the sale of the hedge positions at an amount higher than that represented in the borrowing base. We do not regard the liquidations of our hedges as an ideal interim strategy as these hedges provide protection against the volatility of crude oil prices and enhance the economics of our Central Kansas assets. For every dollar that the price of oil declines during the hedge period, our hedge value increases by one dollar. However, we will monitor the market for our current hedges and consider the possibility of liquidating them and, simultaneously, establishing new hedges that would likely be at a lower price but would still offer downside protection on oil price.

•

Capital market transactions — We are exploring various alternatives with our current equity and debt holders as well as new sources of equity in order to improve our balance sheet and our liquidity, including forbearance by the banks on any borrowing base deficiency. It is too early in the process to know if we will be successful or to discuss the specifics of such efforts.

Additionally, our Amended Credit Facility contains two financial covenants with which we are required to comply quarterly:

1.

Ratio of total debt to EBITDAX (as defined in the Credit Facility agreement): We will not, as of the last day of the fiscal quarter, permit our ratio of total debt as of the end of such fiscal quarter to EBITDAX for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to be greater than 3.5 to 1.0.

2.

Current ratio: We will not, as of the last day of any fiscal quarter, permit our ratio of (i) consolidated current assets (including the unused amount of the total commitments under the Credit Facility, but excluding non-cash assets under SFAS 133) to (ii) consolidated current liabilities (excluding non-cash obligations, SFAS 133 liabilities and current maturities under or with respect to the Credit Facility, the convertible debt or any other senior subordinated debt, whether such amounts are reflected as a liability under GAAP or not) to be less than 1.0 to 1.0.

There exists an intercreditor agreement between the holders of our 10.75% Convertible Debentures and the banks in the Credit Facility whereby the same financial covenants apply to the Convertible Debentures.

As of March 31, 2009, we were in compliance with all financial and non-financial covenants of our debt agreements. However, the lower commodity prices being experienced, coupled with a reduced capital spending budget during this time of tight capital markets, will result in EBITDAX being lower in the upcoming months. Lower EBITDAX may require us to lower our debt outstanding to be able to maintain compliance with the total debt to EBITDAX ratio requirement. The sale of non-operated properties (as discussed above), the liquidation of our oil hedges or a capital market transaction would be possible sources of funds or methods used to lower our outstanding total debt. Due to the uncertain state of the current capital markets and the oil and gas industry, there is no assurance that we would be able to complete any of these undertakings successfully. As discussed above, we do not regard the liquidations of our hedges as an ideal interim strategy as these hedges provide protection against further lowering of the borrowing base. For every dollar that the price of oil declines, our hedge value increases by one dollar, and for every dollar a falling oil price decreases EBITDAX, the oil hedges will increase EBITDAX by one dollar for the hedged volumes. We expect our oil hedges to cover over 90% of our volumes of existing wells production in 2009, with new production from workovers or completions of previously drilled wells being the only volumes sensitive to actual pricing of crude oil. Additionally, the anticipated closing of the sale of the Piceance assets noted above will supply funds to lower the outstanding debt and improve the debt/EBITDAX ratio.

Our operating cash flows may also fluctuate throughout the year due to weather, changes in prices and volumes, as well as the timely collection of receivables. The availability of oil field services and supplies such as concrete, pipe and compression equipment are expected to have a significant influence on our capital budget and net cash provided by operating activities. Our future growth is further dependent upon the success and timing of our exploration and production activities, new project development, efficient operation of our facilities and our ability to obtain financing at acceptable terms. New exploration and production activities and new project development are currently not being pursued, and are not expected to be resumed until we have improved our liquidity position.

As of March 31, 2009, we have more than 90% of our total oil production hedged at a floor price of $90.00 and a ceiling price of $104.00 per barrel, and that 90% ratio is expected to continue throughout 2009 for the currently existing wells. Our hedges are transacted with JPMorgan Chase Bank NA and are currently in place through September 30, 2011. At April 27, 2009, the liquidation value of our oil hedges was $8.2 million. Refer to section entitled Contractual Obligations below for further discussion.

Additionally, 100% of our operated production is purchased by credit worthy third parties. However, management believes that in the absence of these third parties sufficient resources exist to bring this production to market. During the three months ended March 31, 2009, revenues from our operated properties accounted for 97% of total revenues from continuing operations and 60% of total production including discontinued operations.

We rely on the operator to market our share of production from our non-operated properties. Timely collection of receivables depends in large part on the credit worthiness of our operators. We believe that the operators, Berry Petroleum Company, and Evertson Operating Company, are credit worthy operators.

In the past we have also received proceeds from the exercise of outstanding warrants and/or options. However, based on the current price of our common stock compared to the exercise price of the outstanding warrants ($3.24, $6.00 and $6.06 for all outstanding warrants) and options ($3.11 - $3.71 per share) and the current economic environment, we do not anticipate receiving such proceeds during 2009. At March 31, 2009, warrants to purchase 1,272,451 shares of common stock were outstanding. These warrants have a weighted average exercise price of $5.51 per share and expire between April 2010 and December 2012. At March 31, 2009, 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.

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

		March 31,				December 31,
		2009				2008
Financial Position Summary
Cash and cash equivalents		$	360			$	—
Working capital		$	12,902			$	2,166
Debt outstanding		$	54,199			$	55,900
Stockholders’ equity		$	28,108			$	61,271
Ratios
Long-term debt to total capital ratio			65.8	%			47.7	%
Total debt to equity ratio			192.8	%			91.2	%

At March 31, 2009, we had positive working capital of $12,902, due primarily to the reclassification of Piceance Basin assets from long term to current as assets held for sale. Without this item, there would still be positive working capital of $1,142. The change from our normal deficit working capital position to a positive working capital position, excluding the assets held for sale, results largely from the lack of drilling in our non-operated properties and the resultant lower accrued liabilities related to that drilling, and various smaller normal fluctuations in current assets and current liabilities. Additionally, in accordance with SFAS 144, we have recorded $30.1 million of loss from discontinued operations to recognize the impairment of the carrying value of the Piceance assets as evidenced by the purchase and sale agreement price for those assets and loss on sale of Noble assets, which results in a significant increase to our accumulated deficit at March 31, 2009, as compared to December 31, 2008. The accumulated deficit is a component of stockholders’ equity and is reflected in that line above. The higher accumulated deficit, in turn, results in inflating both the long-term debt to total capital and the total debt to equity ratios, as noted above. The volatility of the oil and gas commodity prices used to value the unrealized gains (losses) on the related derivative contracts, as required by SFAS No. 133, may also continue to increase the volatility of results from operations and stockholders’ equity, specifically our accumulated deficit, and that could have a significant effect on the related ratios going forward.

Cash Flows and Capital Requirements

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

		Three months ended March 31,
		2009				2008
Cash provided by (used in):
Operating Activities		$	97			$	(2,700	)
Investing Activities			(559	)			(8,119	)
Financing Activities			822				(7,022	)
Net change in cash		$	360			$	(17,841	)

During the three months ended March 31, 2009, net cash provided by operating activities was $97 as compared to net cash used in operating activities of $2,700 during the same prior year period. Our net loss increased by $27,296 during the three months ended March 31, 2009 as compared to the same prior year period. This increase in net loss is due largely to the loss from discontinued operations of $30.1 million related to the sale of our working interest in the Teton Noble AMI and classification of our working interest in the Piceance Basin as held for sale. Our loss before discontinued operations decreased over the same prior year period by $3,044 due largely to a decrease in general and administrative expenses of $1,929 largely due to a decrease in the amount recognized for employee stock compensation expense ($1.6 million), a decrease in general corporate communications related to a reduction in annual reporting and meeting costs ($165), and a decrease in the professional fees ($252); an increase in the realized gain on derivative contracts of $3,878 related to the oil collars in effect for the first quarter of 2009; and a decrease in interest expense of $2,911 (prior year interest expense included the non-cash amortization of the deferred debt discount and issue costs related to the 8% Debentures which were repaid during the second quarter of 2008). These increases were offset slightly by an decrease in operating income from oil and gas properties as a result of the fact that oil is more costly to produce than natural gas on a per Mcfe basis, an increase in DD&A as a result of the addition of the CKU producing property and an increase in the unrealized loss on oil and gas hedges of $2,642.

During the three months ended March 31, 2009, net cash used in investing activities was $559 as compared to $8,119 in the same prior year period. Cash expenditures during the three month period ended March 31, 2009 relate largely to the completion of the Viall #1-30 well and to workovers completed in our operated properties in the Central Kansas Uplift aimed at maintaining or improving existing production. Our 2009 capital budget has been revised to $3.5 million in light of the current economic and capital market constraints.

During the three months ended March 31, 2009, net cash provided by financing activities was $822 as compared to net cash used of $7,022 in the same prior year period. During the three months ended March 31, 2009, our net borrowings on our Amended Credit Facility were $1,092 and were used to fund our capital budget program, including 2008 capital budget amounts accrued at year-end, and our on-going operations.

Our revised capital budget for 2009 of $3.5 million includes recompletions, 3D seismic activities and maintenance of important leases in the Central Kansas Uplift, recompletions in the Piceance Basin (already completed), maintenance of leases in the Washco property in the DJ Basin, and maintenance of leases and completion the Red River well in the Williston Basin. Of that amount approximately $1.1 million has been accrued or expended in the three months ended March 31, 2009.

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, 2009 are summarized below:

Type of Contract

Remaining Volume

Fixed Price per Barrel

Price Index (1)

Remaining Period

Oil Costless Collar

105,049

$90.00 Floor/$104.00 Ceiling

WTI

04/01/09-12/31/09

Oil Costless Collar

106,876

$90.00 Floor/$104.00 Ceiling

WTI

01/01/10-12/31/10

Oil Costless Collar

66,666

$90.00 Floor/$104.00 Ceiling

WTI

01/01/11-09/30/11

Total Bbl

278,591

The costless collar 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 oil contracts listed above, a $1.00 hypothetical change in the WTI 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 2009 of $279. 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.

RESULTS OF OPERATIONS

Three months ended March 31, 2009 compared to the three months ended March 31, 2008

Sales volume and price comparisons

		Three months ended March 31, (2)
		2009								2008
		Volume				Average Price (1)				Volume				Average Price (1)
Product:
Gas (Mcf)			44,042			$	3.26				24,237			$	7.43
Oil (Bbls)			45,118			$	76.57				13,278			$	76.15
Mcfe			314,750			$	11.43				103,905			$	11.46

For the three months ended March 31, 2009, we had net loss from continuing operations of $5,436 as compared to a net loss of $8,480 in the same prior year period. Factors contributing to the $3,044 decrease in net loss from continuing operations include the following:

Oil and gas production from continuing operations for the three months ended March 31, 2009 increased 203% to 314,750 Mcfe as compared to 103,905 Mcfe in the same prior year period. The increase in production is the result of:

•

The significant increase in oil production resulting from the addition of the CKU property which was acquired on April 2, 2008, contributing its initial production to our operations starting after the first quarter 2008;

•

The increase in gas production from the addition of the CKU property; and

•

Various smaller fluctuations in the volumes at Washco and the Williston Basin properties.

Oil and gas sales from continuing operations increased 37% from $1,304 for the three months ended March 31, 2008 to $1,791 for the three months ended March 31, 2009. The increase in revenue from continuing operations is due to the same items noted above for production volumes. The average price per Mcfe remained virtually flat from period to period, after the effect of hedging gains/losses.

Oil and gas production expenses

		Three Months Ended March 31,
		2009				2008
		(in dollars per Mcfe)
Average price		$	11.43			$	11.46
Production costs			3.56				2.14
Production taxes			0.45				0.78
Total operating costs			4.01				2.92
Gross margin before DD&A		$	7.42			$	8.54
Gross margin percentage			65	%			75	%

Our production costs (lease operating expenses, workover expense and transportation costs) and production taxes, all from continuing operations, for the three months ended March 31, 2009 increased $959, due primarily to adding a new operating area, CKU, and to increased oil production as discussed above. Production costs per Mcfe increased from $2.14 to $3.56 per Mcfe primarily due to the addition of the new operating area with higher oil production which results in higher per unit LOE costs (increased by the move of the gas properties in Teton-Noble AMI and Piceance into the discontinued operations section of the statement of operations), as well as an increase in transportation costs related to oil in the Central Kansas Uplift. Production taxes decreased from $0.78 per Mcfe to $.45 per Mcfe. The decrease is due to the change in production location from Colorado and Nebraska (with the sales and pending sales of Teton-Noble AMI and Piceance assets) to Kansas (with the acquisition of the CKU properties) where the production tax percentage is higher being more than offset by the higher volumes that the taxes are being spread across.

General and administrative expenses decreased $1,929, from $3,819 to $1,890 for the three months ended March 31, 2009. The decrease is due primarily due to 1) a decrease in non-cash compensation expenses ($1,620) related to the fact that in 2008 we were accruing for the 2006, 2007 and 2008 LTIP plans, but in 2009 the 2006 and 2007 LTIP plans have been canceled and the 2008 LTIP plan is not probable of any payout, 2) a decrease in professional fees of $252 related to the use of financial consultants in the first quarter 2008 who are no longer used and 3) an decrease in corporate communications costs of $165. There were no other individually significant increases or decreases.

Depletion, depreciation and amortization expense related to oil and gas properties increased from $935 for the three months ended March 31, 2008 to $1,413 for the three months ended March 31, 2009. This increase is due to the new productive area of the Central Kansas Uplift ($1,235) offset by a decrease in the DD&A rate in Washco and the Williston Basin. The decrease in DD&A on these properties is primarily the result of an increase in the proved developed producing reserves in these areas. The Company-wide DD&A rate for the three months ended March 31, 2009 was $4.49 per Mcfe. We believe this rate is indicative of future DD&A based on the Company’s reduced capital program.

During the three months ended March 31, 2009, we recorded a realized gain on oil and gas derivative contracts of $3,765 and a net unrealized loss (non-cash) on derivative contracts of $3,875. The realized gain results from the hedged value of the contracts for first quarter being higher than the actual price received for the product and the fact that we liquidated our future contracts for the period October 1, 2011 through April 30, 2013 for net proceeds of $1,958. The unrealized loss represents marking the derivative contracts to market at March 31, 2009, based on the future expected prices of the related commodities (see discussion on fair value measurement above).

Net interest expense for the three months ended March 31, 2009 was $1,306 compared to $4,217 for the same prior year period. The 2009 interest expense reflects the actual interest incurred on the Amended Credit Facility and the 10.75% Secured Convertible Notes, as well as related amortization of $184 of debt issuance costs on those facilities and the amortization of the deferred debt discount related to the 10.75% Secured Convertible Notes of $121. The 2008 interest expense reflects the actual interest incurred on the Credit Facility and the 8% Senior Subordinated Convertible Notes (retired in May 2008), as well as the amortization of $4,204 of debt issuance discount and costs on the 8% Senior Subordinated Convertible Notes.

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 Secured Convertible Notes (“Convertible Notes”) were a negotiated instrument and are therefore recorded at fair value. The Company evaluated the Convertible Notes and determined that, upon adoption of EITF 07-5 on January 1, 2009, embedded conversion features existed which were required to be bifurcated and accounted for separately as a derivative instrument. See discussion below on the embedded conversion features.

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 recognizes realized gains and losses under the other income and expense caption in its consolidated statement of operations. At March 31, 2009, we did not have any derivative contracts that qualify as cash flow hedges.

Derivative assets and liabilities included in Level 2 include fixed-rate swap arrangements for the sale of oil and natural gas and hedge contracts, valued using the Black-Scholes-Merton valuation technique, in place through the third quarter of 2011 for a total of approximately 278,591 Bbls of oil production. During the three months ended March 31, 2009, the Company recognized a realized gain of $3,765 related to the first quarter hedging settlements and to the sale of its open positions for the fourth quarter of 2011 through April 2013. A loss of $3,875 is included under unrealized gains and losses under other income relating to the change in fair value of the open hedging positions.

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. The Company evaluates 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.

On April 2, 2008, in conjunction with the purchase of production and reserves related to 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 and therefore are not reported as a liability or measured at fair value on a recurring basis.

The Company adopted the provisions of EITF 07-5 on January 1, 2009. The Company evaluated its 10.75% Secured Convertible Debentures under the provisions of this EITF and determined that the embedded conversion features constitute embedded derivatives which are not linked to the equity of the Company. These embedded features, which include provisions to protect the investor in the event the Company issues stock dividends, goes through a subsequent rights offering or enters into a fundamental or change of control transaction, were valued using the Black-Scholes-Merton valuation technique. The inputs to this model include significant unobservable inputs which require management’s judgment and are considered to be level 3 inputs within the meaning of FAS 157. As of March 31, 2009, the fair value of the embedded conversion features was $0. The initial adoption was recorded as a debt discount and a cumulative effect of a change in accounting principle and recorded in retained earnings. The embedded derivative conversion features are re-measured at each reporting period with subsequent changes in the fair value being recorded under the other income and expense caption in the consolidated statement of operations.

Additionally, the Company has freestanding warrants which were evaluated and determined to meet the scope exceptions in SFAS No. 133. Accordingly, these warrants are not measured at fair value.

Assets Measured at Fair Value on a Non-Recurring Basis

The fair value of long-lived assets is determined using, to the extent possible, level 2 inputs which may include, third-party valuations of the PV10 value of reserves, and level 1 inputs, which may include, public information regarding the sales price of like assets in an orderly transaction between willing market participants. In the absence of available information, the Company uses significant unobservable level 3 inputs to assess the fair value of long-lived assets.

In accordance with the provisions of SFAS No. 144, long-lived assets held for sale are recorded at their fair value. As a result, an impairment charge of $28,949 was taken and is included in discontinued operations. The fair value of the assets held for sale was valued using level 1 inputs as the fair value pertains to the Purchase and Sale Agreement which is representative of the quoted price in an active market for the sale of these assets.

The Company’s undeveloped properties are subject to impairment under the provisions of SFAS No. 19. The recoverability of the carrying value of the properties is compared to the expected future cash flows, or the fair value of the asset. For the period ended March 31, 2009, the Company used level 2 and level 3 inputs to determine the fair value of its undeveloped properties. The current economic state and lack of market activity constitutes an inactive market under the provisions of SFAS No. 157. Accordingly, the Company applied judgment to adjust level 2 inputs, including Q4 2008 sales of similar assets and its knowledge of transactions between private companies, as current and relevant observable data in unavailable. As a result, an impairment of $837 and $406 was recorded related to the undeveloped properties in the Williston Basin and Central Kansas Uplift, respectively.

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 gains or losses, but rather indicators of reasonably possible gains or 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, 2009, our income before income taxes for the period would have moved up or down approximately $6 for every $1.00 change in oil prices and $4 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 price fluctuations. Refer to “Contractual Obligations” above for a breakout of our outstanding hedge positions at March 31, 2009.

Interest Rate Risk

At March 31, 2009, we had $30,742 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 2.25% or a base rate (the higher of the Prime Rate or the Federal Funds Rate plus 0.5%) plus applicable margins of 0% to .75%, at our request. We are 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. Based on the $30,742 outstanding under our Credit Facility at March 31, 2009, 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 $77 per quarter.

ITEM 4. CONTROLS AND PROCEDURES

We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities and Exchange Commission (“SEC”) reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management necessarily applied its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management’s control objectives.

In accordance with the Securities Exchange Act of 1934, as amended, 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 the design and operation of our disclosure controls and procedures as of March 31, 2009. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the SEC.

There has been no change in our internal control over financial reporting that occurred during the quarter ended March 31,2009 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

The following is the only material change in our Risk Factors from those reported in Item 1A of Part I of our 2008 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 5, 2009.

As noted in Note 2 to our financial statements, our ability to continue as a going concern is dependent on obtaining sufficient resources to fund our current working capital requirements and to service our existing debt:

Historically, our primary sources of liquidity have been cash provided by debt and equity offerings as well as borrowings under our Amended Credit Facility. However, the adverse developments in financial and credit markets during the last quarter of 2008 and early 2009 have made it very difficult and much more expensive to access capital markets. Depending on the timing and amounts of our capital projects and future developments in the capital markets, we will likely be required to seek additional sources of capital through alternative financing arrangements with third parties and the sale of assets. Due to the uncertain state of the current capital markets, securing additional financing is likely to be much more difficult than it has been in the past, and, if secured, will likely contain more onerous terms. In addition, effective May 1, 2009, the group of banks which participate in the Amended Credit Facility will redetermine our borrowing base. The redetermination is expected to result in a borrowing base deficiency which, by contract, is due in equal monthly payments over three months and we do not have adequate funds available to repay a material borrowing base deficiency at this time. In addition to our plan to seek additional sources of capital, our management continues to re-examine all aspects of our business for areas of improvement and continues to focus on our fixed cost base to better align our expenses with our current operating levels. However, we can provide no assurance that our plans could be consummated on acceptable terms or at all. As a result, there is substantial doubt as to our ability to continue as a going concern. Should we be unable to continue as a going concern, we may be unable to realize the carrying value of our assets and to meet our liabilities as they become due, which could adversely affect our business, financial condition and results of operations.

Our borrowing base is likely to be reduced to a materially lower level relative to our current limit:

We currently finance our operations through borrowings under the Amended Credit Facility and through cash generated by operating activities. The Amended Credit Agreement contains provisions to redetermine the borrowing base at least every six months. The borrowing base will be redetermined effective May 1, 2009, and we have not been notified by the bank group of the amount of the redetermined borrowing base as of the filing date, however, we do expect a material decrease that will result in a borrowing base deficiency. The bank group may require the excess outstanding borrowings over the re-determined borrowing base to be repaid in three equal installments on the last day of each month following the redetermination. Although we primarily are planning to sell our non-operated properties to generate cash necessary to pay down the outstanding debt on the Amended Credit Facility, we can provide no assurance that we can effect such sales and, even if we can effect such sales, whether the proceeds from such sales will be adequate to cover the borrowing base deficiency. If the redetermined borrowing base creates a deficiency larger than we can repay, our lenders could accelerate our indebtedness under the Amended Credit Facility and exercise any available rights and remedies. In addition, the failure to make our scheduled interest payments or the acceleration of the indebtedness under the Amended Credit Agreement would result in a default of our 10.75% Secured Convertible Debentures.

Although we expect a material decrease in the borrowing base on our Amended Credit Agreement, we do not have a forbearance agreement in place:

The borrowing base on our Amended Credit Agreement will be redetermined effective May 1, 2009. We have not been notified by the bank group of the amount of the redetermined borrowing base as of the filing date, however, we do expect a material decrease that will result in a borrowing base deficiency. We are actively engaged in discussions with our lenders to amend certain terms of our Amended Credit Agreement to allow for greater operating flexibility although we currently do not have a forbearance agreement in place. We can provide no assurance that current discussions will result in a forbearance agreement or any amendments to the Amended Credit Agreement. Even if we were able to successfully negotiate a forbearance agreement, we may be required to pay significant amounts to our lenders to obtain their agreement to forbear exercising their rights and remedies. In addition, any forbearance agreement would have a limited duration and any future failures to comply with the covenants under the Amended Credit Agreement could result in further events of default which, if not cured or waived, could trigger prepayment obligations, which could adversely affect our business, financial condition and results of operations.

The current constraints on our liquidity impose significant risks to our operations:

Our liquidity position will likely adversely affect our relationships with our creditors, suppliers, customers and employees. Further, as a result of the public disclosure of our liquidity constraints, our ability to maintain normal credit terms with our suppliers may become impaired. Customers’ perception of our financial position may adversely affect their business dealings with us. We may also have difficulty maintaining our ability to attract, motivate and retain management and other key employees. Failure to maintain any of these important relationships could adversely affect our business, financial condition and results of operations.

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 2009.

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 on 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 on 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 on July 3, 2001.
	3.1.4			Certificate of Amendment to Certificate of Incorporation of Teton Petroleum Company, incorporated by reference to Exhibit 2.1.4 of Teton’s Form 10-SB (File No. 000-31170), filed on July 3, 2001.
	3.1.5			Certificate of Amendment to Certificate of Incorporation of Teton Petroleum Company, incorporated by reference to Exhibit 2.1.5 of Teton’s Form 10-SB (File No. 000-31170), filed on 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 on August 20, 2002.

	4.1			Secured Subordinated Convertible Debenture Indenture dated September 19, 2008 among Teton Energy Corporation, Teton North America LLC, Teton Piceance LLC, Teton DJ LLC, Teton Williston LLC, Teton Big Horn LLC, Teton DJCO LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on September 23, 2008).
	4.2			Form of 10.75% Secured Convertible Debenture dated June 18, 2008 issued by Teton Energy Corporation (incorporated by reference to Exhibit 4.1 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.3			Form of Global 10.75% Secured Subordinated Convertible Debenture (included in Exhibit 4.1).
	4.4			Form of Securities Purchase Agreement dated June 9, 2008, entered into by and between Teton Energy Corporation and the investors (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.5			Letter Agreement dated September 19, 2008 amending and supplementing the Securities Purchase Agreement dated June 9, 2008 (incorporated by reference to Exhibit 10.2 of Teton’s Form 8-K filed with the SEC on September 23, 2008).
	4.6			Form of Registration Rights Agreement (incorporated by reference to Exhibit 10.2 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.7			Subordinated Guaranty and Pledge Agreement dated June 18, 2008, entered into by and between Teton Energy Corporation, Teton North America LLC, Teton Piceance LLC, Teton DJ LLC, Teton Williston LLC, Teton Big Horn LLC, Teton DJCO LLC and Whitebox Advisors LLC (incorporated by reference to Exhibit 10.4 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.8			Form of Amended and Restated Subordinated Guaranty and Pledge Agreement dated September 19, 2008 (incorporated by reference to Exhibit 10.3 of Teton’s Form 8-K filed with the SEC on September 23, 2008).
	4.9			Form of Intercreditor and Subordination Agreement dated June 9, 2008, entered into by and between, Teton Energy Corporation, JPMorgan Chase Bank, N.A. as administrative agent and the representative for the subordinated holders (incorporated by reference to Exhibit 10.3 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.10			Amended and Restated Intercreditor and Subordination Agreement dated September 19, 2008 (incorporated by reference to Exhibit 10.4 of Teton’s Form 8-K filed with the SEC on September 23, 2008).
	10.1			Purchase and Sale Agreement between Teton DJ LLC and Noble Energy, Inc. dated effective February 1, 2009 (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on April 3, 2009).
	10.2			Purchase and Sale Agreement between Teton Energy Corporation and Teton Piceance LLC and Puckett Land Company, dated April 22, 2009 (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on April 28, 2009).
	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 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 on 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 on 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 on July 3, 2001.
	3.1.4			Certificate of Amendment to Certificate of Incorporation of Teton Petroleum Company, incorporated by reference to Exhibit 2.1.4 of Teton’s Form 10-SB (File No. 000-31170), filed on July 3, 2001.
	3.1.5			Certificate of Amendment to Certificate of Incorporation of Teton Petroleum Company, incorporated by reference to Exhibit 2.1.5 of Teton’s Form 10-SB (File No. 000-31170), filed on 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 on August 20, 2002.
	4.1			Secured Subordinated Convertible Debenture Indenture dated September 19, 2008 among Teton Energy Corporation, Teton North America LLC, Teton Piceance LLC, Teton DJ LLC, Teton Williston LLC, Teton Big Horn LLC, Teton DJCO LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on September 23, 2008).
	4.2			Form of 10.75% Secured Convertible Debenture dated June 18, 2008 issued by Teton Energy Corporation (incorporated by reference to Exhibit 4.1 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.3			Form of Global 10.75% Secured Subordinated Convertible Debenture (included in Exhibit 4.1).
	4.4			Form of Securities Purchase Agreement dated June 9, 2008, entered into by and between Teton Energy Corporation and the investors (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.5			Letter Agreement dated September 19, 2008 amending and supplementing the Securities Purchase Agreement dated June 9, 2008 (incorporated by reference to Exhibit 10.2 of Teton’s Form 8-K filed with the SEC on September 23, 2008).
	4.6			Form of Registration Rights Agreement (incorporated by reference to Exhibit 10.2 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.7			Subordinated Guaranty and Pledge Agreement dated June 18, 2008, entered into by and between Teton Energy Corporation, Teton North America LLC, Teton Piceance LLC, Teton DJ LLC, Teton Williston LLC, Teton Big Horn LLC, Teton DJCO LLC and Whitebox Advisors LLC (incorporated by reference to Exhibit 10.4 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.8			Form of Amended and Restated Subordinated Guaranty and Pledge Agreement dated September 19, 2008 (incorporated by reference to Exhibit 10.3 of Teton’s Form 8-K filed with the SEC on September 23, 2008).

	4.9			Form of Intercreditor and Subordination Agreement dated June 9, 2008, entered into by and between, Teton Energy Corporation, JPMorgan Chase Bank, N.A. as administrative agent and the representative for the subordinated holders (incorporated by reference to Exhibit 10.3 of Teton’s Form 8-K filed with the SEC on June 19, 2008).
	4.10			Amended and Restated Intercreditor and Subordination Agreement dated September 19, 2008 (incorporated by reference to Exhibit 10.4 of Teton’s Form 8-K filed with the SEC on September 23, 2008).
	10.1			Purchase and Sale Agreement between Teton DJ LLC and Noble Energy, Inc. dated effective February 1, 2009 (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on April 3, 2009).
	10.2			Purchase and Sale Agreement between Teton Energy Corporation and Teton Piceance LLC and Puckett Land Company, dated April 22, 2009 (incorporated by reference to Exhibit 10.1 of Teton’s Form 8-K filed with the SEC on April 28, 2009).
	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.