Edgar Filing: TETON ENERGY CORP

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended June 30, 2006

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

For the transition period from to

Commission file number: 001-31679

TETON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(303) 565-4600

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b—2 of the Act). (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

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

As of August 10, 2006, 14,698,414 shares of the issuer’s common stock were outstanding.

TETON ENERGY CORPORATION

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Unaudited Consolidated Financial Statements

	Consolidated Balance Sheets June 30, 2006 (Unaudited) and December 31, 2005	2

	Unaudited Consolidated Statements of Operations and Comprehensive Loss Three months ended June 30, 2006 and 2005	3

	Unaudited Consolidated Statements of Operations and Comprehensive Loss Six months ended June 30, 2006 and 2005	4

	Unaudited Consolidated Statements of Cash Flows Six months ended June 30, 2006 and 2005	5

Notes to Unaudited Consolidated Financial Statements		6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	17

Item 4.	Controls and Procedures	17

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	18

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	18

Item 3.	Defaults Upon Senior Securities	18

Item 4.	Submission of Matters to a Vote of Security Holders	18

Item 5.	Other Information	19

Item 6.	Exhibits	19

SIGNATURES		20

TETON ENERGY CORPORATION

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets

	June 30,			December 31,
	2006			2005
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	5,140,044		$	7,064,295
Trade accounts receivable	532,280			247,769
Advances to operator	227,750			224,429
Prepaid expenses and other assets	195,678			137,729
Total current assets	6,095,752			7,674,222

Non-current assets
Oil and gas properties (using successful efforts method of accounting)
Proved	5,980,005			1,717,213
Unproved	13,598,435			10,636,279
Wells in progress	4,000,848			2,105,884
Facilities in progress	641,506			120,554
Fixed assets	174,095			71,045
Total property and equipment	24,394,889			14,650,975
Less accumulated depreciation and depletion	(622,973		)	(193,702		)
Net property and equipment	23,771,916			14,457,273
Debt issuance costs	190,328			—
Total non-current assets	23,962,244			14,457,273
Total assets	$	30,057,996		$	22,131,495
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	3,796,185			1,281,457
Accrued liabilities	159,695			297,351
Accrued payroll and severance	555,776			396,589
Accrued royalties	—			94,403
Accrued franchise taxes payable	23,569			62,025
Deposits on sale of assets	—			300,000
Accrued liability of discontinued operations	—			255,000
Accrued purchase consideration	3,699,311			—
Total current liabilities	8,234,536			2,686,825

Long-term liability
Asset retirement obligations	24,342			3,851

Commitments and contingencies

Stockholders’ equity
Common stock, $0.001 par value, 250,000,000 shares authorized, 12,262,392 and 11,329,652 shares issued and outstanding at June 30, 2006 and December 31, 2005, respectively	12,262			11,329
Additional paid-in capital	47,879,540			43,929,216
Accrued stock based compensation	1,196,013			—
Accumulated deficit	(27,288,697		)	(24,499,726		)
Total stockholders’ equity	21,799,118			19,440,819
Total liabilities and stockholders’ equity	$	30,057,996		$	22,131,495

See notes to unaudited consolidated financial statements

TETON ENERGY CORPORATION

Unaudited Consolidated Statements of Operations and Comprehensive Loss

	For the Three Months Ended
	June 30,
	2006			2005

Oil and gas sales	$	650,234		$	—

Cost of sales and expenses:
Lease operating expenses	114,410			—
Production taxes	11,832			—
General and administrative	1,705,942			1,581,743
Depreciation and depletion	330,173			4,953
Exploration	74,745			113,654
Total cost of sales and expenses	2,237,102			1,700,350

Loss from operations	(1,586,868		)	(1,700,350		)

Other income
Other income	60,523			55,657
Total other income	60,523			55,657

Net loss	(1,526,345		)	(1,644,693		)

Preferred stock dividend	—			(24,487		)

Net loss applicable to common shares	$	(1,526,345	)	$	(1,669,180	)

Basic and diluted weighted average common shares outstanding	12,017,214			9,871,569

Basic and diluted loss per common share	$	(.13	)	$	(.17	)

See notes to unaudited consolidated financial statements.

TETON ENERGY CORPORATION

Unaudited Consolidated Statements of Operations and Comprehensive Loss

	For the Six Months Ended
	June 30,
	2006			2005

Oil and gas sales	$	940,483		$	—

Cost and expenses:
Lease operating expenses	148,198			—
Production taxes	19,850			—
General and administrative	3,048,745			2,273,740
Depreciation and depletion	425,939			9,850
Exploration	215,262			150,880
Total cost of sales and expenses	3,857,994			2,434,470

Loss from operations	(2,917,511		)	(2,434,470		)

Other income
Other income	128,540			134,270
Total other income	128,540			134,270

Net loss	(2,788,971		)	(2,300,200		)

Preferred stock dividend	—			(48,975		)

Net loss applicable to common shares	$	(2,788,971	)	$	(2,349,175	)

Basic and diluted weighted average common shares outstanding	11,821,760			9,636,420

Basic and diluted loss per common share	$	(.24	)	$	(.24	)

See notes to unaudited consolidated financial statements.

TETON ENERGY CORPORATION

Unaudited Consolidated Statements of Cash Flows

	For the Six Months Ended
	June 30,
	2006			2005

Cash flows from operating activities
Net loss	$	(2,788,971	)	$	(2,300,200	)

Adjustments to reconcile net loss to net cash used in operating Activities
Depreciation and depletion	425,939			9,850
Accrued stock based compensation, net of stock returned	1,038,513			834,775
Changes in assets and liabilities
From discontinued operations	(255,000		)	—
Trade accounts receivable	(284,511		)	—
Advances to operator	(3,321		)	—
Prepaid expenses and other current assets	(57,949		)	(313,044		)
Accounts payable and accrued liabilities	497,324			201,907
Accrued royalties, franchise taxes and payroll and severance	26,328			—
	1,387,323			733,488
Net cash used in operating activities	(1,401,648		)	(1,566,712		)

Cash flows from investing activities
Proceeds from sale of oil and gas properties	2,700,000			—
Increase in fixed assets	(103,050		)	(5,345		)
Increase in oil and gas properties	(7,037,981		)	(8,755,835		)
Net cash used in investing activities	(4,441,031		)	(8,761,180		)

Cash flows from financing activities
Proceeds from exercise of warrants and issuance of stock, net of issue costs of $0 and $48,862, respectively	4,108,756			248,527
Debt issuance costs from bank debt	(190,328		)	—
Payment of dividends	—			(48,975		)
Net cash provided by financing activities	3,918,428			199,552

Net decrease in cash and cash equivalents	(1,924,251		)	(10,128,340		)
Cash and cash equivalents- beginning of year	7,064,295			17,433,424
Cash and cash equivalents - end of period	$	5,140,044		$	7,305,084

Supplemental Cash Flow Information:
Non-cash accruals for awards in respect of stock based compensation	$	1,196,013		$	—
Reduction in service fees	$	157,500		$	—
Deposit applied to oil and gas properties – Note 1	$	300,000		$	—
Capital expenditures included in accounts payable	$	1,879,748		$	282,500
Accrued purchase consideration. – Note 1	$	3,699,311		$	—
Common stock and warrants issued for the acquisition of PGR LLC	$	—		$	1,088,949
Common stock issued for accounting and legal services	$	—		$	905,625
Common stock issued for settlement of accrued liabilities	$	—		$	10,500
Common stock issued for services by outside director	$	—		$	39,400
Common stock and warrants issued for the acquisition of oil and gas properties	$	—		$	792,928

See notes to unaudited consolidated financial statements.

TETON ENERGY CORPORATION

Notes to Unaudited Consolidated Financial Statements

Note 1 — Organization and Summary of Significant Accounting Policies

Organization

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

Interim Reporting

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), they do not necessarily include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of June 30, 2006, the results of operations for the three and six months ended June 30, 2006, and 2005, and cash flows for the six months ended June 30, 2006, and 2005. For a more complete understanding of our operations, financial position and accounting policies, these consolidated unaudited financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2005, previously filed with the SEC on March 10, 2006.

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

The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of natural gas and oil reserves used in calculating depletion, the amount of expected future cash flows used in determining possible impairments of oil and gas proved and unproved properties, and the amount of future capital costs used in such calculations. Assumptions, judgments, and estimates also are required in determining future abandonment obligations.

Principles of Consolidation

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

Sale of Oil and Gas Properties

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

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

Purchase of Oil and Gas Properties

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

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

In addition to our 25% interest, we have two partners in the acreage: American, which has a 50% working interest in the acreage, and Evertson Energy Company (“Everston”), which has a 25% interest. Current plans call for an affiliate of Everston to drill one multi-lateral horizontal well in 2006 at an estimated cost of $4.5 million to $5.5 million to test the acreage.

Revenue Recognition

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

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

At June 30, 2006, there are no liabilities in respect of gas balancing arrangements.

Successful Efforts Method of Accounting

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

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

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

Note 2 — Earnings per Share

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

Note 3 — Revolving Credit Facility

On June 15, 2006, the Company entered into a $50 million revolving credit facility (the “Credit Facility”) with BNP Paribas as administrative agent, sole lead arranger, and sole book runner. The Credit Facility matures on June 15, 2010.

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

Under the Credit Facility, each loan bears interest at a Eurodollar rate or a base rate, as requested by us, plus an additional margin based on the amount of our total outstanding borrowings relative to the total borrowing base. The Eurodollar rate is based on the London Interbank Offered Rate. The base rate is the higher of the Prime Rate or the Federal Funds Rate plus one-half of one percent. In addition, under the terms of the Credit Facility, we are required to pay a commitment fee based on the average daily amount of the unused amount of the commitment of each lender. This fee accrues at a rate of 0.05% per annum and is paid quarterly in arrears on the last day of March, June, September, and December of each year and on the date on which the Credit Facility is terminated. Loans made under the Credit Facility are secured by a first mortgage against the Company’s properties, a pledge of the equity of our subsidiaries and a guaranty by those same subsidiaries.

The Credit Facility contains customary affirmative and negative covenants such as minimum/maximum ratios for liquidity and leverage. Under the terms of the Credit Facility, certain covenants are not immediately effective and are phased in beginning at the end of the first quarter of 2007 and are then gradually phased-in over the first three quarters of 2007. As of June 30, 2006, there were no outstanding balances associated with the credit facility.

Note 4 — Stockholders’ Equity

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

During the six months ended June 30, 2006, 980,835 warrants and options were exercised, purchasing an equivalent of number of common shares of the Company for net proceeds to the Company of $4,108,756.

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

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

Note 5 — Stock-based Compensation

At June 30, 2006, we had several stock-based compensation plans, which are more fully described in Note 8 in our Annual Report on Form 10-K for the year ended 2005.

Prior to 2006, we accounted for those plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, as permitted by SFAS No. 123. Effective January 1, 2006, we adopted Statement of Financial Accounting Standard 123R Share-Based

Payment (“SFAS 123R”) which applies to all employee awards granted, modified, or settled after January 1, 2006. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. It also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments.

SFAS No. 123R requires measurement of the cost of share-based payment transactions to employees at the fair value of the award on the grant date and recognition of expense over the requisite service or vesting period. SFAS No. 123R requires implementation using a modified version of prospective application, under which compensation expense for the unvested portion of previously granted awards and all new awards will be recognized on or after the date of adoption. SFAS No. 123R also allows companies to adopt SFAS No. 123R by restating previously issued financial statements, basing the amounts on the expense previously calculated and reported in their pro forma footnote disclosures required under SFAS No. 123. The provisions of SFAS No. 123R were adopted by the Company effective January 1, 2006, using the modified prospective application method.

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

Awards under our 2003 Employee Stock Compensation Plan vest in periodic installments after their grant and expire 10 years from grant date. Therefore, the cost related to stock-based employee compensation included in the determination of net income in 2005 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS 123. Awards under our 2005 Long-term Incentive Plan (“LTIP”) vest upon the attainment of one, two, and three year performance milestones. During the second quarter of 2005, we issued 45,000 options to certain employees that vest in equal tranches for three years, and are described in further detail below.

Stock options granted during 2005 under the 2003 Plan will vest over a three year period and a pro rata portion of the anticipated total expense of that grant or $9,863 was accrued during the three-month period ending March 31, 2006, to account for the pro rata portion attributable for the first quarter of 2006. An additional accrual of $9,863 has been made to reflect the balance in respect of that portion of the grant that vested during the quarter ended June 30, 2006. These options are exercisable at $3.11 per share and vest over a three-year period, assuming the employees remain in our employ. These stock options were valued at $118,529 on the grant date using the Black-Scholes option-pricing model with the following assumptions: volatility of 109.46%, a risk-free rate of 4%, zero dividend payments and a life of 10 years. Vested and unvested options outstanding under the Plan at June 30, 2006, are 2,524,434 shares with exercise prices ranging from $3.11 to $3.71 per share.

A summary of stock option activity under our stock-based compensation plans for the six months ended June 30, 2006 is summarized below:

	Number Outstanding	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at December 31, 2005	2,875	$	3.54
Granted	—
Exercised	351	3.53
Forfeited or Expired	—
Outstanding at June 30, 2006	2,524	$	3.54	5.69	$	5,478

Exercisable at June 30, 2006	2,494	$	3.55	5.66	$	5,400

There were no options granted during the six months ended June 30, 2006. As of June 30, 2006, the total unrecognized compensation cost adjusted for estimated forfeitures related to non-vested options was $78,900, which is expected to be recognized over a weighed average period of approximately 24 months or 8 remaining quarters.

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

regarding consultants, vendors, and non-executive employees.

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

The 2005 Grants totaled 400,000 performance share units (each unit equivalent to one share of common stock, assuming vesting) in respect of the target or base objectives and 800,000 performance share units in respect of stretch objectives. The 2005 Grants called for vesting of 20% in 2005, 30% in 2006 and 50% in 2007, provided the milestones are achieved. The number of shares finally awarded will range from zero shares if the minimum criteria are not met, to 200% of the target award if all criteria are met at the “stretch objective” level each year. The calculation is based upon a weighted average calculation using the weighting percentages specified by the Board of Directors. Valuation of the 2005 Grants was $4.88 per share, based upon the closing price on the date of the grant, July 26, 2005. No performance grant shares vested in 2005. Of the 392,500 performance share units awarded in respect of the base case 2005 Grant, 92,500 performance share units were forfeited because of early Terminations, as defined in the LTIP as of June 30, 2006.

The 2006 Grants of performance share unit grants were awarded by the Compensation Committee of the Board of Directors during the first quarter of 2006. The 2006 Grants reserved 1,250,000 performance share units in respect of base performance and 2,500,000 in respect to achievement of stretch objectives. Each performance share unit is equivalent to one share of common stock, assuming vesting. Performance share units are performance plus service based, and vest over a one, two, and three year period (20% in 2006, 30% in 2007 and 50% in 2008, respectively), assuming both performance targets and service requirements are met. These grants are valued at $6.86, the weighted average of the closing price of the Company’s stock as reported by the American Stock Exchange on the date of the grant. The range of the grants that vest are from 0 to 200%, based upon relative achievement of the goals. To date, not all performance share units reserved have been awarded. For the first and second quarters, expense was not recognized for shares reserved for anticipated new hires (including hires after June 30, 2006) and consultants, as well as planned Terminations, as defined in the LTIP. Thus, 352,500 of 1,250,000 performance share units authorized in respect of base targets were not recognized as expense in the six months ended June 30, 2006. During the second quarter ended June 30, 2006, we issued 175,000 performance share units to new hires. Of the 908,625 performance share units awarded in respect of the base case 2006 Grants, 11,125 performance share units were forfeited because of early Terminations, as of June 30, 2006.

A summary of the status of performance share units granted under our LTIP as of June 30, 2006, and changes during the six month period ended June 30, 2006, are presented below:

	Six Months Ended June 30, 2006
(performance share unit data in thousands)	Performance Share Units		Weighted- Average Grant Date Fair Value
Outstanding at beginning of year	392.5		$	4.88
Granted	908.6		$	6.86
Vested and released	—		—
Forfeited/cancelled	(103.6	)	$	5.10
Outstanding at end of period	1,197.5		$	6.36

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

Compensation cost for both restricted shares and performance share units is calculated by taking the pro-rata portion of the number of shares expected to vest in the current fiscal year multiplied by the fair-value price on the date of the grant and amounted to $938,273 for the six months ended June 30, 2006. During the six months ended June 30, 2005, we did not award any restricted stock or performance share units under the LTIP (which had not yet been authorized by our Shareholders), and accordingly, no equivalent expense was charged to earnings.

In December 2005, grants of 195,000 restricted shares were made, which vest equally over 3 years, beginning January 1, 2006, and are based solely on service. These grants were valued at $6.06 per share, the closing price on the date of the grant. These shares will be issued only upon satisfaction of the vesting conditions. On April 1, 2006, a grant of 15,000 restricted shares was made to an executive which vest in equal installments on January 1, 2007, January 1, 2008 and January 1, 2009, provided the executive remains in our employ. This grant was valued at $6.91 per share. A grant of 20,000 shares was made to an executive, which grant vests in equal installments over a three year period beginning June 1, 2006, provided the executive remains in the our employ. This grant was valued at $6.57 per share. Prior to his becoming a director, a grant of 5,000 shares was made to a consultant (who became a director in June 2006) for services provided. The shares issued to the consultant vested at the date of grant were valued at $6.34 per share. Compensation expense for the restricted stock is $238,014 for the six months ended June 30, 2006. There was no share based compensation expense for the six months ended June 30, 2005.

The fair value of restricted stock issued pursuant to the Company’s LTIP is determined based on the market value of the common stock on the grant date. A summary of the status of restricted stock activity granted under our LTIP for the six month period ended June 30, 2006, is summarized below:

	Restricted Stock		Weighted Average Grant-Date Fair Value
	(in thousands)

Non-vested at December 31, 2005	195		$	6.06
Granted	40		$	6.67
Vested	(5	)	6.34
Forfeited	—		—
Non-vested at June 30, 2006	230		$	6.16

Note 6 — Commitments and Contingencies

Mr. Arleth, our President and Chief Executive Officer, signed an employment agreement on May 1, 2003. The agreement is for a three-year term, with an initial salary of $10,000 per month that was increased to $15,000 per month beginning in January 2004 and $20,833 beginning January 2006. Under the terms of the agreement, Mr. Arleth is entitled to 24 months severance pay in the event of a change of position or change in control of the Company. The agreement contains an evergreen provision, which automatically extends the term of Mr. Arleth’s agreement for a two-year period if the agreement is not terminated by notice by either party at least 60 days prior to the end of the stated term.

Mr. Pennington, our Executive Vice President and Chief Financial Officer, signed an employment agreement on June 1, 2006. The initial salary is $190,000 per year. Under the terms of the agreement, Mr. Pennington is entitled to 12 months severance pay in the event of a change of position or change in control of the Company. The agreement contains an evergreen provision, which automatically extends the term of Mr. Pennington’s agreement for a two-year period if the agreement is not terminated by notice by either party at least 60 days prior to the end of the initial stated term which is one year.

Mr. Schultz, our Vice President of Production, signed an employment agreement on April 1, 2006. The initial salary is $165,000 per year. Under the terms of the agreement, Mr. Schultz is entitled to six months severance pay in the event of a change of position or change in control of the Company. The agreement contains an evergreen provision, which automatically extends the term of Mr. Schultz’s agreement for a two-year period if the agreement is not terminated by notice by either party at least 60 days prior to the end of the initial stated term, which is one year.

We have entered into a three-year lease for office space, which expires in April 30, 2009. Contractual commitments under this lease are $31,847 for 2006, $63,694 for 2007, $66,412 for 2008, and $23,043 for 2009.

During 2005, we established a Simple IRA plan, allowing for the deferral of employee income. The plan provides for us to match employee contributions up to 3% of gross awards. For the three and six months ended June 30, 2006, we contributed $12,952 and $19,197 to such plan, respectively.

Note 7 — Subsequent Event

On July 27, 2006, we announced that we closed a public offering of 2,300,000 shares of our common stock, which was priced on July 27, 2006 at $5.20 per share. Total shares delivered at closing included the underwriter’s over-allotment option to purchase 300,000 additional common shares, which was exercised at closing. We received net proceeds from the offering of $11.04 million. The Company intends to use the proceeds raised from the offering for working capital, acquisitions and general corporate purposes.

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

FORWARD LOOKING STATEMENTS

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

Management Discussion And Analysis

Overview

Accomplishments and Highlights, Quarter Ended June 30, 2006

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

Financial and operational highlights for the quarter ended June 30, 2006 include the following:

· Our net loss decreased to $1,526,345 ($.13 per share) for the three month period ended June 30, 2006 from $1,669,180 ($.17 per share) for the same period in 2006.

· Our revenue from the sale of natural gas was $650,234, which is based on the sale of 131,343 mcf of natural gas at an average price of $4.95 per mcf after a total deduction of $101,797 for gathering, fuel, transportation and marketing expenses, net to the Company.

· We participated in the drilling of six wells in the current quarter to total depth on its acreage in the Piceance Basin of Colorado. We also completed seven wells in the quarter of which five wells were drilled in 2005 and two wells were drilled in the quarter ended March 31, 2006.

· We closed on the acquisition of a 25% working interest in approximately 59,000 net acres in the Williston Basin located in North Dakota.

· We entered into a $50 million revolving credit facility (the “Credit Facility”) with BNP Paribas as administrative agent, sole lead arranger, and sole book runner.

· We hired two new senior executives: a Chief Financial Officer and a Vice President of Production.

Results of Operations for the Three Months Ended June 30, 2006

We had a net loss for the three months ended June 30, 2006, of $1,526,345, which is $142,835 less than the net loss from for the same period in 2005. The decreased loss was due primarily to an increase in gas revenue associated with higher levels of gas production from the prior period when we had yet to commence producing activities in the Rocky Mountains.

During the three months ended in June 30, 2006, oil and gas production net to our interest totaled 131,343 mcf resulting in $650,234 in oil and gas sales, at an average price of $4.95 per mcf after a total deduction of $101,797 for gathering, fuel,

transportation and marketing expenses for the quarter. There were no comparative revenues in for the three months ended June 30, 2005, as we had not yet commenced operations.

Lease operating expenses and production taxes expenses for the three-month period ended June 30, 2006, were $114,410 and $11,832, respectively, (or a total of 19% of revenues) net to us resulting in operating income from oil and gas activities of $523,992 before depreciation and depletion, exploration costs, general and administrative expenses, and other income. There were no comparative expenses during the corresponding three month period ended June 30, 2005, as we had not yet commenced formal operations.

During the second quarter of 2006, general and administrative expense increased from $1,581,743 during 2005 to $1,705,942 which is primarily due to an increase in non-cash charges as described in greater detail below. Significant changes in general and administrative expenses for the three months ended June 30, 2006, compared to 2005 include:

· An increase in compensation expense increased of approximately $995,966, which increase was due primarily to $706,989 of non-cash compensation accruals of stock-based grants as a result of the performance estimates associated with our long-term incentive plan and our adoption of Statement of Financial Accounting Standard 123R Share-Based Payment, effective as of January 1, 2006. Our compensation increased as a result of an increase in the number of employees from 2005 associated with the growth in our operations.

· Stock transfer and listing fees increased $52,295 from the prior year due to the shelf registrations.

· Travel expenses increased by approximately $28,000 as a result of additional staff relative to 2005, which additional staff was responsible for overseeing increased operations relative to the comparable period.

During the three-month period ended June 30, 2006; certain general and administrative expenses were lower than in the prior year three-month period:

· Legal and accounting, decreased by approximately $832,633 from the prior year period in 2005 as a result of decreased legal and accounting costs associated with non cash compensation of approximately $798,000 related to stock awards made in 2005 to consultants providing legal and accounting services to the Company.

· Insurance-related costs were approximately $5,000 lower from the prior year period as a result of lower D&O premiums coupled with reduced premiums as a result of the closing of all satellite offices.

During the second quarter of 2006, we incurred $74,745 in exploration expenses, primarily on our DJ Basin properties, relating to delay rentals.

Depreciation and depletion expense increased from $4,953 in the second quarter in 2005 to $330,173 in the same quarter in 2006 due to the gas production in 2006 compared to none in 2005.

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

Results of Operations for the Six Months Ended June 30, 2006

We had a net loss for the six months ended June 30, 2006, of $2,788,971, which is $439,796 more than the net loss from for the same period in 2005. As described in further detail below, the increased loss was due primarily to accruals of non-cash compensation charges.

In the six months ended in June 30, 2006, oil and gas production net to our interest totaled 176,533 mcf resulting in $940,483 in oil and gas sales, at an average price of $5.33 per mcf after a total deduction of $144,578 for gathering, fuel, transportation and marketing expenses for the first six months of 2006. There were no comparative revenues in respect of the six months ended June 30, 2005, as we had not yet commenced operations.

Lease operating expenses and production taxes for the six-month period ended June 30, 2006, were $148,198 and $19,850, respectively (or a total of 18% of revenues) net to us resulting in operating income from oil and gas activities of $772,435 before depreciation and depletion, exploration costs, general and administrative expenses, and other income. There were no comparative expenses during the corresponding six-month period ended June 30, 2005, as we had not yet commenced formal operations.

During the six months ended June 30, 2006, general and administrative expense increased from $2,273,740 for the comparable period during 2005 to $3,048,745. Significant changes in general and administrative expenses for the six months ended June 30, 2006, compared to 2005 include:

· Compensation expense increased approximately $1.6 million, which increase was due primarily to $1,196,013 million of non-cash compensation accruals of stock-based grants as a result of the implementation of our long-term incentive plan and our adoption of Statement of Financial Accounting Standard 123R Share-Based Payment, effective as of January 1, 2006 and a increase in the number of employees associated with our growth between 2005 and 2006.

· Stock transfer and listing fees increased $75,729 from the prior year due to the shelf registrations.

· Office expenses increased by approximately $98,000 due to larger office space and office supplies due to increased activity.

During the six-month period ended June 30, 2006; certain general and administrative expenses were lower than in the prior year six-month period:

· Legal and accounting, decreased by approximately $895,898 from the prior year period in 2005 as a result of decreased legal and accounting costs for non cash compensation of $798,000 and lower accounting fees in 2006 from the prior year.

During the six months ended June 30, 2006, we incurred $215,262 in exploration expenses, primarily on our DJ Basin properties, relating to delay rentals.

Depreciation and depletion expense increased from $9,850 for the six months ended June 30, 2005 to $425,939 in the same period in 2006 due to the gas production in 2006 compared to none in 2005.

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

Anticipated and Completed Key Third Quarter Items

We plan to consider and pursue additional acquisitions as appropriate based on our business plan. As a result, we may incur due diligence and legal expenses, which will be capitalized only if we successfully complete an acquisition. If an acquisition is not successful, we will include those costs, in our general and administrative expenses in the year in which such expenses are incurred.

On August 1, 2006, we closed on a public offering of our 2.3 million shares of common stock, which raised, net of cost and expenses associated with that underwriting approximately $11.04 million.

On July 6, 2006, we announced that our directors had appointed Robert F. Bailey as a director of the Company.

Liquidity and Capital Resources

We had cash and cash equivalents of $5,140,044 at June 30, 2006, and a working capital deficit of $2,138,784.

We have revised our 2006 capital commitment to approximately $17.8 million net to the Company’s interest. This revised commitment includes our proportionate costs associated with the drilling of up to 30 total wells (depending on rig availability and other factors) and our proportionate costs relative to the construction of an access road on the Piceance Basin acreage of approximately $15.75 million net to the Company’s interest. We also anticipate that we could incur potential additional expenditures relating to gathering systems on our DJ Basin acreage of $500,000 (net to the Company’s interest), as drilling results become known. Also included in the total $17.8 million is $1.55 million net to the Company’s interest for capital requirements in respect of our commitment in the development of our Williston Basin property acquisition for the balance of the year.

We anticipate that we will utilize working capital generated from our ongoing operations in the Piceance Basin to meet some of our 2006 commitments. In addition, in March 2006, we filed S-3 and S-4 shelf registration statements for $50 million each in financing capacity, or a total of $100 million, which registration statements have been declared effective by the SEC. We may also receive proceeds from the exercise of outstanding warrants as we did during the six months ended June 30, 2006. At August 1, 2006, warrants to purchase 867,819 shares of common stock were outstanding. These warrants

have a weighted average exercise price of $3.14 per share and expire between April 2008 and December 2012.

In June 2006, we established a $50 million revolving credit facility with BNP Paribas (the “Credit Facility”). The Credit Facility has an initial borrowing base of $3 million and matures on June 15, 2010. The Credit Facility provides for as much as $50 million in borrowing capacity, depending upon a number of factors, such as the projected value of our proven oil and gas assets. The borrowing base for the Credit Facility at any time will be the loan value assigned to the proved reserves attributable to our and/or our subsidiaries’ direct or indirect oil and gas interests. The borrowing base will be redetermined on a semi-annual basis, based upon an engineering report delivered by us from an approved petroleum engineer. The Credit Facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit.

Subsequent to June 30, 2006, we closed on a public underwriting, which raised approximately $11.04 million from the issuance of 2.3 million shares of common stock for the Company net of underwriting discounts and expenses associated with the underwriting.

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

Sources and Uses of Funds

Historically, our primary source of liquidity has been cash provided by equity offerings. These offerings may continue to play an important role in financing our business. Our primary uses for cash raised from third parties or generated through operations will be in respect of additional acquisitions or in connection with drilling programs associated with our various properties.

Cash Flows and Capital Expenditures

During the six months ended June 30, 2006, we used $1,401,648 of cash in our operating activities. This amount compares to $1,566,712 of cash used in our operating activities during the six month period in 2005. The decrease of net cash used in our operating activities of $165,064 was primarily due to an increase in accounts payable and accrued liabilities.

During six months ended June 30, 2006 we received cash of $2,700,000 in connection with the entering into the Acreage Earning Agreement with Noble involving our DJ Basin acreage. During the same period, we incurred costs of $7,037,981 related to our drilling and completion operations in the Piceance Basin and our acquisition of the 25% working interest in the Williston Basin.

During six months ended June 30, 2006, holders of 629,935 warrants exercised these warrants and purchased an equivalent number of common shares of the Company for net proceeds to us of $2,869,022, and holders of 350,900 stock options exercised these options and purchased an equivalent under of common shares of the Company for net proceeds to us of $1,239,732. For the six months ended June 30, 2006, we raised $4,108,756 from the combined sale of options and warrants.

Income Taxes, Net Operating Losses and Tax Credits

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

Critical Accounting Policies and Estimates

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

Reserve Estimates

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

Impairment of Oil and Gas Properties

We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in their carrying value. We estimate the expected future cash flows of our developed proved properties and compare such future cash flows to the carrying values of the proved properties to determine if the carrying value is recoverable. If the carrying value exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of the oil and gas properties to their fair value. The factors used to determine fair value include, without limitation, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the carrying values associated with oil and gas properties.

Stock Compensation

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

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

During the quarter ended June 30, 2006, we recorded current compensation of $706,989 based on our management’s current assessments of the progress being made in the satisfaction of performance and service conditions for these awards that could vest at yearend 2006, provided the milestones are achieved. The performance assessment is scored based on an evaluation of the degree of progress made in achieving each of threshold, base, and stretch objectives established by the Compensation Committee of our Board of Directors by yearend. Our compensation expense will increase or decrease in subsequent quarters based on management’s progress toward the achievement of these objectives. Improved performance during the subsequent quarters of the year will increase compensation expense in those quarters whereas diminished performance will reduce compensation expense in subsequent quarters.

Under SFAS 123R, our accounting for stock options has changed materially. We now amortize the unvested portion of stock option grants over the vesting period at the fair value of the option, as described in Note 5 to the financial statements. At June 30, 2006, there were 45,000 option grants unvested.

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 natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses depending on market dynamics. This forward-looking information provides indicators of how we view and manage (or anticipate managing) our ongoing market risk exposures.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable in past years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. For the three months ended June 30, 2006, our income before income taxes, including hedge settlements, would have changed by $13,134 for each $0.10 per mcf change in natural gas prices. During the three months ended June 30, 2006, we had no oil production.

To date, we have not entered into financial hedging activities with respect to any portion of our projected natural gas and oil production, although we may do so in the future, particularly if we were to make a large acquisition of producing assets.

Interest Rate Risk

At June 30, 2006, we had no debt outstanding on our Credit Facility. Under the Credit Facility, each loan bears interest at a Eurodollar rate or a base rate, as requested by us, plus an additional margin based on the amount of our total outstanding borrowings relative to the total borrowing base. The Eurodollar rate is based on the London Interbank Offered Rate (“LIBOR”). The base rate is the higher of the Prime Rate or the Federal Funds Rate plus one-half of one percent. In addition, under the terms of the Credit Facility, we are required to pay a commitment fee based on the average daily amount of the unused amount of the commitment of each lender. This fee accrues at a rate of 0.050% per annum and is paid quarterly in arrears on the last day of March, June, September, and December of each year and on the date on which the Credit Facility is terminated. Although there are currently no outstanding borrowings against the Credit Facility, a one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate would have resulted in an estimated $7,500 increase in interest expense on a quarterly basis, assuming we were to draw down on the entire amount of our borrowing base of $3 million.

ITEM 4. CONTROLS AND PROCEDURES

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this Quarterly Report on Form 10-Q. In designing and evaluating the disclosure controls and procedures, management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. Based on that evaluation, our Chief Executive Offer and Chief Financial Officer concluded that, as of the end of such period, our disclosure controls and procedures are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported on a timely basis.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the six months ended June 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 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

Our Annual Meeting of Shareholders was held on April 13, 2006. The matters voted upon, including the number or votes cast for, against or withheld, as well as the number of abstentions, as to each such matter were as follows:

Proposal 1: All five nominees for directors listed in the Company’s 2006 proxy statement were elected. The number of votes cast for each nominee was as follows:

Karl F. Arleth	7,976,004	Shares In Favor	127,820	Shares Withheld

John T. Connor, Jr.	7,975,999	Shares In Favor	127,825	Shares Withheld

Thomas F. Conroy	7,971,601	Shares In Favor	132,223	Shares Withheld

William K. White	7,838,561	Shares In Favor	265,263	Shares Withheld

James J. Woodcock	7,788,966	Shares In Favor	314,828	Shares Withheld

Proposal 2: The Proposal to appoint Ehrhardt Keefe Steiner & Hottman PC as independent auditors to examine the Company’s financial statements for the fiscal year ending December 31, 2006 was ratified by the following vote:

For		Against		Abstain
8,088,813		12,611		2,400

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS:

Exhibits

10.1 Purchase Agreement between American Oil and Gas, Inc. and Teton Energy Corporation.

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

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

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

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

SIGNATURES

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

	TETON ENERGY CORPORATION


Date: August 14, 2006	By:	/s/ Karl F. Arleth
		Karl F. Arleth President and Chief Executive Officer


Date: August 14, 2006	By:	/s/ Bill I. Pennington
		Bill I. Pennington Chief Financial Officer (Principal Financial and Accounting Officer)