HESS BAKKEN INVESTMENTS I (AEZ) 10-Q 2009 Q1 Quarterly report

United States Securities and Exchange Commission

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2009

OR

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

For the transition period from                    to                    

Commission File No. 1-31900

AMERICAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Nevada	88-0451554
(State or jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1050 17th Street, Suite 2400, Denver, CO	80265
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (303) 991-0173

Indicate by check mark whether the issuer (i) 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. Yesþ Noo

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). Yeso Noo (None required)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common equity as of the latest practicable date:

The total shares of $.001 Par Value Common Stock outstanding at May 4, 2009 were 48,307,399.

AMERICAN OIL & GAS, INC.
FORM 10-Q
INDEX

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	3
Condensed Consolidated Balance Sheets — March 31, 2009 and December 31, 2008	3
Condensed Consolidated Statements of Income — Three Months Ended March 31, 2009 and 2008	4
Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2009 and 2008	5
Notes to Condensed 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 Risks	15
Item 4. Controls and Procedures	16
PART II. OTHER INFORMATION
Item 1A. Risk Factors	17
Item 6. Exhibits	17
Signatures	18
EX-31.1
EX-31.2
EX-32.1
EX-32.2

2

PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2009			2008
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	15,726,398		$	23,269,725
Short-term investments		5,000,000			5,450,000
Accounts receivable		757,399			1,186,749
Materials and supplies inventory		1,913.287			1,236,591
Prepaid expenses		135,373			133,360
Total current assets		23,532,457			31,276,425
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $33,915,965 at 3/31/09 and $31,837,965 at 12/31/08)		42,044,989			40,456,632
Other property and equipment		366,354			366,354
Total property and equipment		42,411,343			40,822,986
Less-accumulated depreciation, depletion and amortization		(5,112,721	)		(4,980,578	)
Net property and equipment		37,298,622			35,842,408
OTHER ASSETS
Deferred income tax assets (net of valuation allowance, Note 6)		—			—
Intangible asset, net of accumulated amortization		195,000			240,000
Other		30,385			30,385
	$	61,056,464		$	67,389,218
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	1,793,857		$	4,286,618
Income taxes payable		—			104,000
Total current liabilities		1,793,857			4,390,618
LONG-TERM LIABILITIES
Asset retirement obligations		440,614			430,686
COMMITMENTS AND CONTINGENCIES(Note 9)
STOCKHOLDERS’ EQUITY
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding - 48,307,399 shares at 3/31/09 and 47,875,899 shares at 12/31/08		48,307			47,876
Additional paid-in capital		91,670,568			91,275,557
Accumulated deficit		(32,646,882	)		(28,755,519	)
Accumulated other comprehensive income (loss)		(250,000	)		—
		58,821,993			62,567,914
	$	61,056,464		$	67,389,218

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

3

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATION

(UNAUDITED)

	Three months ended
	March 31,
	2009			2008
REVENUES
Oil and gas sales	$	305,674		$	507,804
OPERATING EXPENSES
Lease operating		299,675			254,775
General and administrative		1,629,546			1,390,208
Depletion, depreciation and amortization		177,143			353,504
Impairments		2,100,000			—
Accretion of asset retirement obligation		9,653			8,085
		4,216,017			2,006,572
LOSS FROM OPERATIONS		(3,910,343	)		(1,498,768	)
OTHER INCOME (LOSS)
Investment income		20,980			223,711
Gain (loss) on sale of securities		—			(330,804	)
Interest expense		—			(23,524	)
		20,980			(130,617	)
LOSS BEFORE INCOME TAXES		(3,889,363	)		(1,629,385	)
Income tax expense-current		—			—
Income tax expense (reduction) -deferred		—			(458,000	)
NET LOSS		(3,889,363	)		(1,171,385	)
Less dividends on preferred stock		—			(149,040	)
Less deemed dividend on warrant re-pricing		(2,000	)		—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(3,891,363	)	$	(1,320,425	)
NET LOSS PER COMMON SHARE(basic and diluted)	$	(0.08	)	$	(0.03	)
Weighted average common shares outstanding, basic and diluted		48,238,988			46,478,491

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

4

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three months ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(3,889,363	)	$	(1,171,385	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairment of oil and gas properties		2,100,000			—
Share-based compensation expenses		393,442			266,859
Depletion, depreciation and amortization		177,143			353,504
Accretion of asset retirement obligations		9,653			8,085
Realized loss on sale of short-term investments		—			330,804
Deferred income taxes		—			(458,000	)
Changes in assets and liabilities:
Decrease (increase) in receivables		349,350			(42,748	)
Decrease (increase) in prepaid expenses		(2,013	)		31,389
Decrease (increase) in inventory		(676,696	)		—
Increase (decrease) in accounts payable and accrued liabilities		30,919			91,790
Net cash used in operating activities		(1,507,565	)		(589,702	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties		(6,235,762	)		(2,025,180	)
Proceeds from redemptions and sales of short-term investments		200,000			474,596
Cash paid for office equipment		—			(6,414	)
Net cash used by investing activities		(6,035,762	)		(1,556,998	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowing		—			8,600,000
Net cash provided by financing activities		—			8,600,000
NET INCREASE (DECREASE) IN CASH		(7,543,327	)		6,453,300
CASH, BEGINNING OF PERIODS		23,269,725			2,388,219
CASH, END OF PERIODS	$	15,726,398		$	8,841,519
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	—
Cash paid for income taxes	$	130,000		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING ACTIVITIES
Net increase (decrease) in payables for capital expenditures	$	(2,627,680	)	$	1,901,527
Preferred dividends paid in shares of common stock	$	—		$	298,080
Share-based compensation expenses	$	393,442		$	266,859
Drilling prepayments applied to drilling costs	$	—		$	209,773

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

5

AMERICAN OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(UNAUDITED)
March 31, 2009

NOTE 1 — COMPANY AND BUSINESS

In these Notes, the terms “Company”, “American”, “we”, “us”, “our” and terms of similar import refer to American Oil & Gas, Inc.

We are an independent energy company engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States. Our operations are currently focused in Wyoming and North Dakota. We own a wholly-owned subsidiary, Tower American Corporation, for conducting oil and gas exploration and production operations in Colorado. We do not anticipate operating outside the United States. Our fiscal year end is December 31.

NOTE 2 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying interim financial statements of American are unaudited. In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three-month period ended March 31, 2009 are not necessarily indicative of the operating results for the entire year ending December 31, 2009.

We have prepared the financial statements included herein pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosure normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and recommend that these condensed financial statements be read in conjunction with the financial statements and notes included in our Form 10-K for the year ended December 31, 2008.

USE OF ESTIMATES— As further discussed on pages F-7 and F-8 of our Form 10-K for the year ended December 31, 2008, the preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

SIGNIFICANT ACCOUNTING POLICIES— For descriptions of the Company’s significant accounting policies, please see pages F-8 through F-11 of Form 10-K for the year ended December 31, 2008.

For interim financial reporting during a fiscal year, current and deferred tax provisions are based on projected effective tax rates for the full year applied to the pre-tax income for the interim period, whereby the deferred tax assets and liabilities at the end of an interim period are impacted by their projected balances for the year-end.

Amortization of oil and gas property costs is computed quarterly and not year-to-date, using the estimated proved reserves as of the end of the calendar quarter. Amortization for the fiscal year is the sum of the four quarterly amortization amounts. Management estimated the proved reserves at March 31, 2009 and March 31, 2008, with consideration of (1) the proved reserve estimates for the prior fiscal year-end prepared by independent engineering consultants and (2) significant new discoveries and significant changes during the interim period in production, ownership, and other factors underlying reserve estimates.

RECENT ACCOUNTING PRONOUNCEMENTS— As of March 31, 2009, there have been no recent accounting pronouncements currently relevant to the Company in addition to those discussed on page F-11 of our Form 10-K for the year ended December 31, 2008.

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In April 2009, the FASB issued three FASB Staff Positions (“FSPs”) to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities:

• FSP FAS 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,

• FSP FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instrumentand

• FSP FAS 115-2 and FAS 124-2,Recognition and Presentation of Other-Than-Temporary Impairment.

These three FSPs are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We did not adopt the provisions of these FSPs for the three months ended March 31, 2009. Management does not expect the forthcoming adoption of these FSPs will have a material impact on our financial position or results of operations.

GAS BALANCING— As of March 31, 2009 and December 31, 2008, our gas production was in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.

INVENTORY— Inventories classified as current assets consists of purchased well casing and tubing stored in central yards serving multiple oil and gas companies. Such inventory is carried at the lower of cost or market using weighted average cost. Casing and tubing moved to well sites are classified as non-current assets to be used in the completion of wells.

RECLASSIFICATION —Certain amounts in the 2008 consolidated financial statements have been reclassified to conform to the 2009 financial statement presentation. Such reclassifications have had no effect on net loss.

The following table reflects the change in ARO for the three-month periods ended March 31, 2009 and March 31, 2008:

	Three-month Period
	Ended March 31,
	2009			2008
Asset retirement obligation, beginning of period	$	430,686		$	323,369
Liabilities incurred		8,811			4,442
Liabilities settled		—			—
Accretion		9,653			8,085
Revisions in estimated liabilities		(8,536	)		(6,125	)
Asset retirement obligation, end of period	$	440,614		$	329,771
Current portion of obligation, end of period	$	—		$	—

NET INCOME (LOSS) PER SHARE— Basic net income (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted number of common shares outstanding during the period. Diluted net income (loss) per share reflects per share amounts that would have resulted if dilutive potential common stock had been converted to common stock.

For the three-month periods ended March 31, 2009 and March 31, 2008, there are no adjustments for dilution because of each period’s net loss (rather than net income) to common shareholders. Securities outstanding at March 31, 2009 that could in the future potentially dilute basic net income (loss) per share for common stockholders are described in Notes 7 and 9 and include (i) warrants for 885,626 shares, (ii) outstanding stock options for 3,022,000 shares (of which 1,003,833 were exercisable at March 31, 2009), and (iii) an option for 2,900,000 common shares in exchange for certain oil and gas properties.

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NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at March 31, 2009, consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization	$	33,915,965
Evaluated costs		8,129,024
		42,044,989
Office equipment, furniture and software		366,354
		42,411,343
Less accumulated depreciation, depletion and amortization		(5,112,721	)
Property and equipment	$	37,298,622

During the three-month period ended March 31, 2009, we incurred $3.7 million in oil and gas property acquisition, exploration and development. Of those costs, $1.3 million were for the completion of the productive Sims 7-25 well at our Fetter project and the marginally productive Viall 30-1 well completed in the Red River formation at our Goliath project in North Dakota. We incurred $1.2 million in costs of acquiring leases and performing preliminary field activities at our Bigfoot project. We also incurred approximately $900,000 in additional costs of other unevaluated properties. Included in the capital additions were $264,000 of internal land department and geologist costs directly associated with acquired or owned property. There were no other significant property acquisitions and no significant property divestitures in the three-month periods ended March 31, 2009 and March 31, 2008.

We use the full-cost accounting method, which requires recognition of an impairment of oil and gas properties when the total capitalized costs (net of related deferred income taxes) exceed a “ceiling” as described on page F-9 of our Form 10-K as of December 31, 2008. We recognized as of March 31, 2009, $2,100,000 ($1,330,000, net of a $770,000 increase in deferred tax assets before valuation allowances) in impairments of oil and gas properties. The calculated impairment considered oil and gas prices as of April 30, 2009, as allowed by SEC staff guidance, reducing the impairment by $100,000 from what otherwise would have been recorded based on March 31, 2008 oil and gas prices.

The following table shows Depreciation, Depletion and Amortization (“DD&A”) expense by type of asset:

	Three-month Period
	Ended March 31,
	2009		2008
Amortization of costs for evaluated oil and gas properties	$	113,000	$	290,000
Amortization of Intangible Asset		45,000		45,000
Depreciation of office equipment, furniture and software		19,143		18,504
Total DD&A expense	$	177,143	$	353,504

NOTE 4 — SHORT-TERM INVESTMENTS

Our short-term investments at March 31, 2009 and December 31, 2008 were comprised of auction-rate preferred shares (“ARPS”) issued by closed-end mutual funds. ARPS are a form of auction-rate securities (“ARS”) that were bought and sold at par value prior to March 2008 at special auctions held every 7 days or 28 days and paying variable-rate dividends, with the rate re-determined at the auctions. After February 2008, there were no parties willing to buy ARPS at par value at the auctions, i.e., the auctions “failed.” Since February 2008, some mutual funds have redeemed some or all of their ARPS at par value, and several large investment banks and brokerage firms (generally in settlement with customers or with government agencies) have bought back their customers’ ARPS at par value.

ARPS issuers redeemed at par value $11,500,000 of our ARPS in the year ended December 31, 2008, another $200,000 of our ARPS in the three months ended March 31, 2009, and $75,000 of our ARPS in April 2009.

8

These short-term investments are classified under SFAS 115 as investments held for sale, rather than marketable securities. Unrealized gains and temporary unrealized losses are recorded in Other Comprehensive Income (Loss). Unrealized losses that are “other-than-temporary” are reflected in the consolidated statement of operations and not reversible in subsequent periods. The ARPS’ total par value and carrying value (estimated fair value) were as follows:

	March 31,		December 31,
	2009		2008
Total par value	$	5,550,000	$	5,750,000
Carrying value (and estimated fair value—see Note 5)	$	5,000,000	$	5,450,000

Of the $550,000 in unrealized loss at March 31, 2009, $300,000 was regarded in 2008 as other-than-temporary and recognized in the 2008 Statement of Operations. The other $250,000 in unrealized loss arose as of March 31, 2009 and is viewed by our management as a temporary loss, recorded in Other Comprehensive Loss.

NOTE 5 — FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”) for all financial assets and liabilities measured at fair value on a recurring basis. We chose not to elect the fair value option as prescribed by SFAS 159 for financial assets and liabilities that had not been previously carried at fair value. Therefore, material financial assets and liabilities not carried at fair value, such as trade accounts receivable and accounts payable, are still reported at their face values.

SFAS 157 establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. It defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of fair values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement calls for disclosures grouping these financial assets and liabilities, based on the following levels of significant inputs to measuring fair value:

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

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

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

At December 31, 2008, our financial assets measured at fair value consisted of $5,450,000 of ARPS (discussed in Note 4). Their fair values were based on Level 3 inputs. At March 31, 2009, our financial assets and liabilities measured at fair value were as follows:

	Total at
	March 31,		Level 1		Level 2		Level 3
	2009		inputs		inputs		inputs
Financial Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares	$	5,000,000	$	—	$	—	$	5,000,000
Financial Liabilities	$	—	$	—	$	—	$	—

Management’s estimate of the ARPS’ fair value at March 31, 2009 considered several factors, particularly as to the likelihood and timing of future liquidity of such ARPS at par value. In addition to the factors disclosed on page F-15 of our Form 10-K as of December 31, 2008, we considered that Calamos funds have not yet announced board approval for redemption of the funds’ ARPS, including the Calamos ARPS we hold ($2,325,000 par value). We no longer expect our Calamos ARPS to be redeemed soon and have reduced estimated total fair value of our ARPS by an additional $250,000 to account for a delay in redemption of the Calamos ARPS.

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NOTE 6 — INCOME TAXES

We account for income taxes under the provisions of SFAS No. 109, “Accounting for Income Taxes,”which provides for an asset and liability approach in accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

We currently estimate that our effective tax rate for the year ending December 31, 2009 will be approximately 31.7%. Deferred income tax reductions of $0 (net of a $1,200,000 valuation allowance) and $458,000 were reported for the three-month periods ended March 31, 2009 and 2008, respectively. As of March 31, 2009, net deferred tax assets were $0, after a 100% valuation allowance applied to net deferred tax assets of $5,952,308.

We file annual US federal income tax returns and have filed annual income tax returns for the states of Colorado, Montana, North Dakota and Utah. We primarily do business in Wyoming, but Wyoming does not impose corporate income taxes. We believe we are no longer subject to income tax examinations by tax authorities for years before 2003 for Colorado and for 2004 for all other returns. Our income tax returns and supporting records have never been examined by tax authorities.

On January 1, 2007, we adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes(“FIN 48”). We found no significant uncertain tax positions as of any date as of March 31, 2009.

Our policy is to recognize accrued interest related to unrecognized tax benefits in interest expense and to recognize tax penalties in operating expense. However, given our substantial net operating loss carryforwards at the federal level prior to 2008 and at the state levels prior to 2009, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2009.

NOTE 7 — EQUITY

Common Stock

The following transactions occurred during the first quarter ended March 31, 2009 with regard to our common stock:

• On January 14, 2009, our Board of Directors granted an aggregate of 427,500 shares of common stock pursuant to the 2006 Stock Incentive Plan to certain employees, officers and directors of the Company. Of the 427,500 shares, 90,000 vested at grant and the other 337,500 shares vest upon the earlier of January 14, 2014 or a change in control of the Company.

• On January 14, 2009, our Board reduced the exercise price from $7.00 per share to $3.50 per share for a warrant issued in April 2008, expiring April 16, 2013, to acquire 50,000 shares of our common stock. The $2,000 estimated fair value of reducing the exercise price was recognized as a deemed dividend, increasing Additional Paid-In Capital by the $2,000 value.

• In February 2009, we issued 4,000 shares of common stock to our Vice-President of Land as required under his employment contract of February 2007.

• For the quarter ended March 31, 2008, Additional Paid-In Capital increased by $393,442 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of (i) $259,008 in share-based compensation related to stock options, (ii) $50,734 related to accruals for granted stock vesting after grant and (iii) $83,700 for the January 14, 2009 granting and immediate vesting of 90,000 shares of common stock.

Warrants

The table below reflects the status of warrants outstanding at March 31, 2009 held by others to acquire our common stock:

	Common		Exercise		Expiration
Issue Date	Shares		Price		Date
April 16, 2008		50,000	$	3.50	April 16, 2013
July 22, 2005		835,626	$	6.00	September 30, 2009
		885,626

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At March 31, 2009, the per-share weighted average exercise price of outstanding warrants was $5.86 per share, and the weighted average remaining contractual life was 0.7 years.

Stock Options

In the three months ended March 31, 2009, stock option activity was insignificant—we granted no stock options; stock options for 15,000 shares were forfeited and no stock options were exercised. On January 14, 2009, we granted extensions of approximately four years to vested options of 403,000 shares. The extension grants had an estimated total fair value of $93,660, which was recognized in option expense at the time of grant.

Other Comprehensive Loss

During the quarter ended March 31, 2009, Other Comprehensive Loss increased by $250,000 to reflect a temporary decline in the fair value of short-term investments, net of related deferred income taxes, as discussed in Note 4.

NOTE 8 — MATERIAL RELATED PARTY TRANSACTIONS

We had no material related party transactions during the quarter ended March 31, 2009.

NOTE 9—COMMITMENTS AND CONTINGENCIES

The Company may be subject to various possible contingencies, which are derived primarily from interpretations of federal and state laws and regulations affecting the oil and gas industry. Although management believes it has complied with the various laws and regulations, new rulings and interpretations may require the Company to make future adjustments.

North Finn Option

Under our January 2006 participation agreement with North Finn, LLC, we fund 60% of North Finn’s lease, drilling and other project related capital obligations in jointly owned project areas, in order to earn 60% of North Finn’s interest in that particular lease or well, including offset locations. We paid $535,000, and reimbursed approximately $976,000 to North Finn for 60% of all project related costs that North Finn has incurred in jointly owned project areas after the effective date of August 1, 2005.

Under the participation agreement, the Company and North Finn each has the right (an option), during specified time periods, to trigger the transfer to the Company by North Finn of 60% of North Finn’s interests in any unearned project areas in which the Company already has an interest, and a simultaneous issuance by the Company to North Finn of 2,900,000 shares of the Company’s common stock. North Finn’s right of exchange is exercisable at any time on or before July 31, 2012, and the Company’s right of exchange is exercisable at any time beginning August 1, 2010 and ending July 31, 2012. If the exchange occurs and the Company receives the 60% interest from North Finn, the Company will not earn or fund any additional interests in the North Finn acreage under the participation agreement.

As North Finn has not exercised its option nor made a commitment to exercise, under the AICPA Emerging Issues Task Force Interpretation 96-18, the value of North Finn’s option is not currently recognized in our financial statements.

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

This discussion and analysis should be read in conjunction with the accompanying financial statements and related notes. Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an ongoing basis, we review our estimates and assumptions. Our estimates are based on our historical experience and other assumptions that we believe to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but we do not believe such differences will materially affect our financial position or results of operations.

Our critical accounting policies (the policies we believe are most important to the presentation of our financial statements and require the most difficult, subjective and complex judgments) are outlined in our notes to financial statements.

This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Actual events or results may differ materially from those anticipated or implied in the forward-looking statements. There are a number of risks and uncertainties that could cause our actual results to differ materially from those indicated by such forward-looking statements. These risks and uncertainties include, but are not limited to, those described in this report, in Part II, “Item 1A. Risk Factors,” those described in our Annual Report on Form 10-K for the year ended December 31, 2008, and those described from time to time in our future reports filed with the SEC.

Overview

We are an independent oil and gas exploration and production company, engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States. Our current operations are focused primarily in four main project areas that we call Fetter, Goliath, Krejci and Bigfoot. The following project updates should be read in conjunction with our Annual Report on Form 10-K for our fiscal year ended December 31, 2008.

Fetter Project (Powder River Basin, Wyoming)

Our Fetter project, located in the southern Powder River Basin of Wyoming, currently encompasses approximately 53,000 gross acres. We own a 69.375% working interest in approximately 49,000 net acres, giving us approximately 34,000 total net acres at Fetter. Red Technology Alliance, LLC (“RTA”) owns a 25% working interest and North Finn LLC retains the remaining 5.625% working interest. The drilling and completion operations have been project managed by Halliburton Energy Services, Inc.

We continue to progress toward establishing a commercially successful drilling program within our Fetter project area. Currently, our activities include a re-entry program that could enable us to establish production from formations in addition to the primary Frontier formation which is currently productive in a number of existing wells.

We have two vertical wells, the Wallis 6-23 and the Hageman 11-22, that were each drilled to approximately 13,000 feet, approximately 1,500 feet below the Frontier formation. Both wells have been producing exclusively from the Frontier formation, with lower, potentially productive formations temporarily plugged off. Our planned re-entry work in the Wallis 6-23 well includes attempting to drill out the bridge plug that was set below the Frontier formation in an effort to commingle production from two lower formations, the Dakota and Mowry.

Directly above the Frontier formation are two more over-pressured and gas bearing formations, the Niobrara formation and Steele formation. There are number of existing wells which we could re-enter and test these formations. Our plans are to re-enter at least one well (the first well is likely to be the Hageman 16-34HR well) to set a removable bridge plug above the Frontier formation and complete and fracture stimulate the Niobrara formation. After production testing of only the Niobrara formation, we expect to remove the temporary bridge plug and flow the well from both the Niobrara and Frontier formations. Depending on results of commingling production from the Frontier and Niobrara formations, we may repeat the re-entry operation to test and combine production from the Steele formation.

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Our recently expanded field compression capabilities in our gathering system have enabled us to consistently deliver natural gas to purchaser(s) of our gas. Although the Frontier formation with the Fetter area is primarily a natural gas bearing formation, these wells also produce a volume of high-quality oil. We have installed artificial lift systems (plunger lifts) in a total of four wells that we expect could allow the wells to better lift the high quality oil up the well, adding to revenues and proved reserves while reducing the risk of the oil collecting in the wells in ways that can reduce or block the flow of natural gas from the wells. Early indications are that the wells are responding favorably to the plunger lifts. We have also installed injection equipment that allows circulating produced natural gas back down the wellbore, increasing the gas-to-oil ratio, which in turn increases the amount of natural gas and oil production. Early indications are also positive for this injection system to increase production. Because we have only recently been able to consistently produce the wells at Fetter, we have spent a considerable amount of time and effort in actively managing the filed production. As a result of these additional efforts, which we view as short term and temporary, the lease operating expenses for the Fetter project were abnormally high during the quarter ended March 31, 2009. We expect that as we understand how best to produce the wells at Fetter and the field production is operating efficiently, monthly lease operating expenses will decrease to a much lower level.

We continue to experience a general decrease in service costs and by combining lower costs to drill and complete wells with commingling production from multiple formations and enhancing existing production with artificial lift methods, we remain confident that the Fetter project could provide commercially successful production which will support further development, even in today’s low natural gas commodity price environment.

Goliath Bakken Project (Williston Basin, North Dakota)

Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are targeting both the middle member of the Bakken and Three Forks formations in the North Dakota portion of the Williston Basin. Our Goliath project area currently encompasses approximately 87,000 gross acres, and we own a 50% working interest in approximately 65,000 lease net acres. Our acreage position lies directly west and adjacent to the Nesson Anticline.

We do not expect to expend substantial capital within the Goliath project during 2009. During the first quarter 2009, we terminated the previously announced agreement with RTA that provided RTA the opportunity to earn an ownership interest in Goliath by paying 100% of the cost to drill two to four horizontal wells to test the Bakken and/or Three Forks formations. We are seeking an outside participant to pay for all or a substantial portion of one or more wells, in return for an ownership interest in Goliath. Recent success by other companies west of the Nesson anticline has provided increased interest for our Goliath acreage position.

Advancements in drilling and completion techniques that have resulted in successful Bakken wells by other operators west of the Nesson Anticline, will be incorporated into future drilling at Goliath. We also expect that future drilling will be designed to provide important reservoir and geological data from other prospective formations in the project area including the Three Forks/Sanish, Madison, Nisku, Duperow, Interlake, Stonewall, Red River and Winnipeg.

Krejci Oil Project (Powder River Basin, Wyoming)

Within our Krejci project, we have been and continue to primarily evaluate the productive potential of the Mowry formation at an approximate depth of 7,500 feet. We have focused our efforts in and around the Krejci Field in Niobrara County, Wyoming. Our Krejci project area currently encompasses approximately 128,000 gross (approximately 52,000 net) acres. In addition to the productive potential of the Mowry formation, there are multiple other formations that are productive in different areas in the middle and southern Powder River Basin and we continue to evaluate our Krejci acreage position for production potential from these other formations.

Other companies are now either drilling or planning to drill wells targeting the Mowry formation in the middle and southern parts of the Powder River Basin, and we will be watching the level of success these other companies have with their drilling, stimulation and completion operations. We do not expect to incur significant capital expenditures in the Krejci project unless or until other companies are successful in establishing commercial production from the Mowry formation. However, we are participating in a vertical well and own an approximate 9% working interest in a well operated by a private oil and gas company. This well has been drilled and completed vertically in the Mowry formation. Early indications from the well are positive as the well has produced oil and natural gas from the Mowry formation. Current plans for this well are to place the well on pump and monitor the production.

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Bigfoot Project (Rocky Mountain Region)

We currently control approximately 157,000 net acres in a project that we call Bigfoot. This is a shallow natural gas project located in the Rocky Mountain region. This project remained in the lease acquisition stage at March 31, 2009. We expect to acquire additional 2D seismic data, drill test wells and acquire additional leasehold in the Bigfoot area during 2009.

Results of Operations

The following discussion should be read in conjunction with the audited financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended March 31, 2009 Compared with the Quarter Ended March 31, 2008

For the quarter ended March 31, 2009, we recorded a net loss attributable to common stockholders of $3,891,363 ($0.08 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $1,320,425 ($0.03 loss per common share, basic and diluted) for the quarter ended March 31, 2008. The $2.6 million increase in loss includes a $2,100,000 non-cash impairment of our oil and gas properties under full-cost accounting rules.

For the quarter ended March 31, 2009, we recorded total oil and gas revenues of $305,674 compared with $507,804 for the quarter ended March 31, 2008. The $202,130 decrease from the 2008 quarter is attributable exclusively to lower oil and gas prices. Oil and gas sales and production costs are summarized in the following table:

	Three months ended
	March 31,
	2009			2008
Oil sold (barrels)		3,778			3,028
Average oil price	$	33.83		$	81.84
Oil revenue	$	127,809		$	247,831
Gas sold (mcf)		51,414			29,216
Average gas price	$	3.46		$	8.90
Gas revenue	$	177,865		$	259,973
Total oil and gas revenues	$	305,674		$	507,804
Less lease operating expenses		(299,675	)		(254,775	)
Less oil & gas amortization expense		(113,000	)		(290,000	)
Less accretion of asset retirement obligation		(9,653	)		(8,085	)
Less impairment of oil and gas assets		(2,100,000	)		—
Producing revenues less direct expenses		(2,216,654	)		(45,056	)
Less depreciation of office facilities		(19,143	)		(18,504	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(1,629,546	)		(1,390,208	)
Income (loss) from operations	$	(3,910,343	)	$	(1,498,768	)
Total barrels of oil equivalent (“boe”) sold		12,347			7,897
Revenue per boe sold	$	24.76		$	64.30
Lease operating expense per boe sold	$	24.27		$	32.26
Amortization expense per boe sold	$	9.15		$	36.72

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Lease operating expenses for the quarter ended March 31, 2009 were abnormally high primarily because of additional costs incurred to actively manage the production within our Fetter project. We expect that the Fetter project lease operating expenses will decrease as we conclude the additional work required to manage production during the early phases of development.

For the quarters ended March 31, 2009 and March 31, 2008, we incurred $1,629,546 and $1,390,208, respectively, in general and administrative expenses. The $239,338 increase is largely attributable to greater compensation expense, including a $159,000 increase in share-based compensation expense.

Liquidity and Capital Resources

At March 31, 2009 and December 31, 2008, we had working capital of $21.7 million and $26.9 million, respectively. We had cash and cash equivalents at March 31, 2009 of $15.7 million.

Depending on the level of drilling activity in our Fetter project, which we expect to determine after our current re-entry activities are concluded, we anticipate capital expenditures in the nine months ending December 31, 2009, to be between $2.0 million and $8.2 million to fund our share of planned oil and gas drilling operations and other costs of oil and gas property acquisition to fund other known oil and gas related costs such as land and geological costs.

For the three-month periods ended March 31, 2009 and March 31, 2008, our sources and uses of cash were as follows:

Net Cash Used By Operating Activities — Our net cash used by operating activities increased by $917,863, (from $589,702 during the quarter ended March 31, 2008, to $1,507,565 for the quarter ended March 31, 2009). The increase was due primarily to (i) $676,696 spent in 2009 acquiring spare inventory of well casing and tubing, carried as a current asset, (ii) an approximately $200,000 decrease in revenues due to a significant decline in oil and gas prices since March 31, 2008, and (iii) an approximately $200,000 decline in investment income due to use of short-term investment funds and due to a decline in dividend and interest rates on short-term investments and cash equivalents.

Net Cash Used In Investing Activities — During the quarter ended March 31, 2009, we used a net $6.0 million in investing activities as compared with $1.6 million used in the quarter ended March 31, 2008. The $4.4 million increase is primarily due to timing of payments of accounts payable, where accounts payable relating to capital expenditures decreased $2.6 million in the quarter ended March 31, 2009 and increased $1.9 million in the quarter ended March 31, 2008.

Net Cash Provided By Financing Activities — For the quarter ended March 31, 2009, we had ample cash assets and received no cash provided by financing activities. In the quarter ended March 31, 2008, we received $8,600,000 from a short-term loan in March 2008 when we were unable to liquidate ARPS at par value. The loan was fully repaid with ARPS redemptions by June 2008.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

Our oil and gas business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices. Declines in oil and gas prices reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves). Declines in oil and gas prices can reduce the value of our oil and gas properties and increase impairment expense, as occurred in the last half of 2008.

We expect oil and gas price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.

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Operating Cost Risk

During 2008, we generally experienced rising operating costs (including drilling costs) which impacts our cash flow from operating activities and profitability. With the decline in oil and gas prices in recent months, we have seen a reduction in drilling activity in the Rocky Mountain region where our properties are located, and we are beginning to see significant decreases in drilling costs and little reduction in oil and gas production costs other than production taxes (which are generally levied as a percentage of revenue). If oil and gas prices were to recover to levels seen in the spring of 2008, we anticipate the reductions in drilling activity and drilling cost rates will substantially reverse and may fully reverse and continue to rise.

Decreases in drilling costs and production costs can have a significant impact on our profitability and may be deciding factors on how many wells we will drill in a given project.

Interest Rate Risk

At March 31, 2009, we had no interest-bearing debt or credit facilities, and short-term interest rates on our cash-equivalent investments were less than 0.5% per annum. Short-term dividend rates on our $5,000,000 in Auction Rate Preferred Shares approximated 1% per annum and are at rates approximating 150% of 30-day US LIBOR rates. An increase in short-term interest rates would be favorable to us, increasing our investment income in proportion to our short-term investments and cash-equivalent investments, and likely increasing the fair value of ARPS closer to their par value.

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2009 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Disclosure controls and procedures, no matter how well designed and implemented, can provide only reasonable assurance of achieving an entity’s disclosure objectives. The likelihood of achieving such objectives is affected by limitations inherent in disclosure controls and procedures. These limitations include the fact that human judgment in decision-making can be faulty and that breakdowns in internal control can occur because of human failures such as simple errors or mistakes or because of intentional circumvention of the established process.

During the period covered by this report, there have been no changes in our internal controls over financial reporting or in other factors, which could significantly affect internal controls over financial reporting.

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PART II
OTHER INFORMATION

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the risk factors discussed in Part I, “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. There have been no material changes in our risk factors from those disclosed in our Annual Report on Form 10-K.

Item 6. EXHIBITS

Exhibit No.		Description
	31.1	302 Certification of Chief Executive Officer
	31.2	302 Certification of Chief Financial Officer
	32.1	906 Certification of Chief Executive Officer
	32.2	906 Certification of Chief Financial Officer

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SIGNATURES

In accordance with the requirements of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Signatures	Title	Date
/s/ Patrick D. O’BrienPatrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors	May 8, 2009
/s/ Joseph B. FeitenJoseph B. Feiten	Chief Financial Officer	May 8, 2009

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EXHIBIT INDEX

Exhibit No.		Description
	31.1	302 Certification of Chief Executive Officer
	31.2	302 Certification of Chief Financial Officer
	32.1	906 Certification of Chief Executive Officer
	32.2	906 Certification of Chief Financial Officer

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