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, 2010

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. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o {Files Not required}.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ *	Smaller reporting company o
		(*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). Yes o No þ

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 10, 2010 were 60,600,856.

AMERICAN OIL & GAS INC.
FORM 10-Q
INDEX

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	3
Condensed Consolidated Balance Sheets — March 31, 2010 and December 31, 2009	3
Condensed Consolidated Statements of Income — Three Months Ended March 31, 2010 and 2009	4
Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2010 and 2009	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3. Quantitative and Qualitative Disclosures about Market Risks	16
Item 4. Controls and Procedures	16
PART II. OTHER INFORMATION
Item 1A. Risk Factors	17
Item 6. Exhibits	17
Signatures	17
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

2

PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	73,892,442		$	40,632,284
Short-term investment		2,950,000			2,925,000
Accounts receivable		2,591,235			564,533
Materials and supplies inventory		1,076,645			1,269,774
Prepaid expenses		124,390			149,991
Current deferred tax assets		76,763			—
Total current assets		80,711,475			45,541,582
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $54,766,939 at 3/31/10 and $35,611,363 at 12/31/09)		64,076,308			44,454,942
Other property and equipment		423,216			406,273
Total property and equipment		64,499,524			44,861,215
Less-accumulated depreciation, depletion and amortization		(6,037,247	)		(5,771,547	)
Net property and equipment		58,462,277			39,089,668
OTHER ASSETS
Drilling prepayments		285,900			—
Intangible asset, net of accumulated amortization		15,000			60,000
Other		80,652			80,652
	$	139,555,304		$	84,771,902
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	6,778,145		$	1,032,248
Income taxes payable		200,000			—
Total current liabilities		6,978,145			1,032,248
LONG-TERM LIABILITIES
Asset retirement obligations		117,466			436,487
Deferred income taxes		6,606,763			—
Total long-term liabilities		6,724,229			436,487
COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS’ EQUITY
Preferred stock, $.001 par value, authorized 24,100,000 shares; no outstanding shares at 03/31/10 and 12/31/09		—			—
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding - 57,700,856 shares at 3/31/10, 57,472,399 shares at 12/31/09		57,701			57,472
Additional paid-in capital		136,795,414			122,267,594
Accumulated deficit		(11,062,185	)		(39,096,899	)
Accumulated other comprehensive income		62,000			75,000
Total equity		125,852,930			83,303,167
	$	139,555,304		$	84,771,902

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,
	2010		2009
REVENUES
Oil and gas sales	$	859,971	$	305,674
OPERATING EXPENSES
Lease operating		241,409		299,675
General and administrative		2,002,729		1,631,546
Depletion, depreciation and amortization		310,701		177,143
Impairments		—		2,100,000
Accretion of asset retirement obligation		10,213		9,653
		2,565,052		4,218,017
GAIN ON SALE OF OIL & GAS PROPERTIES		36,400,000		—
INCOME (LOSS) FROM OPERATIONS		34,694,919		(3,912,343	)
OTHER INCOME (LOSS)
Investment income		31,795		20,980
		31,795		20,980
INCOME (LOSS) BEFORE INCOME TAXES		34,726,714		(3,891,363	)
Income tax provision — current		200,000		—
Income tax provision — deferred		6,492,000		—
NET INCOME (LOSS)	$	28,034,714	$	(3,891,363	)
NET INCOME (LOSS) PER SHARE:
Basic	$	0.49	$	(0.08	)
Diluted	$	0.46	$	(0.08	)

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,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	28,034,714		$	(3,891,363	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Gain on sale of oil and gas assets		(36,400,000	)		—
Deferred income taxes		6,492,000			—
Impairment of oil and gas properties		—			2,100,000
Share-based compensation expenses		315,499			395,442
Depletion, depreciation and amortization		310,701			177,143
Accretion of asset retirement obligations		10,213			9,653
Changes in assets and liabilities:
Decrease (increase) in receivables		(76,704	)		349,350
Decrease (increase) in prepaid expenses		25,601			(2,013	)
Decrease (increase) in inventory		—			(676,696	)
Increase (decrease) in accounts payable and accrued liabilities		1,887,778			30,919
Net cash provided by (used in) operating activities		599,802			(1,507,565	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash proceeds from sale of oil and gas properties		46,181,289			—
Cash paid for oil and gas property acquisition, exploration & development		(13,621,890	)		(6,235,762	)
Drilling prepayments		(285,900	)
Proceeds from redemptions and sales of short-term investments		—			200,000
Cash paid for office equipment		(16,943	)		—
Net cash provided (used) by investing activities		32,256,556			(6,035,762	)
CASH FLOWS FROM FINANCING ACTIVITIES
Employee exercises of stock options		403,800			—
Net cash provided by financing activities		403,800			—
NET INCREASE (DECREASE) IN CASH		33,260,158			(7,543,327	)
CASH, BEGINNING OF PERIODS		40,632,284			23,269,725
CASH, END OF PERIODS	$	73,892,442		$	15,726,398
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	—
Cash paid for income taxes	$	—		$	130,000
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Oil and gas properties acquired for stock	$	13,804,000		$	—
Net increase (decrease) in payables for capital expenditures	$	4,058,119		$	(2,627,680	)
Supplies inventory used in new wells	$	193,129		$	—

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, 2010

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, acquisition and sale 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

We have prepared the accompanying unaudited condensed balance sheet as of December 31, 2009 (which has been derived from audited financial statements) and the accompanying unaudited interim condensed financial statements 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 our audited financial statements and notes included in our amended Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2010 are not necessarily indicative of the operating results for the entire year ending December 31, 2010.

USE OF ESTIMATES — As further discussed on pages F-7 and F-8 of our amended Annual Report on Form 10-K for the year ended December 31, 2009, 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 our amended Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2010 and March 31, 2009, 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.

6

RECENT ACCOUNTING PRONOUNCEMENTS — As of March 31, 2010, there have been no recent accounting pronouncements currently relevant to the Company in addition to those discussed on page F-12 of our amended Annual Report on Form 10-K for the year ended December 31, 2009.

GAS BALANCING — As of March 31, 2010 and December 31, 2009, 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 third-party 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 2009 consolidated financial statements have been reclassified to conform to the 2010 financial statement presentation. Such reclassifications have had no effect on net loss for the period in 2009.

ASSET RETIREMENT OBLIGATIONS — The following table reflects the change in asset retirement obligations for the three-month periods ended March 31, 2010 and March 31, 2009:

	Three-month Period
	Ended March 31,
	2010			2009
Asset retirement obligation, beginning of period	$	436,488		$	430,686
Liabilities incurred		14,259			8,811
Liabilities settled		(341,709	)		—
Accretion		10,213			9,653
Revisions in estimated liabilities		(1,785	)		(8,536	)
Asset retirement obligation, end of period	$	117,466		$	440,614
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.

NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at March 31, 2010 and December 31, 2009, consisted of the following:

	March 31,			December 31,
	2010			2009
Oil and gas properties, full cost method
Unevaluated costs, not yet subject to amortization	$	54,766,939		$	35,611,363
Evaluated costs		9,309,369			8,843,579
		64,076,308			44,454,942
Less accumulated amortization		(5,756,016	)		(5,510,016	)
Net carrying value of oil and gas properties		58,320,292			38,944,926
Cost of other property and equipment		423,216			406,273
Less accumulated depreciation and amortization		(281,231	)		(261,531	)
Net property and equipment	$	58,462,277		$	39,089,668

7

On March 31, 2010, we sold all of our oil and gas interests in the Fetter and Krejci projects located in the Power River Basin, Wyoming and received approximately $46.2 million in sales proceeds. Our primary focus area is our Goliath Bakken and Three Forks focused project located in the Williston Basin, North Dakota where we control approximately 68,500 net acres. We are in the process of evaluating the productive potential of another area located in the Rocky Mountain region that we call our Bigfoot project. This is a shallow natural gas project where we currently control approximately 213,000 gross (131,000 net) acres. We are primarily targeting a formation that is less that 2,000’ deep and have drilled test wells for less than $100,000 per well.

Sale of Oil & Gas Property

On March 31, 2010, American and North Finn LLC (“North Finn”) sold all of their ownership in wells and undeveloped acreage in three Wyoming counties, including American’s ownership interests in the Fetter and Krejci projects. For the properties sold, American received $46,181,289 in cash on March 31, 2010.

Under the full cost accounting method, we recognized a $36,400,000 gain on the sale, by allocating cost to the properties sold based on their relative total fair value to the estimated fair value of the full cost pool immediately preceding the sale. Under the full cost accounting method, gain on property sales is not recognized unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves of the cost center. Non-recognition of the $36,400,000 gain would have reduced the amortization base to zero, significantly altering the relationship, whereby non-recognition was not allowed under full cost accounting. Since the properties sold were significantly different from the properties retained with regard to the nature and extent of proved reserves and property economics, then under the full cost accounting method, the sale’s gain was based on allocating a portion of the US cost center’s capitalized costs to the properties sold based on the relative total fair value of the properties sold to the estimated total fair value of the US cost center’s properties immediately preceding the sale.

As previously disclosed on pages F-25 and F26 in our amended Annual Report on Form 10-K for the year ended December 31, 2009, North Finn fully earned its right to 2,900,000 shares of our common stock upon the closing of the sale. The 2,900,000 shares were issued to North Finn after the sale. With the sale, all of the remaining North Finn property rights to be exchanged for the 2,900,000 shares were effectively transferred at the time of closing to American in determining the allocation of sales proceeds between American and North Finn. Consequently the $13,804,000 fair value of North Finn’s right to the 2,900,000 shares was recognized in our financial statements at the time of closing, increasing additional paid-in-capital by that amount. The same amount was added to the cost of oil and gas properties owned immediately prior to the sale, increasing the full cost pool’s total cost to be allocated between properties sold and properties retained based on relative fair values of properties sold and properties retained.

Unevaluated Oil and Gas Properties

Our $54,766,939 of capitalized unevaluated costs at March 31, 2010, substantially consisted of (i) $44.7 million of costs of acreage at our Goliath Project in North Dakota, (ii) $3.2 million for drilling-in-progress of the Ron Viall 1-25H well, which was successfully completed and placed on production in early May 2010, and (iii) approximately $4 million in BigFoot undeveloped acreage and approximately $1 million in costs of wells drilled or in progress, but not yet evaluated.

‘Ceiling’ Impairment

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 amended Annual Report on Form 10-K as of December 31, 2009. We recognized a $2,100,000 impairment for the three-month period ended March 31, 2009.

8

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

	Three-month Period
	Ended March 31,
	2010		2009
Amortization of costs for evaluated oil and gas properties	$	246,000	$	113,000
Amortization of Intangible Asset		45,000		45,000
Depreciation of office equipment, furniture and software		19,701		19,143
Total DD&A expense	$	310,701	$	177,143

NOTE 4 — SIGNIFICANT CHANGES IN PROVED RESERVE ESTIMATES

Our proved reserves at March 31, 2010 were estimated internally by management. The estimates are significantly greater than at December 31, 2009, as shown in the following table:

	Oil (bbls)			Gas (mcf)
Proved reserves at December 31, 2009		147,510			956,550
Less proved reserves of properties sold 3/31/10		(22,957	)		(392,601	)
Less production, quarter ended 3/31/10		(7,820	)		(45,490	)
Proved reserve additions, three Tong Trust sites*		394,131			908,609
Other additions & net revisions		106,554			109,388
Proved reserves at March 31, 2010		617,418			1,536,456
Percentage net change in proved reserves		319	%		61	%

* The three Tong Trust sites are the drill site of the Tong Trust 1-20H well and two offsetting drill sites for which proved undeveloped reserves were assigned as of March 31, 2010. In mid-March 2010, the Tong Trust 1-20H well began producing after fracture stimulation.

NOTE 5 — SHORT-TERM INVESTMENTS

Our short-term investments at March 31, 2010 and December 31, 2009 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. By March 2009, there were no parties willing to buy ARPS at par value at the auctions, i.e., the auction system collapsed. The ARPS are preferred shares with no maturity date and with no right for the holder to ‘put’ the securities to the ARPS issuer (the closed-end mutual fund) for redemption. Since March 2008, many issuers of ARPS 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.

For the ARPS we held at March 31, 2010 [$3,150,000 total par value, carried at $2,950,000 fair value], $1,200,000 par value (and fair value) are to be redeemed at par value on May 27, 2010.

On August 6, 2009, American filed with the Financial Industry Regulatory Authority (“FINRA”) a statement of claim against Jefferies & Company, Inc. (“Jefferies”), as American’s broker with regards to the ARPS. The statement of claim seeks in arbitration to have Jefferies (i) purchase at par value American’s remaining unredeemed ARPS, (ii) reimburse American for consequential damages (approximating $140,000 to date) and for American’s legal costs in the arbitration and (iii) pay American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions. The arbitration hearing is scheduled to take place in early December 2010.

We expect to have our ARPS entirely liquidated for cash before December 31, 2010. Absent full liquidation at par value, we expect to sell before December 2010 any remaining ARPS in the secondary market at expected losses (including significant transaction costs) approximating 10% to 20% of the par value of ARPS sold. We may receive an award in arbitration with Jefferies; however, we have no assurance that we will be successful in our claim against Jefferies.

9

The ARPS we own at March 31, 2010 are classified as short-term investments and are classified under ASC Topic 320 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. Unrealized gains resulting from increases in fair value are recorded in Other Comprehensive Income.

At March 31, 2010, the ARPS’ $3,150,000 total par value exceeded their $2,950,000 total carrying value (i.e., estimated fair value) by $200,000. The $200,000 net loss is composed of (i) a $300,000 other-than-temporary loss recognized in the Statement of Operations for the year ended December 31, 2008 and (ii) a $100,000 temporary unrealized gain recorded (net of $38,000 related deferred income taxes) in Other Comprehensive Income. Fair value, by definition, is before transaction costs in selling the ARPS (See Note 6).

The ARPS dividend rates approximated 0.8% per annum at March 31, 2010. Dividend rates fluctuate weekly or monthly generally at a small premium over 30-day LIBOR or over short-term AA commercial paper.

NOTE 6 — FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted ASC 820 Fair Value Measurements and Disclosures 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 ASC 820 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.

ASC 820 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. ASC 820 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.

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2010 and December 31, 2009. The table shows the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values.

			Level 1		Level 2		Level 3
	Total		inputs		inputs		inputs
As of December 31, 2009
Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (“ARPS”)	$	2,925,000	$	—	$	—	$	2,925,000
Liabilities	$	—	$	—	$	—	$	—
As of March 31, 2010
Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (“ARPS”)	$	2,950,000	$	—	$	1,200,000	$	1,750,000
Liabilities	$	—	$	—	$	—	$	—

10

During the three-month period ended March 31, 2010, the fair value of assets measured with Level 3 inputs was (i) reduced by $1,200,000 for assets re-valued with Level 2 inputs associated with the announced redemption of those assets and (ii) increased by $25,000 for changes in estimated fair values of the ARPS.

Our claim against Jefferies (see Note 5) is not reflected in estimation as to the fair value of our ARPS, because fair value is based on what a third party would be willing to pay for the securities excluding any legal rights at March 31, 2010 that American may have against Jefferies.

The risk of loss associated with credit risk is negligible because credit rating agencies continue to classify such ARPS as Triple-A credit risks. Federal law requires the closed-end mutual fund that issued the ARPS to maintain asset values of no less than 200% of the ARPS par value and accrued dividends. A decline in asset value below the 200% ratio requires the fund to quickly restore the ratio such as by selling some assets and using the sale proceeds to pay accrued dividends and buy back a portion of the ARPS at par value. The closed-end mutual funds that issued the ARPS we hold have substantially all of their assets in a variety of corporate bonds and/or stock, which facilitates the selling of assets to redeem sufficient ARPS to maintain the required 200% coverage ratio.

The methodology for Level 3 valuation at March 31, 2010 was similar to that at December 31, 2009 described on page F-18 of our amended Annual Report on Form 10-K as of December 31, 2009.

NOTE 7 — 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, 2010 will be approximately 39%. For the three-month period ended March 31, 2010, we recorded a $200,000 current provision for estimated alternative minimum tax and a $6,492,000 deferred income tax provision, net of a $7 million reversal of the deferred tax asset valuation allowance.

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 that as of May 12, 2010, we are no longer subject to income tax examinations by tax authorities for years before 2005 for Colorado and before 2006 for federal, Montana, North Dakota and Utah income tax returns. Income taxing authorities have conducted no formal examinations of our past federal and state income tax returns and supporting records. In March and April 2009, the Utah State Tax Commission conducted a limited review of our franchise tax returns for 2005, 2006 and 2007, but the review did not become a formal examination or audit, and the Commission issued no notice of any taxes, penalties or interest due.

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, 2010.

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 2010 and at the state levels prior to 2010, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2010.

11

NOTE 8 — EQUITY

Common Stock

The following transactions occurred during the first quarter ended March 31, 2010 with regard to our common stock:

• On January 26, 2010, we issued to each of our three independent directors 7,519 shares of common stock pursuant to our 2006 Stock Incentive Plan, with 2,506 shares vesting immediately and 5,013 shares vesting when the individual is no longer a director.

• In February 2010, our Vice-President of Land earned on the third anniversary of his employment 4,000 shares of our common stock.

• A Director exercised his option, buying 12,500 shares of our common stock, at a $2.38 exercise price per share.

• Our CFO exercised his option, buying 68,000 shares of our common stock, at an exercise price of $2.00 per share.

• Four non-officer employees exercised options to purchase a total of 121,400 shares of our common stock, at an exercise price of $2.00 per share.

• For the quarter ended March 31, 2010, Additional Paid-In Capital increased by $315,499 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of (i) $174,762 in share-based compensation related to stock options, (ii) $50,734 related to accruals for granted stock vesting after grant and (iii) $90,003 relating to stock granted to directors with limited vesting restrictions.

• Effective March 31, 2010 with the closing of the sale of certain Powder River Basin oil and gas properties, we increased Additional Paid-In Capital by $13,804,000 in recognition of the sale fulfilling all obligations of North Finn LLC for its right to receive 2,900,000 restricted shares of our common stock, as discussed further in Note 3. We issued the shares to North Finn LLC subsequent to March 31, 2010.

Warrants

At December 31, 2009 and March 31, 2010, we had one outstanding warrant to purchase our common shares. The warrant was issued April 16, 2008 and expires April 16, 2013. It is for 50,000 shares of our common stock at an exercise price of $3.50 per share.

Stock Options

In the three-month period ended March 31, 2010, we granted no stock options and none were forfeited or expired. As described above, one director and five employees exercised stock options to acquire a total of 201,900 shares of our common stock.

Other Comprehensive Income

During the quarter ended March 31, 2010, Other Comprehensive Income increased by $25,000 (to $100,000) to reflect a change in the fair value of short-term investments and decreased by $38,000 (to $62,000) in recognition of deferred income taxes relating to the $100,000 gain on short-term investments.

NOTE 9 — EARNINGS PER SHARE

The following table summarizes the calculations of basic and diluted net income (loss) per common share for the three-month periods ended March 31, 2010 and March 31, 2009:

	For the three-month period ended
	March 31, 2010		March 31, 2009
Net income (loss)	$	28,034,714	$	(3,891,363	)
Adjustments for dilution		—		—
Net loss adjusted for effects of dilution	$	28,034,714	$	(3,891,363	)
Basic Weighted Ave. Common Shares		57,583,788		48,238,988
Add dilutive effects of options and warrants		4,004,377		—
Diluted Weighted Ave. Common Shares Outstanding		61,588,165		48,238,988
Net income (loss) per common share — basic	$	0.49	$	(0.08	)
Net income (loss) per common share — diluted	$	0.46	$	(0.08	)

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NOTE 10 — MATERIAL RELATED PARTY TRANSACTIONS

We had no material related party transactions during the quarter ended March 31, 2010.

NOTE 11 — 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.

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

On March 31, 2010, we sold all of our oil and gas interests in the Fetter and Krejci projects located in the Power River Basin, Wyoming and received approximately $46.2 million in sales proceeds. Our primary focus area is our Goliath Bakken and Three Forks focused project located in the Williston Basin, North Dakota where we control approximately 68,500 net acres.

The Williston Basin has become one of the most actively drilled basins in the continental United States. Recent advancements in drilling, completion and stimulation technologies used by other operators have resulted in commercially successful Bakken and Three Forks wells. We have recently commenced drilling operations that utilize these advanced technologies.

In December 2009, we commenced drilling the Tong Trust 1-20H Bakken well pursuant to a participation agreement with Halliburton Energy Services, Inc. (“Halliburton”). Halliburton paid us approximately $1.1 million in cash and paid 100% of our share of costs to drill and complete the Tong Trust 1-15H well. In return, Halliburton earned a 25% working interest in approximately 30,000 of our net acres in the eastern portion of our Goliath project, resulting in our current ownership in the Goliath project area of approximately 68,500 net acres. We now own a 27.1% working interest and an approximate 21.7% net revenue interest in the Tong Trust well. In mid-March 2010, the Tong Trust well was placed on production at an initial 24 hour production rate of 1,421 barrels of oil equivalent (“BOE”) per day (1,114 barrels of oil and 1.84 MMcf of natural gas).

In February 2010, we commenced drilling the Ron Viall 1-25H Bakken well at Goliath and in mid-May, this well was placed on production at an initial 24 hour production rate of 2,844 BOE (1,981 barrels of oil and 5.2 MMcf of natural gas). This well was drilled outside of the area of mutual interest with Halliburton. We own a 95% working interest and an approximate 76% net revenue interest in this well.

We now have a two-rig continual drilling program for 2010. Ensign rig 24 is currently drilling the Bergstrom 15-23H Bakken well (95% WI) located in T156N-R98W Sections 23 and 14, Williams County, and Nabors rig 486 is drilling the Johnson 15-35H Bakken well (approximate 83% WI), located in T156N-R98W Sections 35 and 26, Williams County. Including wells already drilled, we expect to drill a total of ten to twelve gross (seven to nine net) wells during 2010 and expect that at least one of these wells will target the Three Forks formation.

We are in the process of evaluating the productive potential of another area located in the Rocky Mountain region that we call our Bigfoot project. This is a shallow natural gas project where we currently control approximately 213,000 gross (131,000 net) acres. We are primarily targeting a formation that is less that 2,000’ deep and have drilled test wells for less than $100,000 per well. During 2010, we expect to continue to drill test wells as we evaluate the commercial viability of this area.

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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, 2009. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended March 31, 2010 Compared with the Quarter Ended March 31, 2009

For the quarter ended March 31, 2010, we recorded net income of $28,034,714 ($0.49 per share, basic and $0.46 per share, diluted), as compared to a net loss attributable to common stockholders of $3,891,363 ($0.08 loss per common share, basic and diluted) for the quarter ended March 31, 2009. The $32 million increase in net income is primarily due to a $36.4 million pre-tax gain on the sale of substantially all of our Wyoming oil and gas interests on March 31, 2010. The increase in net income is also attributable in part to an $8.3 million change in deferred tax asset valuation allowances, with a $7 million reduction in valuation allowance for the 2010 quarter compared with a $1.2 million increase in valuation allowance in the 2009 quarter. There was no impairment expense in the 2010 quarter compared with a $2,100,000 impairment in the 2009 quarter. Oil production and oil and gas prices were significantly greater in the 2010 period compared with the 2009 period as shown in the table below.

For the quarter ended March 31, 2010, we recorded total oil and gas revenues of $859,971 compared with $305,674 for the quarter ended March 31, 2009. The $554,297 increase from the 2009 quarter is attributable to a 107% increase in oil production and significantly higher oil and gas prices. Oil and gas sales and production costs and other components of income from operations are summarized in the following table:

	Three months ended
	March 31,
	2010		2009
Oil sold (barrels)		7,820		3,778
Average oil price	$	71.14	$	33.83
Oil revenue	$	556,342	$	127,809
Gas sold (mcf)		45,490		51,414
Average gas price	$	6.67	$	3.46
Gas revenue	$	303,629	$	177,865

	Three months ended
	March 31,
	2010			2009
Total oil and gas revenues	$	859,971		$	305,674
Less lease operating expenses		(241,409	)		(299,675	)
Less oil & gas amortization expense		(246,000	)		(113,000	)
Less accretion of asset retirement obligation		(10,213	)		(9,653	)
Less impairment of oil and gas assets		—			(2,100,000	)
Plus gain on sale of oil and gas properties		36,400,000			—
Income (loss) from oil & gas operations		36,762,349			(2,216,654	)
Less depreciation of office facilities		(19,701	)		(19,143	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(2,002,729	)		(1,631,546	)
Income (loss) from operations		34,694,919		$	(3,912,343	)
Total barrels of oil equivalent (“boe”) sold		15,402			12,347
Revenue per boe sold	$	55.84		$	24.76
Lease operating expense per boe sold	$	15.67		$	24.27
Amortization expense per boe sold	$	15.97		$	9.15

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Both the 2010 quarter and the 2009 quarter results summarized above include the revenues and lease operating expense of the Powder River Basin properties sold on March 31, 2010. Excluding the revenues and lease operating expense of the sold properties, the quarterly revenues and lease operating expenses would have been as follows:

	Three months ended
Pro Forma Revenues and Expenses	March 31,
(excluding properties sold on 3/31/10)	2010			2009
Oil sold (barrels)		3,553			1,875
Average oil price	$	73.64		$	32.34
Oil revenue	$	261,626		$	60,642
Gas sold (mcf)		5,855			3,291
Average gas price	$	6.17		$	8.03
Gas revenue	$	36,149		$	26,420
Total oil and gas revenues	$	297,775		$	87,062
Less lease operating expenses		(67,426	)		(93,448	)
Revenues net of lease operating expenses	$	230,349		$	(6,386	)

As shown in the above Pro Forma table, the revenues from our oil and gas properties retained after the March 31, 2010 sale accounted for very little of our revenues and lease operating expenses in the quarters ended March 31, 2010 and 2009.

For the quarters ended March 31, 2010 and March 31, 2009, we incurred $2,002,729 and $1,631,546, respectively, in general and administrative expenses. The $371,183 increase is largely attributable to a $283,000 increase in employee compensation expense, including $150,000 in employee cash bonuses relating to the successful March 31, 2010 sale of our Powder River Basin properties. The bonuses were to all employees, excluding the four employees who also are directors or large shareholders.

Liquidity and Capital Resources

At March 31, 2010 and December 31, 2009, we had working capital of $73.7 million and $44.5 million, respectively. We had cash and cash equivalents at March 31, 2010 of $73.9 million.

For the calendar year ending December 31, 2010, we anticipate spending a total of approximately $70 million in capital expenditures, consisting primarily of (i) approximately $55 million drilling and completing North Dakota wells to the Bakken formation or Three Forks formation at our Goliath Project, (ii) approximately $10 million for North Dakota lease acquisitions and extensions, and approximately $1 million drilling wells at our Bigfoot Project. As a result of our 2010 drilling program, we expect increased revenues from operations in 2010, compared to 2009, for the last nine months of the year. We anticipate using cash from operations and cash on hand at March 31, 2010 to pay for capital expenditures in 2010.

For the three-month periods ended March 31, 2010 and March 31, 2009, our sources and uses of cash were as follows:

Net Cash Provided (Used) By Operating Activities — Our net cash provided by operating activities increased by $2,107,367 (from $1,507,565 net cash used for operating activity for the quarter ended March 31, 2009 to $599,802 cash provided by operations for the quarter ended March 31, 2010). The increase was due primarily to a $1.7 million increase in payables for lease operating expenses and general and administrative expenses for the quarter ended March 31, 2010.

Net Cash Provided (Used) In Investing Activities — During the quarter ended March 31, 2010, investing activities provided a net $32.3 million in cash as compared with $6.0 million of cash used by investing activities in the quarter ended March 31, 2009. The $38.3 million increase is primarily due to (i) the $46.2 million received on the sale of oil and gas properties in the Powder River Basin in Wyoming, less (ii) our $7.4 million increase in spending, relating to our leasing costs and drilling activity relating to our Goliath Project.

Net Cash Provided By Financing Activities — During the quarters ended March 31, 2010 and 2009, the only financing activities were $403,800 in cash received in the 2010 period relating to stock option exercises by five employees and one director.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

The Company’s oil and gas business makes it 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 2008 and early 2009.

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.

Operating Cost Risk

During 2008 and 2009, we have generally experienced fluctuations in operating costs (including costs of drilling and completing wells) which impact our cash flow from operating activities and profitability. We expect our drilling activity in 2010 to be focused on drilling oil wells with long laterals in the Bakken and/or Three Forks formations in North Dakota. Several other companies seek to drill similar wells in the general area in 2010 whereby drilling and operating costs may rise in response to demand for limited rigs and services in the North Dakota Bakken play.

Fluctuations in drilling costs and production costs, as well as fluctuations in oil and gas prices 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, 2010, we had no interest-bearing debt or credit facilities. Short-term interest rates were less than 1% per annum on our $73.9 million of cash and cash-equivalent investments at March 31, 2010. Short-term dividend rates on our $3,150,000 par value in Auction Rate Preferred Shares approximated 0.8% per annum and are at rates which vary with short-term commercial paper and US LIBOR rates. An increase in short-term interest rates would be favorable to us in 2010, increasing our investment income in proportion to our short-term investments and cash-equivalent investments.

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, 2010 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 amended Annual Report on Form 10-K for the year ended December 31, 2009, which could materially affect our business, financial condition or future results. The risks described in our amended 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 amended Annual Report on Form 10-K for the year ended December 31, 2009.

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

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/ Pat O’Brien Patrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors	May 17, 2010
/s/ Joseph B. Feiten Joseph B. Feiten	Chief Financial Officer (principal financial officer and principal accounting officer)	May 17, 2010

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