HESS BAKKEN INVESTMENTS I (AEZ) 10-Q 2008 Q3 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 September 30, 2008

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. 001-31900

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 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.

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

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 November 4, 2008 were 47,875,899.

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

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	3
Condensed Consolidated Balance Sheets — September 30, 2008 and December 31, 2007	3
Condensed Consolidated Statements of Operations — Three and Nine months Ended September 30, 2008 and 2007	4
Condensed Consolidated Statements of Cash Flows — Nine months Ended September 30, 2008 and 2007	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3. Quantitative and Qualitative Disclosure About Market Risk	24
Item 4. Controls and Procedures	25
PART II. OTHER INFORMATION
Item 1A. Risk Factors	25
Item 6. Exhibits	25
Signatures	26
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

	September 30,			December 31,
	2008			2007
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,299,612		$	2,388,219
Short-term investments		5,684,000			18,302,900
Trade receivables		1,765,736			566,789
Prepaid expenses		56,347			149,440
Inventory		40,904			40,904
Current deferred income tax assets		42,406			347,658
Total current assets		12,889,005			21,795,910
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $38,249,403 at 9/30/08 and $40,937,747 at 12/31/07)		50,581,592			56,987,732
Other property and equipment		354,082			338,614
Total property and equipment		50,935,674			57,326,346
Less-accumulated depreciation, depletion and amortization		(5,638,418	)		(3,694,805	)
Net property and equipment		45,297,256			53,631,541
OTHER ASSETS
Goodwill		11,670,468			11,670,468
Other intangible asset, net of accumulated amortization		285,000			420,000
Drilling prepayments		36,881			542,876
Long-term deferred income tax assets		6,745,249			—
Other		30,385			30,385
	$	76,954,244		$	88,091,180
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Note payable	$	2,325,000		$	—
Accounts payable and accrued liabilities		2,797,080			1,568,806
Preferred dividends payable		—			261,648
Total current liabilities		5,122,080			1,830,454
LONG-TERM LIABILITIES
Asset retirement obligations		391,436			323,369
Deferred income taxes		—			1,060,003
Total long-term liabilities		391,436			1,383,372
COMMITMENTS AND CONTINGENCIES(Note 12)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value; authorized 400,000 shares; issued and outstanding: no shares at 9/30/08 and 138,000 shares at 12/31/07		—			138
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding shares: 47,875,899 at 9/30/08 and 46,434,063 at 12/31/07		47,876			46,434
Additional paid-in capital		91,034,563			89,426,687
Accumulated deficit (Note 13,Subsequent Events)		(19,641,711	)		(4,595,905	)
Accumulated other comprehensive income		—			—
		71,440,728			84,877,354
	$	76,954,244		$	88,091,180

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

3

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three months ended						Nine months ended
	September 30,						September 30,
	2008			2007			2008			2007
REVENUES
Oil and gas sales	$	1,159,621		$	780,963		$	2,604,786		$	1,580,553
Other revenues		—			—			—			12,000
		1,159,621			780,963			2,604,786			1,592,553
OPERATING EXPENSES
Lease operating		475,382			213,708			1,025,987			466,444
General and administrative		768,780			969,845			3,260,093			3,271,647
Depletion, depreciation and amortization		1,241,021			447,381			2,078,612			969,449
Impairments		18,000,000			—			18,000,000			—
Accretion of asset retirement obligation		8,427			6,537			24,759			18,142
		20,493,610			1,637,471			24,389,451			4,725,682
LOSS FROM OPERATIONS		(19,333,989	)		(856,508	)		(21,784,665	)		(3,133,129	)
OTHER INCOME (LOSS)
Investment income		73,329			368,148			446,560			733,718
Gain (loss) on sale of securities		—			—			(369,172	)		108,059
Impairment of short-term investments		—			—			(116,000	)		—
Interest expense		(6,000	)		—			(94,647	)		—
		67,329			368,148			(133,259	)		841,777
LOSS BEFORE INCOME TAXES		(19,266,660	)		(488,360	)		(21,917,924	)		(2,291,352	)
Income tax expense-current		—			—			—			—
Income tax expense (reduction) -deferred		(6,520,000	)		(220,000	)		(7,500,000	)		(767,000	)
NET LOSS		(12,746,660	)		(268,360	)		(14,417,924	)		(1,524,352	)
Less dividends on preferred stock		(33,627	)		(149,040	)		(327,882	)		(453,490	)
Less deemed dividends on warrants extension		—			—			(300,000	)		—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS		(12,780,287	)	$	(417,400	)	$	(15,045,806	)	$	(1,977,842	)
NET LOSS PER COMMON SHARE:
Basic and diluted	$	(.27	)	$	(.01	)	$	(.32	)	$	(.05	)
Weighted average common shares outstanding:
Basic and diluted		47,525,743			46,250,379			46,844,855			43,734,060

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)

	Nine months ended
	September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(14,417,924	)	$	(1,524,352	)
Adjustments to reconcile net loss to net cash used by operating activities:
Share-based compensation expenses		663,013			879,879
Depletion, depreciation and amortization		2,078,612			969,449
Accretion of asset retirement obligations		24,759			18,142
Loss (gain) on sales of short-term investments		369,172			(108,059	)
Impairment on short-term investments		116,000			—
Impairment on oil and gas properties		18,000,000			—
Deferred income taxes		(7,500,000	)		(767,000	)
Changes in non-cash current assets and liabilities:
Decrease (increase) in receivables relating to operations		(598,947	)		(434,075	)
Decrease in advances and prepaid expenses		93,093			202,116
Increase (decrease) in accounts payable and accrued liabilities for operations		53,945			(334,475	)
Net cash used by operating activities		(1,118,277	)		(1,098,375	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from short-term investment redemptions (Note 4)		11,450,000			—
Sales of other short-term investments		683,728			808,059
Proceeds from the sale of oil and gas properties		5,329,877			777,461
Cash paid for oil and gas properties		(15,800,105	)		(12,093,224	)
Cash paid for office equipment		(15,468	)		(26,767	)
Net cash provided (used) by investing activities		1,648,032			(10,534,471	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowing		10,925,000			—
Repayment of short-term borrowing		(8,600,000	)		—
Gross proceeds from sale of common stock		—			28,506,602
Cash paid for stock offering and issuance costs		—			(1,956,465	)
Proceeds from exercise of common stock warrants and stock options		56,638			368,746
Net cash provided by financing activities		2,381,638			26,918,883
NET INCREASE IN CASH		2,911,393			15,286,037
CASH, BEGINNING OF PERIOD		2,388,219			7,488,474
CASH, END OF PERIOD	$	5,299,612		$	22,774,511
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest expense	$	94,647		$	—
Cash paid for income taxes incurred	$	—		$	— —
SUPPLEMENTAL DISCLOSURES OF NON-CASH ACTIVITIES
Net increase in payables for capital expenditures	$	1,174,329		$	—
Conversion of preferred stock into common stock	$	600,048		$	6,048,000
Share-based compensation expense	$	663,013		$	879,879
Preferred dividends paid in shares of common stock	$	589,530		$	820,224
Drilling prepayments applied to drilling costs	$	505,995		$	107,226

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)

September 30, 2008

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 nine-month period ended September 30, 2008 are not necessarily indicative of the operating results for the entire year, as further discussed in Note 3Property and Equipment and Note 13Subsequent Events.

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, 2007.

USE OF ESTIMATES— As further discussed on pages F-7 and F-8 of our Form 10-K for the year ended December 31, 2007, 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, 2007.

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 September 30, 2008 and September 30, 2007, 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, sales prices and other factors underlying reserve estimates.

6

RECENT ACCOUNTING PRONOUNCEMENTS— As of September 30, 2008, there have been no recent accounting pronouncements currently relevant to us in addition to those discussed on pages F-11 and F-12 of our Form 10-K for the year ended December 31, 2007. See that discussion and Note 8 herein as to our partial adoption of SFAS 157 on January 1, 2008 and our election under SFAS 159 to not adopt the fair value option for certain assets and liabilities held on January 1, 2008.

GAS BALANCING— As of September 30, 2008 and December 31, 2007, 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.

RECLASSIFICATION —Certain amounts in the 2007 consolidated financial statements have been reclassified to conform to the 2008 financial statement presentation. Such reclassifications have had no effect on net loss.

NET LOSS PER SHARE— Basic net loss per common share is computed by dividing net loss attributable to common stockholders by the weighted number of common shares outstanding during the period. Diluted net 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 and nine month periods ended September 30, 2008 and September 30, 2007, there are no adjustments for dilution because of each period’s net loss (rather than net income) to common shareholders. Securities outstanding at September 30, 2008 that could in the future potentially dilute basic net income per share for common stockholders are described in Note 10 and include (i) warrants for 885,626 shares, (ii) outstanding stock options for 3,091,750 shares and (iii) an option for 2,900,000 common shares in exchange for certain oil and gas properties.

NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at September 30, 2008, consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization	$	38,249,403
Evaluated costs		12,332,189
		50,581,592
Office equipment, furniture and software		354,082
		50,935,674
Less accumulated depreciation, depletion and amortization		(5,638,418	)
Property and equipment	$	45,297,256

7

Our major projects are Fetter, Goliath, Krejci and West Douglas. They are described more fully in Item 2 of this Form 10-Q. The following table presents the capitalized oil and gas properties’ costs and net additions therein for the nine-month period ended September 30, 2008, with the unevaluated costs by major project (beginning with properties sold on October 27, 2008 for $26.4 million as discussed in Note 13Subsequent Events):

Capitalized Costs (in millions)

			Net Additions					Net Acres Owned
	12/31/07		(Reductions)			9/30/08		at 9/30/08
Project (State)								(approximate)
Sold on October 27, 2008:
West Douglas Project, Powder River Basin (WY)	$	4.2	$	(0.1	)	$	4.1		19,000
Douglas Project, Powder River Basin (WY)		0.9		0.0			0.9		11,000
Fetter’s western edge, adjoining Douglas acreage (WY)		2.3		0.0			2.3		5,000
Subtotal		7.4		(0.1	)		7.3		35,000
Core portion of Fetter Project, Powder River Basin (WY)	$	12.1	$	2.0		$	14.1		30,500
Goliath Project, Williston Basin (ND)		7.0		0.7			7.7		31,500
Krejci Oil Project, Powder River Basin (WY)		9.2		(6.3	)		2.9		49,000
Colorado project sold in September 2008		1.7		(1.7	)		—		—
Bigfoot project		0.8		2.1			2.9		100,000
Other projects		2.7		0.6			3.3		34,000
Total unevaluated costs	$	40.9	$	(2.7	)	$	38.2		280,000
Evaluated Costs, net of accumulated DD&A	$	12.4	$	(5.5	)	$	6.9

The $2.7 million of net reductions in unevaluated costs for the first nine months of 2008 consist of $17 million in property costs transferred to evaluated costs and $2 million in cost of property sold less approximately $16.3 million in additions. Additions were primarily (i) $6.3 million of exploratory well costs and $1.8 million of property acquisition costs at Fetter, (ii) $3.1 million of exploratory well costs at Krejci, (iii) $0.8 million of exploratory well costs and $0.7 million of property acquisition costs at Goliath (iv) $2.1 million of acquisition and seismic costs at Bigfoot and (v) $0.7 million for well costs in a smaller project. Additions in the nine months ended September 30, 2008 included $252,000 of internal direct costs for acquisition, evaluation and maintenance of properties we acquired.

For the nine-month period ended September 30, 2008, the $5.5 million net reduction in net evaluated costs is largely attributable to $17 million in property costs moved from unevaluated property costs plus $616,000 in additional costs relating to previously proved properties less (i) $18 million in impairment at September 30, 2008 (discussed below), (ii) $3.4 million in unrecognized gain on sale of unproved property (discussed below) and (iii) $1.9 million in amortization expense (see table below)

Impairment at September 30, 2008

At September 30, 2008, we recognized a “ceiling test” impairment of $18 million (or $11,430,000, net of deferred income tax benefit). The impairment is due largely to the decline in oil and gas prices during the three months ended September 30, 2008 (from $90.74 per barrel of oil equivalent (“boe”) at June 30, 2008 to $60.02/boe at September 30, 2008 for the respective ceiling tests). The lower oil and gas prices as of September 30, 2008, resulted in a $10 million decrease in the full cost accounting method’s ceiling limit for capitalized oil and gas property costs. We concluded at September 30, 2008, that as a result of the lower oil prices, $5.3 million in costs of two Krejci wells previously classified in unevaluated costs were impaired, reducing the ceiling limit by an additional $5.3 million.

Full cost accounting rules allow a ceiling impairment to be reduced or eliminated for subsequent price increases or reserve additions that indicate that the costs were not impaired at September 30, 2008. However, those rules do not allow the impairment to be reduced for our October 27, 2008 sale of a portion of our unproved properties for $19.1 million more than the sold properties’ capitalized costs. See Note 13Subsequent Events.

8

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

	Nine-month Period
	Ended September 30,
	2008		2007
Amortization of costs for evaluated oil and gas properties	$	1,887,000	$	786,818
Amortization of Other Intangible Asset		135,000		135,000
Depreciation of office equipment, furniture and software		56,612		47,631
Total DD&A expense	$	2,078,612	$	969,449

The $1,887,000 amortization expense includes $1,171,000 for the quarter ended September 30, 2008. The $1,171,000 amortization expense reflects an amortization rate of $80.77/boe compared with $39.43/boe for the previous quarter and $22.23/boe immediately after the $18 million cost reduction for the ceiling test impairment. The relatively high $80.77/boe rate is due to two related factors: (1) the declines in oil and gas prices reduced the Company’s estimated proved reserves by approximately 56% and (2) the amortization of costs for evaluated oil and gas properties is determined before the $18 million cost reduction for the ceiling test impairment.

NOTE 4 — SHORT-TERM INVESTMENTS

Our short-term investments at September 30, 2008 and December 31, 2007 were comprised primarily of auction-rate preferred shares in taxable closed-end mutual funds:

	September 30,		December 31,
	2008		2007
Auction-rate preferred shares at fair value	$	5,684,000	$	17,325,000
PetroHunter stock at fair value (sold prior to September 30, 2008)		—		977,900
Total, short-term investments	$	5,684,000	$	18,302,900

These short-term investments are classified under SFAS 115 as available-for-sale securities. Temporary unrealized gains and losses are recorded in accumulated other comprehensive income. Unrealized losses expected to be permanent are reflected in the Condensed Consolidated Statement of Operations.

Auction-Rate Preferred Shares

At September 30, 2008, we owned auction-rate preferred shares (“ARPS”) with a par value of $5,800,000 and an estimated fair value of $5,684,000 (which is 98% of par value). See Note 5 for discussion of how the $5,684,000 fair value was determined. At June 30, 2008, management expected the $116,000 unrealized loss to be permanent, and the loss was reflected in our Consolidated Statement of Operations for the three months ended June 30, 2008.

ARPS normally provide liquidity via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. ARPS auctions and similar auctions have had insufficient bids to buy the ARPS from those wishing to sell, whereby (starting in mid-February 2008 and for the foreseeable future) holders of ARPS have been unable to sell ARPS in the auction process. In response, issuers of all ARPS we hold announced they were investigating ways to redeem the ARPS at par value if the ARPS could not otherwise be liquidated at par value.

Of the $17,325,000 in ARPS we held at December 31, 2007, we sold $75,000 of ARPS at par value prior to mid-February, and $11,450,000 were redeemed at par value for cash in May and June of 2008, leaving $5,800,000 of ARPS at par value held at September 30, 2008.

Until the ARPS are liquidated, the issuers pay dividends every 7 to 28 days. Dividends were paid at rates averaging approximately a 4.1% per annum rate for the dividends most recently paid to us by September 30, 2008. Rates fluctuate but on average approximate 148% of 30-day LIBOR (USD), which is a short-term benchmark interest rate.

9

PetroHunter Common Stock

At December 31, 2007, we owned 4,445,000 shares of PetroHunter common stock carried at a fair value of $0.22 per share. We had sold those shares by May 30, 2008 for a net realized loss of $369,172 before any related income tax benefit.

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 or in markets in which little information is released publicly, 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, 2007, our financial assets measured at fair value consisted of $18,302,900 of short-term investments. Their fair values were based on Level 1 inputs. We had no financial liabilities at December 31, 2007. At September 30, 2008, our financial assets and liabilities measured at fair value were as follows:

	Total at		Level 1		Level 2		Level 3
	September 30, 2008		inputs		inputs		inputs
Financial Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (See Note 4)	$	5,684,000	$	—	$	—	$	5,684,000
Financial Liabilities:
Note payable, fully repaid on 11/4/2008 (See Note 8)	$	2,325,000	$	—	$	—	$	2,325,000

We had no financial assets or financial liabilities at June 30, 2008 or at December 31, 2007 for which fair values were measured using primarily Level 3 inputs. The fair values of Auction Rate Preferred Shares (or ARPS) were measured at December 31, 2007 using Level 1 inputs and measured at June 30, 2008 using Level 2 inputs. For the quarter ended September 30, 2008, the $348,000 increase in fair value of the ARPS is an unrecognized gain, reducing Other Comprehensive Loss to zero.

The $5,684,000 fair value for ARPS held at September 30, 2008 was based on management’s expectation that 40.1% of the ARPS would be redeemed at par value by January 31, 2009, and the rest would be redeemed or sold before July 31, 2009 at a loss of no more than 2% of the total $5,800,000 par value.

10

We hold $2,325,000 (40.1%) of our ARPS in three Calamos taxable closed-end funds, which announced in July 2008 board approval and loan arrangements to redeem all of their remaining ARPS if the SEC issues an order permitting them to use debt and a 200% asset coverage ratio on the debt. The SEC issued a similar order on October 23, 2008, for five Eaton Vance taxable closed-end funds. We do not own ARPS in any of the five Eaton Vance funds. Since (i) the Eaton Vance funds were the first fund group to request such an order in 2008 and the Calamos funds were the second and (ii) the two requests are similar in nature and fact pattern, Company management expects that (i) the SEC will issue a similar order for the Calamos funds by early December 2008 and (ii) the Calamos funds will redeem remaining ARPS within seven weeks after the SEC order allowing Calamos funds to do so. Since the Calamos ARPS are expected to be redeemed at par value within four months after September 30, 2008 and since those ARPS pay a dividend every 7 or 28 days at a rate approximating 150% of LIBOR, Company management estimated that the fair value of the Calamos ARPS was their $2,325,000 par value.

For the remaining ARPS ($3,475,000 par value) we hold, we estimate the 9/30/08 fair value to approximate $3,359,000 (or 96.7% of par value), considering several factors, most notably the following:

• The remaining ARPS are in five other taxable closed-end mutual funds, also paying dividends approximating 150% of LIBOR.

• The five funds have publicly stated that they are evaluating various ways to allow their ARPS holders to liquidate their investments at par value.

• As taxable closed-end mutual funds, they could request the SEC for an order similar to the October 23, 2008 order for the Eaton Vance taxable closed-end mutual funds, but have not yet done so to our knowledge.

• Various state and federal officials have publicly stated in September a desire to help ARPS holders liquidate their investments at par value, such as by having the brokers buy the ARPS at par value, but so far we know of no officials who are seeking to have our broker buy back ARPS at par value.

• The ARPS could be sold in a secondary market, named SecondMarket (a division of Green Drake, Inc. and formerly the Restricted Securities Trading Network or RSTN) at approximately 90% of par value during the third quarter of 2008. We expect, but cannot assure, that before September 30, 2009, roughly half of the $3,475,000 will be redeemed at par value and the rest sold (at discounts of 10% or less of par value) and not necessarily sold through SecondMarket.

NOTE 6 — GOODWILL AND OTHER INTANGIBLE ASSET

In April 2005 Tower Colombia Corporation (“TCC”) merged into American with our exchange of 5,800,000 of restricted American common stock for all outstanding TCC stock. We accounted for the merger as a business acquisition at fair value, whereby the estimated $15,196,000 fair value of the restricted stock issued to TCC’s three shareholders was allocated to the underlying assets acquired and liabilities assumed at their estimated fair values, with the excess of $11,670,468 recorded as goodwill. The primary tangible assets acquired were oil and gas lease rights classified as unproved oil and gas property. The merger with TCC in 2005 was insignificant to our 2005 Consolidated Statement of Operations and our 2005 Consolidated Statement of Cash Flows. There was no impairment of the Goodwill in 2005, 2006, 2007 or in the nine months ended September 30, 2008.

In the merger, we recognized a $900,000 other intangible asset. It relates to non-compete provisions and performance-based compensation terms reflected in five-year employment agreements with TCC’s three owners, who serve as officers of American. The $900,000 asset is being amortized over five years, beginning in April 2005, on a straight-line basis, equating to a $45,000 amortization expense every three months.

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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 for the year ending December 31, 2008, our weighted average statutory income tax rate (federal and state combined) will approximate 36.5% and our effective income tax rate will approximate 34.4%. The effective rate differs from the statutory rate due to permanent differences primarily relating to stock options granted to employees and relating to percentage depletion. Deferred income tax reductions of $7,500,000 and $767,000 were reported for the nine-month periods ended September 30, 2008 and 2007, respectively. We did not incur federal or state income tax liabilities for 2007 and through the first nine months of 2008.

We expect to incur for the remainder of 2008 and pay by December 15, 2008 approximately $100,000 in income tax liabilities arising from the Alternative Minimum Tax, for which net operating loss carryforwards are limited to 90% of the AMT taxable income before deducting loss carryforwards.

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 September 30, 2008.

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 and state levels, we do not anticipate any interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2009 as such adjustments would very likely simply reduce our net operating loss carryforwards.

NOTE 8 — NOTE PAYABLE

In September 2008, we borrowed $2,325,000 from Jefferies Group, Inc., parent of our stockbroker Jefferies & Company, Inc. The loan bore interest at an annual rate of overnight LIBOR plus 3.5%, with interest paid monthly and was secured by our $5,800,000 in ARPS. We repaid the loan on November 4, 2008.

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NOTE 9 — ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations (“ARO”) relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of our oil and gas properties. The following table reflects the change in ARO for the three-month and nine-month periods ended September 30, 2008 and September 30, 2007:

	Three months ended					Nine months ended
	September 30,					September 30,
	2008		2007			2008		2007
Beginning asset retirement obligation	$	337,122	$	276,011		$	323,369	$	235,268
Liabilities incurred		2,141		70,822			33,655		131,970
Liabilities settled		—		—			—		(22,898	)
Revisions in estimated liabilities		43,746		(48,236	)		9,653		(57,348	)
Accretion		8,427		6,537			24,759		18,142
Ending asset retirement obligation	$	391,436	$	305,134		$	391,436	$	305,134
Current portion of obligation, end of period	$	—	$	32,396		$	—	$	32,396

NOTE 10 — EQUITY

Common Stock

The following material changes occurred during the three-month period ended September 30, 2008 with regard to our common stock:

• In conjunction with our Series AA Convertible Preferred Stock, we are required to pay an 8% dividend on a semi-annual basis. We can make the dividend payments in cash or equivalent shares of our common stock, at our discretion. Effective July 22, 2008, we paid a semi-annual dividend payment of $291,450 by issuing 76,972 common shares, which shares were valued at $3.7864 per share in accordance with methodology prescribed in the Certificate of Designation of Rights, Preferences and Privileges of Series AA Preferred Stock.

• On July 22, 2008, all outstanding Series AA Convertible Preferred Stock (126,888 shares) were converted into 1,141,992 shares of common stock as required under the terms of the preferred stock.

• For the three-month period ended September 30, 2008, Additional Paid-In Capital increased by $146,516 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of $111,476 in share-based compensation related to stock options and $35,040 primarily related to accruals for granted stock not yet vested.

• In September, warrants issued in 2003 were exercised for 64,850 shares of common stock at an average exercise price of $0.87.

The following transactions occurred during the six-month period ended June 30, 2008 with regard to our common stock:

• In conjunction with our Series AA Convertible Preferred Stock, we are required to pay an 8% dividend on a semi-annual basis. We can make the dividend payments in cash or equivalent shares of our common stock, at our discretion. Effective January 22, 2008, we paid a semi-annual dividend payment of $298,080 by issuing 54,014 common shares, which shares were valued at $5.5186 per share in accordance with methodology prescribed in the Certificate of Designation of Rights, Preferences and Privileges of Series AA Preferred Stock.

• In February 2008, we paid 4,000 shares of restricted common stock to our Vice-President of Land as required under his employment contract of February 2007.

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• For the quarter ended March 31, 2008, Additional Paid-In Capital increased by $266,859 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of $199,819 in share-based compensation related to stock options and $67,040 related to accruals for granted stock not yet vested.

• For the quarter ended June 30, 2008, Additional Paid-In Capital increased by $249,638 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of $218,038 in share-based compensation related to stock options and $31,600 primarily related to accruals for granted stock not yet vested.

• Holders of 11,112 shares of our Series AA Convertible Preferred Stock converted those shares into 100,008 shares of our common stock.

• Additional Paid-In Capital also increased by $300,000 and Accumulated Deficit increased by $300,000 for recognition of a deemed dividend at fair value for the extension of certain warrants as discussed further in this Note 10.

Preferred Stock

At September 30, 2008 there were no outstanding shares of Series AA Convertible Preferred Stock (“Preferred Stock”). On July 22, 2008, the 126,888 shares of preferred stock automatically converted into 1,141,992 shares of common stock. Effective that same day, we paid the final semi-annual preferred stock dividend.

Warrants

The table below reflects the status of warrants outstanding at September 30, 2008 held by others to acquire our common stock:

	Common		Exercise		Expiration
Issue Date	Shares		Price		Date
April 16, 2008		50,000	$	7.00	April 16, 2013
July 22, 2005		835,626	$	6.00	September 30, 2009
		885,626

At September 30, 2008, the per-share weighted average exercise price of outstanding warrants was $6.06 per share, and the weighted average remaining contractual life was 11.5 months.

Stock Options

Under our 2004 Stock Option Plan (the “2004 Plan”), stock options may be granted at an exercise price not less than the fair market value of our common stock at the date of grant. Options may be granted to key employees and other persons who contribute to our success. We have reserved 2,500,000 shares of common stock for issuance under the Plan. At September 30, 2008, options to purchase 181,990 shares were available to be granted pursuant to the 2004 Plan.

Under our 2006 Stock Incentive Plan (the “2006 Plan”), up to 1,500,000 additional shares of common stock may be issued to employees, directors and other persons who provide services to the Company. Issuance of those shares may be by stock option awards, restricted stock awards or restricted stock unit awards. At September 30, 2008, 357,275 shares were available to be granted pursuant to the 2006 Plan.

In January 2006, we entered into a participation agreement with North Finn (“North Finn”). An element of that agreement is that North Finn has an option until July 31, 2012 to receive 2,900,000 shares of our common stock in exchange for certain oil and gas rights held by North Finn. A second element is that beginning on August 1, 2010 until July 31, 2012, we have an option to require North Finn to exchange those property interests in return for the 2,900,000 shares. 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. The option and the participation agreement are discussed in Note 12Commitments and Contingencies.

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Other than this North Finn option, outstanding stock options at September 30, 2008 are those granted under the 2004 Plan or 2006 Plan. The following table summarizes the status of stock options outstanding under the 2004 Plan and 2006 Plan:

				Weighted
				Average
	Number of			Exercise
	Shares			Price
Options outstanding — December 31, 2007 (1,359,500 exercisable)		2,515,000		$	4.04
Options granted in the nine months ended September 30, 2008		625,000		$	3.41
Less options forfeited in the nine months ended September 30, 2008		(28,250	)	$	5.03
Less options expired in the nine months ended September 30, 2008		(20,000	)	$	4.66
Less options exercised in the nine months ended September 30, 2008		—
Options outstanding — September 30, 2008 (1,743,000 exercisable)		3,091,750		$	3.90

The weighted-average, grant-date estimated fair value of stock options granted during the quarter ended September 30, 2008 was $1.18 per underlying common share. The following valuation models and key model assumptions were used for the significant options granted in the nine-month periods ended September 30, 2008 and September 30, 2007:

	2008		2007
	Modified		Modified
Model	Binomial		Binomial
Option life (in years)		4		4 to 5
Annual volatility over option life		45%		35%
Annual volatility for black-out periods		0%		0%
Risk-free interest rate		2.3%	4.7% to 5.1%
Pre-vesting forfeiture rate		12%		0%
Dividend yield		0%		0%
Intrinsic Value /share that urges exercise		$2.00		$2.00 to $2.16

The modified binomial model takes into consideration that as a stock price rises significantly above the option exercise price, the resulting significant “intrinsic value” of the option can urge an employee to exercise the option, either (i) to sell some or all of the underlying stock to convert intrinsic value to cash, or (ii) to begin holding some or all of the stock for one year to reduce the income tax rate on the later anticipated gain from sale of the stock.

We have a policy of prohibiting directors, executive officers and all other employees from buying or selling our stock (or arranging 10b5-1 plans to sell stock in any future month) during four “black-out periods” of the year. These generally begin a few days before a calendar quarter ends and end two trading days after the quarter’s report on Form 10-Q or Form 10-K is filed with the SEC. The four black-out periods cover approximately 66% of trading days per year. On occasion, we may extend or add to the black-out periods. Consequently, the stock options’ values are reduced to reflect the inability to fully profit from volatility in the Company’s common stock price.

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We believe that the modified binomial model provides a better estimate than the Black-Scholes model of the fair value of stock options granted to our employees since the modified binomial model can reflect additional factors such as expectations that some employees will exercise options if and when the options’ intrinsic values become significant.

The following table presents additional information related to the stock options outstanding at September 30, 2008 under the 2004 Plan and 2006 Plan:

Exercise		Remaining
price		contractual		Number of shares
per share		life (years)		Outstanding		Exercisable
$	1.25		1.4		403,000		403,000
$	2.38		2.2		100,000		100,000
$	2.48		2.3		80,000		80,000
$	3.27		6.8		15,000		—
$	3.29		4.8		100,000		12,500
$	3.34		6.8		21,000		—
$	3.37		6.8		465,000		—
$	3.66		4.3		750,000		500,000
$	4.30		4.2		9,000		6,000
$	4.57		0.2		6,000		6,000
$	4.95		7.8		250,000		130,000
$	4.98		5.1		200,000		130,000
$	5.15		5.7		30,000		10,000
$	5.80		4.4		75,000		60,000
$	5.84		6.7		400,000		140,000
$	6.03		3.2		178,750		162,500
$	6.70		5.8		9,000		3,000
					3,091,750		1,743,000
Weighted Ave. remaining contractual life				4.7 years		3.8 years
Aggregate intrinsic value, September 30, 2008				$	—	$	—

Subsequent Event

On November 5, 2008, our Board of Directors granted for twelve employees who are not members of the Board an exchange (or amendment) of their old stock options with an average exercise price of $4.47 for an equal number of new stock options with an exercise price of $2.00 per share. The closing price of our common stock on November 5, 2008 was $1.55 per share. The new stock options generally vest annually over the next five years of employment, and expire five years after vesting. The old stock options were 37% vested, with the remainder vesting on average within 2.5 years. The old options typically expired five years after vesting.

Excluded from the exchanges were our outside directors, our CEO, our President, and two of our Vice Presidents. Those four senior officers each own between 1.9% and 5.3% of our currently outstanding stock.

The purpose of the option exchanges is to restore the employee stock option program’s value in retaining employees and in aligning employee interests with shareholder interests. The exchanges also provide a uniform exercise price for all employees hired in the past three years. While other companies’ option exchange programs in recent months have typically set the new options’ exercise price at the stock’s market price, the Board and management believed the interests of employees and shareholders would be best served with a $2.00 exercise price.

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The following table lists the stock options outstanding at September 30, 2008, as if the November 5th option exchange had occurred on September 30, 2008:

Exercise		Remaining
price		contractual		Number of shares
per share		life (years)		Outstanding		Exercisable
$	1.25		1.4		403,000		403,000
$	2.00		7.6		1,798,000		—
$	2.38		2.2		100,000		100,000
$	3.29		4.8		100,000		12,500
$	3.34		6.8		6,000		—
$	3.66		4.3		500,000		333,333
$	4.57		0.2		6,000		6,000
$	6.03		3.2		178,750		162,500
					3,091,750		1,017,333
Weighted Ave. remaining contractual life				5.9 years		2.7 years
Aggregate intrinsic value, September 30, 2008				$	—	$	343,170

NOTE 11 — MATERIAL RELATED PARTY TRANSACTIONS

We had no material related party transactions during the nine months ended September 30, 2008.

NOTE 12—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

On January 5, 2006, we entered into a participation agreement with North Finn LLC (“North Finn”). Under the agreement, we fund 60% of North Finn’s subsequent 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 restricted 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. In many of the joint project areas, North Finn owns a 25% working interest, and the Company owns a 75% working interest.

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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.

NOTE 13 — SUBSEQUENT EVENTS

Sale of Certain Wyoming Unproved Properties

On October 27, 2008, we sold for $26,365,402 approximately 35,100 net acres of non-core unproved acreage and other unproved property, consisting of all our interests in a twelve township block that included our West Douglas project, the western edge of our Fetter project and other Douglas acreage not in the Fetter or West Douglas projects.

We anticipate recognizing in the fourth quarter a $16,500,000 gain on the sale. Taxable gain approximates $19.1 million, but under the full cost accounting method, the sale’s gain is based on 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. The remaining $2.6 million of sales proceeds in excess of the sold properties’ tax basis will be credited as a reduction in the full cost pool’s capitalized costs.

See Note 3Property and Equipmentand Note 7Income Taxesfor further discussion of the sale’s impact on the Company’s financial results for 2008.

Stock Option Exchange

See Note 10Equityfor discussion of stock option exchanges granted by the Board of Directors on November 5, 2008.

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. These statements are only predictions. Actual events or results may differ materially. 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” in our Annual Report on Form 10-K for the year ended December 31, 2007, and those described from time to time in our future reports filed with the SEC.

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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 three main project areas that we call Douglas, Krejci and Goliath. Our Douglas project area includes our Fetter and West Douglas projects. We are also in the early stages of working in additional project areas where we are currently leasing additional acreage and performing geological evaluations. The following project updates should be read in conjunction with our Annual Report on Form 10-K for our fiscal year ended December 31, 2007.

Fetter Project (Powder River Basin, Wyoming)

Our Fetter project currently encompasses approximately 56,000 gross acres. We are essentially finished with drilling and completing initial wells pursuant to a participation agreement with Red Technology Alliance, LLC (“RTA”) whereby RTA has agreed to pay 100% of the costs to drill and complete two horizontal wells and one vertical well in the Fetter project area. We have been carried through the tanks in this phase of the drilling program and own a 23.125% working interest in each of the three wellbores. RTA has earned a 25% working interest in the undrilled acreage, and our ownership at Fetter has decreased from a 92.5% working interest in approximately 48,000 net lease acres to a 69.375% working interest, giving us approximately 33,000 net acres at Fetter. North Finn LLC retains the remaining 5.625% working interest. The drilling and completion operations are project managed by Halliburton Energy Services, Inc.

We are continuing the drilling program at Fetter and have drilled and completed the Hageman 11-22 and Hageman 11-22UK wells. Both of these wells were drilled in section 22 of T33N-R71W, Converse County, WY. In the Hageman 11-22 well, completion attempts have been made in each of the Dakota, Muddy, Mowry and Frontier formations, and the well is currently producing exclusively from the Frontier formation. The Hageman 11-22UK well has been completed in the Teapot formation at approximately 7,700 feet, and the well has not shown commercial success.

We expect near term future operations at Fetter will focus on completions in the Frontier and possibly the Niobrara formations, and we expect to drill both vertical and horizontal wells while we continue to evaluate the optimum drilling and completion approach. Although we have been able to establish compelling reserve potential in the Dakota and Mowry formations, completion efforts remain challenging, and we expect to focus on those formations again at a later date. By focusing on the Frontier and Niobrara formations, we anticipate being able to better build reserves and cash flow.

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Douglas Project Area — West Douglas Project (Powder River Basin, Wyoming)

Subsequent to September 30, 2008, we sold our interest in the West Douglas and greater Douglas project areas and received approximately $26.4 million in sales proceeds.

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 primarily targeting the middle member of the Bakken formation in an emerging horizontal drilling play in the North Dakota Williston Basin. Our Goliath project area currently encompasses approximately 80,000 gross acres, and we own a 50% working interest in approximately 65,000 lease net acres.

During the third quarter we and other working owners signed a participation agreement with Red Technology Alliance LLC (“RTA”), which gives RTA the option to fund 100% of the drilling, completion and equipping of up to four horizontal Bakken wells at Goliath. RTA has committed to commence drilling the first Bakken well under this agreement within 90 days of our spudding the Viall 30-1 well that will target the Red River formation. Upon completion of the first Bakken well drilled pursuant to this participation agreement with RTA, RTA will own a 50% working interest in the well and the expected 1,280 acre spacing unit. Within 90 days of the completion of the first well, RTA has the option to commence a second Bakken well. Upon completion of the second well, RTA will own a 50% working interest in this well and spacing unit and will earn a 40% working interest in approximately 30,000 net undeveloped acres. Within 90 days of completion of the second well, RTA may elect to drill a third Bakken well in which it will own a 50% working interest (and in the spacing unit) and will earn a 40% working interest in an additional approximate 15,000 net undeveloped acres. Again, within 90 days of completion of the third well, RTA may elect to drill a fourth Bakken well in which it will own a 50% working interest (and in the spacing unit) and will earn a 40% working interest in the remaining approximate 15,000 net undeveloped acres. RTA will earn its proportionate rights to all formations in the Goliath project area with the exception of formations below the Three Forks Formation (which includes the Red River Formation) in a 40 square mile area surrounding the recently completed 10.5 square mile 3D seismic program that covers acreage on trend to our successful Solberg 32-2 well.

We will be carried for a 25% working interest in all costs related to drilling, completing and equipping the four wells under this agreement. Should RTA elect to drill all four wells, we will retain 30% working interest in the Goliath project. Halliburton Energy Services Inc. will serve as project manager in the drilling and completion of these initial four wells.

We and the other working interest owners at Goliath (which does not include RTA) plan to drill the 14,400’ deep Viall 30-1 well (formerly called the Machette 1-30 well) that will target the Stonewall, Red River and Winnipeg formations on a prospect identified by a recent 3D seismic program at Goliath. The Viall 30-1 will be located approximately 2.5 miles NW of the Solberg 32-2 well. Subject to rig availability, the well is planned to commence before year end 2008.

Recent 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 our upcoming program. While these four wells will target completion in the Bakken formation, the Goliath drilling program will be designed to provide important reservoir and geological data from other prospective formations in the project area including the Three Forks/Sannish, Madison, Nisku, Duperow, Interlake, Stonewall, Red River and Winnipeg.

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Krejci Oil Project (Powder River Basin, Wyoming)

Within our Krejci project, we are evaluating the productive potential of the Mowry formation at an approximate depth of 7,500 feet. We are focusing our efforts in and around the Krejci Field in Niobrara County, Wyoming. Our Krejci project area currently encompasses approximately 131,000 gross (approximately 49,000 net) acres.

We have participated in the drilling and completion of five wells so far in the Krejci project. Three of the wells drilled are producing and two wells are shut-in while we evaluate additional stimulation techniques. Although we currently have production from three of the five wells, we do not consider those wells to be commercially successful. Other companies are either drilling or planning to drill wells targeting the Mowry formation in the southern Powder River Basin, and we will be watching the level of success these other companies have with their drilling, stimulation and completion operations. Accordingly, we do not expect to continue drilling new wells at Krejci in the near term.

Bigfoot Project

We currently control approximately 150,000 net acres in a project that we call Bigfoot. This is a shallow natural gas project located in the Rocky Mountain region. This project remains in the lease acquisition stage.

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, 2007. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended September 30, 2008 Compared with the Quarter Ended September 30, 2007

For the quarter ended September 30, 2008, we recorded a net loss attributable to common stockholders of $12,780,287 ($0.27 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $417,400 ($0.01 loss per common share, basic and diluted) for the quarter ended September 30, 2007. The $12.4 million increase in loss is primarily due to the current quarter’s $18 million impairment ($11,430,000 net of related deferred tax benefit) and the $791,000 increase in oil & gas amortization expense computed on capitalized costs before recognition of the impairment. The $18 million impairment is primarily due to a $10 million decline in the present value of discounted future cash flows resulting from the decline in oil and gas prices at September 30, 2008 from prices at June 30, 2008, as discussed in Note 3 to the financial statements contained in this Form 10-Q.

The loss in the quarter ended September 30, 2008 is not indicative of results for the subsequent three months. Management anticipates reporting net income for the quarter ending December 31, 2008, due to recognition in that quarter of a $16.5 million gain on the sale of certain unproved properties discussed in Note 13 to the financial statements contained in this Form 10-Q.

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For the quarter ended September 30, 2008, we recorded total oil and gas revenues of $1,159,621 compared with $780,963 for the quarter ended September 30, 2007. The $378,658 increase from the 2007 quarter is attributable to higher oil and gas prices as shown in the table below:

	Three months ended
	September 30,
	2008			2007
Oil sold (barrels)		5,609			7,222
Average oil price	$	108.83		$	67.18
Oil revenue	$	610,437		$	485,185
Gas sold (mcf)		53,783			51,345
Average gas price	$	10.21		$	5.76
Gas revenue	$	549,184		$	295,778
Total oil and gas revenues	$	1,159,621		$	780,963
Less lease operating expenses		(475,382	)		(213,708	)
Less oil & gas amortization expense		(1,177,000	)		(386,000	)
Less impairment		(18,000,000	)		—
Less accretion of asset retirement obligation		(8,427	)		(6,537	)
Producing revenues less direct expenses		(18,501,188	)		174,718
Less depreciation of office facilities		(19,021	)		(16,381	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(768,780	)		(969,845	)
Add other revenue		—			—
Loss from operations	$	(19,333,989	)	$	(856,508	)
Total barrels of oil equivalent (“boe”) sold		14,573			15,780
Revenue per boe sold	$	79.57		$	49.49
Lease operating expense per boe sold	$	32.62		$	13.54
Amortization expense per boe sold	$	80.77		$	24.46

General and administrative expenses for the quarter ended September 30, 2008 decreased by $201,065 (21%) over the quarter ended September 30, 2007. The major changes in general and administrative costs were (1) a $180,000 reduction for identified internal employee costs that are capitalized as direct costs for the acquisition and maintenance of oil and gas property, (2) approximately $100,000 decrease in share based compensation arising from an increase in expected forfeitures of unvested stock options and (3) expense increases relating to new employees since September 30, 2007.

The Nine-month Period ended September 30, 2008 Compared with the Nine-month Period ended September 30, 2007

We recorded net loss attributable to common stockholders of $15,045,806 ($0.32 per common share, basic and diluted) for the nine-month period ended September 30, 2008, as compared to net loss attributable to common stockholders of $1,977,842 ($0.05 per common share, basic and diluted) for the nine-month period ended September 30, 2007. The approximately $13,100,000 increase in loss is primarily attributable to the third quarter’s $18 million impairment ($11,430,000 net of related deferred tax benefit) and the third quarter’s $791,000 increase in oil & gas amortization expense computed on capitalized costs before recognition of the impairment.

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For the nine months ended September 30, 2008, we recorded total oil and gas revenues of $2,604,786 compared with $1,580,553 for the nine months ended September 30, 2007. The $1,024,233 increase from the nine months ended September 30, 2007, is largely attributable to higher oil and gas prices as shown in the table below:

	Nine months ended September 30,
	2008			2007
Oil sold (barrels)		13,503			16,057
Average oil price	$	104.97		$	60.74
Oil revenue	$	1,417,403		$	975,279
Gas sold (mcf)		117,711			102,060
Average gas price	$	10.09		$	5.93
Gas revenue	$	1,187,383		$	605,274
Total oil and gas revenues	$	2,604,786		$	1,580,553
Less lease operating expenses		(1,025,987	)		(466,444	)
Less oil & gas amortization expense		(1,887,000	)		(786,818	)
Less impairment		(18,000,000	)		—
Less accretion of asset retirement obligation		(24,759	)		(18,142	)
Producing revenues less direct expenses		(18,332,960	)		309,149
Less depreciation of office facilities		(56,612	)		(47,631	)
Less amortization of other intangible asset		(135,000	)		(135,000	)
Less general and administrative expenses		(3,260,093	)		(3,271,647	)
Add other revenue		—			12,000
Income (loss) from operations		(21,784,665	)		(3,133,129	)
Total barrels of oil equivalent (“boe”) sold		33,122			33,067
Revenue per boe sold	$	78.64		$	47.80
Lease operating expense per boe sold	$	30.98		$	14.11
Amortization expense per boe sold	$	56.97		$	23.79

We did not incur federal or state income tax liabilities for 2007 and through the first nine months of 2008. We expect to incur approximately $400,000 in income tax liabilities for the remainder of 2008 as discussed further in Note 7 to the financial statements contained in this Form 10-Q.

Dividends on preferred stock for the 2008 period declined $125,608 from the 2007 period due to conversion of a small number of preferred shares into common stock in early 2008 followed by conversion of all remaining preferred shares into common shares on July 22, 2008.

Liquidity and Capital Resources

At September 30, 2008, we had $5.3 million in cash and cash equivalents and $7.8 million in working capital. Working capital includes investments in Auction Rate Preferred Shares (ARPS), which had a fair value of $5,684,000 at September 30, 2008. Liquidity of the ARPS is discussed more fully in Notes 4 and 5 to the financial statements contained in this Form 10-Q.

In the first nine months of 2008, we incurred nearly $17 million of capital expenditures, as further explained in Note 3 to the financial statements contained in this Form 10-Q. We currently anticipate capital expenditures for the last three months of 2008 to be approximately $9 million. We intend to fund these capital expenditures, other commitments and working capital requirements from cash on hand at September 30, 2008 and with the $26.4 million in cash proceeds from the October 27, 2008 property sale discussed in Note 13 to the financial statements contained in this Form 10-Q.

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For the nine-month periods ended September 30, 2008 and September 30, 2007, our sources and uses of cash were as follows:

Net Cash Used By Operating Activities — Our net cash used by operating activities increased by $19,902 (from $1,098,375 for the nine months ended September 30, 2007, to $1,118,277 for the nine months ended September 30, 2008). The 2% net increase arises from several offsetting factors such as increased revenues partially offset by increased expenses and partially offset by delays in receiving payment of revenues on new wells’ production until royalty ownerships are confirmed.

Net Cash Provided (Used) By Investing Activities — During the nine months ended September 30, 2008, we provided a net $1.6 million in cash from investing activities as compared with $10.5 million used in the nine months ended September 30, 2007. The $12.1 million change is primarily due to $12.1 million in redemptions and sales of short-term investments in equity securities during the nine months ended September 30, 2008.

Net Cash Provided By Financing Activities — In the nine months ended September 30, 2008, our only financing activities were to (i) borrow $8,600,000 in March and $2,325,000 in September, secured by our ARPS investments, and (ii) repay the $8,600,000 by late June using proceeds from redemptions of some ARPS. During the nine months ended September 30, 2007, we received $26.9 million in cash provided from the sale of common stock in a public offering and from exercise of warrants and stock options.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

Because of our relatively low level of current oil and gas production, we are not exposed to a great degree of market risk relating to the pricing applicable to our oil and natural gas production. However, our ability to raise additional capital at attractive pricing, our future revenues from oil and gas operations, our future profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. 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

We have experienced rising operating costs which impacts our cash flow from operating activities and profitability. We recognize that rising operating costs could continue and that continued rising operating costs would negatively impact our oil and gas operations.

Interest Rate Risk

Our exposure to market risks for changes in interest rates is insignificant.

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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 September 30, 2008 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 have materially affected, or are reasonably likely to materially affect, the effectiveness of our internal controls over financial reporting.

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, 2007, 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
10.1	Letter agreement dated August 22, 2008 for the property sale closed October 27, 2008 (incorporated by reference to Exhibit 10.1 to the Amendment No. 1 to Form 8-K/A filed with the Securities and Exchange Commission on October 28, 2008).
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	November 7, 2008
/s/ Joseph B. Feiten	Chief Financial Officer	November 7, 2008
Joseph B. Feiten

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Letter agreement dated August 22, 2008 for the property sale closed October 27, 2008 (incorporated by reference to Exhibit 10.1 to the Amendment No. 1 to Form 8-K/A filed with the Securities and Exchange Commission on October 28, 2008).
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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