HESS BAKKEN INVESTMENTS I (AEZ) 10-Q 2009 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, 2009

OR

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

For the transition period from                    to                    

Commission File No. 1-31900

AMERICAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

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

Indicate by check mark whether the issuer (i) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noo 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 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 3, 2009 were 48,307,399.

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

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements		3
Condensed Consolidated Balance Sheets — September 30, 2009 and December 31, 2008		3
Condensed Consolidated Statements of Income — Three and Nine Months Ended September 30, 2009 and 2008		4
Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2009 and 2008		5
Notes to Condensed Consolidated Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3. Quantitative and Qualitative Disclosures about Market Risks		21
Item 4. Controls and Procedures		21
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		22
Item 1A. Risk Factors		22
Item 6. Exhibits		22
Signatures		22
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,
	2009			2008
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	12,997,776		$	23,269,725
Short-term investment		2,925,000			5,450,000
Accounts receivable		544,565			1,186,749
Materials and supplies inventory		1,347,296			1,236,591
Prepaid expenses		46,280			133,360
Total current assets		17,860,917			31,276,425
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $34,694,565 at 9/30/09 and $31,837,965 at 12/31/08)		43,334,656			40,456,632
Other property and equipment		402,818			366,354
Total property and equipment		43,737,474			40,822,986
Less-accumulated depreciation, depletion and amortization		(5,584,310	)		(4,980,578	)
Net property and equipment		38,153,164			35,842,408
OTHER ASSETS
Deferred income tax assets (net of valuation allowance, Note 7)		—			—
Intangible asset, net of accumulated amortization		105,000			240,000
Other		80,485			30,385
	$	56,199,566		$	67,389,218
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	1,213,744		$	4,286,618
Income taxes payable		—			104,000
Total current liabilities		1,213,744			4,390,618
LONG-TERM LIABILITIES
Asset retirement obligations		411,832			430,686
COMMITMENTS AND CONTINGENCIES(Note 10)
STOCKHOLDERS’ EQUITY
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding: 48,307,399 shares at 9/30/09 and 47,875,899 shares at 12/31/08		48,307			47,876
Additional paid-in capital		92,098,256			91,275,557
Accumulated deficit		(37,647,573	)		(28,755,519	)
Accumulated other comprehensive income		75,000			—
		54,573,990			62,567,914
	$	56,199,566		$	67,389,218

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

3

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATION

(UNAUDITED)

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
REVENUES:
Oil and gas sales	$	462,553		$	1,159,621		$	1,285,705		$	2,604,786
OPERATING EXPENSES:
Lease operating		278,429			475,382			848,354			1,025,987
General and administrative		1,198,188			768,780			4,242,539			3,260,093
Depletion, depreciation and amortization		276,417			401,021			738,732			1,238,612
Impairment of oil & gas properties		1,850,000			18,840,000			3,950,000			18,840,000
Impairment of materials and supplies inventory		409,852			—			565,991			—
Accretion of asset retirement obligation		9,837			8,427			30,057			24,759
		4,022,723			20,493,610			10,375,673			24,389,451
LOSS FROM OPERATIONS		(3,560,170	)		(19,333,989	)		(9,089,968	)		(21,784,665	)
OTHER INCOME (LOSS):
Investment income		9,632			73,329			47,949			446,560
Gain (loss) on sale of securities		—			—			—			(369,172	)
Impairment of short-term investments		—			—			—			(116,000	)
Interest expense		—			(6,000	)		—			(94,647	)
		9,632			67,329			47,949			(133,259	)
LOSS BEFORE INCOME TAXES		(3,550,538	)		(19,266,660	)		(9,042,019	)		(21,917,924	)
Income tax expense (reduction) -current		(149,965	)		—			(149,965	)		—
Income tax expense (reduction) -deferred		—			(6,520,000	)		—			(7,500,000	)
NET LOSS		(3,400,573	)		(12,746,660	)		(8,892,054	)		(14,417,924	)
Less dividends on preferred stock		—			(33,627	)		—			(327,882	)
Less deemed dividends on warrants extension		—			—			—			(300,000	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(3,400,573	)	$	(12,780,287	)	$	(8,892,054	)	$	(15,045,806	)
NET LOSS PER COMMON SHARE:
Basic and diluted	$	(0.07	)	$	(.27	)	$	(0.18	)	$	(.32	)
Weighted average common shares outstanding:
Basic and diluted		48,307,399			47,525,743			48,284,846			46,844,855

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,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(8,892,054	)	$	(14,417,924	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairment of oil and gas properties		3,950,000			18,840,000
Share-based compensation expenses		823,130			663,013
Depletion, depreciation and amortization		738,732			1,238,612
Impairment of materials and supplies inventory		565,991			—
Accretion of asset retirement obligations		30,057			24,759
Realized loss on sale of short-term investments		—			369,172
Impairment on short-term investments		—			116,000
Deferred income taxes		—			(7,500,000	)
Changes in assets and liabilities:
Decrease (increase) in receivables		271,629			(598,947	)
Decrease (increase) in prepaid expenses		87,080			93,093
Decrease (increase) in inventory		(676,696	)		—
Increase (decrease) in accounts payable and accrued liabilities		45,057			53,945
Net cash provided (used) by operating activities		(3,057,074	)		(1,118,277	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties		(9,728,311	)		(15,800,105	)
Proceeds from the sale of oil and gas properties		—			5,329,877
Proceeds from redemptions of auction-rate preferred shares		2,600,000			11,450,000
Proceeds from sales of short-term investments		—			683,728
Cash paid for office equipment		(36,464	)		(15,468	)
Cash paid for other long-term assets		(50,100	)		—
Net cash provided (used) by investing activities		(7,214,875	)		1,648,032
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowing		—			10,925,000
Repayment of short-term borrowings		—			(8,600,000	)
Proceeds from exercise of common stock warrants and stock options		—			56,638
Net cash provided by financing activities		—			2,381,638
NET INCREASE (DECREASE) IN CASH		(10,271,949	)		2,911,393
CASH, BEGINNING OF PERIODS		23,269,725			2,388,219
CASH, END OF PERIODS	$	12,997,776		$	5,299,612
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	94,647
Cash paid for income taxes	$	130,000		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING ACTIVITIES
Share-based compensation expenses	$	823,130		$	663,013
Exchange of oil and gas properties	$	420,000		$	—
Net increase in payables for capital expenditures	$	—		$	1,174,329
Drilling prepayments applied to drilling costs	$	—		$	505,995
Preferred dividends paid in shares of common stock	$	—		$	589,530
Conversion of preferred stock into common stock	$	—		$	600,048

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)

June 30, 2009

NOTE 1 — COMPANY AND BUSINESS

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

We are an independent oil and gas exploration and production company, engaged in the exploration, development, acquisition and production of crude oil and natural gas in the western United States. Our current operations are focused primarily 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, 2009 are not necessarily indicative of the operating results for the entire year ending December 31, 2009.

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

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

SIGNIFICANT ACCOUNTING POLICIES— We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (GAAP) that we follow in preparing our financial statements of our financial condition, results of operations, and cash flows. References to GAAP issued by the FASB in these footnotes are to theFASB Accounting Standards Codification,^™ sometimes referred to as the Codification or ASC. The FASB finalized the Codification effective for periods ending on or after September 15, 2009. Prior FASB standards (like FASB Statement No. 165,Subsequent Events, issued in May 2009) are superseded by the Codification, and new FASB Statements are not being issued. For further discussion of the Codification see “FASB Codification Discussion” in Management’s Discussion and Analysis of Financial Condition and Results of Operations (commonly referred to as MD&A) elsewhere in this report.

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

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

6

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, 2009 and September 30, 2008, with consideration of (1) the proved reserve estimates for the prior fiscal year-end prepared by independent engineering consultants and (2) significant new discoveries and significant changes during the interim period in production, ownership, and other factors underlying reserve estimates.

RECENT ACCOUNTING PRONOUNCEMENTS—FASB Codification. In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168,The FASB Accounting Standards Codification^™and the Hierarchy of Generally Accepted Accounting Principle,as codified in FASB ASC Topic 105,Generally Accepted Accounting Principles.This standard establishes two levels of U.S. GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (“the Codification” or “ASC”) became the source of authoritative, nongovernmental GAAP, except for financial accounting rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became non-authoritative. The new authoritative guidance under ASC Topic 105 became effective for periods ending on or after September 15, 2009, and did not have a material impact on the Company’s consolidated financial statements.

Reporting of Oil and Gas Reserve Information. In December 2008 the SEC published final rules and interpretations updating its oil and gas reporting requirements. In October 2009, the SEC issued Staff Accounting Bulletin No. 113 (SAB No. 113), effective November 4, 2009, revising Staff Accounting Bulletin Series Topic 12“Oil and Gas Producing Activities”primarily to conform Topic 12 to the aforementioned SEC updates to its oil and gas reporting requirements. Key changes to the SEC’s rules and interpretations include a requirement to use 12-month average pricing rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure of probable and possible reserves. The full-cost accounting method, which we follow, is changed to no longer allow the option of ceiling test impairments being reduced or eliminated by consideration of oil and gas price increases occurring subsequent to the impairment date.

The new authoritative guidance will be effective for registration statements filed after January 1, 2010 and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company will apply this new authoritative guidance in the Company’s Annual Report on Form 10-K for the fiscal year ending December 31, 2009.

Newly proposed authoritative accounting guidance by the FASB would align FASB ASC Topic 932, “Extractive Activities — Oil and Gas” with the aforementioned SEC changes in how proved reserves are defined and determined. For example, the proposed guidance would have the 12-month average pricing reflected in the disclosure of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. We anticipate that this proposal will become an issued accounting update within the last quarter of 2009 with an effective date for annual reports for fiscal years ending on or after December 15, 2009.

Company management expects that the new SEC authoritative guidance and the proposed ASC guidance, if adopted, will not have a material impact on the Company’s consolidated financial statements for the year ending December 31, 2009. However, the required use of 12-month average pricing rather than using period-end prices may materially impact the Company’s consolidated financial statements for subsequent periods in cases where oil and gas prices at the end of the period are materially different from the corresponding twelve-month average price. Such price variations can materially impact proved reserve estimates, evaluated property amortization expense, ceiling test impairment and/or the standard measure.

SUBSEQUENT EVENTS— Those subsequent events known to the Company’s principal executive officer or principal financial officer prior to the first issuance of the financial statements are evaluated for incorporation in the financial statements and notes thereto. These financial statements were first issued on November 6, 2009 at the time of filing this Form 10-Q with the SEC.

We use the full cost method of accounting for oil and gas properties, as described on page F-9 of our Form 10-K/A for the year ended December 31, 2008. In evaluating impairment of capitalized costs under the full cost method, SEC guidance allows (but does not require) the impairment to be reduced for certain subsequent events occurring reasonably before the filing date of the affected financial statements and indicative that capitalized costs were not impaired at period-end. Such subsequent events are increased oil and gas prices and the proving up of additional reserves on properties owned at period-end. For this allowance, we consider (i) oil and gas prices as of the end of the first month after the latest balance sheet date and (ii) the proving up of additional reserves during the first month after the balance sheet date.

7

GAS BALANCING— As of September 30, 2009 and December 31, 2008, our gas production was in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.

INVENTORY— Inventories classified as current assets consists of purchased well casing and tubing stored in central yards serving multiple oil and gas companies. Such inventory is carried at the lower of cost or market. In the three-month period and the nine-month period ended September 30, 2009, we wrote-down the carrying value of our well casing and tubing inventory to market values, recognizing $409,852 and $565,991, respectively, of impairments of materials and supplies inventory. Casing and tubing moved to well sites are classified as non-current assets to be used in the completion of wells.

DISCRETIONARY COMPENSATION— The Company accrues for annual year-end bonuses traditionally paid to employees who are not officers. The Company does not accrue for discretionary bonuses to officers because the Company retains significant discretion in the payment of such bonuses. Although upon Board approval the Company paid $50,000 bonuses to each of its seven officers in January 2009 as disclosed in Item 11 of our Form 10-K/A for the year ended December 31, 2008, the Company retains significant discretion and ability to pay little or no future bonuses to officers with regards to officer performance or employment in 2009. Consequently, no liability exists at September 30, 2009 with respect to future officer bonuses, and no future officer bonuses have been accrued as of September 30, 2009.

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

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

For the nine-month periods ended September 30, 2009 and September 30, 2008, 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, 2009 that could in the future potentially dilute basic net income (loss) per share for common stockholders are described in Notes 8 and 10 and include (i) a warrant for 50,000 shares, (ii) outstanding stock options for 3,037,000 shares (of which options to purchase 1,285,366 shares were exercisable at September 30, 2009), 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, 2009, consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization	$	34,694,565
Evaluated costs		8,640,091
		43,334,656
Less accumulated depreciation , depletion and amortization		(5,342,017	)
Net carrying value of oil and gas properties		37,992,639
Office equipment, furniture and software (net of $242,293 accumulated depreciation and amortization)		160,525
Property and equipment	$	38,153,164

8

Our major projects are Fetter, Goliath, Krejci and Bigfoot and are described more fully in our Form 10-K/A for 2008 and 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 months ended September 30, 2009, with the unevaluated costs by major project:

	Capitalized Costs (in millions)
Project (State)	12/31/08		Net Change			9/30/09
Fetter Project, Powder River Basin (WY)	$	14.7	$	0.3		$	15.0
Goliath Project, Williston Basin (ND)		7.7		1.5			9.2
Bigfoot		3.3		1.7			5.0
Krejci Oil Project, Powder River Basin (WY)		2.7		(0.3	)		2.4
Other unevaluated costs		3.5		(0.4	)		3.1
Total unevaluated costs		31.9		2.8			34.7
Evaluated costs, net of accumulated DD&A		3.8		(0.5	)		3.3
Total, oil and gas properties	$	35.7	$	2.3		$	38.0

The $2.3 million increase during the nine-month period ended September 30, 2009 primarily consisted of $6.7 million of costs incurred in oil and gas property acquisition, exploration and development, less $3.95 million in expensed impairment and less $546,000 in amortization expense.

During the nine months ended September 30, 2009, we paid approximately $9.7 million in cash for oil and gas property acquisition, exploration and development including approximately $4 million for costs incurred in 2008. At September 30, 2009, we owed nearly $1 million for incurred oil and gas property acquisition, exploration and development costs.

Of the $6.7 million of incurred costs, $1.4 million were for the completion of the productive Sims 7-25 well at our Fetter project and the marginally productive Viall 30-1 well completed in the Red River formation at our Goliath project in North Dakota. We incurred $1.5 million in costs of acquiring leases and performing preliminary field activities at our Bigfoot project. We also incurred approximately $0.9 million in various additional costs at Fetter and $0.4 million in Wyoming wells in progress at September 30, 2009 located outside our four major projects. On June 30, 2009, we spent $0.9 million acquiring Goliath Project working interests, as further described in the next paragraph. Included in capital additions were $0.7 million of internal land department and geologist costs directly associated with the acquisition, exploration and development of oil and gas properties. There were no significant property divestitures in the nine-month period ended September 30, 2009.

Acquisitions and an Exchange of Working Interests in North Dakota

On June 30, 2009 we closed on a $900,000 cash purchase, effective July 1, 2009, of certain oil and gas properties held by a third party in the Goliath Project. Approximately $500,000 of the purchase related to acquiring unevaluated, undeveloped oil and gas leases of approximately 14,900 net acres; the remainder related to acquiring the third-party’s 25% working interest in the Champion 1-25H well (increasing our working interest to 75%), 17% ownership in the Viall 1-30 well (increasing our working interest to approximately 51%), 6% ownership in the Solberg 32-2 well (increasing our working interest to approximately 18%) and working interests in seven gross (approximately 0.12 net) producing Bakken wells.

On July 15, 2009, we closed on an acreage exchange at Goliath with another third party, which resulted in our receiving approximately 11,600 net acres and the third-party receiving a 50% working interest in the Champion 1-25H well, a 34% working interest in the Viall 1-30 well, an 11.9% working interest in the Solberg 32-2 well and American’s rights to formations below the Three Forks formation in four 640-acre sections. Both the June 30, 2009 and the July 15^th transactions combined were for assets and operations that were insignificant to our $67 million in assets at December 31, 2008 and our operations in 2008 and 2009 year-to-date.

After closing these transactions, we controlled approximately 60,000 net undeveloped acres at Goliath, a 25% working interest in the Champion 1-25H well, a 17% working interest in the Viall 1-30 well, a 6% working interest in the Solberg 32-2 well and an interest in seven gross (approximately .36 net) other producing Bakken wells.

9

Amortization

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

	Nine-month Period
	Ended September 30,
	2009		2008
Amortization of costs for evaluated oil and gas properties	$	546,000	$	1,047,000
Amortization of Intangible Asset		135,000		135,000
Depreciation of office equipment, furniture and software		57,732		56,612
Total DD&A expense	$	738,732	$	1,238,612

The $1,047,000 amortization in the nine-month period ended September 30, 2008 reflects a reclassification of $840,000 from amortization expense (as reported at September 30, 2008) to property impairment expense, consistent with the classification and computation in our Form 10-K/A for the year ended December 31, 2008 as described on its page F-15.

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 Form 10-K/A as of December 31, 2008. At March 31, 2009, we recognized such an impairment of $2,100,000 ($1,330,000, net of a $770,000 increase in deferred tax assets before valuation allowances). At September 30, 2009, we recognized an additional impairment of $1,850,000 ($1,170,000, net of an $680,000 increase in deferred tax assets before valuation allowance.)

NOTE 4 — 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, 2009 and September 30, 2008:

	Three months ended					Nine months ended
	September 30,					September 30,
	2009			2008		2009			2008
Beginning asset retirement obligation	$	492,115		$	337,122		430,686		$	323,369
Liabilities incurred		142			2,141		53,509			33,655
Liabilities settled		(79,432	)		—		(79,432	)		—
Revisions in estimated liabilities		(10,830	)		43,746		(22,988	)		9,653
Accretion		9,837			8,427		30,057			24,759
Ending asset retirement obligation		411,832		$	391,436		411,832		$	391,436
Current portion of obligation, end of period	$	—		$	—	$	—		$	—

NOTE 5 — SHORT-TERM INVESTMENTS

Our short-term investments at September 30, 2009 and December 31, 2008 were comprised of auction-rate preferred shares (“ARPS”) issued by closed-end mutual funds. ARPS are a form of auction-rate securities (“ARS”) that were bought and sold at par value prior to March 2008 at special auctions held every 7 days or 28 days and paying variable-rate dividends, with the rate re-determined at the auctions. After February 2008, there were no parties willing to buy ARPS at par value at the auctions, i.e., the 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 February 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.

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At March 1, 2008, most of our ARPS were issued by three Calamos closed-end mutual funds, which redeemed the majority of their ARPS in May and June of 2008 and redeemed their remaining ARPS in June through August 2009.

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 $130,000 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. We understand from Jefferies that FINRA is separately investigating Jefferies’ role as a broker of ARPS and as an Auction Dealer in ARPS.

We expect to have our ARPS entirely liquidated for cash before June 30, 2010. Absent full liquidation at par value, we intend to sell before June 30, 2010 any remaining ARPS in the secondary market at a loss, not expected to exceed approximately $225,000. We may receive an award in arbitration with Jefferies; however, we have no assurance that we will be successful in our claim against Jefferies.

The ARPS we own at September 30, 2009 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.

The ARPS’ total par value and carrying value (estimated fair value) since March 31, 2008 through September 30, 2009 are summarized in the following table:

	Par Values ($ thousands)									Fair Values ($ thousands)
	Calamos			Other			All			Calamos			Other			All
	Funds			Funds			Funds			Funds			Funds			Funds
Balance at March 1, 2008		11,250			6,000			17,250			11,250			6,000			17,250
Less redemptions by 12/31/08		(8,925	)		(2,575	)		(11,500	)		(8,925	)		(2,575	)		(11,500	)
Other-than-temporary loss											—			(300	)		(300	)
Balance at December 31, 2008		2,325			3,425			5,750			2,325			3,125			5,450
Less redemptions by 3/31/09		—			(200	)		(200	)		—			(200	)		(200	)
Temporary loss at 3/31/09											(250	)		—			(250	)
Balance at March 31, 2009		2,325			3,225			5,550			2,075			2,925			5,000
Less redemptions by 6/30/09		(1,300	)		(75	)		(1,375	)		(1,300	)		(75	)		(1,375	)
Fair value increases by 6/30/09											250			75			325
Balance at June 30, 2009		1,025			3,150			4,175			1,025			2,925			3,950
Less July 2009 redemptions		(325	)		—			(325	)		(325	)					(325	)
Less August 2009 redemptions		(700	)		—			(700	)		(700	)					(700	)
Change in fair value at 9/30/09														—			—
Balance at September 30, 2009		—			3,150			3,150			—			2,925			2,925

At September 30, 2009, our remaining ARPS were preferred shares in five closed-end mutual funds: $1,200,000 par value in Evergreen Income Advantage (symbol EAD), $1,075,000 par value in Advent Claymore Convertible Securities (symbol AVK) and $875,000 total par value in the PSY, BPP and PHT funds. The ARPS’ $3,150,000 total par value exceeded their $2,925,000 total carrying value by $225,000. The $225,000 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 $75,000 temporary unrealized gain recorded in Other Comprehensive Income.

The ARPS dividend rates approximated 0.8% per annum at September 30, 2009. Dividend rates fluctuate weekly or monthly generally at a small premium over 30-day LIBOR or over AA commercial paper.

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NOTE 6 — FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted ASC 820Fair Value Measurements and Disclosuresfor 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 establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. It defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of fair values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement calls for disclosures grouping these financial assets and liabilities, based on the following levels of significant inputs to measuring fair value:

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

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

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

The following table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values:

	Total at
	September 30,		Level 1		Level 2		Level 3
	2009		inputs		inputs		inputs
Financial Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (“ARPS”)	$	2,925,000	$	—	$	—	$	2,925,000
Financial Liabilities	$	—	$	—	$	—	$	—

The table in Note 5 provides a reconciliation between the $5,450,000 fair value of the ARPS at December 31, 2008 and the $2,925,000 fair value of the ARPS at September 30, 2009.

Our estimate of the fair value of the ARPS at September 30, 2009, reflected the same general methodology at December 31, 2008. For the ARPS ($3,150,000 par value) held at September 30, 2009, we estimated fair value based primarily on discounted cash flow analyses reflecting estimates of when ARPS would be redeemed in the coming years.

Our claim against Jefferies (see Note 5) is not reflected in estimation as to the fair value of our ARPS at September 30, 2009, because fair value is based on what a third party would be willing to pay for the securities excluding any legal rights at September 30, 2009 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.

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NOTE 7 — INCOME TAXES

We account for income taxes under the provisions of ASC Topic 740,“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 expect to owe little or no federal or state income taxes for 2009. In the three-month period ended September 30, 2009, we recorded a $149,965 reduction in income tax expense. The 2008 federal income tax return filed in September 2009 was $149,965 less than the $244,000 current income tax provision for 2008 shown on page F-4 and F-18 of our Form 10-K/A for the year ended December 31, 2008. The tax reduction is due to our decision in September 2009 to deduct more intangible drilling costs than planned in March of 2009 at the time of filing our Form 10-K for the year ended December 31, 2008.

We currently estimate that our effective tax rate for the year ending December 31, 2009 will be approximately 33%. Deferred income tax reductions of $0 (net of a $3.1 million valuation allowance) and $7,500,000 were reported for the nine-month periods ended September 30, 2009 and 2008, respectively. As of September 30, 2009, net deferred tax assets were $0, after a 100% valuation allowance applied to net deferred tax assets of approximately $7.9 million. At September 30, 2009, we have estimated net operating loss carryforwards of approximately $19 million and percentage depletion carryforward of approximately $1.4 million.

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 November 6, 2009, we are no longer subject to income tax examinations by tax authorities for years before 2005 for Colorado and Montana and before 2006 for federal, 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 ASC Topic 740 regarding uncertainty in income taxes. We found no significant uncertain tax positions as of any date on or before September 30, 2009. Given our substantial net operating loss carryforwards at both the federal and state levels prior to 2009, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of income tax returns prior to 2009.

NOTE 8 — EQUITY

Common Stock

The following transactions occurred during the nine-month period ended September 30, 2009 with regard to our common stock:

• On January 14, 2009, our Board of Directors granted an aggregate of 427,500 shares of common stock pursuant to the 2006 Stock Incentive Plan to certain employees, officers and directors of the Company. Of the 427,500 shares, 10,000 shares to each of the three outside directors vested at date of grant, and 20,000 shares to each of the three outside directors vest when the individual is no longer a director of the Company. The other 337,500 shares were to three officers and one other employee and vest upon the earlier of January 14, 2014 or a change in control of the Company.

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

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

• For the quarter ended March 31, 2009, Additional Paid-In Capital increased by $395,442 for recognition, in accordance with ASC Topic 718, of share-based compensation consisting of (i) $259,008 in share-based compensation related to stock options, (ii) $50,734 related to accruals for granted stock vesting after grant, (iii) $83,700 for the January 14, 2009 granting and immediate vesting of 90,000 shares of common stock and (iv) $2,000 for the aforementioned change in warrant terms.

• For the quarter ended June 30, 2009, Additional Paid-In Capital increased by $202,610 for recognition, in accordance with ASC Topic 718, of share-based compensation consisting of (i) $151,877 in share-based compensation related to stock options and (ii) $50,733 related to accruals for granted stock vesting after grant.

• For the quarter ended September 30, 2009, Additional Paid-In Capital increased by $225,078 for recognition, in accordance with ASC Topic 718, of share-based compensation consisting of (i) $174,345 in share-based compensation related to stock options and (ii) $50,733 related to accruals for granted stock vesting after grant.

Warrants

The warrants outstanding at September 30, 2009 consisted of a warrant issued April 16, 2008 and expiring on April 16, 2013. The warrant is for 50,000 shares of our common stock at an exercise price of $3.50 per share.

Stock Options

In the nine-month period ended September 30, 2009:

• we granted in July to a new employee stock options for 15,000 shares, exercisable at $2.00 per share and vesting over three years, with an estimated fair value of $0.40 per share considering both the Black-Scholes valuation method and a modified binomial valuation model;

• stock options for 15,000 shares were forfeited by an employee upon termination in March 2009;

• no stock options were exercised; and

• there were vestings of options for 294,033 shares at exercise prices ranging from $2.00 to $3.66 per share and averaging $2.78 per share.

On January 14, 2009, we granted extensions of approximately four years to vested options of 403,000 shares. The extension grants had an estimated total fair value of $93,660, which was recognized in option expense at the time the extensions were granted.

At September 30, 2009, there were outstanding options for 3,037,000 shares of common stock at a weighted-average exercise price of $2.42 per share. Of these, there were vested at September 30, 2009 options for 1,285,366 shares of common stock at a weighted-average exercise price of $2.84 per share. At September 30, 2009, our stock price closed at $1.97 per share. The only outstanding options with intrinsic value at September 30, 2009 were exercisable options for 403,000 shares with a total intrinsic value of $290,160.

Other Comprehensive Loss

During the quarter ended September 30, 2009, Other Comprehensive Income did not change, as discussed further in Note 5.

NOTE 9 — SIGNIFICANT CHANGES IN RESERVE INFORMATION

At September 30, 2009, we recognized proved undeveloped reserves of approximately 65,000 barrels of oil and approximately 68,000 mcf of natural gas for our interest in a 640-acre section offsetting two wells producing from the Bakken formation in North Dakota. We expect a well to be drilled on the section within the next six months. We intend to participate in drilling and completing the well using a portion of our available cash resources. We estimate that the standardized measure of discounted cash flow relating to our share of proved undeveloped reserves approximates $0.9 million, net of our estimated $1.2 million share of drilling and completion costs.

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NOTE 10—COMMITMENTS AND CONTINGENCIES

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

North Finn Option

Under our January 2006 participation agreement with North Finn, LLC, we fund 60% of North Finn’s lease, drilling and other project related capital obligations in certain jointly owned project areas, in order to earn 60% of North Finn’s interest in that particular lease or well, including offset locations. The project areas include, but are not limited to, the Fetter Project and the Krejci Project and exclude the Goliath and Bigfoot projects. We paid $535,000, and reimbursed approximately $976,000 to North Finn for 60% of all project related costs that North Finn has incurred in jointly owned project areas after the effective date of August 1, 2005.

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

As North Finn has not exercised its right nor made a commitment to exercise, under ASC paragraphs 505-50-30-11 and -12, the value of North Finn’s right is not currently recognized in our financial statements.

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

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

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

This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Actual events or results may differ materially from those anticipated or implied in the forward-looking statements. There are a number of risks and uncertainties that could cause our actual results to differ materially from those indicated by such forward-looking statements. These risks and uncertainties include, but are not limited to, those described in this report, in Part II, “Item 1A. Risk Factors,” those described in our Annual Report on Form 10-K/A for the year ended December 31, 2008, 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, acquisition and production of crude oil and natural gas in the western United States. Our current operations are focused primarily in four main project areas that we call Fetter, Goliath, Krejci and Bigfoot. The following project updates should be read in conjunction with our Annual Report on Form 10-K/A for our fiscal year ended December 31, 2008.

Fetter Project (Powder River Basin, Wyoming)

Our Fetter project, located in the southern Powder River Basin of Wyoming, currently encompasses approximately 52,000 gross acres. We own a 69.375% working interest in approximately 49,000 net acres, giving us approximately 34,000 total net acres at Fetter. Red Technology Alliance, LLC (“RTA”) owns a 25% working interest and North Finn LLC retains the remaining 5.625% working interest. The drilling and completion operations have been project managed by Halliburton Energy Services, Inc.

We continue to progress toward establishing a commercially successful drilling program within our Fetter project area. Currently, our activities include a re-entry program that could enable us to establish production from formations in addition to the primary Frontier formation. We have identified up to five wells that we will focus on in these efforts. Our plans are to re-enter these wells to set a removable bridge plug above the Frontier formation and complete and fracture stimulate the Niobrara formation. After production testing of only the Niobrara formation, we expect to remove the temporary bridge plug and flow the wells from both the Niobrara and Frontier formations. Preparations for the first well re-completion are underway and we expect this re-entry program could take three to six months.

During the third quarter, 2009 we signed an agreement with Halliburton Energy Services, Inc, whereby Halliburton has agreed to pay all costs related to perforating and fracture stimulating the Niobrara formation in up to five existing wells in the field. Pursuant to the agreement, Halliburton will receive 80% of the net revenues from Niobrara production in these wells until the wells cumulatively have paid back a maximum of 200% of the total costs. We retain our proportionate share of the remaining 20% of the net revenue from Niobrara production on the subject wells during the pay back period. Once the payback threshold has been achieved, Halliburton’s net revenue interest in the wells will revert back to us and other existing working interest owners at Fetter. This agreement is specific to the five candidate wells. We retain our existing 69.375% working interest in all future wells and formations in the remaining Fetter field net acreage position.

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

Goliath Bakken and Three Forks Project (Williston Basin, North Dakota)

Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are targeting both the middle member of the Bakken and Three Forks formations in the North Dakota portion of the Williston Basin. In late June and mid-July 2009, we increased our working interest in the approximate 87,000 gross acre Goliath project from a 50% working interest to a 95% working interest in approximately 63,000 lease net acres.

On June 30, 2009, we purchased approximately 14,900 net undeveloped acres, a 25% ownership in the Champion 1-25H well, a 17% ownership in the Viall 1-30 well, a 6% ownership in the Solberg 32-2 well, and interests in seven gross (approximately .12 net) producing Bakken wells for $900,000 in cash. On July 15, 2009, we closed on an acreage exchange at Goliath which resulted in our receiving approximately 11,600 net acres in return for our 50% working interest in the Champion 1-25H well, our 34% working interest in the Viall 1-30 well, our 11.9% working interest in the Solberg 32-2 well and our rights to formations below the Three Forks in four 640 acre sections.

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After closing these transactions, we controlled approximately 60,000 net undeveloped acres at Goliath, a 25% working interest in the Champion 1-25H well, a 17% working interest in the Viall 1-30 well, a 6% working interest in the Solberg 32-2 well and an interest in seven gross (approximately .36 net) other producing Bakken wells.

In October 2009, we signed a purchase agreement to acquire an additional approximate 16,000 net acres in Williams County, North Dakota. This project area acreage, which we call “Titan,” is located directly north of and adjacent to our Goliath project area. We have closed on approximately 9,900 net acres and expect to close on the remaining 6,200 net acres within 30 days. With the addition of this acreage position, we would control approximately 76,000 net acres targeting the Bakken and Three Forks formations.

Krejci Oil Project (Powder River Basin, Wyoming)

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

Other companies are now either drilling or planning to drill wells targeting the Mowry formation in the middle and southern parts of the Powder River Basin, and we will be evaluating the level of success these other companies have with their drilling, stimulation and completion operations. We do not expect to incur significant capital expenditures in the Krejci project unless or until other companies are successful in establishing commercial production from the Mowry formation.

Bigfoot Project (Rocky Mountain Region)

We currently control approximately 157,000 net acres in a project that we call Bigfoot. This is a shallow natural gas project located in the Rocky Mountain region. We are primarily targeting a formation that is less that 2,000’ deep and have drilled a series of test wells for less than $100,000 per well. We expect to continue to drill test wells as we evaluate the commercial viability of the area.

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/A for the fiscal year ended December 31, 2008. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended September 30, 2009 Compared with the Quarter Ended September 30, 2008

For the quarter ended September 30, 2009, we recorded a net loss attributable to common stockholders of $3,400,573 ($0.07 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $12,780,287 ($0.27 loss per common share, basic and diluted) for the quarter ended September 30, 2008. The $9,379,714 decrease in loss reflects a $16,990,000 decrease in impairment of oil and gas properties, less a $6,520,000 decrease in reduction of deferred income taxes.

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For the quarter ended September 30, 2009, we recorded total oil and gas revenues of $462,553 compared with $1,159,621 for the quarter ended September 30, 2008. The $697,068 decrease from the 2008 quarter is substantially attributable to lower oil and gas prices. Oil and gas sales and production costs are summarized in the following table:

	Three months ended
	September 30,
	2009			2008
Oil sold (barrels)		4,877			5,609
Average oil price	$	59.17		$	108.83
Oil revenue	$	288,567		$	610,437
Gas sold (mcf)		49,949			53,783
Average gas price	$	3.48		$	10.21
Gas revenue	$	173,986		$	549,184
Total oil and gas revenues	$	462,553		$	1,159,621
Less lease operating expenses		(278,429	)		(475,382	)
Less oil & gas amortization expense		(212,001	)		(337,000	)
Less impairment of oil and gas properties		(1,850,000	)		(18,840,000	)
Less accretion of asset retirement obligation		(9,837	)		(8,427	)
Less impairment of materials & supplies inventory		(409,852	)		—
Producing revenues less direct expenses		(2,297,566	)		(18,501,188	)
Less depreciation of office facilities		(19,416	)		(19,021	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(1,198,188	)		(768,780	)
Loss from operations	$	(3,560,170	)	$	(19,333,989	)
Total barrels of oil equivalent (“boe”) sold		13,202			14,573
Revenue per boe sold	$	35.04		$	79.57
Lease operating expense per boe sold	$	21.09		$	32.62
Amortization expense per boe sold	$	16.06		$	23.13

Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various natural gas liquids (“NGL”) that are sold separately from the remaining natural gas. We sell some of our processed gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses, and our share of NGL revenues are included in gas revenues.

For the quarters ended September 30, 2009 and September 30, 2008, we incurred $1,198,188 and $768,780, respectively, in general and administrative expenses. The $429,408 increase is largely attributable to the following in the 2009 period: (i) $78,562 in increased share-based compensation, (ii) approximately $140,000 in increased various other personnel costs, (iii) a $60,000 reduction in land department costs capitalized, (iv) approximately $48,000 in increased rent for additional office space, and (v), in September 2009, approximately $69,000 in bad debt expense.

The Nine-month Period ended September 30, 2009 Compared with the Nine-month Period ended September 30, 2008

We recorded net loss attributable to common stockholders of $8,892,054 ($0.18 loss per common share, basic and diluted) for the nine-month period ended September 30, 2009, as compared to net loss attributable to common stockholders of $15,045,806 ($0.32 loss per common share, basic and diluted) for the nine-month period ended September 30, 2008. The approximately $6.2 million decrease in loss is largely attributable to (i) a $14,890,000 favorable change (before tax effects) in impairment of oil and gas properties, (ii) a $7,500,000 net unfavorable change in deferred income tax expense and (iii) a $982 ,446 increase in general and administrative expenses. Various other significant, but offsetting, changes occurred as shown in the table below.

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For the nine months ended September 30, 2009, we recorded total oil and gas revenues of $1,285,705 compared with $2,604,786 for the nine months ended September 30, 2008. The $1,319,081 decrease from the nine months ended September 30, 2008, is attributable to significantly lower oil and gas prices in the 2009 period, as shown in the table below:

	Nine months ended September 30,
	2009			2008
Oil sold (barrels)		14,056			13,503
Average oil price	$	46.87		$	104.97
Oil revenue	$	658,759		$	1,417,403
Gas sold (mcf)		183,386			117,711
Average gas price	$	3.42		$	10.09
Gas revenue	$	626,946		$	1,187,383
Total oil and gas revenues	$	1,285,705		$	2,604,786
Less lease operating expenses		(848,354	)		(1,025,987	)
Less oil & gas amortization expense		(546,000	)		(1,047,000	)
Less impairment of oil and gas assets		(3,950,000	)		(18,840,000	)
Less accretion of asset retirement obligation		(30,057	)		(24,759	)
Less impairment of materials & supplies inventory		(565,991	)		—
Producing revenues less direct expenses		(4,654,697	)		(18,332,960	)
Less depreciation of office facilities		(57,732	)		(56,612	)
Less amortization of other intangible asset		(135,000	)		(135,000	)
Less general and administrative expenses		(4,242,539	)		(3,260,093	)
Loss from operations	$	(9,089,968	)		(21,784,665	)
Total barrels of oil equivalent (“boe”) sold		44,620			33,122
Revenue per boe sold	$	28.81		$	78.64
Lease operating expense per boe sold	$	19.01		$	30.98
Amortization expense per boe sold	$	12.24		$	31.61

Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various natural gas liquids (“NGL”) that are sold separately from the remaining natural gas. We sell some of our processed gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses, and our share of NGL revenues are included in gas revenues.

General and administrative expenses for the nine months ended September 30, 2009 increased $982,446 (30%) over the same nine-month period in 2008 due primarily to the following in the 2009 period: (i) approximately $500,000 of costs relating to third-party financial advisory services, (ii) approximately $160,117 in increased share-based compensation and (iii) approximately $475,000 in increased various other personnel costs.

We incurred no federal and state income tax liabilities for the nine-month period ended September 30, 2008, but recognized in the three months ended December 31, 2008 current federal income tax expense of $240,000 relating to (a) $26.5 million in taxable gain on sales of certain unproved oil and gas properties (primarily in October 2008) and (b) tax planning at the time to capitalize for our 2008 federal income tax return approximately $11.5 million in intangible drilling costs so as to utilize our net operating loss carryforward and our percentage depletion carryforward, as more fully explained on page F-19 of our Form 10-K/A filed for the year ended December 31, 2008. We ultimately decided to expense for the 2008 federal income tax return filed in September 2009 all intangible drilling costs incurred in 2008 except for capitalization of approximately $800,000, whereby our federal income taxes for 2008 were $90,035 of Alternative Minimum Tax. The $149,965 reduction in income taxes for 2008 is recognized as a $149,965 income tax benefit in the three months ended September 30, 2009. We expect to incur nominal or no income tax liabilities for the remainder of 2009.

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Liquidity and Capital Resources

At September 30, 2009 and December 31, 2008, we had working capital of $16.6 million and $26.9 million, respectively. We had cash and cash equivalents at September 30, 2009 of $13.0 million.

We do not expect significant capital or cash requirements for expenditures in the three-month period ending December 31, 2009. We currently anticipate that net cash used by operations and investing activities in the three months ending December 31, 2009, will be less than $2 million. With regards to the proved undeveloped reserves discussed in Note 9 of the financial statements included in this Form 10-Q report, we anticipate spending the estimated $1.2 million of development costs in early 2010.

For the nine-month periods ended September 30, 2009 and September 30, 2008, our sources and uses of cash were as follows:

Net Cash Used By Operating Activities — Our net cash used by operating activities increased by $1,938,797, (from $1,118,277 during the nine months ended September 30, 2008, to $3,057,074 for the nine months ended September 30, 2009). The increase in cash usage was due primarily to the previously mentioned $1,319,081 decrease in oil and gas revenues and an $822,329 increase in general and administrative expenses (other than $160,117 in increased share-based compensation) for the nine-month period in 2009 compared to that in 2008.

Net Cash Used In Investing Activities — During the nine months ended September 30, 2009, we used a net $7.2 million in investing activities as compared with $1.6 million cash provided in the nine months ended September 30, 2008. The approximately $8.8 million increase in usage of cash is primarily because the $2.6 million of cash provided by redemptions of ARPS for the 2009 period were $8.85 million less than the 2008 period’s $11.45 million of cash provided by redemptions of ARPS and other securities. At the beginning of the 2009 period, we had $20.8 million more in cash and cash equivalents than we had at the beginning of the 2008 period as a source for funding investment activities.

Net Cash Provided By Financing Activities — For the nine months ended September 30, 2009, we had significant cash assets and received no cash provided by financing activities. In March 2008, we received $8,600,000 from a short-term loan in March 2008 when we were unable to liquidate ARPS at par value. We repaid the loan with ARPS redemptions in May and September 2008. In September 2008, we borrowed an additional $2,325,000, which we repaid in November of 2008.

FASB Codification Discussion

We follow accounting standards set by the U.S. Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (GAAP) that we follow in preparing our financial statements of financial condition, results of operations, and cash flows. Over the years, the FASB and other designated GAAP-setting bodies, have issued standards in the form of FASB Statements, Interpretations, FASB Staff Positions, EITF consensuses, AICPA Statements of Position and other documents.

The FASB recognized the complexity of its standard-setting process and embarked on a revised process in 2004 that culminated in the release on July 1, 2009, of theFASB Accounting Standards Codification,^™ sometimes referred to as the Codification or ASC. The Codification does not change how we account for our transactions or the nature of related disclosures made. However, when referring to guidance issued by the FASB, we refer now to topics in the ASC rather than FASB Statements and other standards superseded by the ASC. The above change was made effective by the FASB for periods ending on or after September 15, 2009.

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Item 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

Our oil and gas business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By current definition, proved reserves are based on current oil and gas prices. Declines in oil and gas prices reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves). Declines in oil and gas prices can reduce the value of our oil and gas properties and increase impairment expense, as occurred in the last half of 2008 and at times in 2009.

Beginning with reserve estimates at December 31, 2009, SEC regulations require that proved reserves for reporting to the SEC be estimated using not current oil and gas prices, but a simple average of first-of-the-month each well’s oil and gas prices for the twelve months ending on the effective date of the reserve estimates. For financial reporting by companies, the Financial Accounting Standards Board has proposed adopting the SEC’s new definition of proved reserves effective as of December 31, 2009. These changes to a one-year average price will substantially eliminate changes in proved reserves arising from monthly and quarterly volatility in oil and gas prices.

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, we generally experienced rising operating costs (including drilling costs) which impacted our cash flow from operating activities and profitability. With the decline in oil and gas prices in late 2008 and early 2009, we have seen a reduction in drilling activity in the Rocky Mountain region where our properties are located, and significant decreases in drilling costs but little reduction in oil and gas production costs other than production taxes (which are generally levied as a percentage of revenue). If oil and gas prices were to recover to levels seen in the summer of 2008, we anticipate the reductions in drilling activity and drilling cost rates will substantially reverse and may fully reverse and continue to rise.

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

Interest Rate Risk

At September 30, 2009, we had no interest-bearing debt or credit facilities, and short-term interest rates on our cash-equivalent investments were less than 0.5% per annum. At September 30, 2009, we had investments in $3,150,000 par value of auction rate preferred shares having dividend rates approximating 0.8% per annum at September 30, 2009. Dividend rates fluctuate weekly or monthly generally at a small premium over 30-day LIBOR or over AA commercial paper. An increase in short-term interest rates would be favorable to us, increasing our investment income in proportion to our short-term investments and cash-equivalent investments, and likely increasing the fair value of ARPS closer to their par value.

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2009 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

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

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PART II
OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

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 auction rate preferred shares discussed in Notes 5 and 6 of American’s financial statements contained in this Form 10-Q. 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 $130,000 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.

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/A for the year ended December 31, 2008, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K/A are not the only risks facing us. Our business operations could also be affected by additional factors that apply to all companies operating in the United States, as well as other risks that are not presently known to us or that we currently consider to be immaterial to our operations. There have been no material changes in our risk factors from those disclosed in our Annual Report on Form 10-K/A.

Item 6. EXHIBITS

Exhibit No.		Description
3(iv)		Bylaws of the Company (as revised on June 12, 2009). (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on June 18, 2009.)
	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/ Patrick D. O’BrienPatrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors (principal executive officer)	November 6, 2009
/s/ Joseph B. FeitenJoseph B. Feiten	Chief Financial Officer (principal financial officer and principal accounting officer)	November 6, 2009

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