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, 2010


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 17^th Street, Suite 2400, Denver, CO		80265

(Address of principal executive offices)		(Zip Code)

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

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

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

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer o * (*Do not check if a smaller reporting company)		Smaller reporting company þ

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

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

The total shares of $.001 Par Value Common Stock outstanding at November 9, 2010 were 61,029,656.

AMERICAN OIL & GAS INC.
FORM 10-Q
INDEX


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements			3

Condensed Consolidated Balance Sheets — September 30, 2010 and December 31, 2009			3

Condensed Consolidated Statements of Operation — Three and Nine Months Ended September 30, 2010 and 2009			4

Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2010 and 2009			5

Notes to Condensed Consolidated Financial Statements			6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			16

Item 3. Quantitative and Qualitative Disclosures about Market Risks			21

Item 4. Controls and Procedures			22

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			23

Item 6. Exhibits			25

Signatures			25

Exhibit 2.5
Exhibit 10(ii)
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


	September 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	13,806,712		$	40,632,284
Short-term investments		1,650,000			2,925,000
Accounts receivable		19,201,075			564,533
Well equipment inventory		1,353,183			1,269,774
Prepaid expenses		131,024			149,991
Current deferred tax assets		114,763			—

Total current assets		36,256,757			45,541,582

PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $76,347,322 at 9/30/10 and $35,611,363 at 12/31/09)		122,422,388			44,454,942
Other property and equipment		449,270			406,273

Total property and equipment		122,871,658			44,861,215
Less-accumulated depreciation, depletion and amortization		(8,382,557	)		(5,771,547	)

Net property and equipment		114,489,101			39,089,668
OTHER ASSETS
Drilling prepayments		269,020			—
Intangible asset, net of accumulated amortization		—			60,000
Other		130,752			80,652

	$	151,145,630		$	84,771,902

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	18,369,405		$	1,032,248
Income taxes payable		—			—

Total current liabilities		18,369,405			1,032,248

LONG-TERM LIABILITIES
Asset retirement obligations		225,099			436,487
Deferred income taxes		6,239,763			—

Total long-term liabilities		6,464,862			436,487

COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS’ EQUITY
Preferred stock, $.001 par value, authorized 24,100,000 shares; no outstanding shares at 09/30/10 and 12/31/09		—			—
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding — 61,029,656 shares at 9/30/10, 57,472,399 shares at 12/31/09		61,030			57,472
Additional paid-in capital		137,685,912			122,267,594
Accumulated deficit		(11,435,579	)		(39,096,899	)
Accumulated other comprehensive income		—			75,000

Total equity		126,311,363			83,303,167

	$	151,145,630		$	84,771,902

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

AMERICAN OIL & GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATION

(UNAUDITED)


	Three months ended						Nine months ended
	September 30						September 30
	2010			2009			2010		2009
REVENUES:
Oil and gas sales	$	4,806,383		$	462,553		$	8,083,918	$	1,285,705


OPERATING EXPENSES:
Lease operating		912,493			278,429			1,777,764		848,354
General and administrative		2,804,686			1,198,188			6,168,688		4,242,539
Depletion, depreciation and amortization		1,621,413			276,417			2,671,011		738,732
Impairment of oil & gas properties		—			1,850,000			—		3,950,000
Impairment of well equipment inventory		26,571			409,852			200,356		565,991
Accretion of asset retirement obligation		3,741			9,837			16,849		30,057

		5,368,904			4,022,723			10,834,668		10,375,673

GAIN ON SALE OF OIL & GAS PROPERTIES		—			—			36,400,000		—

INCOME (LOSS) FROM OPERATIONS		(562,521	)		(3,560,170	)		33,649,250		(9,089,968	)
OTHER INCOME (LOSS):
Investment income		38,255			9,632			137,070		47,949

INCOME (LOSS) BEFORE INCOME TAXES		(524,266	)		(3,550,538	)		33,786,320		(9,042,019	)
Income tax provision (benefit) -current		(200,000	)		(149,965	)		—		(149,965	)
Income tax provision (benefit) -deferred		(205,000	)		—			6,125,000		—

NET INCOME (LOSS)	$	(119,266	)	$	(3,400,573	)	$	27,661,320	$	(8,892,054	)


NET INCOME (LOSS) PER SHARE:
Basic	$	(0.00	)	$	(0.07	)	$	0.46	$	(0.18	)
Diluted	$	(0.00	)	$	(0.07	)	$	0.45	$	(0.18	)
Weighted average common shares outstanding:
Basic		61,029,384			48,307,399			59,790,245		48,284,846
Diluted		61,029,384			48,307,399			61,108,977		48,284,846

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

AMERICAN OIL & GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Nine months ended
	September 30
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	27,661,320		$	(8,892,054	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Gain on sale of oil and gas assets		(36,400,000	)		—
Deferred income taxes		6,125,000			—
Depletion, depreciation and amortization		2,671,011			738,732
Share-based compensation expenses		808,977			823,130
Impairment of oil and gas properties		—			3,950,000
Impairment of well equipment inventory		200,356			565,991
Accretion of asset retirement obligations		16,849			30,057

Changes in assets and liabilities:
Decrease (increase) in receivables		(4,513,769	)		271,629
Decrease (increase) in prepaid expenses		18,967			87,080
Decrease (increase) in well equipment inventory		(283,765	)		(676,696	)
Increase (decrease) in accounts payable and accrued liabilities		999,936			45,057

Net cash used in operating activities		(2,695,118	)		(3,057,074	)


CASH FLOWS FROM INVESTING ACTIVITIES
Cash proceeds from sale of oil and gas properties		47,774,112			—
Cash paid for oil and gas property acquisition, exploration & development		(73,546,599	)		(9,728,311	)
Drilling prepayments		(269,020	)
Proceeds from redemptions and sales of short-term investments		1,200,000			2,600,000
Cash paid for office equipment		(42,997	)		(36,464	)
Cash paid for other long-term assets		(50,100	)		(50,100	)

Net cash used in investing activities		(24,934,604	)		(7,214,875	)


CASH FLOWS FROM FINANCING ACTIVITIES
Stock option exercises		716,650			—
Stock warrant exercise		87,500			—

Net cash provided by financing activities		804,150			—

NET DECREASE IN CASH		(26,825,572	)		(10,271,949	)
CASH, BEGINNING OF PERIODS		40,632,284			23,269,725

CASH, END OF PERIODS	$	13,806,712		$	12,997,776


SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	—
Cash paid for income taxes	$	—		$	130,000

SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Oil and gas properties acquired for stock	$	13,804,000		$	—
Exchange of oil and gas properties	$	—		$	420,000
Net increase in payables for capital expenditures	$	16,337,221		$	—
Net increase in receivables for capital expenditures	$	15,908,110		$	—

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

AMERICAN OIL & GAS INC.

Notes to Condensed Consolidated Financial Statements

(UNAUDITED)

September 30, 2010

NOTE 1 — COMPANY AND BUSINESS

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

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

NOTE 2 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

We have prepared the accompanying unaudited condensed balance sheet as of December 31, 2009 (which has been derived from audited financial statements) and the accompanying unaudited interim condensed financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosure normally included in financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and recommend that these condensed financial statements be read in conjunction with our audited financial statements and notes included in our amended Annual Report on Form 10-K for the year ended December 31, 2009.

References to GAAP issued by the Financial Accounting Standards Board (“FASB”) in these footnotes are to the FASB Accounting Standards Codification,^™ sometimes referred to as the Codification or ASC.

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

USE OF ESTIMATES — As further discussed on pages F-7 and F-8 of our amended Annual Report on Form 10-K for the year ended December 31, 2009, the preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

SIGNIFICANT ACCOUNTING POLICIES — For descriptions of the Company’s significant accounting policies, please see pages F-8 through F-11 of our amended Annual Report on Form 10-K for the year ended December 31, 2009.

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

Amortization of oil and gas property costs is computed quarterly and not year-to-date, using the estimated proved reserves as of the end of the calendar quarter. Amortization for the fiscal year is the sum of the four quarterly amortization amounts. Management estimated the proved reserves at September 30, 2010 and September 30, 2009, with consideration of (1) the proved reserve estimates for the prior fiscal year-end prepared by independent engineering consultants and (2) significant new discoveries and significant changes during the interim period in production, ownership, and other factors underlying reserve estimates.

RECENT ACCOUNTING PRONOUNCEMENTS — As of September 30, 2010, there have been no recent accounting pronouncements currently relevant to the Company in addition to those discussed on page F-12 of our amended Annual Report on Form 10-K for the year ended December 31, 2009.

GAS BALANCING — As of September 30, 2010 and December 31, 2009, our gas production was in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.

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

RECLASSIFICATION — Certain amounts in the 2009 consolidated financial statements have been reclassified to conform to the 2010 financial statement presentation. Such reclassifications have had no effect on net loss for the period in 2009.

ASSET RETIREMENT OBLIGATIONS — 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, 2010 and September 30, 2009:


	Three months ended						Nine months ended
	September 30,						September 30,
	2010			2009			2010			2009
Beginning asset retirement obligation	$	151,309		$	492,115		$	436,488		$	430,686
Liabilities incurred		73,791			142			125,009			53,509
Liabilities settled		—			(79,432	)		(341,709	)		(79,432	)
Revisions in estimated liabilities		(3,742	)		(10,830	)		(11,538	)		(22,988	)
Accretion		3,741			9,837			16,849			30,057

Ending asset retirement obligation	$	225,099		$	411,832			225,099		$	411,832

Current portion of obligation, end of period	$	—		$	—		$	—		$	—

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

NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at September 30, 2010 and December 31, 2009, consisted of the following:


	September 30,			December 31,
	2010			2009
Oil and gas properties, full cost method
Unevaluated costs, not yet subject to amortization	$	76,347,322		$	35,611,363
Evaluated costs		46,075,066			8,843,579

		122,422,388			44,454,942
Less accumulated amortization		(8,061,016	)		(5,510,016	)

Net carrying value of oil and gas properties		114,361,372			38,944,926
Cost of other property and equipment		449,270			406,273
Less accumulated depreciation and amortization		(321,541	)		(261,531	)

Net property and equipment	$	114,489,101		$	39,089,668

Our primary focus area is our Goliath Bakken and Three Forks focused project located in the Williston Basin, North Dakota where we control at September 30, 2010, approximately 85,000 net acres.

At September 30, 2010, we were evaluating the productive potential of another area located in the Rocky Mountain region that we call our Bigfoot project. This is a shallow natural gas project where we currently control approximately 213,000 gross (131,000 net) acres. We are primarily targeting a formation that is less that 2,000’ deep and have drilled test wells for less than $100,000 per well.

Sales of Oil & Gas Properties

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

On June 29, 2010, American sold to Chesapeake for $1,592,823 American’s remaining rights in oil and gas leases in those three counties after American was able to demonstrate having satisfactory title to the lease rights sold in June. The $1,592,823 in sales proceeds were received on July 7, 2010.

Under the full cost accounting method, we recognized at March 31, 2010 a $36,400,000 gain on the March 31^st sale, by allocating cost to the properties sold based on their relative total fair value to the estimated fair value of the full cost pool immediately preceding the sale. Under the full cost accounting method, gain on property sales is not recognized unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves of the cost center. Non-recognition of the $36,400,000 gain would have reduced the amortization base at March 31, 2010 to zero, significantly altering the relationship, whereby non-recognition was not allowed under full cost accounting. Since the properties sold were significantly different from the properties retained with regard to the nature and extent of proved reserves and property economics, then under the full cost accounting method, the sale’s gain at March 31, 2010 was based on allocating a portion of the US cost center’s capitalized costs to the properties sold based on the relative total fair value of the properties sold to the estimated total fair value of the US cost center’s properties immediately preceding the sale.

The gain on the sale of properties in June 2010 was not recognized because non-recognition would not significantly alter the relationship between capitalized costs and proved oil and gas reserves of the cost center.

Unevaluated Oil and Gas Properties

Our $76,347,322 of capitalized unevaluated costs at September 30, 2010, substantially consisted of (i) approximately $53 million for lease rights at our Goliath Project, (ii) nearly $15 million for wells-in-progress at our Goliath Project in North Dakota, (iii) approximately $4 million in Bigfoot undeveloped acreage and (iv) approximately $1 million in costs of wells drilled or in progress, but not yet evaluated at Bigfoot. Included in capital additions for the nine-month period ended September 30, 2010 were $0.7 million of internal land department and geologist costs directly associated with the acquisition, exploration and development of oil and gas properties.

‘Ceiling’ Impairment

We use the full-cost accounting method, which requires recognition of an impairment of oil and gas properties when the total capitalized costs (net of related deferred income taxes) exceed a “ceiling” as described on page F-9 of our amended Annual Report on Form 10-K as of December 31, 2009. We had no ceiling impairment for the nine-month period ended September 30, 2010, but we recognized a $3,950,000 impairment for the nine-month period ended September 30, 2009.

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


	Nine-month Period
	Ended September 30,
	2010		2009
Amortization of costs for evaluated oil and gas properties	$	2,551,000	$	546,000
Amortization of Intangible Asset		60,000		135,000
Depreciation of office equipment, furniture and software		60,011		57,732

Total DD&A expense	$	2,671,011	$	738,732

NOTE 4 — SIGNIFICANT CHANGES IN PROVED RESERVE ESTIMATES

Our proved reserves at September 30, 2010, were estimated internally by management. The estimates are significantly greater than at December 31, 2009, as shown in the following table:


	Oil (bbls)			Gas (mcf)
Proved reserves at December 31, 2009		147,510			956,550
Less proved reserves of properties sold 3/31/10		(22,957	)		(392,601	)
Less production for nine months ended 9/30/10		(119,374	)		(68,324	)
Proved reserve additions, nine months ended 9/30/10		1,815,264			2,891,687
Net revisions		155,733			(143,937	)

Proved reserves at September 30, 2010		1,976,176			3,243,375

Percentage net change in proved reserves		1,240	%		239	%

Proved reserve additions relate primarily to our interests in thirteen North Dakota wells and four proved undeveloped locations in our Goliath Project.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves increased from approximately $2.5 million at December 31, 2009, to approximately $38 million at September 30, 2010.

NOTE 5 — SHORT-TERM INVESTMENTS

Our short-term investments of $1,650,000 at September 30, 2010, and $2,925,000 at December 31, 2009, were comprised of auction-rate preferred shares (“ARPS”) issued by closed-end mutual funds. ARPS are a form of auction-rate securities (“ARS”) that were bought and sold at par value prior to March 2008 at special auctions held every 7 days or 28 days and paying variable-rate dividends, with the rate re-determined at the auctions. By March 2009, there were no parties willing to buy ARPS at par value at the auctions, i.e., the auction system collapsed. The ARPS are preferred shares with no maturity date and with no right for the holder to ‘put’ the securities to the ARPS issuer (the closed-end mutual fund) for redemption. Since March 2008, many issuers of ARPS have redeemed some or all of their ARPS at par value, and several large investment banks and brokerage firms (generally in settlement with customers or with government agencies) have bought back their customers’ ARPS at par value.

The ARPS’ total par value and carrying value (estimated fair value) since December 31, 2009, through September 30, 2010, are summarized in the following table:


				Carrying
	Par Value			Value
As of December 31, 2009	$	3,150,000		$	2,925,000
Increase in estimated fair value		n/a			25,000

As of March 31, 2010		3,150,000			2,950,000
Less redemption in May 2010		(1,200,000	)		(1,200,000	)
Decrease in estimated fair value at 9/30/10		n/a			(100,000	)

As of September 30, 2010	$	1,950,000		$	1,650,000

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 $150,000 to date) and for American’s legal costs in the arbitration and (iii) pay American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions. The arbitration hearing is scheduled to take place in June 2011.

We expect to have our ARPS entirely liquidated for cash before September 30, 2011. Absent full liquidation at par value, we expect to sell any remaining ARPS in the secondary market at expected losses (including significant transaction costs) approximating 10% to 20% of the par value of ARPS sold. We may receive an award in arbitration with Jefferies; however, we have no assurance that we will be successful in our claim against Jefferies.

The ARPS we own at September 30, 2010 are classified as short-term investments held for sale. Unrealized gains and temporary unrealized losses are recorded in Other Comprehensive Income (Loss). Unrealized losses that are “other-than-temporary” are reflected in the consolidated statement of operations. Unrealized gains resulting from increases in fair value are recorded in Other Comprehensive Income.

At September 30, 2010, the ARPS’ $1,950,000 total par value exceeded their $1,650,000 total carrying value (i.e., estimated fair value) by $300,000. The $300,000 net loss was recognized in 2008. Fair value, by definition, is before transaction costs in selling the ARPS (See Note 6).

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

NOTE 6 — FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted ASC 820 Fair Value Measurements and Disclosures for all financial assets and liabilities measured at fair value on a recurring basis. We chose not to elect the fair value option as prescribed by ASC 820 for financial assets and liabilities that had not been previously carried at fair value. Therefore, material financial assets and liabilities not carried at fair value, such as trade accounts receivable and accounts payable, are still reported at their face values.

ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes market or observable inputs as the preferred sources of fair values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement calls for disclosures grouping these financial assets and liabilities, based on the following levels of significant inputs to measuring fair value:

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

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

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

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2010 and December 31, 2009. The table shows the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values.


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

As of September 30, 2010
Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (“ARPS”)	$	1,650,000	$	—	$	—	$	1,650,000
Liabilities	$	—	$	—	$	—	$	—

Our claim against Jefferies (see Note 5) is not reflected in estimation as to the fair value of our ARPS, because fair value is based on what a third party would be willing to pay for the securities excluding any legal rights at September 30, 2010 that American may have against Jefferies.

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

The methodology for Level 3 valuation at September 30, 2010 was similar to that at December 31, 2009 described on page F-18 of our amended Annual Report on Form 10-K as of December 31, 2009.

NOTE 7 — INCOME TAXES

We account for income taxes under the provisions of 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.

At September 30, 2010, we expect to owe no alternative minimum tax for 2010 and we have reversed the $200,000 estimated alternative minimum tax recorded at March 31, 2010. For the nine-month period ended September 30, 2010, we recognized a $0 current tax provision and a $6,125,000 deferred income tax provision, net of a $7 million reversal of the deferred tax asset valuation allowance. We currently estimate that our effective income tax rate for the year ending December 31, 2010 will approximate 18% (and 39% excluding the effect of the reversal of the deferred tax asset valuation allowance).

We file annual US federal income tax returns and have filed annual income tax returns for the states of Colorado, Montana, North Dakota and Utah. We have done business in Wyoming, but Wyoming does not impose corporate income taxes. We believe that as of November 12, 2010, we are no longer subject to income tax examinations by tax authorities for years before 2006 for Colorado and before 2007 for federal, Montana, North Dakota and Utah income tax returns. Income taxing authorities have conducted no formal examinations of our past federal and state income tax returns and supporting records, except for an IRS examination for the year 2007. The IRS examination began in October 2010 and is still in process. We do not expect the examination to result in any assessments of taxes, penalties or interest.

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 as of September 30, 2010.

Our policy is to recognize 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, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2010.

NOTE 8 — EQUITY

Common Stock

The following transactions occurred during the nine-month period ended September 30, 2010 with regard to our common stock:

•

On January 26, 2010, we issued to each of our three independent directors 7,519 shares of common stock.

•

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

•

During the quarter ended March 31, 2010, a Director exercised his option, buying 12,500 shares of our common stock, at a $2.38 exercise price per share.

•

During the quarter ended March 31, 2010, our CFO exercised his option, buying 68,000 shares of our common stock, at an exercise price of $2.00 per share.

•

During the quarter ended March 31, 2010, four non-officer employees exercised options to purchase a total of 121,400 shares of our common stock, at an exercise price of $2.00 per share.

•

During the quarter ended June 30, 2010, three option holders exercised stock options, buying a total of 213,800 shares at a total exercise cost of $312,850.

•

During the quarter ended September 30, 2010, an independent contractor exercised his warrant to purchase 25,000 shares of our common stock at an exercise price of $3.50 per share.

•

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

•

For the quarter ended June 30, 2010, Additional Paid-In Capital increased by $258,914 for recognition of share-based compensation consisting of (i) $170,780 in share-based compensation related to stock options, and (ii) $88,134 related to accruals for granted stock vesting after grant.

•

For the quarter ended September 30, 2010, Additional Paid-In Capital increased by $234,565 for recognition of share-based compensation consisting of (i) $117,631 in share-based compensation related to stock options and warrants, and (ii) $116,934 related to accruals for granted stock vesting after grant.

•

On July 1, 2010, we issued and held in escrow a total of 110,000 restricted, unvested shares of common stock granted in April 2010 among all employees except for four employees who were either directors or owned more than 500,000 shares of Company common stock.

•

On July 1, 2010, we issued and held in escrow 80,000 restricted unvested shares of common stock granted on May 28, 2001 to a petroleum engineer hired to serve as our Completions and Production Manager for our Goliath Project.

•

Effective March 31, 2010 with the closing of the sale of certain Powder River Basin oil and gas properties, we increased Additional Paid-In Capital by $13,804,000 in recognition of the sale fulfilling all obligations of North Finn LLC for its right to receive 2,900,000 restricted shares of our common stock. In May 2010, North Finn LLC formally exercised its option and received the 2,900,000 shares.

Warrants

On April 6, 2010, we granted warrants to two consultants, each for 25,000 shares, vesting on April 6, 2011 (or upon an earlier change in control) and expiring on April 6, 2013, with an exercise price of $7.25 per share.

At December 31, 2009, we had one outstanding warrant to purchase our common shares. The warrant was issued April 16, 2008 and was to expire April 16, 2013. It was for 50,000 shares of our common stock at an exercise price of $3.50 per share. In February 2010, the warrant was re-issued as two warrants for 25,000 shares each, with the same exercise price per share and the same expiration date. One of those two warrants was fully exercised in September 2010, whereby only three of the four warrants were outstanding at September 30, 2010.

Stock Options

In the nine-month period ended September 30, 2010, we granted no stock options and none were forfeited or expired. As described above, several individuals exercised stock options to acquire a total of 415,700 shares of our common stock at a total exercise cost of $716,650.

Other Comprehensive Income

During the nine months ended September 30, 2010, Other Comprehensive Income was reduced (from $75,000) to $0 to reflect a change (net of related deferred income taxes) in the fair value of short-term investments.

NOTE 9 — EARNINGS PER SHARE

The following table summarizes the calculations of basic and diluted net income (loss) per common share for the three-month and nine-month periods ended September 30, 2010 and September 30, 2009:


	Three months ended						Nine months ended
	September 30						September 30
	2010			2009			2010		2009
Net income (loss)	$	(119,266	)	$	(3,400,573	)	$	27,661,320	$	(8,892,054	)
Adjustments for dilution		—			—			—		—

Net income (loss) adjusted for dilution effects	$	(119,266	)	$	(3,400,573	)	$	27,661,320	$	(8,892,054	)


Basic Weighted Average Common Shares		61,029,384			48,307,399			59,790,245		48,284,846
Add dilutive effects of options and warrants		—			—			1,318,732		—

Diluted Weighted Ave. Shares Outstanding		61,029,384			48,307,399			61,108,977		48,284,846


Net income (loss) per common share, basic	$	(0.00	)	$	(0.07	)	$	0.46	$	(0.18	)
Net income (loss) per common share, diluted	$	(0.00	)	$	(0.07	)	$	0.45	$	(0.18	)

NOTE 10 — PROPOSED MERGER OF AMERICAN INTO HESS SUBSIDIARY

Agreement and Plan of Merger

On July 27, 2010, American entered into an Agreement and Plan of Merger (the “Agreement”) with the Hess Corporation (“Hess”) and Hess Investment Corp., a wholly-owned subsidiary of Hess (“Merger Sub”). Pursuant to the terms of the Agreement, American will merge with Merger Sub, and upon consummation of the merger the separate corporate existence of Merger Sub shall cease, and American shall continue as the surviving corporation and a wholly-owned subsidiary of Hess (the “Merger”).

At the effective time of the Merger (the “Closing”), each share of American common stock will be converted into the right to receive 0.1373 shares of Hess common stock. Hess will not assume any stock options of American. Unvested stock options will become fully exercisable immediately prior to the Closing, and holders of such options may exercise their options or receive Hess shares as provided in the Agreement. In addition, each share of American restricted stock will become fully vested prior to the Closing and will have the same rights as each share of common stock not subject to any restrictions.

The Agreement provides for a possible cash dividend to American’s stockholders to the extent of American’s positive working capital as of the Closing Date, and subject to available cash. Working capital will be determined in accordance with GAAP as American’s current assets less current liabilities one business day prior to the Closing Date. Current liabilities also will include the American’s transaction expenses and the amount required to be paid to terminate American’s office lease that expires in May 2013 if determined or, if not determined, the present value of the remaining obligations under American’s office lease. Current assets also will include land acquisition costs paid by American after the date of the Merger Agreement with the prior consent of Hess that do not involve existing contracts or outstanding offers as of the date of the Merger Agreement, but will not include any cash or cash equivalents received by American in connection with the exercise of any stock options or warrants after the date of the Merger Agreement.

American, Hess and Merger Sub have made representations, warranties and covenants in the Agreement, including covenants by American to conduct its business in the ordinary course and not to engage in certain kinds of transactions and activities during the period between the execution of the Agreement and the consummation of the Merger. American also has made certain additional covenants, including, among others, covenants, subject to certain exceptions, (1) not to solicit proposals regarding alternative business combination transactions, (2) not to enter into discussions concerning, or provide confidential information in connection with, alternative business combination transactions, (3) not to approve or recommend any alternative business combination transaction proposals, (4) to cause a stockholder meeting to be held to consider approval of the Merger and (5) for its Board of Directors to recommend approval of the Agreement by American’s stockholders.

Each of the parties to the Agreement may terminate the Agreement upon the occurrence of several events. Among other things, the Agreement may be terminated if (1) American’s Board of Directors changes its recommendation to its common stockholders to approve the Merger, or authorizes or endorses an Alternative Transaction (as defined in the Agreement), (2) the Agreement is not adopted by the American’s stockholders, (3) the Merger is not completed by January 31, 2011 or (4) American directly or indirectly takes action to solicit an Alternative Transaction. Upon termination of the Agreement under specified circumstances, American will be required to pay Hess a termination fee of $13.5 million and reimburse expenses of Hess not to exceed $2.25 million. With certain exceptions, all costs and expenses incurred in connection with the Agreement will be paid by the party incurring such expenses, whether or not the Merger is consummated.

Completion of the Merger is conditioned upon, among other things, adoption of the Agreement by American’s common stockholders and the accuracy of representations and warranties (subject to materiality exceptions) as of the date of the Agreement and the Closing Date, and the performance by the parties in all material respects of their covenants under the Agreement.

In connection with the Merger, certain officers, directors and 5% beneficial owners who own an aggregate of approximately 20.5% of American’s common stock entered into voting agreements dated as of July 27, 2010 (the “Voting Agreement”). Each Voting Agreement provides that each holder will vote his shares in favor of the approval and adoption of the Merger Agreement and will not sell or transfer his shares. Each Voting Agreement terminates at the Closing of the Merger or if the Merger Agreement is terminated in accordance with its terms.

The Merger Agreement calls for American to use commercially reasonable efforts to sell American’s Bigfoot properties to one or more third parties at fair market value and otherwise on terms and conditions reasonably acceptable to Hess.

See Notes 14 and 15 for discussion of lawsuits filed against American with regard to the merger agreement.

NOTE 11 — HESS CREDIT FACILITY

In connection with the proposed Merger with Hess, Hess provided us with a senior secured short-term revolving credit facility of $30 million (which facility has been expanded to $45 million) to help finance our exploration and production activities and other working capital needs prior to closing of the Merger. We did not draw on the facility until October 1, 2010, when we received $10,000,000. We borrowed an additional $2 million on November 1, 2010, and have requested an additional $12 million to be funded on November 15, 2010. After the draw on November 15, 2010, we will have $24 million outstanding and $21million available on the $45 million credit facility. The current interest rate on the borrowings approximates 3.3% per annum, computed as 3% plus the reserve adjusted one-month LIBOR rate.

NOTE 12 — MATERIAL RELATED PARTY TRANSACTIONS

During August and September 2010, American sold to Hess 41,773 barrels of oil and 2,591 mcf of gas for which the total oil and gas revenues were $2,704,762.

NOTE 13 — ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE

Our $19,201,075 of accounts receivable at September 30, 2010, consisted of the following:

•

Approximately $15.3 million in receivables from other working interest owners for their share of capital expenditures and operating costs for wells and projects we operate,

•

Approximately $3.1 million in accrued oil and gas revenues, net of production taxes, at September 30, 2010 (including approximately $2.4 million due from Hess),

•

A$0.8 million receivable for remaining reimbursement of costs we had incurred on behalf of an unrelated oil and gas company, and less

•

An allowance for doubtful accounts of $15,011.

Our $18,369,405 of accounts payable and accrued liabilities at September 30, 2010, consisted of the following:

•

Approximately $10 million in invoiced trade payables, primarily for cost in drilling and completing wells in North Dakota, including costs reimbursable to us from other working interest owners in the wells we operate for various working interest owner groups, and

•

Approximately $8 million in accrued liabilities, primarily for uninvoiced costs incurred as of September 30, 2010 in the drilling and completion of wells in North Dakota.

In the Condensed Consolidated Statements of Cash Flows, the changes in accounts receivable and accounts payable for cash used in operating activities exclude changes in payables and receivables for capital expenditures.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

We 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 us to make future adjustments.

American has agreed to merge with Hess, subject to approval by a majority of American’s stockholders, as described in Note 10. American, the members of American’s board of directors and Hess are named as defendants in putative class action lawsuits brought by certain American stockholders challenging American’s proposed merger with Hess. The lawsuits were filed in state and federal courts in Colorado and in state court in Nevada. The lawsuits generally allege that the members of American’s board of directors, aided and abetted by American and Hess, breached their fiduciary duties to American’s stockholders by entering into the agreement and plan of merger for the sale of American to Hess for what plaintiffs claim to be inadequate consideration and pursuant to what plaintiffs claim to be an inadequate process. The lawsuits seek, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms or to rescind the merger to the extent already implemented.

At September 30, 2010, American had a commitment to purchase by December 31, 2010 for approximately $14.0 million (including sales tax) a variety of specific new casing and tubing to be delivered to American by December 31, 2010 for use in wells to be drilled and completed by American, as operator of those wells. The total fair value of the casing and tubing at September 30, 2010 slightly exceeded the future $14 million cost.

NOTE 15 — SUBSEQUENT EVENTS

As described in Part II, Item 1 of this Report, we entered into a Stipulation of Settlement with regards to certain litigation involving the merger with Hess.

IMPORTANT ADDITIONAL INFORMATION

Communications in this Form 10-Q do not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation of any vote or approval in respect of the proposed merger transaction involving Hess and American. In connection with the proposed transaction, Hess initially filed with the U.S. Securities and Exchange Commission (the “SEC”) on August 23, 2010 a registration statement on Form S-4 containing a preliminary proxy statement/prospectus, and Hess filed an Amendment No. 1 to the registration statement on Form S-4 on October 4, 2010. Each of Hess and American also plan to file other documents with the SEC regarding the proposed transaction. The proposed merger transaction involving Hess and American will be submitted to American’s stockholders for their consideration and a definitive proxy statement/prospectus will be mailed to American’s stockholders. INVESTORS AND SECURITY HOLDERS OF AMERICAN ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND OTHER DOCUMENTS REGARDING THE PROPOSED TRANSACTION THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY DO AND WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION.

Investors and stockholders will be able to obtain free copies of the proxy statement/prospectus and other documents containing important information about Hess and American, once such documents are filed with the SEC, through the website maintained by the SEC at http://www.sec.gov. Copies of the documents filed with the SEC by Hess will be available free of charge on Hess’ internet website at www.hess.com or by contacting Hess’ Corporate Secretary Department at 212-536-8602. Copies of the documents filed with the SEC by American will be available free of charge on American’s internet website at www.americanog.com or by contacting American’s Investor Relations Department at 303-449-1184.

Hess, American, their respective directors and executive officers and other persons may be deemed to be participants in the solicitation of proxies from the stockholders of American in connection with the proposed transaction. Information about the directors and executive officers of Hess is set forth in its proxy statement for its 2010 annual meeting of stockholders and in its annual report on Form 10-K, which were filed with the SEC on March 25, 2010 and February 26, 2010, respectively. Information about the directors and executive officers of American is set forth in its proxy statement for its 2010 annual meeting of stockholders and in its annual report on Form 10-K, as amended, which were filed with the SEC on May 14, 2010 and March 15, 2010 (as amended on March 29, 2010 and April 30, 2010), respectively. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available.

The information in this Form 10-Q shall not constitute an offer to sell or the solicitation of an offer to buy any securities, a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.


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

On March 31, 2010, we sold all of our oil and gas interests in the Fetter and Krejci projects located in the Power River Basin, Wyoming and received approximately $46.2 million in sales proceeds on March 31 and an additional $1.7 million in early July, 2010. As a result of the sale, our primary focus area is now our Goliath Bakken and Three Forks focused project located in Williams County, North Dakota.

We have operated or participated in the drilling of 22 gross (12.9 net) wells thus far in the Goliath project area in Williams County, North Dakota. We are currently operating a four-rig drilling program and including wells-in- progress, have operated the drilling of a total of 16 gross (11.2 net wells) at Goliath, and six gross (1.7 net) wells have been drilled or are in progress by other operators. We have also operated the drilling and completion of the currently producing Summerfield 15-15H well (approximate 35% working interest), located in Dunn County, North Dakota. Including the Summerfield well, we operate and own interests in five gross (3.05 net) currently producing wells.

The table below presents the current status of our operated oil and natural gas drilling, completion and production operations:


WELL NAME	LOCATION	STATUS

Summerfield 15-15H WI=35% NRI=28.4%	Sec. 15 T147N-R96W, Dunn County, ND	Commenced production in May 2010. IP rate of 2,799 barrels of oil equivalent (“BOE”). Average daily rate for initial 30, 60, 90, 120 and 150 days of 1,046, 812, 693, 608 and 547 BOE, respectively. Total cumulative production at 10-31-2010 (167 actual production days) of 86,668 BOE (71,113 bbls of oil and 76 mmcf of natural gas).

Tong Trust 1-20H WI=25.3% NRI=20.2%	Sec. 20 T157N-R96W, Williams County, ND	Commenced Production March 2010 at 1,421 BOE. Average daily rate for initial 30, 60, 90, 120 and 150 days of 652, 496, 401, 346 and 309 BOE, respectively. Total cumulative production at 11-5-2010 (173 actual production days) of 49,812 BOE (38,283 bbls of oil and 70 mmcf of natural gas).

Ron Viall 1-25H WI=94% NRI=75.2%	Sec. 25 T156N-R98W Williams County, ND	Commenced production May 2010. IP rate of 2,844 BOE. Average daily rate for initial 30, 60, 90 and 120 days of 987, 739, 628 and 561BOE, respectively. Total cumulative production at 11-5-2010 (144 actual production days) of 76,534 BOE (56,075 bbls of oil and 123 mmcf of natural gas).


WELL NAME	LOCATION	STATUS

Bergstrom 15-23H WI=95% NRI=76%	Sec. 23 T156N-R98W Williams County, ND	Commenced production August 2010. IP rate of 3,049 BOE. Average daily rate for initial 30 and 60 days of 1,061 and 860 BOE, respectively. Total cumulative production at 11-5-2010 (76 actual production days) of 58,875 BOE (45,861 bbls of oil and 78 mmcf of natural gas).

Johnson 15-35H WI=81.9% NRI=65.5%	Sec. 35 T156N-R98W Williams County, ND	Commenced production August 2010. Due to North Dakota Industrial Commission orders, production flow was choked back upon initial production due to excessive smoke from the flare. Average daily rate for initial 30 and 60 days of 806 and 711 BOE, respectively. Total cumulative production at 11-5-2010 (71 actual production days) of 47,348 BOE (36,188 bbls of oil and 67 mmcf of natural gas).

Hickel 15-35H WI=62.3% NRI=49.8%	Sec. 35 T157N-R97W Williams County, ND	Drilling operations concluded on July 27, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. Remedial work is underway to prepare this well for frac as frac crews are scheduled to commence completion in mid-November 2010. If this well is not ready for completion, frac crews may move to complete the Hodenfield 15-7H well.

Hodenfield 15-33H WI=57.4% NRI=45.9%	Sec. 33 T157N-R97W Williams County, ND	Drilling operations concluded on August 5, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. Fracture stimulation concluded on November 4, 2010. Temporary plugs are expected to be drilled out before November 15, 2010 and the well should commence production in mid-November 2010.

Hodenfield 15-7H WI=52.3% NRI=41.8%	Sec. 7 T157N-R97W Williams County, ND	Drilling operations concluded on August 14, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. Crews are expected to commence completion operations on or about November 15, 2010 and the well is expected to be placed on production prior to the end of November 2010.

Bergstrom 2-27H WI=72.9% NRI=58.3%	Sec. 27 T156N-R98W Williams County, ND	Drilling operations concluded on September 29, 2010. Completion assembly installed to facilitate a 27-stage hydraulic fracture stimulation completion. Crews are expected to commence completion operations immediately after completing the Hodenfield 15-7H well.

Olson 15-36H WI=68.2% NRI=54.5%	Sec. 36 T157N-R98W Williams County, ND	Drilling operations concluded on September 17, 2010. Completion assembly installed to facilitate a 32-stage hydraulic fracture stimulation completion. Frac crews are finalizing the completion to place the well on production.

Hodenfield 15-23H WI=55.3% NRI=44.2%	Sec. 23 T157N-R98W Williams County, ND	Drilling operations concluded on September 16, 2010. Completion assembly installed to facilitate a 30-stage hydraulic fracture stimulation completion. No completion date has been set.

Reid 3-3H WI=59.3% NRI=47.4%	Sec. 3 T157N-R97W Williams County, ND	Drilling operations concluded on October 17, 2010. Completion assembly installed to facilitate a 27-stage hydraulic fracture stimulation completion. No completion date has been set.


WELL NAME	LOCATION	STATUS

Bergstrom 2-28H WI=83.1% NRI=66.5%	Sec. 28 T156N-R98W Williams County, ND	Drilling operations also concluded on October 17, 2010. Completion assembly installed to facilitate a 22-stage hydraulic fracture stimulation completion. No completion date has been set.

Dustin Brose 2-29H WI=81.4% NRI=65.1%	Sec. 29 T156N-R98W Williams County, ND	Drilling operations concluded on November 7, 2010. Completion assembly installed to facilitate a 30-stage hydraulic fracture stimulation completion. No completion date has been set.

Twilight 1-24H WI=32.75% NRI=26.2%	Sec. 24 T156N-R99W Williams County, ND	Ensign drilling rig 24 commenced drilling on October 18, 2010 and is currently drilling in the lateral portion in the targeted Bakken formation.

Haug 14-19H WI=85.4% NRI=68.3%	Sec. 19 T156N-R98W Williams County, ND	Unit drilling rig 234 commenced drilling on October 23, 2010 and is currently drilling the vertical portion of the well.

Dahl 15-22H WI=64.5% NRI=51.6%	Sec. 22 T156N-R97W Williams County, ND	Ensign drilling rig 88 commenced drilling on October 25, 2010 and is currently cementing the 9-5/8 casing in the vertical portion of the well.

Foss Family Trust 15-23H WI=51.4% NRI=41.1%	Sec. 23 T156N-R97W Williams County, ND	Preparations are underway to move Nabors drilling rig 486 from the Dustin Brose well location. This well is expected to commence drilling during the third week of November 2010.

Results of Operations

The following discussion should be read in conjunction with the audited financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended September 30, 2010 Compared with the Quarter Ended September 30, 2009

For the quarter ended September 30, 2010, we recorded a net loss of $119,266 ($0.00 per share, basic and diluted), as compared to a net loss of $3,400,573 ($0.07 loss per common share, basic and diluted) for the quarter ended September 30, 2009. The $3,281,307 decrease in net loss is primarily due to (i) a $4.3 million increase in oil and gas revenues and (ii) $2.2 million in reductions of impairments of oil and gas properties and supplies inventory, less (iii) a $2 million increase in lease operating expenses and amortization expense and less (iv) approximately $1.2 million in general and administrative expenses directly related to investment banking and legal services with regard to the July 27, 2010 agreement to merge with Hess Corporation, subject to approval by American’s stockholders.

For the quarter ended September 30, 2010, we recorded total oil and gas revenues of $4,806,383 compared with $462,553 for the quarter ended September 30, 2009. The $4,343,830 increase from the 2009 quarter is attributable to a 1,400% increase in oil production and significantly higher oil and gas prices, partially offset by a decline in gas sales. Oil and gas sales and production costs and other components of income from operations are summarized in the following table:


	Three months ended
	September 30,
	2010			2009
Oil sold (barrels)		73,112			4,877
Average oil price	$	64.64		$	59.17

Oil revenue	$	4,725,598		$	288,567


Gas sold (mcf)		17,040			49,949
Average gas price	$	4.74		$	3.48

Gas revenue	$	80,785		$	173,986


Total oil and gas revenues	$	4,806,383		$	462,553
Less lease operating expenses		(912,493	)		(278,429	)
Less oil & gas amortization expense		(1,601,000	)		(212,001	)
Less accretion of asset retirement obligation		(3,741	)		(9,837	)
Less impairment of well equipment inventory		(26,571	)		(409,852	)
Less impairment of oil & gas properties		—			(1,850,000	)

Income (loss) from oil & gas operations		2,262,578			(2,297,566	)
Less depreciation of office facilities		(20,413	)		(19,416	)
Less amortization of other intangible asset		—			(45,000	)
Less general and administrative expenses		(2,804,686	)		(1,198,188	)

Income (loss) from operations	$	(562,521	)	$	(3,560,170	)


Total barrels of oil equivalent (“boe”) sold		75,952			13,202
Revenue per boe sold	$	63.28		$	35.04
Lease operating expense per boe sold	$	12.01		$	21.09
Amortization expense per boe sold	$	21.08		$	16.06

For the quarters ended September 30, 2010 and September 30, 2009, we incurred $2,804,686 and $1,198,188, respectively, in general and administrative expenses. Total costs increased approximately $1.6 million primarily due to (i) approximately $1.0 million paid for a third party fairness opinion in July 2010 of the then-proposed merger with Hess Corporation and (ii) a $0.5 million increase in legal fees and expenses, primarily relating to the merger, including the defense of lawsuits filed in connection with the merger.

The Nine-month Period ended September 30, 2010 Compared with the Nine-month Period ended September 30, 2009

For the nine months ended September 30, 2010, we recorded net income of $27,661,320 ($0.46 per share, basic and $0.45 per share, diluted), as compared to a net loss of $8,892,054 ($0.18 loss per common share, basic and diluted) for the nine months ended September 30, 2009. The $36.6 million increase in net income is primarily due to (i) a $36.4 million gain on the March 31, 2010 sale of most of our Wyoming oil and gas properties, plus (ii) a $2 million increase in oil and gas revenues, net of lease operating expenses and related oil and gas property amortization expense, plus (iii) approximately $4 million reduction in impairments of oil and gas properties and supplies inventories, less (iv)a $6.1 million increase in deferred income taxes.

For the nine months ended September 30, 2010, we recorded total oil and gas revenues of $8,083,918 compared with $1,285,705 for the nine months ended September 30, 2009. The $6,798,213 increase from the 2009 period is attributable to a 749% increase in oil production and significantly higher oil and gas prices, partially offset by a decline in gas sales. Oil and gas sales and production costs and other components of income from operations are summarized in the following table:


	Nine months ended
	September 30,
	2010			2009
Oil sold (barrels)		119,374			14,056
Average oil price	$	64.25		$	46.87

Oil revenue	$	7,669,920		$	658,759


Gas sold (mcf)		68,324			183,386
Average gas price	$	6.06		$	3.42

Gas revenue	$	413,998		$	626,946


Total oil and gas revenues	$	8,083,918		$	1,285,705
Less lease operating expenses		(1,777,764	)		(848,354	)
Less oil & gas amortization expense		(2,551,000	)		(546,000	)
Less accretion of asset retirement obligation		(16,849	)		(30,057	)
Less impairment of materials & supplies inventory		(200,356	)		(565,991	)
Less impairment of oil & gas properties		—			(3,950,000	)
Plus gain on sale of oil and gas properties		36,400,000			—

Producing revenues less direct expenses		39,937,949			(4,654,697	)
Less depreciation of office facilities		(60,011	)		(57,732	)
Less amortization of other intangible asset		(60,000	)		(135,000	)
Less general and administrative expenses		(6,168,688	)		(4,242,539	)

Income (loss) from operations		33,649,250		$	(9,089,968	)

Total barrels of oil equivalent (“boe”) sold		130,761			44,620
Revenue per boe sold	$	61.82		$	28.81
Lease operating expense per boe sold	$	13.60		$	19.01
Amortization expense per boe sold	$	19.51		$	12.24

For the nine months ended September 30, 2010 and September 30, 2009, we incurred $6,168,688 and $4,242,539, respectively, in general and administrative expenses. Total costs increased by $1,926,149, primarily due to (i) an approximately $1.1 million increase in investment banking and legal fees and expenses, primarily relating to the merger, including the defense of lawsuits filed in connection with the merger and (ii) an approximately $0.8 million increase in employee compensation.

Liquidity and Capital Resources

At September 30, 2010 and December 31, 2009, we had working capital of $17.9 million and $44.5 million, respectively. We had cash and cash equivalents at September 30, 2010 of $13.8 million.

For the calendar year ending December 31, 2010, including capital expenditures in the nine months ended September 30, 2010 of $73.6 million, we anticipate spending a total of approximately $129 million in capital expenditures, consisting primarily of (i) approximately $97 million drilling and completing North Dakota wells to the Bakken formation or Three Forks formation at our Goliath Project and (ii) approximately $32 million for North Dakota lease acquisitions and extensions. Including wells already drilled or drilled and completed, we expect our 2010 drilling program to consist of drilling 25 gross (14.5 net) wells. Due to the tightness of completion crews, we expect to be able to complete twelve gross (7.1 net) wells in 2010.

In connection with the proposed Merger with Hess, Hess had provided us with a senior secured short term revolving credit facility of $30 million to help finance our planned exploration and production activities and other working capital needs prior to closing of the Merger. As of November 11, 2010, the credit facility was expanded to $45 million. As of September 30, 2010, we had not borrowed on the facility. As of November 12, 2010 we had $12 million outstanding under the facility and have requested an additional $12 million to be funded on November 15, 2010. After the additional borrowing on November 15, 2010, we will have $24 million outstanding and $21million available on the $45 million credit facility. As of November 12, 2010, we had approximately $12.9 million in cash and cash equivalents.

As a result of our 2010 drilling program, we expect increased revenues from operations in 2010, compared to 2009, for the last three months of the year. We anticipate using (i) cash currently on hand, (ii) cash from operations, (iii) advance payments for drilling and completion costs from working interest partners and (iv) the $45 million credit facility from Hess Corporation to pay for capital expenditures in the fourth quarter of 2010.

If the merger is not complete by January 31, 2011, the merger will terminate pursuant to terms of the merger agreement. We expect to have adequate capital to continue our operations through January 31, 2011. If the merger term expires and the merger terminates, we are required to repay the borrowings under the Hess senior secured short term revolving credit facility within 90 days and we expect to need additional financing to repay these borrowings and for working capital. Such financing could come from sale of additional debt, equity and or the sale of assets. We have not solicited and have no commitments for financing, and the availability of financing is not assured. Any such financing may be on terms that are not advantageous to us. All of our assets serve as collateral for repayment of the borrowings from Hess.

The merger agreement with Hess provides for a possible cash dividend to American’s stockholders to the extent of American’s positive working capital as of the closing date, and subject to available cash (See Note 10 to our accompanying financial statements). We do not expect there will be positive working capital, as defined in the merger agreement, sufficient to pay a dividend.

For the nine-month periods ended September 30, 2010 and September 30, 2009, our sources and uses of cash were as follows:

Net Cash Provided (Used) By Operating Activities — Our net cash used by operating activities decreased by $361,956 (from $3,057,074 net cash used for operating activity for the nine-month period ended September 30, 2009 to $2,695,118 cash used by operations for the nine-month period ended September 30, 2010). Our cash received from oil and gas revenues in the 2010 period were approximately $2 million greater than for the 2009 period. Our cash expenditures for general and administrative expenses for the 2010 period were approximately $2 million greater than for the 2009 period. In the 2010 period, our net purchases of well equipment inventory held in third party yards were approximately $315,000 less than in the 2009 period.

Net Cash Provided (Used) In Investing Activities — During the nine-month period ended September 30, 2010, investing activities used a net $24.9 million in cash as compared with $7.2 million of cash used by investing activities in the nine-month period ended September 30, 2009. The $17.7 million increase in cash usage is primarily due to (i) our $63.8 million increase in acquisition, exploration and development of our oil and gas properties (primarily in our Goliath Project), less (ii) the $46.2 million received in March 2010 on the sale of oil and gas properties in the Powder River Basin in Wyoming.

Net Cash Provided By Financing Activities — During the nine-month periods ended September 30, 2010 and September 30, 2009, the only financing activities were $804,150 in cash received in the 2010 period relating to exercises of stock options and a warrant.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

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

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

Our operations are currently focused on drilling and completing wells in the Williston Basin of North Dakota. Because the Williston basin is one of the most actively drilled basins in the continental United States, production coming from the basin has been steadily increasing. Although there are plans and projects underway to expand the take-away capacity (the ability to transport oil out of the basin and to market) in the Williston Basin, we perceive that current take-away capacity has not been expanding at a rate necessary to continue to transport all of the oil production to market. We also perceive that production could expand beyond the take-away capacity in the very near future. Should this occur, the basis differential (the price producers receive for Williston basin oil production as compared to the higher West-Texas Intermediate price commonly used as the benchmark oil price) could greatly increase. Should the basis differential for Williston basin oil substantially increase, our oil revenue per barrel would decrease relative to the benchmark oil price, and the economic profile of our drilling program would be negatively affected.

Operating Cost Risk

During 2008, 2009 and 2010 to date, we have generally experienced fluctuations in operating costs (including costs of drilling and completing wells) which impact our cash flow from operating activities and profitability. Our drilling activity is focused on drilling oil wells with long laterals in the Bakken and/or Three Forks formations in North Dakota. The North Dakota Williston Basin is currently one of the most actively drilled basins in the continental United States. There are currently upwards of 150 drilling rigs in operation targeting the Bakken and Three Forks formations. We are experiencing increasing costs and difficulty in securing drilling and completion services. We are also experiencing significant increases in costs for these services.

Fluctuations in drilling, completion and production costs, as well as fluctuations in oil and gas prices can have a significant negative impact on our profitability and may negatively impact how many wells we will drill in the Goliath project.

Interest Rate Risk

We currently have limited exposure to interest rate risk. At September 30, 2010, we had no outstanding interest-bearing debt, but had a $30 million short-term credit facility from Hess (which facility has been expanded to $45 million) for which the interest rate is a function of the reserve adjusted one-month LIBOR rate. At September 30, 2010 we earn interest income on our cash and cash equivalents at short-term rates of less than 1% per annum. Short-term dividend rates on our $1,950,000 par value in Auction Rate Preferred Shares approximated 0.8% per annum and are at rates which vary with short-term commercial paper and US LIBOR rates.

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, 2010 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

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

PART II

OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Litigation Relating to the Merger

American, the members of American’s board of directors, Hess and Merger Sub are named as defendants in a number of putative class action lawsuits brought by certain American stockholders challenging American’s proposed merger with Hess. The lawsuits were filed in state and federal courts in Colorado and in state courts in Nevada. The lawsuits seek to certify a class of all American stockholders (excluding defendants and related or affiliated persons or entities), and generally allege that the members of American’s board of directors, aided and abetted by American and Hess, breached their fiduciary duties to American stockholders by entering into the agreement and plan of merger for the sale of American to Hess for allegedly inadequate consideration and pursuant to an allegedly inadequate process. In particular, the complaints variously allege that (i) the merger consideration is inadequate given American’s past and purported future economic performance as compared to Hess’ past and purported future economic performance, (ii) the director defendants will personally benefit from the vesting of illiquid or restricted stock options, (iii) the voting and lockup agreements, termination fee, and non-solicitation provision of the agreement and plan of merger improperly deter a superior, alternative offer from emerging, (iv) the agreement and plan of merger did not contain a “collar” or pricing adjustment provision tied to Hess’ trading price, and (v) American’s board of directors did not adequately explore alternative transactions. The lawsuits seek, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms or to rescind the merger to the extent already implemented.

The known cases filed to date include: (i) Edgar Cobb, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01833-PAB, filed in the United States District Court for the District of Colorado; (ii) Jeffrey P. Feinman, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01846-MSK, filed in the United States District Court for the District of Colorado; (iii) Morton Finkel, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01808-RPM, filed in the United States District Court for the District of Colorado; (iv) Jeffrey Veigel, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01852-MSK, filed in the United States District Court for the District of Colorado; (v) Ernest Cox Wilkerson, Herb D. Johnson and Virginia Park, On Behalf of Themselves and All Others Similarly Situated v. American Oil & Gas, et al., 2010-CV-6153, filed in the District Court of the State of Colorado For the City and County of Denver; (vi) James Thurston, Individually and on Behalf of All Others Similarly Situated v. Patrick D. O’Brien, et al, 2010CV6141, filed in the District Court of the State of Colorado For the City and County of Denver; (vii) Jeffrey Veigel, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01852-MSK, filed in the District Court of the State of Colorado For the City and County of Denver; (viii) Richard Buckman, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., Case No. 10 DC 00322, filed in the First Judicial District Court of the State of Nevada in and for Carson City; (ix) Ronald J. Kane, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., Case No. A-10-622644-B, filed in the Eighth Judicial District Court of the State of Nevada in and for Clark County; (x) Joseph Luvara, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., Case No. 10-DC-0032-1B, filed in the First Judicial District Court of the State of Nevada in and for Carson City; (xi) Roger Smitherman, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., Case No. CV-10-02434, filed in the Second Judicial District Court of the State of Nevada in and for County of Washoe; (xii) David Speight, Individually and on Behalf of All Others Similarly Situated v. Patrick D. O’Brien, et al., Case No. 10-DC-00340-1B, filed in the Second Judicial District Court of the State of Nevada in and for Carson City; (xiii) Michael Kunaman, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, Inc. et. al, Case No. 10-02484-B6, filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe; (xiv) Michael Kunaman, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, Inc. et al., Case No. 10 OC 00435-1B, filed in the First Judicial Court of the State of Nevada in and for the County of Carson City; (xv) Jorge Quiros, Individually and on Behalf of All Others Similarly Situated v. Andrew Calerich et. al., Case No. A-10-622573-C, filed in the Eighth Judicial District Court of the State of Nevada in and for Clark County and (xvi) Colin Trueman, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, Inc. et al., Case No. A-10-624248-C, filed in the Eighth Judicial District Court of the State of Nevada in and for Clark County.

On September 24, 2010, the Speight court entered an order dismissing the claims against American, Hess Investment Corporation, and Hess on grounds of forum non conveniens, and a motion to dismiss as to the Individual Directors is pending. The Kane action was voluntarily dismissed on September 9, 2010.

The Buckman, Luvara, Smitherman, Quiros, and Trueman actions were removed by Defendants to Nevada federal court, and the parties are contesting whether the cases should be transferred to federal court in Colorado or remanded back to Nevada state court.

In the Cobb, Veigel, Finkel, and Feinman actions, the parties held discovery conferences before Magistrate Judge Kathleen Tafoya, who approved an expedited discovery stipulation. Document and deposition discovery has begun. On October 5, 2010, the Colorado federal court (the “Court”) consolidated the Cobb, Veigel, Finkel, and Feinman actions under the caption Finkel v. American Oil & Gas, Inc., No. 10-cv-1808-CMA-MEH (the “Consolidated Colorado Federal Action”), and a consolidated complaint was filed by the plaintiffs on October 29, 2010. The Cobb Action was dismissed without prejudice. On October 15, 2010, plaintiffs in the Consolidated Colorado Federal Action filed a Motion for Preliminary Injunction seeking to enjoin the proposed merger.

Settlement of Litigation Relating to the Merger

On November 12, 2010, plaintiffs in the Consolidated Colorado Federal Action, and the Buckman, Luvara, and Kunaman actions pending in federal and state court in Nevada, on behalf of themselves and the Settlement Class, entered into the Stipulation of Settlement with the defendants to fully and finally resolve the Settlement Class members’ claims challenging the proposed merger.

Pursuant to the Stipulation of Settlement, and in exchange for the releases by the plaintiffs and the Settlement Class described below, Hess and American have included plaintiffs’ counsel in the disclosure process, and Hess and American are to make certain supplemental disclosures in the forthcoming amendment to Hess’s Form S-4 filing with the SEC and in the forthcoming proxy statement to American’s stockholders. The supplemental disclosures address issues identified by plaintiffs. As part of the negotiated settlement, defendants agreed not to object to an attorneys’ fees application by plaintiffs’ counsel up to $200,000. Defendants also agreed to pay plaintiffs’ attorneys’ fees and expenses in an amount awarded by the Court not to exceed $850,000.

Pursuant to the Stipulation of Settlement, the Settlement Class will release all the defendants from any and all claims relating to, among other things, the merger, the agreement and plan of merger and any disclosures made in connection therewith. The Consolidated Colorado Federal Action will be also dismissed with prejudice on the merits by the Court upon final approval of the settlement. The Stipulation of Settlement is subject to customary conditions, including the consummation of the merger, class certification of the Settlement Class, and final approval by the Court, following notice to the stockholders of American.

The settlement will not affect the form or amount of consideration to be received by American stockholders in the merger.

The defendants have denied and continue to deny any wrongdoing or liability with respect to all claims, events and transactions complained of in the aforementioned litigations or that they have engaged in any wrongdoing. The defendants have entered into the Stipulation of Settlement to (i) eliminate the burden and expense of further litigation, (ii) put the released claims to rest, finally and forever, without in any way acknowledging wrongdoing, fault, liability, or damage to the Settlement Class, and (iii) permit the proposed merger to close without risk of injunctive or other relief.

The foregoing description is a summary of material terms of the Stipulation of Settlement, a copy of which has been attached as an exhibit.

American’s Arbitration Claim Against Jefferies

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 $150,000 to date) and for American’s legal costs in the arbitration and (iii) pay American approximately $1 million in interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions. The arbitration hearing is scheduled currently to take place in June 2011.

Item 6. EXHIBITS


Exhibit No.			Description

	2.1		Credit Agreement dated as of August 27, 2010 between American Oil & Gas Inc. and Hess Corporation (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on August 30, 2010)
	2.2		Security Agreement dated as of August 27, 2010 and entered into by and among American Oil & Gas Inc. and each Additional Grantor and the Hess Corporation (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on August 30, 2010)
	2.3		Form of Mortgage, Security Agreement, Financing Statement and Assignment of Production from American Oil & Gas Inc. to Hess Corporation, dated effective as of August 27, 2010 (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on August 30, 2010)
	2.4		Form of Loan Notice, Note, Form of Compliance Certificate and Solvency Certificate (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on August 30, 2010)
	2.5		Amendment (dated as of November 11, 2010) to the Credit Agreement dated as of August 27, 2010 between American Oil & Gas Inc. and Hess Corporation
	10	(i)	Agreement and Plan of Merger dated as of July 27, 2010 among Hess Corporation, Hess Investment Corp. and American Oil & Gas Inc. (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on July 29, 2010)
	10	(ii)	Stipulation and Agreement of Settlement and Release (November 2010)
	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’Brien	Chief Executive Officer and Chairman of The Board of Directors	November 12, 2010
Patrick D. O’Brien

/s/ Joseph B. Feiten	Chief Financial Officer	November 12, 2010
Joseph B. Feiten	(principal financial officer and principal accounting officer)

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AMERICAN OIL & GAS INC 10-Q