HESS BAKKEN INVESTMENTS I (AEZ) 10-Q/A 2006 Q2 Quarterly report (amended)

United States Securities And Exchange Commission

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

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

For the quarterly period ended June 30, 2006

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 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 filero                      Non-accelerated filerþ

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 August 11, 2006 was 36,838,659.

EXPLANATORY NOTE

     In response to a Comment Letter received from the SEC Division of Corporation Finance and to subsequent management review of the Company’s 2005 financial statements previously filed, we are filing this Quarterly Report on Form 10-Q/A as an amendment to our Quarterly Report on Form 10-Q for the three and six- month periods ended June 30, 2006, originally filed on August 11, 2006 (the “Original 10-Q”).

     As further explained in Note 1 to these financial statements, this amendment reflects changes to our unaudited financials statements for the three and six month periods ended June 30, 2006 and June 30, 2005. Most notably, this amendment reflects the effects on our unaudited financial statements for the three and six-month periods ended June 30, 2006 and June 30 2005 resulting from the April 2, 2007 restatement of our 2005 audited financial statements to record the April 2005 merger of Tower Colombia Corporation as a purchase at fair values (rather than as a merger of entities under common control recorded at carry-over basis). These financial statements also include a change to the Consolidated Statement of Cash Flows for the six-month period ending June 30, 2006 to reflect the payment of preferred dividends with common stock as a non-cash financing activity.

     For the financial statements for the three and six-month periods ended June 30, 2006, the correction of accounting for the TCC Merger in April 2005 decreased net income by $125,000 and $158,000, respectively, and increased total assets by $15.9 million and total equity by $14.3 million at June 30, 2006, primarily due to recognition of $11.7 million in goodwill.

     For the financial statements for both the three and six-month periods ended June 30, 2005, the correction of accounting for the TCC Merger in April 2005 decreased net income by $44,000.

     This amendment also reflects our changes to Management’s Discussion and Analysis of Financial Condition and Results of Operation (in Item 2 of Part I) in light of the aforementioned changes to the unaudited financial statements.

     Other than the April 2, 2007 filing of Form 10-KSB/A for the year ended December, 31, 2005, this amendment does not reflect events occurring after the filing of the Original 10-Q and does not modify or update the disclosures therein in any way other than as required to reflect the changes described above. Accordingly, this Amendment should be read in conjunction with the registrants’ filings with the SEC subsequent to the filing of the Original 10-Q.

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

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	4
Consolidated Balance Sheets – June 30, 2006 and December 31, 2005	4
Consolidated Statements of Income — Three and Six Months Ended June 30, 2006 and 2005	5
Consolidated Statements of Cash Flows – Six Months Ended June 30, 2006 and 2005	6
Consolidated Notes to Financial Statements	7
Summary of Significant Accounting Policies	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3. Quantitative and Qualitative Disclosure about Market Risk	24
Item 4. Controls and Procedures	24
PART II. OTHER INFORMATION
Item 1A. Risk Factors	25
Item 6. Exhibits	25
Signatures	25
Exhibit 31.1 Certification
Exhibit 31.2 Certification
Exhibit 32.1 Certification
Exhibit 32.2 Certification

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PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31,
	(UNAUDITED)			2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents (Note 1)	$	13,043,189		$	6,022,822
Short-term investments (Note 5)		4,280,000			—
Trade receivables		698,492			1,481,543
Receivable for sale of oil and gas properties		3,699,312			—
Inventory		40,904			40,904
Advances and prepaid expenses		247,606			156,475
Total Current Assets		22,009,503			7,701,744
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $20,369,282 at 6/30/06 and $17,843,133 at 12/31/05)		23,557,874			26,547,922
Other property and equipment		187,135			68,023
Total property and equipment		23,745,009			26,615,945
Less accumulated depreciation, depletion and amortization		(2,255,402	)		(1,636,246	)
Net property and equipment		21,489,607			24,979,699
OTHER ASSETS
Goodwill		11,670,468			11,670,468
Investment in Equity Securities (Note 5)		1,610,000			—
Other intangible assets		690,000			780,000
Drilling prepayments and other		20,043			643,485
	$	57,489,621		$	45,775,396
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	395,240		$	954,544
Deferred income taxes		1,249,680			—
Preferred dividends payable		474,903			479,342
Total current liabilities		2,119,823			1,433,886
LONG TERM LIABILITIES
Asset retirement obligations		112,267			117,011
Deferred income taxes		5,174,038			1,893,581
COMMITMENTS AND CONTINGENCIES (Note 9)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value, authorized 400,000 shares Issued and outstanding – 250,000 shares at 6/30/06 and 12/31/2005. Redemption value of $13,974,903 at 6/30/06; $13,979,342 at 12/31/05		250			250
Common stock, $.001 par value, authorized 100,000,000 shares; Issued and outstanding – 36,724,209 shares at 6/30/06, 36,476,202 at 12/31/05		36,724			36,476
Additional paid-in capital		44,853,426			43,225,408
Deferred compensation		(71,820	)		—
Retained earnings/(accumulated deficit)		3,234,593			(931,216	)
Accumulated other comprehensive income		2,030,320			—
		50,083,493			42,330,918
	$	57,489,621		$	45,775,396

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

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AMERICAN OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three months ended					Six months ended
	June 30,					June 30,
	2006			2005		2006			2005
REVENUES
Oil and gas sales	$	259,033		$	1,239,042	$	1,829,885		$	1,925,769
Service fee		1,530,000			—		1,530,000			—
		1,789,033			1,239,042		3,359,885			1,925,769
OPERATING EXPENSES
Lease operating		64,602			57,400		165,793			94,503
General and administrative		758,749			665,303		1,831,319			1,132,010
Depletion, depreciation and amortization		144,292			417,507		709,156			560,971
Accretion of asset retirement obligation		808			1,062		1,787			2,087
		968,451			1,141,272		2,708,055			1,789,571
INCOME FROM OPERATIONS		820,582			97,770		651,830			136,198
OTHER INCOME
Gain on sale of oil and gas properties (Note 4)		2,897,616			—		7,159,470			—
Investment income		137,929			17,642		170,527			40,876
		3,035,545			17,642		7,329,997			40,876
INCOME BEFORE INCOME TAXES		3,856,127			115,412		7,981,827			177,074
Income tax expense (reduction)-deferred		1,624,412			—		3,280,457			—
NET INCOME		2,231,715			115,412		4,701,370			177,074
Less dividends on preferred stock		(269,260	)		—		(535,561	)		—
NET INCOME TO COMMON STOCKHOLDERS	$	1,962,455		$	115,412	$	4,165,809		$	177,074
NET INCOME PER COMMON SHARE -BASIC	$	0.05		$	0.00	$	0.11		$	0.01
NET INCOME PER COMMON SHARE - - DILUTED	$	0.05		$	0.00	$	0.11		$	0.01
Basic Weighted Average Common Shares Outstanding		36,687,937			34,437,740		36,654,267			32,171,810
Diluted Weighted Ave. Common Shares Outstanding		37,270,724			34,942,411		37,237,054			32,613,195

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

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AMERICAN OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six months ended June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	4,701,370		$	177,074
Adjustments to reconcile net income to net cash provided by operating activities
Gain on sale of oil & gas properties		(7,159,470	)		—
Deferred income taxes		3,280,457			—
Depletion, depreciation and amortization		709,156			560,971
Share-based compensation		885,467			143,883
Deferred compensation		35,910			141,250
Accretion of asset retirement obligati		1,787			2,087
Changes in current assets and liabilities, net of effects of property acquisitions and divestitures:
Decrease (increase) in receivables		783,051			(866,554	)
(Increase) in short-term investments, net of unrealized gains		(1,000,000	)		—
Decrease in advances and prepaid expenses		(91,131	)		22,406
Increase in accounts payable and accrued liabilities		310,066			838,877
Net cash provided by operating activities		2,456,663			1,019,994
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and gas properties		14,224,712			—
Cash paid to acquire oil and gas properties		(8,016,965	)		(3,606,770	)
Cash paid for office equipment and office lease improvements		(119,112	)		(1,371	)
Investment in Equity Securities (Note 5)		(1,610,000	)		—
Cash paid for drilling bond deposit		(10,000	)		—
Net cash (used) provided by investing activities		4,468,635			(3,608,141	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from exercise of common stock warrants		95,069			152,600
Preferred dividends paid in cash					(18,864	)
Cash received from acquired company		—			1,795
Net cash provided by financing activities		95,069			135,531
NET (DECREASE) INCREASE IN CASH		7,020,367			(2,452,616	)
CASH, BEGINNING OF PERIODS		6,022,822			5,251,889
CASH, END OF PERIODS	$	13,043,189		$	2,799,273
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	—
Cash paid for income taxes	$	170,000		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING ACTIVITIES
Property sales proceeds in the form of a receivable	$	3,699,312		$	—
Preferred dividends paid in shares of common stock	$	540,000		$	—
Stock issued for acquired company	$	—		$	656,833
Stock and share based compensation	$	885,467		$	306,205

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

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AMERICAN OIL & GAS, INC.

Notes to Consolidated Financial Statements

(UNAUDITED)
June 30, 2006

     The accompanying interim financial statements of American Oil & Gas, Inc. are unaudited. The terms “Company”, “American”, “we”, “us”, “our” and terms of similar import refer to American Oil & Gas, Inc. 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 period ended June 30, 2006 are not necessarily indicative of the operating results for the entire year.

     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-KSB/A for the year ended December 31, 2005.

Nature of Business

     We are an independent energy company engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States.

     Our fiscal year end is December 31.

Note 1 – Restatement and Significant Accounting Policies

Restatement (dated as of April 11, 2007)

     We originally recorded the April 2005 Tower Colombia Corporation (“TCC”) merger as a roll-up of two oil and gas companies under common control, whereby the acquired TCC assets and liabilities were recorded at predecessor basis. In a review of the Company’s Form 10-KSB for the year ended December 31, 2005, the SEC staff questioned the appropriateness of accounting for the TCC merger at predecessor basis, rather than as a business combination for which TCC assets and liabilities would be recorded at fair values. Following further discussion with the SEC staff, we filed on April 2, 2007 Amendment No. 1 to our Annual Report on Form 10-KSB/A for 2005, restating our financial statements for the year ended December 31, 2005 to account for the TCC merger as a business combination for which assets and liabilities would be recorded at fair values.

     We later filed on April 2, 2007 our Annual Report on Form 10-K for the year ended December 31, 2006 (“2006 Form 10-K”) in which our financial statements for 2006 and 2005 reflect the effects of the 2005 restatement in the 2005 Form 10-KSB/A.

     The following two tables summarize the effect of the restatement on the Company’s Balance Sheet as of June 30, 2006 and its Statement of Operations for the six-month period ended June 30, 2006. In the tables, certain amounts previously reported have been reclassified to conform to the restated presentation. Such reclassifications have no effect on net income previously reported.

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Table 1: Summary of Our Consolidated Balance Sheet at June 30, 2006, as Previously Reported and as Restated

	As Previously			Adjustments						As
	Reported			TCC related			Other			Restated
ASSETS
Current Assets	$	22,019,546		$	—		$	(10,043	)	$	22,009,503
Property and Equipment at Cost:
Oil and gas properties, evaluated		2,913,076			275,516			—			3,188,592
Oil and gas properties, unevaluated		16,879,763			3,489,519			—			20,369,282
Oil and gas properties, total cost		19,792,839			3,765,035			—			23,557,874
Other property and equipment		187,135			—			—			187,135
Total property and equipment		19,979,974			3,765,035			—			23,745,009
Less accumulated depreciation, depletion, and amortization		(2,102,402	)		(153,000	)		—			(2,255,402	)
Net property and equipment		17,877,572			3,612,035			—			21,489,607
Investment in equity securities		1,610,000			—			—			1,610,000
Goodwill		—			11,670,468			—			11,670,468
Other intangible assets		—			690,000			—			690,000
Drilling prepayments and other		10,000			—			10,043			20,043
Total assets	$	41,517,118		$	15,972,503		$	—		$	57,489,621
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	2,416,186		$	—		$	(296,363	)	$	2,119,823
Asset retirement obligations		112,267			—			—			112,267
Deferred income taxes		3,237,094			1,640,581			296,363			5,174,038
Stockholders’ Equity:
Preferred stock		250			—			—			250
Common stock		36,724			—			—			36,724
Additional paid-in capital		30,233,755			14,539,167			80,504			44,853,426
Deferred compensation		(71,820	)		—			—			(71,820	)
Retained earnings		3,522,342			(207,245	)		(80,504	)		3,234,593
Other comprehensive income		2,030,320			—			—			2,030,320
Total equity		35,751,571			14,331,922			—			50,083,493
	$	41,517,118		$	15,972,503		$	—		$	57,489,621

Table 2: Summary of Our Statement of Operations for the six-month period ended June 30, 2006, as Previously Reported and as Restated

	As Previously		Adjustments					As
	Reported		TCC related			Other		Restated
Revenue	$	3,359,885	$	—		$	—	$	3,359,885
Lease operating expenses		165,793		—			—		165,793
General and administrative expenses		1,831,319		—			—		1,831,319
Depreciation, depletion and amortization		506,156		203,000			—		709,156
Accretion of asset retirement obligation		1,787		—			—		1,787
Total operating expenses		2,505,055		203,000			—		2,708,055
(Loss) Income from operations		854,830		(203,000	)		—		651,830
Gain on sale of oil and gas properties		7,210,470		(51,000	)		—		7,159,470
Investment income		170,527		—			—		170,527
Income before income taxes		8,235,827		(254,000	)		—		7,981,827
Income tax provision		3,376,457		(96,000	)		—		3,280,457
Net income		4,859,370		(158,000	)		—		4,701,370

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	As Previously		Adjustments					As
	Reported		TCC related			Other		Restated
Dividends on preferred stock		535,561		—			—		535,561
Net income attributable to common stockholders	$	4,323,809	$	(158,000	)	$	—	$	4,165,809
Net income per common share, basic and diluted	$	0.12	$	(0.01	)	$	—	$	0.11

     The Other Adjustments shown in Tables 1 and 2 are for the following:

1. Reclassification of the $296,363 current deferred income taxes as long-term deferred income taxes, because the associated timing differences relate to oil and gas properties, which are long-term assets,

2. Reclassification from Current Assets to Long-Term Assets $10,043 in drilling prepayments, which are to be applied in drilling oil and gas wells, which are long-term assets, and

3. Reclassification from Additional Paid-In Capital to Retained Earnings $80,504 in preferred stock dividend payments made prior to 2006.

Significant Accounting Policies

     USE OF ESTIMATES- 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.

     CASH EQUIVALENTS- For purposes of reporting cash flows, we consider as cash equivalents all highly liquid investments with a maturity of three months or less at the time of purchase. At June 30, 2006, there were no cash equivalents. At June 30, 2006, $693,450 of our cash balance is designated to the drilling, completion and connection of oil and gas wells in our Krejci oil project located in Niobrara County, Wyoming.

     SHORT-TERM INVESTMENTS –Short- term investments consist of (i) readily marketable securities expected to be sold within one year and (ii) unregistered securities expected to be readily marketable and sold within one year. Short-term investments are carried at fair value. For investments bought and held principally to sell short-term, changes in fair value are reflected in current income. For other short-term investments, referred to as “available-for-sale,” changes in fair value are reflected, net of related deferred income taxes, in Other Comprehensive Income in the Equity section of the Balance Sheet. If an available-for-sale investment has a net unrealized loss that is considered permanent, such loss is recognized in the current income statement.

     OIL AND GAS PROPERTIES —We follow the full cost method of accounting for oil and gas operations. Under this method, all costs related to the exploration for, and development of, oil and gas reserves are capitalized on a country-by-country basis. Costs include lease acquisition costs, geological and geophysical expenses, overhead directly related to exploration and development activities and costs of drilling both productive and non-productive wells. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being recognized, unless such application of sales proceeds would significantly alter the cost amortization rate.

     As discussed in Note 4, on March 31, 2006 we sold a property having approximately 88% of our proved reserves and recorded a gain on the sale of $4.26 million ($2.57 million, net of tax). As is consistent for full cost accounting companies, the related revenues and expenses associated with the property sold has been reflected as continuing operations.

     DEPLETION, DEPRECIATION AND AMORTIZATION –Capitalized costs of oil and gas properties evaluated as having, or not having, proved reserves are amortized in the aggregate by country using the unit-of-production method based upon estimated proved oil and gas reserves. The costs of properties not yet evaluated are not amortized until evaluation of the property. For amortization purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. For interim financial reporting during a fiscal year, amortization is on the year-to-date basis.

     CEILING TEST- Capitalized costs of oil and gas properties may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unevaluated properties. Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by

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applying period-end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Should this comparison indicate an excess carrying value, the excess is charged to earnings.

     REVENUE RECOGNITION AND GAS BALANCING- We recognize oil and gas revenues from our interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. We use the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of June 30, 2006 and 2005, our gas production were 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.

     IMPAIRMENT –We have adopted SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” which requires that long-lived assets which are held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas properties accounted for using the full cost method of accounting, a method utilized by us, are excluded from this requirement, but will continue to be subject to the ceiling test limitations.

     GOODWILL— We account for goodwill in accordance with SFAS 142,Goodwill and Other Intangible Assets. SFAS 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The impairment assessment requires us to make estimates regarding the fair value of the reporting unit to which goodwill is assigned. If the fair value of the reporting unit exceeds its carrying value (including the carrying value of its assigned goodwill), then under SFAS 142 no impairment of goodwill exists.

     We have only one business segment, oil and gas exploration and production. Within that segment we have only one reporting unit. Accordingly, the fair value of our one reporting unit generally approximates the fair value of our company’s stock. Since recording goodwill in April 2005 through June 30, 2006, the fair value of the Company’s outstanding preferred and common stock has substantially exceeded the carrying value (i.e., book value) of stockholders’ equity for the Company, and no impairment of recorded goodwill existed in 2005 or 2006 under the accounting rules of SFAS 142.

     OTHER INTANGIBLE ASSETS— Intangible assets, other than Goodwill, are amortized over their expected useful lives.

     SHARE BASED COMPENSATION —As of January 1, 2006, we adopted SFAS No. 123(R) “Share-Based Payment” as discussed in Note 2.

     INCOME TAXES– In accordance with SFAS No. 109, “Accounting for Income Taxes,” we recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. 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.

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     ASSET RETIREMENT OBLIGATION- In 2001, the FASB issued SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset’s carrying amount. Over time, accretion of the liability is recognized as an operating expense, and the capitalized cost is amortized over the expected useful life of the related asset. Our asset retirement obligations (“ARO”) relate primarily to well plugging, equipment dismantlement and removal, site reclamation and similar activities of our oil and gas properties.

     We have adopted the provisions of SFAS 143 to record the ARO associated with each well in which we own an interest on the date such obligation arose. Accretion of the ARO on wells from which production has commenced has been calculated using the estimated life of the wells based on a reserve study prepared by an independent reserve engineering firm. The amounts recognized upon adoption are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate. The table below provides reconciliations of our asset retirement obligation liability:

	Three months ended				Six months ended
	June 30,				June 30,
	2006		2005		2006			2005
Beginning asset retirement obligation	$	110,245	$	42,461	$	117,011		$	40,702
Liabilities incurred		1,212		902		1,212			1,636
Reduction in liability from sold properties		—		—		(7,745	)		—
Accretion		810		1,062		1,789			2,087
Ending asset retirement obligation	$	112,267	$	44,425	$	112,267		$	44,425

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

     The following table summarizes the calculations of basic and diluted earnings per share:

	Three months ended				Six months ended
	June 30,				June 30,
	2006		2005		2006		2005
Net income to common stock holders	$	1,962,455	$	115,412	$	4,165,809	$	177,074
Adjustments for dilution		—		—		—		—
Net income adjusted for effects of dilution	$	1,962,455	$	115,412	$	4,165,809	$	177,074
Basic Weighted Ave. Common Shares Outstanding		36,687,937		34,437,740		36,654,267		32,171,810
Add dilutive effects of options and warrants		582,787		504,671		582,787		441,385
Add dilutive effects of convertible preferred stock		—		—		—		—
Diluted Weighted Ave. Common Shares Outstanding		37,270,724		34,942,411		37,237,054		32,613,195
Net income per common share — basic	$	0.05	$	0.00	$	0.11	$	0.01
Net income per common share — diluted	$	0.05	$	0.00	$	0.11	$	0.01

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RECENT ACCOUNTING PRONOUNCEMENTS

     In December 2004, the FASB issued SFAS 123(R), “Share-Based Payment,” (“SFAS 123(R)”) which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS 123(R) is effective for public companies for annual periods beginning after December 15, 2005, supersedes APB Opinion 25, Accounting for Stock Issued to Employees, and amends SFAS 95, Statement of Cash Flows. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. We have adopted SFAS 123(R) as of January 1, 2006 as discussed in Note 2.

     In February 2006, the FASB issued SFAS 155, “Accounting for Certain Hybrid Financial Instruments,” which eliminates the exemption from applying SFAS 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the instrument’s form. SFAS 155 allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event. Adoption is required for all financial instruments acquired or issued by the Company after 2006. Early adoption is permitted. The adoption of SFAS 155 is not expected to have a material effect on our financial statements for 2006.

     In March 2006, the FASB issued SFAS 156, “Accounting for Servicing of Financial Assets,” which requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities to be initially measured at fair value. Adoption is required as of January 1, 2007. Early adoption is permitted. The adoption of SFAS 156 is not expected to have a material effect on our financial statements for 2006.

     In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). It will be effective for the Company on January 1, 2007. FIN 48 clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on measurement, classification, interim accounting and disclosure. We have not yet determined FIN 48’s potential impact on our consolidated financial statements.

Note 2 – Stock Options and Share-Based Compensation

     Under our 2004 Stock Option Plan (the “Plan”), stock options may be granted at an exercise price not less than the fair market value of our common stock at the date of grant. Options may be granted to key employees and other persons who contribute to our success. We have reserved 2,500,000 shares of common stock for the plan. At June 30, 2006, options to purchase 531,990 shares were available to be granted pursuant to the Plan.

  Adoption of SFAS 123(R)

     Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standard 123(R) “Share-Based Payment”(“SFAS 123(R)”) using the modified prospective transition method. In applying SFAS 123(R), we considered the SEC Staff Accounting Bulletin No. 107 “Share-Based Payment” issued in March, 2005, which provides supplemental SFAS 123(R) application guidance based on the views of the SEC.

     Under the modified prospective transition method, results for prior periods have not been restated, and compensation costs recognized in the six-month period ended June 30, 2006 include (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1,

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2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R).

     The adoption of SFAS 123(R) resulted in additional share-based compensation expense for the three-month and six-month periods ended June 30, 2006 of $340,581 and $885,467, respectively. This expense reduced basic and diluted earnings per share by $0.01 and $0.02 for the three-month and six-month periods ended June 30, 2006.

     The Black-Scholes option-pricing model was used to estimate the option fair values. The option-pricing model requires a number of assumptions, of which the most significant are, expected stock price volatility, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire). The following assumptions were used for the significant options granted in the six-month periods ended June 30, 2006 and June 30, 2005:

	June 30, 2006			June 30, 2005
Expected option life (in years)		5 – 8			5
Expected volatility over option life		33% – 63	%		58% – 71	%
Risk-free interest rate		4.5% – 5.2	%		3.09 – 3.36	%
Pre-vesting forfeiture rate		0	%		0	%
Dividend yield		0	%		0	%

The expected five-year annual volatility of 33% for options granted in the second quarter of 2006 is lower than the 45% to 70% twelve-month historical volatility in our common stock and gives consideration to (a) a 35% average expected volatility most recently disclosed before the option grant date by five other Denver-based public oil and gas exploration companies for similar expected option lives, (b) a 32% average expected volatility most recently disclosed before the option grant date by two very large public oil and gas exploration companies for 4 to 6 year expected lives, and (c) our policy at the time of grant of prohibiting company officers, such as the Option holder, from buying or selling our common stock within blackout periods of two days before a quarter ends until two trading days after the related Form 10-Q or Form 10-K is filed. The blackout policy reduces an option holder’s ability to profit from high volatility in the price of the common stock.

     Pro-Forma Stock-Based Compensation Expense for the Quarterly and Six-Month Periods Ended June 30, 2005

     For 2005 we applied the intrinsic value method of accounting for stock options as prescribed by APB 25. Since all options granted in 2005 had an exercise price equal to the closing market price of the underlying common stock on the grant date, no compensation expense was recognized for options granted to employees. If compensation expense had been recognized based on the estimated fair value of each option granted in accordance with the provisions of SFAS 123 as amended by Statement of Financial Accounting Standard 148, our net income and net income per share would have been reduced to the following pro-forma amounts for the three-month and six-month periods ended June 30, 2005:

	Three-month			Six-Month
	Period			Period
Net income to common stockholders, as reported	$	115,412		$	177,074
Add stock-based compensation included in reported net income		134,375			153,691
Deduct stock-based compensation determined under fair value method		(340,259	)		(392,174	)

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	Three-month			Six-Month
	Period			Period
Pro forma net income	$	(90,472	)	$	(61,409	)
Net income (loss) per common share – basic and diluted
As reported	$	0.00		$	0.01
Pro forma	$	0.00		$	0.00
Net income per common share — diluted
As reported	$	0.00		$	0.01
Pro forma	$	0.00		$	0.00

     Stock Options as of the Quarterly Period Ended June 30, 2006

     The following table summarizes stock options outstanding and changes during the six-month period ended June 30, 2006:

				Wgtd. Average
	Number of shares			Exercise Price
Options outstanding at December 31, 2005		1,459,010		$	2.94
Granted		509,000		$	4.80
Less Exercised		(21,340	)	$	3.27
Less Canceled or forfeited		—			—
Options outstanding at June 30, 2006		1,946,670		$	2.79
Options exercisable at June 30, 2006		898,668		$	2.52

     The following table presents additional information related to the options outstanding at June 30, 2006:

					Weighted average
Exercise price	Number of shares				remaining contractual
per share	Outstanding		Exercisable		life (years)
$1.25		403,000		403,000		3.7
2.38		100,000		75,000		4.5
2.48		90,000		60,000		4.5
3.27		10,670		10,670		3.9
3.66		750,000		249,998		6.3
4.30		9,000		—		6.4
4.57		9,000		—		6.6
4.65		250,000		50,000		9.6
4.95		250,000		50,000		10.0
5.80		75,000		—		6.2
		1,946,670		898,668
Wgtd. Ave. remaining contractual life	6.5 years		5.2 years
Aggregate intrinsic value	$	4,681,046	$	2,403,153

Total grant date fair value of share options granted during the quarter ended June 30, 2006 was $473,218. Total estimated unrecognized compensation cost from unvested stock options as of June 30, 2006 was $2,177,950, which is expected to be recognized over a weighted average period of approximately 6.2 years. There were 21,340 options exercised in the three-month period ended June 30, 2006.

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Note 3 – Income Taxes

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

     We were not required to pay federal income taxes for 2005 because of the generation of net operating losses from operations and drilling activities. At December 31, 2005, we had a $7.3 million net operating loss carryforward. At March 31, 2006, we had anticipated paying income tax in 2006 and recorded a $296,251 income tax provision for the quarter ended March 31, 2006. We now anticipate not being required to pay income taxes for 2006 due to the utilization of the carryforward and the allowed deduction of US intangible well costs expected to be incurred in 2006. We are exempt from paying Alternative Minimum Tax in 2006. Accordingly, for the three-month and six-month periods ended June 30, 2006, our current portion of income tax expense was a negative $296,251 and $0, respectively.

     We recorded deferred income tax provisions of $1,624,412 and $3,280,457 for the three –month period and six-month period ended June 30, 2006, respectively. The provisions were based on a projected effective tax rate of 41% for the 2006 taxable year. The estimated combined statutory rate is 38.1% for federal and state income taxes. A reconciliation of the deferred tax provision with the deferred income tax liability accounts is provided below:

	Net Deferred Income Tax Liability
	Current		Long-term
Balance as of December 31, 2005	$	—	$	1,893,581
Add deferred income tax provision, six months ended 6/30/06		—		3,280,457
Deferred taxes on unrecognized gain reflected in other comprehensive income (See Note 5.)		1,249,680
Balance as of June 30, 2006	$	1,249,680	$	5,174,038

Note 4 – Property and Equipment

     Property and equipment at June 30, 2006 consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization or ceiling test	$	20,369,282
Evaluated costs (including $97,562 in asset retirement costs)		3,188,592
		23,557,874
Furniture and equipment		187,135
		23,745,009
Less accumulated depreciation, depletion and amortization		(2,255,402	)
Property and equipment	$	21,489,607

     On March 31, 2006, we sold our interest in the Big Sky project, which at the time of sale represented approximately 95% of our oil and gas production revenue and approximately 88% of our proved oil and gas reserves and their standardized measure. The contract sales price was $11.5 million and the effective date of the sale was February 1, 2006.

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     In April 2006, we sold our 8,653 net acres in unproved Montana leases referred to as the Bear Creek prospect. Our lease interests were sold to privately owned MAB Resources in exchange for a convertible $1,080,000 note from GSL Energy Corp., a private affiliate of MAB Resources. That same month we converted the note into 2,160,000 shares of GSL common stock. In May 2006, GSL merged into a publicly-traded company whereby at June 30, 2006 we owned (in lieu of the $1,080,000 note receivable) 2,160,000 unregistered shares of the merged company Digital Ecosystems Corp. See Note 5.

     In May 2006 we sold to Teton Energy Corporation for $6.2 million a 25% working interest in our Goliath project. The project consisted of unproved leases of approximately 58,000 gross acres in the Williston Basin of North Dakota. Teton paid us $2.46 million in cash at closing and Teton must pay an additional $3.69 million payable on the earlier of May 31, 2007 or as and to the extent of our costs in drilling and completing the project’s first two wells, scheduled to begin this fall.

     The reconciliations of the gains on the sales are as follows:

	Big Sky			Bear Creek			Goliath			Totals
Contract sales price	$	11,500,000		$	1,080,000		$	6,165,520		$	18,745,520
Effective date adjustments		(821,496	)		0			0			(821,496	)
Adjusted sales price		10,678,504			1,080,000			6,165,520			17,924,024
Allocated capitalized costs using the relative fair market value method required under full cost accounting		(6,416,650	)		(648,443	)		(3,699,461	)		(10,764,554	)
Recognized gains on sales of oil and gas properties	$	4,261,854		$	431,557		$	2,466,059		$	7,159,470

Note 5 – Service Fee Revenue and Short-term Investments

     In April 2006, we took a $1,530,000 convertible note from GSL Energy Corp. as a Service Fee under an October 2005 agreement with MAB Resources to receive a $1,530,000 Finder’s Fee upon successfully assisting MAB Resources in acquiring additional Montana lease acreage that was not suitable for our acreage portfolio. As we did with the $1,080,000 convertible note discussed in Note 4, we converted the $1,530,000 note into 3,060,000 shares of GSL common stock at $0.50 per share, which was subsequently exchanged on May 12 for 3,060,000 shares of unregistered shares in common stock of publicly held Digital Ecosystems Corp. (“DEC”).

     At June 30, 2006, we owned 5,220,000 unregistered DEC shares. These shares are approximately 2% of the DEC shares outstanding at June 30, 2006. Registered shares of DEC common stock are traded on a US over-the-counter bulletin board under the symbol DGEO. The stock price approximated $2.14 per share on June 30, 2006 and $2.15 on August 9, 2006. Our investment is available for sale but absent DEC’s registration of the stock, we reasonably expect that only 2,000,000 shares will be sold by June 30, 2007 (under Rule 144 exemption from registration) and the remainder sold by the end of 2007. AOG’s president is a director of a publicly traded company, Falcon Oil & Gas, whose president and largest shareholder is also the largest shareholder of DEC and the majority owner of MAB Resources. However, we do not believe that relationship provides AOG with significant influence in the management of DEC.

     The 2,000,000 shares reasonably expected to become exempt from registration and sold by June 30, 2007 are shown on the consolidated balance sheet as short-term investments available for sale. In accordance with Statement of Financial Accounting Standards No. 115, unregistered shares that are reasonably expected to be sold within one year are recorded at the trading price of registered, marketable shares at June 30, 2006. Therefore, the 2,000,000 shares acquired for $1,000,000 are carried at $4,280,000

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at June 30, 2006. The $3,280,000 gain is unrealized and is recorded (net of $1,249,680 related deferred income taxes) as a $2,030,320 increase in Accumulated Other Comprehensive Income in the Equity section of our June 30, 2006 consolidated balance sheet. The other 3,220,000 DEC shares are recorded as a long-term investment at their cost of $1,660,000 at 50 cents per share. The realized sales price from our future sales of the 5,220,000 DEC shares may vary materially from the $2.14 per share price at June 30, 2006.

Note 6 — Common Stock

     The following material changes occurred during the three-month period ended June 30, 2006 with regard to our common stock and other comprehensive income:

• Other Comprehensive Income of $2,030,320 was recorded for the net unrealized gain on short-term investment available for resale as explained in Note 5.

• Additional paid-in capital increased by $217,296 for the period’s share-based compensation relating to stock options granted before June 30, 2006.

• Shares outstanding increased by 48,745 shares and additional paid-in capital increased by $193,045 relating to shares issued for services and the exercise of stock options.

     The following transactions occurred in the three-month period ended March 31, 2006 with regard to our common stock:

• We issued 23,200 shares of common stock resulting from a warrant exercise at $1.09 per share and received proceeds of $25,288.

• Common stock warrants were exercised for issuance of 11,600 shares of common stock at $0.75 per share. The terms of the warrants provided for a cashless exercise and 1,916 shares were used to exercise the warrants at the market price of $4.54 per share, resulting in issuance of a net amount of 9,684 shares of common stock.

• We issued a total of 27,000 shares of common stock to a consulting firm who is assisting us with our investor relations program. The firm vests ownership of these shares at the rate of 1,500 shares per month through June 2007. We have recorded $107,730 as deferred compensation associated with these shares and we included $17,955 in investor relations expense for the quarter ended March 31, 2006.

• We paid a total of 10,000 shares of restricted common stock to our Vice-President of Land as an additional component of his initial employment. We valued these shares at $4.65 per share, which was the closing price of our common stock on the date of payment, and charged $46,500 to compensation expense.

• In conjunction with our Series AA Convertible Preferred Stock, we are required to pay an 8% dividend on a semi-annual basis. We can make the dividend payments in cash or equivalent shares of our common stock, at our discretion. During the quarter ended March 31, 2006, we paid a semi-annual dividend payment of $540,000 by issuing 130,378 common shares, which shares were valued at $4.14 per share in accordance with methodology prescribed in the Certificate of Designation of Rights, Preferences and Privileges of Series AA Preferred Stock.

Note 7 – Preferred Stock

     At June 30, 2006 there are a total of 250,000 shares of Series AA Convertible Preferred Stock (“Preferred Stock”) outstanding. We are obligated to pay an 8% annual dividend ($1,080,000) on the Preferred Stock in cash or in equivalent shares of common stock, at our discretion. Each share of Preferred Stock is convertible into nine shares of common stock for a total of 2,250,000 shares, which is a conversion rate of $6.00 per share.

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     The Preferred Stock automatically converts into common stock on July 22, 2008, or anytime sooner at the discretion of the preferred holders. We can require conversion of the Preferred Stock if the daily weighted average trading price of our common stock averages at least $9.00 for 25 consecutive trading days.

Note 8 — Related Party Transactions

     During the three-month and six-month periods ended June 30, 2006, we reimbursed Tower Energy Corporation (“TEC”) for our share of administrative related expenditures in the amount of $3,061 and $47,207, respectively. These expenditures were reimbursed at actual cost and did not include any mark-up. Patrick O’Brien, our Chief Executive Officer and Chairman, and Bob Solomon, a Vice-President, each owns 50% of TEC.

     On April 21, 2005, we acquired, through a merger, 100% of the outstanding common stock of Tower Colombia Corporation (“TCC”) in exchange for 5.8 million shares of our restricted common stock. Patrick O’Brien, our Chief Executive Officer and Chairman, Kendell Tholstrom, vice-president and director, and Bob Solomon, vice-president each owned 1/3^rd of TCC prior to our acquisition of TCC. In conjunction with the merger, Pat O’Brien continues in his role as Chief Executive Officer and as Chairman of American. Mr. O’Brien was the president of TCC. Bob Solomon, formerly Vice President of TCC, became Vice President of American and is responsible for oil and gas economic and financial evaluations and the acquisition and disposition of oil and gas assets. Kendell Tholstrom, formerly Vice President of TCC, continues his role as a Director of American, and became Vice-President of American. Mr. Tholstrom is responsible for oil and gas operations. Prior to closing, we obtained a fairness opinion concerning the terms of the merger from an independent investment banking firm.

Note 9 – Commitments and Contingencies

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

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

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

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

     This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. There are a number of risks and uncertainties that could cause our actual results to differ materially from those indicated by such forward-looking statements. These risks and uncertainties include, but are not limited to, those described in this report, in Part II, “Item 1A. Risk Factors,” those described in our annual report on Form 10-KSB for the year ended December 31, 2005, and those described from time to time in our future reports filed with the SEC.

Overview

     We are an independent oil and gas exploration and production company, engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States. The following oil and gas exploration/development project updates should be read in conjunction with our annual report on Form 10-KSB for our fiscal year ended December 31, 2005.

Fetter Prospect and the Greater Douglas Project Area — Powder River Basin, Wyoming

     On July 6, 2006, we commenced the first of a two-well drilling program at our Fetter project with drilling operations on the State 4-36-H well, located in Converse County, Wyoming. This program is a continuation of our initial drilling from 2005, when we drilled the Sims 16-26 and the Hageman 16-34 wells. The current drilling program combines casing drilling with under-balanced horizontal drilling technologies.

     The other participants in the State 4-26 well are North Finn LLC and Turnkey E&P Corporation (“Turnkey”). On March 14, 2006, we announced a joint venture agreement with Turnkey, a wholly owned subsidiary of Calgary, Alberta based Turnkey E&P Inc., to drill these next two wells, with the

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option for a third well, at our Fetter project. Turnkey will operate these wells and will apply casing drilling technology through the use of one of their four purpose-built casing drilling rigs.

     Casing drilling utilizes the actual steel casing as the drilling string, versus drilling with drill pipe, and installs the casing in the well bore while drilling. This process has been shown to reduce, overcome or eliminate the risk of well bore collapse, stuck pipe, lost circulation and other well control issues in many applications and is currently being used as the method of choice in a number of field development programs. Cost savings can be another potential benefit of using casing drilling, as the possibility exists of eliminating one or more casing strings. Casing drilling can be used in conjunction with both underbalanced horizontal drilling technology as well as conventional vertical drilling.

     Under the terms of the agreement, Turnkey will operate and pay for 60% of the costs before casing point and 40% of the costs after casing point in order to earn a 40% working interest in the first two wells and in the 640 acre spacing unit surrounding each well. We are paying for 36% of the costs before casing point and 54% of the costs after casing point and we retained a 54% working interest in these two initial wells.

     Upon mutual agreement, a third test well may be drilled on a non-promoted basis, in order to further evaluate the casing drilling technology. Should a third test well be drilled, Turnkey would pay 30% of the costs and would earn a 30% working interest and we would pay 63% of the costs and would retain a 63% working interest.

     If certain drilling criteria are met on these initial test wells, Turnkey has the option to purchase a 15% working interest in the Fetter acreage block, encompassing the approximate 51,000 gross acres, for approximately $750,000. If Turnkey exercises its option, our existing 67.5% working interest would be reduced by 13.5%, to 54%, and our share of the $750,000 payment would be approximately $675,000.

     We continue to evaluate additional opportunities within our greater Douglas Project acreage position. We control a 90% working interest in approximately 65,000 net acres outside of the Fetter area and we believe that the potential exists for multiple targets for oil and natural gas production, both shallow, and normally pressured as well as deep, and over pressured. We will continue to perform geological evaluations in order to identify additional drilling opportunities.

Krejci Oil Project (Powder River Basin, Wyoming)

     We commenced drilling operations at our Krejci project by spudding the first of a two well horizontal drilling program on July 26, 2006. The Krejci Federal 3-29 well, located in Niobrara County, Wyoming, is the first of two currently planned wells to be drilled in the Krejci AMI project area where we control an approximate 90% working interest in over 63,000 gross acres. Both wells are designed to be horizontal tests of the 7,500 foot deep Mowry shale formation. Austin, Texas based Brigham Exploration Company will participate in and operate the two-well program.

     Under the terms of the agreement, Brigham will fund 100% of the drilling and completion costs of the initial two well horizontal drilling program. Brigham will carry American and North Finn, LLC for our respective 45% and 5% shares of all drilling and completion costs. Brigham will own a 50% interest in each of the first two wells with American owning 45% and North Finn owning 5%. Upon completion of the two well program, plus an additional $1 million of capital expenditures in the AMI project area by Brigham, Brigham will earn 50% of our 90%, and 50% of North Finn’s 10% working interests in the entire project AMI.

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     We anticipate that the Krejci Federal 3-29 well could take 30 to 45 days to drill and evaluate at a total cost of between $3 million to $3.5 million. The second well is currently expected to commence within 120 days from rig release of the first. Any subsequent wells will be operated by either American or Brigham, depending on their location within the project area, and will be funded and owned on the basis of American 45%, Brigham 50% and North Finn 5%.

Goliath Project, Williston Basin, North Dakota

     The Goliath project targets the middle member of the Bakken Formation in an emerging horizontal drilling play in the North Dakota, Williston Basin. On May 5, 2006, we sold a third of our 75% working interest in this project to Teton Energy Corporation for cash of $2.46 million and a commitment from Teton to pay $3.70 million of our share of drilling and completion costs in initial wells. We currently own approximately 29,000 net acres in the Goliath project, and expect to commence drilling our first multi-lateral horizontal well by early September 2006.

Big Sky Project, Williston Basin, Montana

     On March 31, 2006, we sold (effective February 1, 2006) our ownership interest in our Big Sky project for a contract price of $11,500,000. After effective date adjustments, we received cash proceeds at closing of $10,678,504. The Big Sky project is a horizontal drilling program targeting the Mississippian Bakken Formation in the Elm Coulee field in Richland County, Montana. We sold our interests in approximately 1,660 net undeveloped acres, approximately 1,410 net developed acres, and 25 gross (approximately 1.11 net) producing wells at our Big Sky project. The Big Sky project did not account for any of the oil and gas production and revenues for the quarter ended June 30, 2006. At the time of sale, the Big Sky production did account for approximately 95% of our oil and gas production and revenues and 88% of our proved reserves. As a result of the sale, we will not have any significant production revenue unless and until we are able to establish commercial production

Bear Creek Coal Bed Methane Prospect (Big Horn Basin, Montana)

     During the quarter ended June 30, 2006, we sold our entire ownership interest in our Bear Creek Project to GSL Energy Corporation and received a convertible note in the amount of $1,080,000. Subsequent to closing, the note was converted into 2,160,000 shares of restricted common stock of GSL Energy Corporation, which is now Digital Ecosystems Corp. Digital Ecosystems is a publicly traded company that trades on the US electronic bulletin board under the ticker symbol “DGOE.”

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-KSB for the fiscal year ended December 31, 2005. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended June 30, 2006 Compared with the Quarter Ended June 30, 2005

     We recorded net income attributable to common stockholders of $1,962,455 (five cents per common share, basic and diluted) for the quarter ended June 30, 2006, as compared to net income attributable to common stockholders of $115,412 (no cents per common share, basic and diluted) for the quarter ended June 30, 2005. Included in the net income for 2006 are (i) $2,897,616 in gains from the sale of working interests in unevaluated properties and (ii) $1,530,000 in service fee revenue. For the quarter ended June 30, 2005, we had no recognized gain from property sales and no service fee revenue.

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     For the quarter ended June 30, 2006, we recorded total oil and gas revenues of $259,033 compared with $1,239,042 for the quarter ended June 30, 2005. The primary reason for the decline is the sale on March 31, 2006 of our interest in the Big Sky producing property that accounted for substantially all of our revenues in 2005 and in 2006 through March 31. Oil & gas sales and production costs are summarized in the following table:

	Three months ended June 30,
	2006			2005
Oil sold (barrels)		3,874			22,233
Average oil price	$	54.64		$	50.97
Oil revenue	$	211,694		$	1,133,297
Gas sold (mcf)		6,753			16,094
Average gas price	$	7.01		$	6.57
Gas revenue	$	47,339		$	105,745
Total oil and gas revenues	$	259,033		$	1,239,042
Less lease operating expenses		(64,602	)		(57,400	)
Oil & gas amortization expense		(94,527	)		(387,874	)
Producing revenues less direct expenses		99,904			793,768
Less depreciation of office facilities		(5,573	)		(695	)
Less amortization of other intangible asset		(45,000	)		(30,000	)
Less general and administrative expenses		(758,749	)		(665,303	)
Add service fee revenue		1,530,000			—
Income from operations	$	820,582		$	97,770
Total barrels of oil equivalent (“boe”) sold		5,000			24,915
Lease operating expense per boe sold	$	12.92		$	2.30
Amortization expense per boe sold	$	18.91		$	15.57

     For interim reporting, we use the year-to-date method of calculating amortization. The sales of two oil and gas properties in the second quarter of 2006, preceded by the March 31, 2006 sale of our major producing property changed our oil & gas property amortization rate from $17.93/boe for the first quarter of 2006 to $18.91/boe for the six-month period ended June 30, 2006.

     General and administrative expenses for the second quarter of 2006 increased $93,446 (14%) over the same quarter in 2005 primarily due to the adoption of Statement of Financial Accounting Standards No. 123(R) on January 1, 2006 whereby share-based compensation is recognized in 2006 based on the fair value method. In 2005, share-based compensation to employees was recognized based on the intrinsic value method, which was zero for stock options granted to employees by the Company. As disclosed in Note 2 to the Company financial statements contained in this filing, had the Company used in 2005 the fair value method, rather than the intrinsic value method, the share-based compensation for the six months ended June 30, 2005 would have been greater by $205,884.

     At March 31, 2006, we had anticipated paying income tax in 2006 and recorded a $296,251 income tax provision for the quarter ended March 31, 2006. We now anticipate not being required to pay income taxes for 2006 primarily due to the deduction of US intangible well costs expected to be incurred

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in 2006. We are exempt from paying Alternative Minimum Tax in 2006. Accordingly, for the quarter ended June 30, 2006, our current portion of income tax expense was a $296,251 tax reduction. The same projected deduction for intangible well costs (which are capitalized for financial reporting) contributed to a projected deferred income tax provision effective rate of 41% for the year 2006. Applying that rate for the six-months ended June 30, 2006 determined the $1,624,412 deferred tax provision recorded for the three months ended June 30, 2006.

     We recorded $269,260 in preferred stock dividends for the quarter ended June 30, 2006. We had no preferred stock outstanding in the corresponding quarter of 2005. The Series A Convertible Preferred Stock was converted into common shares during January 2005. The Series AA preferred stock was issued in July 2005.

The Six-month Period ended June 30, 2006 Compared with the Six-month Period ended June 30, 2005

     We recorded net income attributable to common stockholders of $4,165,809 (11 cents per common share, basic and diluted) for the six-month period ended June 30, 2006, as compared to net income attributable to common stockholders of $177,074 (one cent per common share, basic and diluted) for the six-month period ended June 30, 2005. Included in the net income for 2006 are (i) $7,159,470 in gains ($4.5 million after tax effect) from the sale of oil and gas properties and (ii) $1,530,000 in service fee revenue. For the six months ended June 30, 2005, we had no recognized gain from property sales and no service fee revenue.

     We do not anticipate service fee revenue or significant property sales in the second half of 2006. Having sold our Big Sky interest in March 2006 representing approximately 88% of our proved reserves at time of sale and having recognized $7 million in gain on property sales, we are at greater risk of having to recognize a cost impairment if drilling is unsuccessful in the coming months. For example, if we were to have $3 million in exploratory dry hole costs in the second half of 2006 with no significant change in proved reserves, the resulting impairment expense, after tax, is estimated to approximate $1 million.

     For the six months ended June 30, 2006, we recorded total oil and gas revenues of $1,829,885 compared with $1,925,769 for the six months ended June 30, 2005. The primary reason for the revenue decline is the sale on March 31, 2006 of our interest in the Big Sky producing property that accounted for substantially all of our revenues in 2005 and in 2006 through March 31. Oil & gas sales and production costs are summarized in the table that follows.

	Six months ended June 30,
	2006			2005
Oil sold (barrels)		28,807			35,958
Average oil price	$	54.92		$	48.92
Oil revenue	$	1,582,109		$	1,759,034
Gas sold (mcf)		29,790			26,163
Average gas price	$	8.32		$	6.37
Gas revenue	$	247,776		$	166,735
Total oil and gas revenues	$	1,829,885		$	1,925,769
Less lease operating expenses		(165,793	)		(94,503	)
Less oil & gas amortization expense		(610,426	)		(486,695	)
		1,053,666			1,344,571
Producing revenues less direct expenses

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	Six months ended June 30,
	2006			2005
Less depreciation of office facilities		(10,517	)		(1,363	)
Less amortization of other intangible asset		(90,000	)		(75,000	)
Less general and administrative expenses		(1,831,319	)		(1,132,010	)
Add service fee revenue		1,530,000			—
Income from operations	$	651,830		$	136,198
Total barrels of oil equivalent (“boe”) sold		33,772			40,319
Lease operating expense per boe sold	$	4.91		$	2.34
Amortization expense per boe sold	$	18.07		$	12.07

     General and administrative expenses for the six months ended June 30, 2006 increased $699,309 (62%) over the same quarter in 2005 due primarily to a $561,965 increase in share-based compensation recorded in the first half of 2006 compared with the first half of 2005. The increase is primarily due to adoption of SFAS 123(R) on January 1, 2006 as discussed in Note 2 to the accompanying financial statements of American. Share-based compensation in the first six months of 2006 includes $255,500 for the estimated value of options granted and immediately vesting upon the hiring of our Vice President of Land in January and our new Chief Financial Officer in June.

     We now anticipate not being required to pay income taxes for 2006 primarily due to the deduction of US intangible well costs expected to be incurred in 2006. We are exempt from paying Alternative Minimum Tax in 2006. Accordingly, for the six months ended June 30, 2006, our recorded current portion of income tax expense was zero.

     For the six months ended June 30, 2006, we recorded a $3,280,457 provision for deferred income taxes and recorded a zero provision for the six months ended June 30, 2005. The $3,280,457 provision reflects a projected 41% effective deferred tax rate for 2006. The projected rate arises from (1) $6 million in projected deductible drilling costs in the last half of 2006 and (2) the taxable gains on sales of property in the first six months of 2006.

     We recorded $535,561 in preferred stock dividends for the six months ended June 30, 2006. We had no preferred stock dividends in the corresponding six months of 2005. The Series A Convertible Preferred Stock converted into common shares on January 5, 2005. The Series AA preferred stock was issued in July 2005.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

     We have not entered into any commodity swap arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. We have no off-balance sheet arrangements.

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, President 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, President and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2006 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.

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     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 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 1 Description of Business” in our Annual Report on Form 10-KSB/A for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-KSB/A, are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. There have been no material changes in our risk factors from those disclosed in our 2005 annual report on Form 10-KSB/A

Item 6. EXHIBITS

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

SIGNATURES

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

Signatures	Title	Date
/s/ Patrick D. O’BrienPatrick D. O’Brien	Chief Executive Officer and Chairman of the Board of Directors	April 11, 2007
/s/ Joseph B. FeitenJoseph B. Feiten	Chief Financial Officer	April 11, 2007

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Exhibit Index

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

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