HESS BAKKEN INVESTMENTS I (AEZ) 10-Q 2009 Q2 Quarterly report

United States Securities and Exchange Commission
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

OR

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

For the transition period from                    to                    

Commission File No. 1-31900

AMERICAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noo Not required.

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

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

The total shares of $.001 Par Value Common Stock outstanding at August 3, 2009 were 48,307,399.

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

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	3
Condensed Consolidated Balance Sheets — June 30, 2009 and December 31, 2008	3
Condensed Consolidated Statements of Income — Three and Six Months Ended June 30, 2009 and 2008	4
Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2009 and 2008	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3. Quantitative and Qualitative Disclosures about Market Risks	19
Item 4. Controls and Procedures	19
PART II. OTHER INFORMATION
Item 1A. Risk Factors	20
Item 6. Exhibits	20
Signatures	21
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2009			2008
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	13,753,376		$	23,269,725
Short-term investment		3,950,000			5,450,000
Accounts receivable		476,673			1,186,749
Materials and supplies inventory		1,757,148			1,236,591
Prepaid expenses		115,389			133,360
Total current assets		20,052,586			31,276,425
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $35,059,051 at 6/30/09 and $31,837,965 at 12/31/08)		43,943,574			40,456,632
Other property and equipment		399,472			366,354
Total property and equipment		44,343,046			40,822,986
Less-accumulated depreciation, depletion and amortization		(5,352,893	)		(4,980,578	)
Net property and equipment		38,990,153			35,842,408
OTHER ASSETS
Deferred income tax assets (net of valuation allowance, Note 7)		—			—
Intangible asset, net of accumulated amortization		150,000			240,000
Other		30,385			30,385
	$	59,223,124		$	67,389,218
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	981,525		$	4,286,618
Income taxes payable		—			104,000
Total current liabilities		981,525			4,390,618
LONG-TERM LIABILITIES
Asset retirement obligations		492,114			430,686
COMMITMENTS AND CONTINGENCIES(Note 10)
STOCKHOLDERS’ EQUITY
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding: 48,307,399 shares at 6/30/09 and 47,875,899 shares at 12/31/08		48,307			47,876
Additional paid-in capital		91,873,178			91,275,557
Accumulated deficit		(34,247,000	)		(28,755,519	)
Accumulated other comprehensive income		75,000			—
		57,749,485			62,567,914
	$	59,223,124		$	67,389,218

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

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AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATION

(UNAUDITED)

	Three months ended						Six months ended
	June 30						June 30
	2009			2008			2009			2008
REVENUES:
Oil and gas sales	$	517,478		$	937,361		$	823,152		$	1,445,165
OPERATING EXPENSES:
Lease operating		270,250			295,830			569,925			550,605
General and administrative		1,412,805			1,101,105			3,042,351			2,491,313
Depletion, depreciation and amortization		285,172			484,087			462,315			837,591
Impairment of oil & gas properties		—			—			2,100,000			—
Impairment of materials and supplies inventory		156,139			—			156,139			—
Accretion of asset retirement obligation		10,567			8,247			20,220			16,332
		2,134,933			1,889,269			6,350,950			3,895,841
LOSS FROM OPERATIONS		(1,617,455	)		(951,908	)		(5,527,798	)		(2,450,676	)
OTHER INCOME (LOSS):
Investment income		17,337			149,520			38,317			373,231
Gain (loss) on sale of securities		—			(38,368	)		—			(369,172	)
Impairment of short-term investments		—			(116,000	)		—			(116,000	)
Interest expense		—			(65,123	)		—			(88,647	)
		17,337			(69,971	)		38,317			(200,588	)
LOSS BEFORE INCOME TAXES		(1,600,118	)		(1,021,879	)		(5,489,481	)		(2,651,264	)
Income tax expense-current		—			—			—			—
Income tax expense (reduction) -deferred		—			(522,000	)		—			(980,000	)
NET LOSS		(1,600,118	)		(499,879	)		(5,489,481	)		(1,671,264	)
Less dividends on preferred stock		—			(145,215	)		—			(294,255	)
Less deemed dividends on warrants extension		—			(300,000	)		(2,000	)		(300,000	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS		(1,600,118	)	$	(945,094	)	$	(5,491,481	)	$	(2,265,519	)
NET LOSS PER COMMON SHARE:
Basic and diluted	$	(0.03	)	$	(.02	)	$	(0.11	)	$	(.05	)
Weighted average common shares outstanding:
Basic and diluted		48,307,399			46,522,849			48,273,382			46,500,670

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

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AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six months ended
	June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(5,489,481	)	$	(1,671,264	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairment of oil and gas properties		2,100,000			—
Share-based compensation expenses		596,052			516,498
Depletion, depreciation and amortization		462,315			837,591
Impairment of materials and supplies inventory		156,139			—
Accretion of asset retirement obligations		20,220			16,332
Realized loss on sale of short-term investments		—			369,172
Impairment on short-term investments		—			116,000
Deferred income taxes		—			(980,000	)
Changes in assets and liabilities:
Decrease (increase) in receivables		352,328			(242,730	)
Decrease (increase) in prepaid expenses		17,971			49,312
Decrease (increase) in inventory		(676,696	)		—
Increase (decrease) in accounts payable and accrued liabilities		(126,256	)		46,033
Net cash provided (used) by operating activities		(2,587,408	)		(943,056	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties		(8,470,823	)		(7,499,179	)
Proceeds from redemptions of auction-rate preferred shares		1,575,000			11,450,000
Proceeds from sales of short-term investments		—			683,728
Cash paid for office equipment		(33,118	)		(15,468	)
Net cash provided (used) by investing activities		(6,928,941	)		4,619,081
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowing		—			8,600,000
Repayment of short-term borrowings		—			(8,600,000	)
Net cash provided by financing activities		—			—
NET INCREASE (DECREASE) IN CASH		(9,516,349	)		3,676,025
CASH, BEGINNING OF PERIODS		23,269,725			2,388,219
CASH, END OF PERIODS	$	13,753,376		$	6,064,244
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	88,647
Cash paid for income taxes	$	130,000		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING ACTIVITIES
Net increase in payables for capital expenditures	$	—		$	3,096,248
Share-based compensation expenses	$	596,052		$	516,498
Drilling prepayments applied to drilling costs	$	—		$	542,876
Preferred dividends paid in shares of common stock	$	—		$	298,080
Conversion of preferred stock into common stock	$	—		$	600,048

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

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AMERICAN OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(UNAUDITED)

June 30, 2009

NOTE 1 — COMPANY AND BUSINESS

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

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

NOTE 2 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying interim financial statements of American are unaudited. In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the six-month period ended June 30, 2009 are not necessarily indicative of the operating results for the entire year ending December 31, 2009.

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

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

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

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

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

RECENT ACCOUNTING PRONOUNCEMENTS— In April 2009, the FASB issued three FASB Staff Positions (“FSPs”) to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities:

• FSP FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,

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• FSP FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instrumentand

• FSP FAS 115-2 and FAS 124-2,Recognition and Presentation of Other-Than-Temporary Impairment.

These three FSPs are effective for interim and annual periods ending after June 15, 2009, and we adopted the FSP provisions as of June 30, 2009. Their adoption did not have a material impact on our financial position or results of operations.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events”(SFAS No. 165). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are first issued (in the case of publicly held companies) or are available to be issued. The standard introduces new terminology and calls for additional disclosure but is based on the same principles for Subsequent Events that existed prior to SFAS No. 165. This statement is effective for interim or annual periods ending after June 15, 2009. We adopted the statement as of June 30, 2009. Its adoption did not have a material impact on our financial position or results of operations.

SUBSEQUENT EVENTS— Those subsequent events known to the Company’s principal executive officer or principal financial officer prior to the first issuance of the financial statements are evaluated for incorporation in the financial statements and notes thereto. These financial statements were first issued on August 7, 2009 at the time of filing this Form 10-Q with the SEC.

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

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

INVENTORY— Inventories classified as current assets consists of purchased well casing and tubing stored in central yards serving multiple oil and gas companies. Such inventory is carried at the lower of cost or market 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 2008 consolidated financial statements have been reclassified to conform to the 2009 financial statement presentation. Such reclassifications have had no effect on net loss.

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

For the six-month periods ended June 30, 2009 and June 30, 2008, there are no adjustments for dilution because of each period’s net loss (rather than net income) to common shareholders. Securities outstanding at June 30, 2009 that could in the future potentially dilute basic net income (loss) per share for common stockholders are described in Notes 8 and 10 and include (i) a warrant for 50,000 shares, (ii) outstanding stock options for 3,022,000 shares (of which 1,260,366 were exercisable at June 30, 2009), and (iii) an option for 2,900,000 common shares in exchange for certain oil and gas properties.

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NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at June 30, 2009, consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization	$	35,059,051
Evaluated costs		8,884,523
		43,943,574
Less accumulated depreciation , depletion and amortization		(5,130,016	)
Net carrying value of oil and gas properties		38,813,558
Office equipment, furniture and software (net of $222,877 accumulated depreciation and amortization)		176,595
Property and equipment	$	38,990,153

Our major projects are Fetter, Goliath, Krejci and Bigfoot and are described more fully in our Form 10-K for 2008 and in Item 2 of this Form 10-Q. The following table presents the capitalized oil and gas properties’ costs and net additions therein for the six months ended June 30, 2009, with the unevaluated costs by major project:

	Capitalized Costs (in millions)
Project (State)	12/31/08		Net Change			6/30/09
Fetter Project, Powder River Basin (WY)	$	14.7	$	0.2		$	14.9
Goliath Project, Williston Basin (ND)		7.7		0.7			8.4
Bigfoot		3.3		1.4			4.7
Krejci Oil Project, Powder River Basin (WY)		2.7		(0.3	)		2.4
Other unevaluated costs		3.5		1.2			4.7
Total unevaluated costs		31.9		3.2			35.1
Evaluated costs, net of accumulated DD&A		3.8		(0.1	)		3.7
Total, oil and gas properties	$	35.7	$	3.1		$	38.8

The $3.1 million increase during the six-month period ended June 30, 2009 consisted of $5.5 million of costs incurred in oil and gas property acquisition, exploration and development, less $2.1 million in expensed impairment and less $334,000 in amortization expense.

Of the $5.5 million of incurred costs, $1.4 million were for the completion of the productive Sims 7-25 well at our Fetter project and the marginally productive Viall 30-1 well completed in the Red River formation at our Goliath project in North Dakota. We incurred $1.3 million in costs of acquiring leases and performing preliminary field activities at our Bigfoot project. We also incurred approximately $0.7 million in various additional costs at Fetter and $0.3 million in Wyoming wells in progress at June 30, 2009 located outside our four major projects. On June 30, 2009, we spent $0.9 million acquiring Goliath Project working interests, as further described in the next paragraph. Included in capital additions were $0.5 million of internal land department and geologist costs directly associated with the acquisition, exploration and development of oil and gas properties. There were no significant property divestitures in the six-month period ended June 30, 2009.

Purchase of working interests in oil and gas properties

On June 30, 2009 we closed on a $900,000 cash purchase, effective July 1, 2009, of certain oil and gas properties held by a third party in the Goliath Project. Approximately $500,000 of the purchase related to unevaluated, undeveloped oil and gas leases; the remainder related to working interests in existing wells. The purchase was insignificant to our $67 million in assets at December 31, 2008, and the acquired wells had income in fiscal year 2008 that was insignificant in comparison to our $24 million loss for fiscal year 2008.

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Impairment

We use the full-cost accounting method, which requires recognition of an impairment of oil and gas properties when the total capitalized costs (net of related deferred income taxes) exceed a “ceiling” as described on page F-9 of our Form 10-K as of December 31, 2008. At March 31, 2009, we recognized such an impairment of $2,100,000 ($1,330,000, net of a $770,000 increase in deferred tax assets before valuation allowances).

Amortization

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

	Six-month Period
	Ended June 30,
	2009		2008
Amortization of costs for evaluated oil and gas properties	$	334,000	$	710,000
Amortization of Intangible Asset		90,000		90,000
Depreciation of office equipment, furniture and software		38,315		37,591
Total DD&A expense	$	462,315	$	837,591

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations (“ARO”) relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of our oil and gas properties. The following table reflects the change in ARO for the three-month and six-month periods ended June 30, 2009 and June 30, 2008:

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
Beginning asset retirement obligation		440,615		$	329,771			430,687		$	323,369
Liabilities incurred		44,555			27,072			53,366			31,514
Liabilities settled		—			—			—			—
Revisions in estimated liabilities		(3,623	)		(27,968	)		(12,159	)		(34,093	)
Accretion		10,567			8,247			20,220			16,332
Ending asset retirement obligation		492,114		$	337,122			492,114		$	337,122
Current portion of obligation, end of period	$	—		$	—		$	—		$	—

NOTE 5 — SHORT-TERM INVESTMENTS

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

At March 1, 2008, most of our ARPS were issued by three Calamos closed-end mutual funds, which redeemed the majority of their ARPS in May and June of 2008 and announced on May 19, 2009, that they would soon be redeeming all remaining outstanding ARPS. One Calamos fund redeemed its ARPS in June, a second in July, and the third fund announced it will redeem its ARPS in August 2009. Our $700,000 of ARPS in the third fund are to be redeemed on August 19, 2009.

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On August 6, 2009, American filed with the Financial Industry Regulatory Authority (“FINRA”) a statement of claim against Jefferies & Company, Inc. (“Jefferies”), as American’s broker with regards to the ARPS. The statement of claim seeks in arbitration to have Jefferies (i) purchase at par value American’s remaining unredeemed ARPS, (ii) reimburse American for consequential damages (approximating $130,000 to date) and for American’s legal costs in the arbitration and (iii) pay American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions. We understand from Jefferies that FINRA is separately investigating Jefferies’ role as a broker of ARPS and as an Auction Dealer in ARPS.

We expect to have our ARPS at June 30, 2009 entirely liquidated for cash before June 30, 2010. We expect such liquidation to be in the form of redemptions for some ARPS and in sale to Jefferies at par value for all other ARPS. Absent full liquidation at par value, we intend to sell before June 30, 2010 any remaining ARPS in the secondary market at a loss, not expected to exceed approximately $225,000. We may in arbitration with Jefferies or in a global FINRA settlement with Jefferies be entitled to have Jefferies reimburse us for any loss we incur in selling the ARPS in the secondary market. However, we have no assurance that we will be successful in our claims against Jefferies.

The ARPS we own at June 30, 2009 are classified as short-term investments and are classified under SFAS 115 as investments held for sale, rather than marketable securities. Unrealized gains and temporary unrealized losses are recorded in Other Comprehensive Income (Loss). Unrealized losses that are “other-than-temporary” are reflected in the consolidated statement of operations. Unrealized gains resulting from increases in fair value are recorded in Other Comprehensive Income.

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

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

At June 30, 2009, the ARPS $4,175,000 total par value exceeded their $3,950,000 total carrying value by $225,000. The $225,000 net loss is composed of (i) a $300,000 other-than-temporary loss recognized in the Statement of Operations for the year ended December 31, 2008 and (ii) a $75,000 temporary unrealized gain recorded in Other Comprehensive Income.

The ARPS dividend rates approximated 0.9% per annum at June 30, 2009. Dividend rates fluctuate weekly or monthly generally at 125% to 150% of short-term LIBOR or commercial paper rates.

NOTE 6 — FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”) for all financial assets and liabilities measured at fair value on a recurring basis. We chose not to elect the fair value option as prescribed by SFAS 159 for financial assets and liabilities that had not been previously carried at fair value. Therefore, material financial assets and liabilities not carried at fair value, such as trade accounts receivable and accounts payable, are still reported at their face values.

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SFAS 157 establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. It defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of fair values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement calls for disclosures grouping these financial assets and liabilities, based on the following levels of significant inputs to measuring fair value:

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

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

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

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

	Total at
	June 30,		Level 1		Level 2		Level 3
	2009		inputs		inputs		inputs
Financial Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (“ARPS”)	$	3,950,000	$	—	$	—	$	3,950,000
Financial Liabilities	$	—	$	—	$	—	$	—

The table in Note 5 provides a reconciliation between the $5,450,000 fair value of the ARPS at December 31, 2008 and the $3,950,000 fair value of the ARPS at June 30, 2009.

Our estimate of the fair value of the ARPS at June 30, 2009, reflected the same general methodology at December 31, 2008:

• Those ARPS with reasonable evidence of redemption at par value within six months after the balance sheet date were valued at par value. At June 30, 2009, those ARPS were the $325,000 of Calamos ARPS redeemed in July 2009 and the $700,000 of Calamos ARPS scheduled to be redeemed on August 19, 2009.

• For the remaining ARPS ($3,150,000 par value) at June 30, 2009, we estimated fair value based primarily on discounted cash flow analyses reflecting estimates of when ARPS would be redeemed in the coming years.

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

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

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NOTE 7 — INCOME TAXES

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

We currently estimate that our effective tax rate for the year ending December 31, 2009 will be approximately 31.4%. Deferred income tax reductions of $0 (net of a $1.7 million valuation allowance) and $980,000 were reported for the six-month periods ended June 30, 2009 and 2008, respectively. As of June 30, 2009, net deferred tax assets were $0, after a 100% valuation allowance applied to net deferred tax assets of approximately $6.5 million.

We file annual US federal income tax returns and have filed annual income tax returns for the states of Colorado, Montana, North Dakota and Utah. We primarily do business in Wyoming, but Wyoming does not impose corporate income taxes. We believe we are no longer subject to income tax examinations by tax authorities for years before 2003 for Colorado and for 2004 for all other returns. Income taxing authorities have conducted no formal examinations of our past federal and state income tax returns and supporting records, with the exception of the Utah State Tax Commission, which informed us on March 2, 2009 of its initiating examinations of our franchise tax returns for 2005, 2006 and 2007. We expect the Utah examination will result in little or no payments of penalties, interest and additional taxes.

On January 1, 2007, we adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes(“FIN 48”). We found no significant uncertain tax positions as of any date on or before June 30, 2009. Given our substantial net operating loss carryforwards at the federal level prior to 2008 and at the state levels prior to 2009, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2009.

NOTE 8 — EQUITY

Common Stock

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

• On January 14, 2009, our Board of Directors granted an aggregate of 427,500 shares of common stock pursuant to the 2006 Stock Incentive Plan to certain employees, officers and directors of the Company. Of the 427,500 shares, 90,000 vested at grant and the other 337,500 shares vest upon the earlier of January 14, 2014 or a change in control of the Company.

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

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

• For the quarter ended March 31, 2009, Additional Paid-In Capital increased by $393,442 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of (i) $259,008 in share-based compensation related to stock options, (ii) $50,734 related to accruals for granted stock vesting after grant and (iii) $83,700 for the January 14, 2009 granting and immediate vesting of 90,000 shares of common stock.

• For the quarter ended June 30, 2009, Additional Paid-In Capital increased by $202,610 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of (i) $151,877 in share-based compensation related to stock options and (ii) $50,733 related to accruals for granted stock vesting after grant.

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Warrants

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

Stock Options

In the six-month period ended June 30, 2009, we granted no stock options; stock options for 15,000 shares were forfeited; no stock options were exercised; and there were vestings of options for 281,533 shares at exercise prices ranging from $2.00 to $3.66 per share and averaging $2.76 per share. On January 14, 2009, we granted extensions of approximately four years to vested options of 403,000 shares. The extension grants had an estimated total fair value of $93,660, which was recognized in option expense at the time of grant.

At June 30, 2009, there were outstanding options for 3,022,000 shares of common stock at a weighted-average exercise price of $2.42 per share. Of these, there were vested at June 30, 2009 options for 1,260,366 shares of common stock at a weighted-average exercise price of $2.83 per share.

Other Comprehensive Loss

During the quarter ended June 30, 2009, Other Comprehensive Income increased by $325,000, from a $250,000 loss at March 31, 2009 to a $75,000 gain at June 30, 2009, as discussed in Note 5.

NOTE 9 — MATERIAL RELATED PARTY TRANSACTIONS

We had no material related party transactions during the six-month period ended June 30, 2009.

NOTE 10 — COMMITMENTS AND CONTINGENCIES

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

North Finn Option

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

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

As North Finn has not exercised its right nor made a commitment to exercise, under the AICPA Emerging Issues Task Force Interpretation 96-18, the value of North Finn’s right is not currently recognized in our financial statements.

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

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

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

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

Fetter Project (Powder River Basin, Wyoming)

Our Fetter project, located in the southern Powder River Basin of Wyoming, currently encompasses approximately 53,000 gross acres. We own a 69.375% working interest in approximately 49,000 net acres, giving us approximately 34,000 total net acres at Fetter. Red Technology Alliance, LLC (“RTA”) owns a 25% working interest and North Finn LLC retains the remaining 5.625% working interest. The drilling and completion operations have been project managed by Halliburton Energy Services, Inc.

We continue to progress toward establishing a commercially successful drilling program within our Fetter project area. Currently, our activities include a re-entry program that could enable us to establish production from formations in addition to the primary Frontier formation.

During the second quarter, 2009, we performed a re-entry of the Wallis 6-23 well to evaluate the Mowry and Dakota formations, which are below the Frontier formation. Natural gas was encountered in both formations, however mechanical issues have resulted in inconsistent flow rates. We have placed the well on production from all three of these formations and will continue to monitor the performance of the well.

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Our current operations consist of continuing the re-entry program, and we have identified up to five wells that we will focus on in these efforts. Our plans are to re-enter these wells to set a removable bridge plug above the Frontier formation and complete and fracture stimulate the Niobrara formation. After production testing of only the Niobrara formation, we expect to remove the temporary bridge plug and flow the wells from both the Niobrara and Frontier formations. We do not expect to perform these operations in a continual fashion, rather we expect to perform a single re-entry, monitor the production and make changes (if deemed necessary) before moving to the next well. We expect this re-entry program could take three to six months.

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

Goliath Bakken Project (Williston Basin, North Dakota)

Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are targeting both the middle member of the Bakken and Three Forks formations in the North Dakota portion of the Williston Basin. In late June and mid-July 2009, we increased our working interest in the approximate 87,000 gross acre Goliath project from a 50% working interest to a 95% working interest in approximately 63,000 net acres. We increased our interest through two separate and unrelated transactions with Teton Energy Corporation and privately held Evertson Energy Partners.

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

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

We do not expect to expend substantial additional capital within the Goliath project during 2009. We expect to be able to bring in an outside participant to pay for all or a substantial portion of one or more wells, in return for an ownership interest in Goliath. Recent and continued success by other companies west of the Nesson anticline has provided increased interest for our Goliath acreage position.

Advancements in drilling and completion techniques that have resulted in successful Bakken wells by other operators west of the Nesson Anticline, will be incorporated into future drilling at Goliath. We also expect that future drilling will be designed to provide important reservoir and geological data from other prospective formations in the project area, primarily focused on the Three Forks formation.

Krejci Oil Project (Powder River Basin, Wyoming)

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

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Other companies are now either drilling or planning to drill wells targeting the Mowry formation in the middle and southern parts of the Powder River Basin, and we will be evaluating the level of success these other companies have with their drilling, stimulation and completion operations. We do not expect to incur significant capital expenditures in the Krejci project unless or until other companies are successful in establishing commercial production from the Mowry formation. However, we are participating in a vertical well and own an approximate 9% working interest in a well operated by a third-party oil and gas company. This well has been drilled and completed vertically in the Mowry formation. The well has recently been placed on production, and we are monitoring the performance of the well. Because of the results of this vertical well, the third-party oil and gas company is planning additional drilling in this area.

Bigfoot Project (Rocky Mountain Region)

We currently control approximately 157,000 net acres in a project that we call Bigfoot. This is a shallow natural gas project located in the Rocky Mountain region. We have begun to drill test wells in this area and expect to continue field operations as we evaluate the commercial viability of the area.

Results of Operations

The following discussion should be read in conjunction with the audited financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008. It also should be read in conjunction with the financial statements and notes thereto included in this report.

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

For the quarter ended June 30, 2009, we recorded a net loss attributable to common stockholders of $1,600,118 ($0.03 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $945,094 ($0.02 loss per common share, basic and diluted) for the quarter ended June 30, 2008. The $655,024 increase in loss includes approximately $500,000 in expenses relating to third party financial advisory services.

For the quarter ended June 30, 2009, we recorded total oil and gas revenues of $517,478 compared with $937,361 for the quarter ended June 30, 2008. The $419,883 decrease from the 2008 quarter is attributable exclusively to lower oil and gas prices. Oil and gas sales and production costs are summarized in the following table:

	Three months ended June 30,
	2009			2008
Oil sold (barrels)		5,401			4,866
Average oil price	$	44.88		$	114.91
Oil revenue	$	242,383		$	559,135
Gas sold (mcf)		82,023			34,712
Average gas price	$	3.35		$	10.90
Gas revenue	$	275,095		$	378,226
Total oil and gas revenues	$	517,478		$	937,361
Less lease operating expenses		(270,250	)		(295,830	)
Less oil & gas amortization expense		(221,000	)		(420,000	)
Less accretion of asset retirement obligation		(10,567	)		(8,247	)
Less impairment of materials & supplies inventory		(156,139	)		—
Producing revenues less direct expenses		(140,478	)		213,284
Less depreciation of office facilities		(19,172	)		(19,087	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(1,412,805	)		(1,101,105	)
Income (loss) from operations	$	(1,617,455	)	$	(951,908	)
Total barrels of oil equivalent (“boe”) sold		19,072			10,651
Revenue per boe sold	$	27.13		$	88.01
Lease operating expense per boe sold	$	14.17		$	27.77
Amortization expense per boe sold	$	11.59		$	39.43

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

For the quarters ended June 30, 2009 and June 30, 2008, we incurred $1,412,805 and $1,101,105, respectively, in general and administrative expenses. The $311,700 increase is largely attributable to (i) approximately $500,000 of costs in the 2009 period relating to third-party financial advisory services less (ii) $240,000 in land department costs capitalized in the 2009 period.

The Six-month Period ended June 30, 2009 Compared with the Six-month Period ended June 30, 2008

We recorded net loss attributable to common stockholders of $5,491,481 ($0.11 loss per common share, basic and diluted) for the six-month period ended June 30, 2009, as compared to net loss attributable to common stockholders of $2,265,519 ($0.05 loss per common share, basic and diluted) for the six-month period ended June 30, 2008. The approximately $3.2 million increase in loss is largely attributable to (i) a $2,100,000 unfavorable change (before tax effects) in impairment of oil and gas properties and (ii) a $980,000 net unfavorable change in deferred income tax expense. Various other significant, but offsetting, changes occurred as shown in the table below.

For the six months ended June 30, 2009, we recorded total oil and gas revenues of $823,152 compared with $1,445,165 for the six months ended June 30, 2008. The $622,013 decrease from the six months ended June 30, 2008, is attributable to significantly lower oil and gas prices in the 2009 period, as shown in the table below:

	Six months ended June 30,
	2009			2008
Oil sold (barrels)		9,179			7,894
Average oil price	$	40.33		$	102.23
Oil revenue	$	370,192		$	806,966
Gas sold (mcf)		133,437			63,928
Average gas price	$	3.39		$	9.98
Gas revenue	$	452,960		$	638,199
Total oil and gas revenues	$	823,152		$	1,445,165
Less lease operating expenses		(569,925	)		(550,605	)
Less oil & gas amortization expense		(334,000	)		(710,000	)
Less accretion of asset retirement obligation		(20,220	)		(16,332	)
Less impairment of materials & supplies inventory		(156,139	)		—
Less impairment of oil and gas assets		(2,100,000	)		—
Producing revenues less direct expenses		(2,357,132	)		168,228
Less depreciation of office facilities		(38,315	)		(37,591	)
Less amortization of other intangible asset		(90,000	)		(90,000	)
Less general and administrative expenses		(3,042,351	)		(2,491,313	)
Income (loss) from operations	$	(5,527,798	)	$	(2,450,676	)
Total barrels of oil equivalent (“boe”) sold		31,419			18,549
Revenue per boe sold	$	26.20		$	77.91
Lease operating expense per boe sold	$	18.14		$	29.68
Amortization expense per boe sold	$	10.63		$	38.28

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

General and administrative expenses for the six months ended June 30, 2009 increased $551,038 (22%) over the same six-month period in 2008 due primarily to the following in the 2009 period: (i) approximately $500,000 of costs relating to third-party financial advisory services, (ii) a $480,000 expense reduction due to land department costs capitalized in the 2009 period, (iii) approximately $108,000 in increased share-based compensation and (iv) approximately $308,000 in increased various other personnel costs.

We incurred approximately $100,000 in federal and state income tax liabilities for 2008 and none through the first six months of 2009. We expect to incur nominal or no income tax liabilities for the remainder of 2009.

Liquidity and Capital Resources

At June 30, 2009 and December 31, 2008, we had working capital of $19.1 million and $26.9 million, respectively. We had cash and cash equivalents at June 30, 2009 of $13.8 million.

Depending on the level of drilling activity in our Fetter project, which we expect to determine after our current re-entry activities are concluded, we anticipate capital expenditures in the six months ending December 31, 2009, to be approximately $2 million to fund our share of planned oil and gas drilling operations and other costs of oil and gas property acquisition to fund other known oil and gas related costs such as land and geological costs.

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

Net Cash Used By Operating Activities — Our net cash used by operating activities increased by $1,644,352, (from $943,056 during the six months ended June 30, 2008, to $2,587,408 for the six months ended June 30, 2009). The increase in cash usage was due primarily to (i) approximately $677,000 spent in 2009 acquiring spare inventory of well casing and tubing, carried as a current asset, (ii) approximately $500,000 spent in 2009 for third-party financial advisory services, (iii) an approximate $335,000 reduction in investment income, and (iv) an approximate $270,000 decrease in revenues due to significant declines in oil and gas prices since June 30, 2008.

Net Cash Used In Investing Activities — During the six months ended June 30, 2009, we used a net $6.9 million in investing activities as compared with $4.6 million cash provided in the six months ended June 30, 2008. The $11.5 million increase in usage of cash is primarily because the $1.6 million of cash provided by redemptions of ARPS for the 2009 period were $10.5 million less than the 2008 period’s $12.1 million of cash provided by redemptions and sales of ARPS and other securities. At the beginning of the 2009 period, we had $20.8 million more in cash and cash equivalents than we had at the beginning of the 2008 period as a source for funding investment activities.

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Net Cash Provided By Financing Activities — For the six months ended June 30, 2009, we had ample cash assets and received no cash provided by financing activities. In the six months ended June 30, 2008, we received $8,600,000 from a short-term loan in March 2008 when we were unable to liquidate ARPS at par value. The loan was repaid with ARPS redemptions in May and June 2008.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

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

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

Operating Cost Risk

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

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

Interest Rate Risk

At June 30, 2009, we had no interest-bearing debt or credit facilities, and short-term interest rates on our cash-equivalent investments were less than 0.5% per annum. At June 30, 2009, we had investments in $3,950,000 of auction rate preferred shares having dividend rates approximating 0.9% per annum at June 30, 2009. Dividend rates fluctuate weekly or monthly generally at 125% to 150% of short-term LIBOR or commercial paper rates. An increase in short-term interest rates would be favorable to us, increasing our investment income in proportion to our short-term investments and cash-equivalent investments, and likely increasing the fair value of ARPS closer to their par value.

Item 4. CONTROLS AND PROCEDURES

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

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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 1. LEGAL PROCEEDINGS

On August 6, 2009, American filed with the Financial Industry Regulatory Authority (“FINRA”) a statement of claim against Jefferies & Company, Inc. (“Jefferies”), as American’s broker with regards to auction rate preferred shares discussed in Notes 5 and 6 of American’s financial statements contained in this Form 10-Q. The statement of claim seeks in arbitration to have Jefferies (i) purchase at par value American’s remaining unredeemed ARPS, (ii) reimburse American for consequential damages (approximating $130,000 to date) and for American’s legal costs in the arbitration and (iii) pay American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions.

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the risk factors discussed in Part I, “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. There have been no material changes in our risk factors from those disclosed in our Annual Report on Form 10-K.

Item 6. EXHIBITS

Exhibit No.		Description
	3(iv)	Bylaws of the Company (as revised on June 12, 2009). (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on June 18, 2009.)
	31.1	302 Certification of Chief Executive Officer
	31.2	302 Certification of Chief Financial Officer
	32.1	906 Certification of Chief Executive Officer
	32.2	906 Certification of Chief Financial Officer

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SIGNATURES

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

Signatures	Title	Date
/s/ Patrick D. O’BrienPatrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors (principal executive officer)	August 7, 2009
/s/ Joseph B. FeitenJoseph B. Feiten	Chief Financial Officer (principal financial officer and principal accounting officer)	August 7, 2009

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EXHIBIT INDEX

Exhibit No.		Description
	3(iv)	Bylaws of the Company (as revised on June 12, 2009). (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on June 18, 2009.)
	31.1	302 Certification of Chief Executive Officer
	31.2	302 Certification of Chief Financial Officer
	32.1	906 Certification of Chief Executive Officer
	32.2	906 Certification of Chief Financial Officer

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