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

OR

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

For the transition period from                    to                    

Commission File No. 001-31900

AMERICAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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 4, 2008 were 47,811,049.

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

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	3
Condensed Consolidated Balance Sheets — June 30, 2008 and December 31, 2007	3
Condensed Consolidated Statements of Operations — Three and Six Months Ended June 30, 2008 and 2007	4
Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2008 and 2007	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3. Quantitative and Qualitative Disclosure about Market Risk	23
Item 4. Controls and Procedures	23
PART II. OTHER INFORMATION
Item 1A. Risk Factors	24
Item 4. Submission of Matters to a Vote of Security Holders	24
Item 6. Exhibits	24
Signatures	25
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

2

PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2008			2007
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,064,244		$	2,388,219
Short-term investments		5,336,000			18,302,900
Trade receivables		1,023,637			566,789
Prepaid expenses		100,128			149,440
Inventory		40,904			40,904
Current deferred income tax assets		169,406			347,658
Total current assets		12,734,319			21,795,910
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $46,577,569 at 6/30/08 and $40,937,747 at 12/31/07)		67,909,338			56,987,732
Other property and equipment		354,082			338,614
Total property and equipment		68,263,420			57,326,346
Less-accumulated depreciation, depletion and amortization		(4,442,397	)		(3,694,805	)
Net property and equipment		63,821,023			53,631,541
OTHER ASSETS
Goodwill		11,670,468			11,670,468
Other intangible asset, net of accumulated amortization		330,000			420,000
Drilling prepayments		—			542,876
Long-term deferred income tax assets		225,249			—
Other		30,385			30,385
	$	88,811,444		$	88,091,180
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	4,711,087		$	1,568,806
Preferred dividends payable		257,823			261,648
Total current liabilities		4,968,910			1,830,454
LONG-TERM LIABILITIES
Asset retirement obligations		337,122			323,369
Deferred income taxes		—			1,060,003
Total long-term liabilities		337,122			1,383,372
COMMITMENTS AND CONTINGENCIES(Note 13)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value; authorized 400,000 shares; issued and outstanding: 126,888 shares at 6/30/08 and 138,000 shares at 12/31/07; redemption value of $7,109,775 at 6/30/08 and $7,713,648 at 12/31/07		127			138
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding shares: 46,592,085 at 6/30/08 and 46,434,063 at 12/31/07		46,592			46,434
Additional paid-in capital		90,541,117			89,426,687
Accumulated deficit		(6,861,424	)		(4,595,905	)
Accumulated other comprehensive income (loss) (Note 6)		(221,000	)		—
		83,505,412			84,877,354
	$	88,811,444		$	88,091,180

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

3

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three months ended						Six months ended
	June 30						June 30
	2008			2007			2008			2007
REVENUES
Oil and gas sales	$	937,361		$	404,090		$	1,445,165		$	799,590
Other revenues		—			12,000			—			12,000
		937,361			416,090			1,445,165			811,590
OPERATING EXPENSES
Lease operating		295,830			149,587			550,605			252,736
General and administrative		1,101,105			1,168,960			2,491,313			2,301,802
Depletion, depreciation and amortization		484,087			237,739			837,591			522,068
Accretion of asset retirement obligation		8,247			6,120			16,332			11,605
		1,889,269			1,562,406			3,895,841			3,088,211
LOSS FROM OPERATIONS		(951,908	)		(1,146,316	)		(2,450,676	)		(2,276,621	)
OTHER INCOME (LOSS)
Investment income		149,520			298,214			373,231			365,570
Gain (loss) on sale of securities		(38,368	)		108,059			(369,172	)		108,059
Impairment of short-term investments		(116,000	)		—			(116,000	)		—
Interest expense		(65,123	)		—			(88,647	)		—
		(69,971	)		406,273			(200,588	)		473,629
LOSS BEFORE INCOME TAXES		(1,021,879	)		(740,043	)		(2,651,264	)		(1,802,992	)
Income tax expense-current		—			—			—			—
Income tax expense (reduction) -deferred		(522,000	)		(194,000	)		(980,000	)		(547,000	)
NET LOSS		(499,879	)		(546,043	)		(1,671,264	)		(1,255,992	)
Less dividends on preferred stock		(145,215	)		(149,040	)		(294,255	)		(304,450	)
Less deemed dividends on warrants extension		(300,000	)		—			(300,000	)		—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS		(945,094	)	$	(695,083	)	$	(2,265,519	)	$	(1,560,442	)
NET LOSS PER COMMON SHARE:
Basic and diluted	$	(.02	)	$	(.02	)	$	(.05	)	$	(.04	)
Weighted average common shares outstanding:
Basic and diluted		46,522,849			44,973,682			46,500,670			42,455,047

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

4

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six months ended June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,671,264	)	$	(1,255,992	)
Adjustments to reconcile net loss to net cash used by operating activities:
Share-based compensation expenses		516,498			607,244
Depletion, depreciation and amortization		837,591			522,068
Accretion of asset retirement obligations		16,332			11,605
Loss on sales of short-term investments		369,172			(108,059	)
Impairment on short-term investments		116,000			—
Deferred income taxes		(980,000	)		(547,000	)
Changes in non-cash current assets and liabilities:
Decrease (increase) in receivables relating to operations		(242,730	)		(61,077	)
Decrease in advances and prepaid expenses		49,312			158,629
Increase (decrease) in accounts payable and accrued liabilities for operations		46,033			(240,361	)
Net cash used by operating activities		(943,056	)		(912,943	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from redeemed auction rate securities (Note 6)		11,450,000			—
Sales of other short-term investments		683,728			808,059
Proceeds from the sale of oil and gas properties		—			777,461
Cash paid for oil and gas properties		(7,499,179	)		(5,024,262	)
Cash paid for office equipment		(15,468	)		(3,931	)
Net cash provided (used) by investing activities		4,619,081			(3,442,673	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowing		8,600,000			—
Repayment of short-term borrowing		(8,600,000	)		—
Gross proceeds from sale of common stock		—			28,506,602
Cash paid for stock offering and issuance costs		—			(1,956,465	)
Proceeds from exercise of common stock warrants and stock options		—			368,746
Net cash provided by financing activities		—			26,918,883
NET INCREASE IN CASH		3,676,025			22,563,267
CASH, BEGINNING OF PERIOD		2,388,219			7,488,474
CASH, END OF PERIOD	$	6,064,244		$	30,051,741
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest expense	$	88,647		$	—
Cash paid for income taxes incurred	$	—		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH ACTIVITIES
Net increase in payables for capital expenditures	$	3,096,248		$	—
Conversion of preferred stock into common stock	$	600,048		$	6,048,000
Share-based compensation expense	$	516,498		$	607,244
Preferred dividends paid in shares of common stock	$	298,080		$	522,144
Drilling prepayments applied to drilling costs	$	542,876		$	218,704

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

5

AMERICAN OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(UNAUDITED)

June 30, 2008

NOTE 1 — COMPANY AND BUSINESS

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

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

NOTE 2 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying interim financial statements of American are unaudited. In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the six-month period ended June 30, 2008 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-K for the year ended December 31, 2007.

USE OF ESTIMATES— As further discussed on pages F-7 and F-8 of our Form 10-K for the year ended December 31, 2007, the preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

SIGNIFICANT ACCOUNTING POLICIES— For descriptions of the Company’s significant accounting policies, please see pages F-8 through F-11 of Form 10-K for the year ended December 31, 2007.

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

6

Amortization of oil and gas property costs is computed quarterly and not year-to-date, using the estimated proved reserves as of the end of the calendar quarter. Amortization for the fiscal year is the sum of the four quarterly amortization amounts. Management estimated the proved reserves at June 30, 2008 and June 30, 2007, with consideration of (1) the proved reserve estimates for the prior fiscal year-end prepared by independent engineering consultants and (2) significant new discoveries and significant changes during the interim period in production, ownership, and other factors underlying reserve estimates.

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

In March 2008 the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”), which relates to disclosures for derivative instruments. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We will be required to adopt SFAS No. 161 beginning January 1, 2009. We currently do not have derivative instruments, but may have such instruments in 2009.

GAS BALANCING— As of June 30, 2008 and December 31, 2007, our gas production was in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.

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

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

For the three and six month periods ended June 30, 2008 and June 30, 2007, there are no adjustments for dilution because of each period’s net loss (rather than net income) to common shareholders. Securities outstanding at June 30, 2008 that could in the future potentially dilute basic net income per share for common stockholders are described in Note 11 and include (i) our preferred stock, which was converted into 1,141,992 common shares on July 22, 2008, (ii) warrants for 950,476 shares, (iii) outstanding stock options for 3,016,000 shares (of which 1,666,250 were exercisable at June 30, 2008), and (iv) an option for 2,900,000 common shares in exchange for certain oil and gas properties.

NOTE 3 — SIGNIFICANT CHANGES IN PROVED RESERVE ESTIMATES

Our proved reserves at June 30, 2008 were estimated internally by management. The estimates are significantly greater than at December 31, 2007, as shown in the following table:

	Oil (bbls)			NGL (bbls)			Gas (mcf)
Proved reserves at December 31, 2007		96,399			53,933			1,307,159
Proved reserve revisions		(13,510	)		(19,624	)		(340,781	)
Less 2008 year-to-date production		(7,894	)		(2,352	)		(63,928	)
Proved reserve additions		219,250			65,044			1,137,656
Proved reserves at June 30, 2008		294,245			97,001			2,040,106
Percentage net change in proved reserves		205	%		80	%		56	%

7

The downward revisions are entirely attributable to two wells drilled in the second half of 2007, which had high initial production rates in late 2007 but experienced production difficulties during the second quarter of 2008, which had not been corrected by August 1, 2008.

Proved reserves additions are largely attributable to reserves estimated for ten proved undeveloped locations that directly offset producing wells. We have a 69.375% working interest in a proved gas well location which offsets our best producing gas well in the Fetter field. We have an average 9.6% working interest in three oil well locations offsetting wells producing oil from the Bakken formation in North Dakota. We have an average 19.3% working interest in six proved undeveloped oil well locations in Wyoming. For our estimated proved reserves at June 30, 2008, future undiscounted development costs at current cost rates are estimated to total $11.2 million.

For our estimated proved reserves at June 30, 2008, the standardized measure of discounted future net cash flows would approximate $15.6 million, compared with $8.3 million at December 31, 2007.

NOTE 4 — PROPERTY AND EQUIPMENT

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

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization	$	46,577,569
Evaluated costs		21,331,769
		67,909,338
Office equipment, furniture and software		354,082
		68,263,420
Less accumulated depreciation, depletion and amortization		(4,442,397	)
Property and equipment	$	63,821,023

The unevaluated costs at June 30, 2008 include $5.4 million incurred in 2007 and an additional $0.6 million in the first half of 2008 for two unevaluated wells-in-progress in the Krejci project. The wells remain unevaluated at August 1, 2008, awaiting additional stimulation work and evaluation thereof over the next few months.

Our major projects are Fetter, West Douglas, Krejci and Goliath and are described more fully in our Form 10-K for 2007. The following table presents the capitalized oil and gas properties’ costs and net additions therein for the six months ended June 30, 2008, with the unevaluated costs by major project:

	Capitalized Costs (in millions)
Project (State)	12/31/07		Net Additions			6/30/08
Fetter Project, Powder River Basin (WY)	$	14.4	$	4.8		$	19.2
West Douglas Project, Powder River Basin (WY)		4.2		0.2			4.4
Douglas Project, Powder River Basin (WY)		0.9		0.0			0.9
Krejci Oil Project, Powder River Basin (WY)		9.2		(1.1	)		8.1
Goliath Project, Williston Basin (ND)		7.0		0.0			7.0
Other projects		5.2		1.9			7.1
Total unevaluated costs	$	40.9	$	5.8		$	46.7
Evaluated Costs, net of accumulated DD&A	$	12.4	$	4.6		$	17.0

8

The $10.4 million of net additions for the first six months of 2008 consist primarily of $4.1 million of drilling at Krejci, $3.4 million of drilling at Fetter, $1.7 million of additional lease acquisitions at Fetter and $1.2 million of lease acquisitions outside of the five major projects.

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

	Six-month Period
	Ended June 30,
	2008		2007
Amortization of costs for evaluated oil and gas properties	$	710,000	$	400,818
Amortization of Other Intangible Asset		90,000		90,000
Depreciation of office equipment, furniture and software		37,591		31,250
Total DD&A expense	$	837,591	$	522,068

NOTE 5 — 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, 2008 and June 30, 2007:

	Three months ended						Six months ended
	June 30,						June 30,
	2008			2007			2008			2007
Beginning asset retirement obligation	$	329,771		$	281,944		$	323,369		$	235,268
Liabilities incurred		27,072			16,140			31,514			61,148
Liabilities settled		—			(22,898	)		—			(22,898	)
Revisions in estimated liabilities		(27,968	)		(5,295	)		(34,093	)		(9,112	)
Accretion		8,247			6,120			16,332			11,605
Ending asset retirement obligation	$	337,122		$	276,011		$	337,122		$	276,011
Current portion of obligation, end of period	$	—		$	43,556		$	—		$	43,556

NOTE 6 — SHORT-TERM INVESTMENTS

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

	June 30,		December 31,
	2008		2007
Auction-rate preferred shares at fair value	$	5,336,000	$	17,325,000
PetroHunter stock at fair value (sold prior to June 30, 2008)		—		977,900
Total, short-term investments	$	5,336,000	$	18,302,900

These short-term investments are classified under SFAS 115 as equity securities available-for-sale. Unrealized gains and temporary unrealized losses are recorded in Accumulated Other Comprehensive Loss. Unrealized losses expected to be permanent are reflected in the Condensed Consolidated Statement of Operations.

9

Auction-Rate Preferred Shares

At June 30, 2008, we owned various auction-rate preferred shares (“ARPS”) which are AAA-rated for credit risk and normally provide liquidity via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. These auctions and similar auctions have had insufficient bids to buy the ARPS from those wishing to sell, whereby (starting in mid-February 2008 and for the foreseeable future) holders of ARPS are unable to sell ARPS in the auction process. In response, issuers of all ARPS we hold announced they are investigating ways to redeem the ARPS at par value if the ARPS cannot otherwise be liquidated at par value.

Of the $17,325,000 in ARPS we held at December 31, 2007, we sold $75,000 of ARPS at par value prior to mid-February, and $11,450,000 were redeemed at par value for cash in May and June of 2008, leaving $5,800,000 of ARPS at par value held at June 30, 2008. Those remaining ARPS can be sold in a secondary market, the Restricted Securities Trading Network (“RSTN”). On June 30, 2008, we received through RSTN a third-party offer to purchase those ARPS for approximately $5,336,000 before transaction costs (primarily brokering fees) of approximately $116,000. We declined the offer and still hold the ARPS at August 7, 2008.

We believe it likely, but not assured, that of the $5,800,000 in ARPS held at June 30, 2008, approximately $3,600,000 will be redeemed at par value in the last three months of 2008 and the rest in at par value in the first quarter of 2009. However, we remain open to selling the ARPS through our broker in private sales or through a secondary market such as RSTN in the coming months, if we believe that doing so is a prudent course of action.

Our expectations of redemptions vary with the particular ARPS we hold and what news we have of plans for redemptions:

• We own $2,325,000 of ARPS in three funds that have board approval and substantially all debt financing in place to redeem 100% of remaining ARPS if and when the SEC approves their July 24, 2008, request for a two-year temporary waiver of the existing law that limits fund debt to no more than one-third of the fund’s total asset value (whereas the law allows a fund’s ARPS book value to be one-half of fund asset value).

• We own $400,000 of ARPS in a fund that plans to redeem 100% of its ARPS if and when the SEC approves the fund’s July 25, 2008, formal request to allow the fund to borrow the needed monies from a bank affiliated with the fund’s management company. The fund’s ARPS book value is less than one-third of total asset value.

• We own $1,125,000 of ARPS in a fund whose ARPS value is close to one-third of total asset value, whereby the fund could use debt to redeem $925,000 of the ARPS we own without having to request permission from the SEC.

• We own $1,950,000 of ARPS in three funds that had previously redeemed 50% of their ARPS and are seeking to redeem the remainder of their ARPS, but have not to our knowledge requested SEC permission to use debt in excess of 25% of fund asset value.

Based on the third-party offer through the RSTN secondary market, we estimate that our investment in ARPS at June 30, 2008 had a fair value of $5,336,000 on that date. The fair value is $464,000 (8%) below the ARPS $5,800,000 par value. Based in part on ARPS issuers’ expressed desires and efforts to redeem at par value in the short-term the ARPS we hold, we view the 8% unrealized loss as largely temporary. However, we recognize that redemption at par value of all our ARPS in the near-term is not certain, and we would likely liquidate any unredeemed ARPS in 2008 if in doing so the aggregate loss were no more than $116,000. Therefore, we view $116,000 of the unrealized loss as permanent and have reflected a $116,000 impairment in the consolidated statement of operations for the quarter ended June 30, 2008. The remaining $348,000 unrealized loss, net of $127,000 related deferred income tax benefit, is recorded as a $221,000 net unrealized loss in Accumulated Other Comprehensive Loss.

10

Until the ARPS are liquidated, the issuers pay dividends every 7 to 28 days at rates averaging for the ARPS we hold approximately 3.65% at June 30, 2008, or 148% of 30-day LIBOR (USD), which is a short-term benchmark interest rate.

PetroHunter Common Stock

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

NOTE 7 — NOTE PAYABLE

In March 2008, we borrowed $8,600,000 from Jefferies Group, Inc., parent of our stockbroker Jefferies & Company, Inc. The loan bore interest at an annual rate of overnight LIBOR plus 2.5%, with interest paid monthly. We repaid the loan during May and June using primarily a portion of the cash received from redemption of ARPS (see Note 6).

NOTE 8 — FAIR VALUE MEASUREMENTS

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

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

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

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

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

At December 31, 2007, our financial assets measured at fair value consisted of $18,302,900 of short-term investments. Their fair values were based on Level 1 inputs. At June 30, 2008, our financial assets and liabilities measured at fair value were as follows:

	Total at		Level 1		Level 2		Level 3
	June 30, 2008		inputs		inputs		inputs
Financial Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (see Note 6)	$	5,336,000	$	—	$	5,336,000	$	—
Financial Liabilities	$	—	$	—	$	—	$	—

As discussed in Note 6, the fair value of our investment in auction rate preferred shares was determined based on a Level 2 input.

11

NOTE 9 — GOODWILL AND OTHER INTANGIBLE ASSET

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

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

NOTE 10 — INCOME TAXES

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

We currently estimate that for the year ending December 31, 2008, our weighted average statutory income tax rate (federal and state combined) will approximate 36.5% and our effective income tax rate will approximate 37%. The effective rate differs from the statutory rate due to permanent differences primarily relating to stock options granted to employees and relating to percentage depletion. Deferred income tax reductions of $980,000 and $547,000 were reported for the six-month periods ended June 30, 2008 and 2007, respectively. We did not incur federal or state income tax liabilities for 2007 and through the first six months of 2008. We expect to incur nominal or no income tax liabilities for the remainder of 2008.

We file annual US federal income tax returns and have filed annual income tax returns for the states of Colorado, Montana, North Dakota and Utah. We primarily do business in Wyoming, but Wyoming does not impose corporate income taxes. We believe we are no longer subject to income tax examinations by tax authorities for years before 2003 for Colorado and for 2004 for all other returns. Our income tax returns and supporting records have never been examined by tax authorities.

On January 1, 2007, we adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes(“FIN 48”). We found no significant uncertain tax positions as of June 30, 2008.

12

Our policy is to recognize accrued interest related to unrecognized tax benefits in interest expense and to recognize tax penalties in operating expense. However, given our substantial net operating loss carryforwards at the federal and state levels, we do not anticipate any interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2009 as such adjustments would very likely simply reduce our net operating loss carryforwards.

NOTE 11 — EQUITY

Common Stock

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

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

• Additional Paid-In Capital also increased by $300,000 and Accumulated Deficit increased by $300,000 for recognition of a deemed dividend at fair value for the extension of certain warrants as discussed further in this Note 11.

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

The following transactions occurred during the quarter ended March 31, 2008 with regard to our common stock:

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

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

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

Preferred Stock

At June 30, 2008 there were a total of 126,888 shares of Series AA Convertible Preferred Stock (“Preferred Stock”) outstanding. On July 22, 2008, the 126,888 shares of preferred stock automatically converted into 1,141,992 shares of common stock. Effective that same day, we paid the final semi-annual preferred stock dividend.

13

Warrants

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

	Common		Exercise		Expiration
Issue Date	Shares		Price		Date
April 16, 2008		50,000	$	7.00	April 16, 2013
July 22, 2005		835,626	$	6.00	June 30, 2009
September 15, 2003		20,000	$	1.15	September 15, 2008
July 23, 2003 to September 24, 2003		44,850	$	0.75	September 24, 2008
		950,476

At June 30, 2008, the per-share weighted average exercise price of outstanding warrants was $5.70 per share, and the weighted average remaining contractual life was 14 months.

We granted on April 16, 2008, to a third-party company a warrant to be issued after seven months of services by the company. The warrant expires on April 16, 2013, and is for 50,000 shares of our common stock at an exercise price of $7.00 per share. We estimated the warrant’s fair value at April 16, 2008 to be $16,700 using the Black-Scholes valuation model. For the model, we assumed an expected option life of 2.8 years, an annual volatility of 45%, an annual risk-free interest rate of 2%, a 0% dividend yield and a 0% pre-vesting forfeiture rate.

For the aforementioned outstanding warrants issued July 22, 2005, we extended on June 20, 2008, their expiration dates to June 30, 2009. Prior to the extension, the warrants were to expire on June 30, 2008 or July 21, 2008. Using a Black-Scholes valuation model, we estimated the fair value of the extension to be $300,000 and recognized in June 2008 a $300,000 deemed dividend for the warrant extensions

Stock Options

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

Under our 2006 Stock Incentive Plan (the “2006 Plan”), up to 1,500,000 additional shares of common stock may be issued to employees, directors and other persons who provide services to the Company. Issuance of those shares may be by stock option awards, restricted stock awards or restricted stock unit awards. At June 30, 2008, 472,275 shares were available to be granted pursuant to the 2006 Plan.

In January 2006, we entered into a participation agreement with North Finn (“North Finn”). An element of that agreement is that North Finn has an option until July 31, 2012 to receive 2,900,000 shares of our common stock in exchange for certain oil and gas rights held by North Finn. A second element is that beginning on August 1, 2010 until July 31, 2012, we have an option to require North Finn to exchange those property interests in return for the 2,900,000 shares. As North Finn has not exercised its option nor made a commitment to exercise under the AICPA Emerging Issues Task Force Interpretation 96-18, the value of North Finn’s option is not currently recognized in our financial statements. The option and the participation agreement are discussed in Note 13Commitments and Contingencies.

14

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

				Weighted
				Average
	Number of			Exercise
	Shares			Price
Options outstanding — December 31, 2007 (1,359,500 exercisable)		2,515,000		$	4.04
Options granted in the six months ended June 30, 2008		510,000		$	3.44
Less options forfeited in the six months ended June 30, 2008		(9,000	)	$	3.37
Less options exercised in the six months ended June 30, 2008		—
Options outstanding — June 30, 2008 (1,666,250 exercisable)		3,016,000		$	3.94

The weighted-average, grant-date estimated fair value of stock options granted during the quarter ended June 30, 2008 was $1.05 per underlying common share. The following valuation models and key model assumptions were used for the significant options granted in the six-month periods ended June 30, 2008 and June 30, 2007:

	June 30, 2008		June 30, 2007
	Modified		Modified
Model	Binomial		Binomial
Option life (in years)		4		4 to 5
Annual volatility over option life		45%		35%
Annual volatility for black-out periods		0%		0%
Risk-free interest rate		2.3%	4.7% to 5.1%
Pre-vesting forfeiture rate		12%		0%
Dividend yield		0%		0%
Intrinsic Value /share that urges exercise		$2.00		$2.00 to $2.16

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

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

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

15

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

	Exercise		Remaining
	price		contractual		Number of shares
	per share		life (years)		Outstanding		Exercisable
	$	1.25		1.64		403,000		403,000
	$	2.38		2.50		100,000		100,000
	$	2.48		2.53		80,000		80,000
	$	3.34		6.80		21,000		—
	$	3.37		6.80		465,000		—
	$	3.66		4.31		750,000		500,000
	$	4.30		4.42		9,000		6,000
	$	4.57		4.59		9,000		6,000
	$	4.66		3.84		20,000		20,000
	$	4.95		8.00		250,000		130,000
	$	4.98		5.31		200,000		90,000
	$	5.15		5.92		30,000		10,000
	$	5.80		4.62		75,000		35,000
	$	5.84		6.91		400,000		140,000
	$	6.03		4.63		195,000		146,250
	$	6.70		6.05		9,000		—
						3,016,000		1,666,250
Weighted Ave. remaining contractual life					5.0 years		4.1 years
Aggregate intrinsic value, June 30, 2008					$	—	$	568,512

Other Comprehensive Income

During the six-months ended June 30, 2008, Other Comprehensive Income decreased by $221,000 to reflect a temporary decline in the fair value of short-term investments, net of related deferred income taxes, as discussed in Note 6.

NOTE 12 — MATERIAL RELATED PARTY TRANSACTIONS

We had no material related party transactions during the six-month period ended June 30, 2008.

NOTE 13—COMMITMENTS AND CONTINGENCIES

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

North Finn Option

On January 5, 2006, we entered into a participation agreement with North Finn LLC (“North Finn”). Under the agreement, we fund 60% of North Finn’s subsequent lease, drilling and other project related capital obligations in jointly owned project areas, in order to earn 60% of North Finn’s interest in that particular lease or well, including offset locations. We paid $535,000, and reimbursed approximately $976,000 to North Finn for 60% of all project related costs that North Finn has incurred in jointly owned project areas after the effective date of August 1, 2005.

Under the participation agreement, the Company and North Finn each has the right (an option), during specified time periods, to trigger the transfer to the Company by North Finn of 60% of North Finn’s interests in any unearned project areas in which the Company already has an interest, and a simultaneous issuance by the Company to North Finn of 2,900,000 restricted shares of the Company’s common stock. North Finn’s right of exchange is exercisable at any time on or before July 31, 2012, and the Company’s right of exchange is exercisable at any time beginning August 1, 2010 and ending July 31, 2012. If the exchange occurs and the Company receives the 60% interest from North Finn, the Company will not earn or fund any additional interests in the North Finn acreage under the participation agreement. In many of the joint project areas, North Finn owns a 25% working interest, and the Company owns a 75% working interest.

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

16

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

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

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

This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. There are a number of risks and uncertainties that could cause our actual results to differ materially from those indicated by such forward-looking statements. These risks and uncertainties include, but are not limited to, those described in this report, in Part II, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, and those described from time to time in our future reports filed with the SEC.

Overview

We are an independent oil and gas exploration and production company, engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States. Our current operations are focused primarily in three main project areas that we call Douglas, Krejci and Goliath. Our Douglas project area includes our Fetter and West Douglas projects. We are also in the early stages of working in additional project areas where we are currently leasing additional acreage and performing geological evaluations. The following project updates should be read in conjunction with our Annual Report on Form 10-K for our fiscal year ended December 31, 2007.

17

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

Our Fetter project currently encompasses approximately 56,000 gross acres, and we own a 92.5% working interest in approximately 53,000 leased net acres. We are essentially finished with drilling and completing initial wells pursuant to a participation agreement with Red Technology Alliance, LLC (“RTA”) whereby RTA has agreed to pay 100% of the costs to drill and complete two horizontal wells and one vertical well in the Fetter project area. We have been carried through the tanks in this phase of the drilling program and own a 23.125% working interest in each of the three wellbores. Upon completion of this initial drilling program, RTA will earn a 25% working interest in the undrilled acreage, and we will retain a 69.375% working interest, giving us approximately 36,000 net acres at Fetter. North Finn LLC will retain the remaining 5.625% working interest. The drilling and completion operations are project managed by Halliburton Energy Services, Inc.

We made significant progress in the Fetter area during the second quarter 2008. All three of the wells pursuant to the RTA agreement have been drilled and completed and are now producing into the sales line. Although the production for most of the second quarter was inconsistent due primarily to testing, repairs and maintenance of the main natural gas pipeline connected to the Douglas natural gas processing plant, we expect that the pipeline issue has now been remedied and we will no longer be subject to extended shut-ins due to pipeline constraints.

Plunger lifts have been installed in the Hageman 16-34HR well (a horizontal Frontier formation completion) and the Wallis 6-23 well (a vertical well currently undergoing extended testing exclusively from the Frontier formation) that are designed to assist in lifting the high gravity oil which is producing from the Frontier formation in both wells. Both wells have initially shown favorable response relative to prior production. The Sims 15-26H well (a horizontal Frontier completion), which first went on production in the summer of 2007, continues to produce at rates recently averaging approximately one mmcfe/day. The State 4-36 well (drilled in 2006 and completed vertically in an unstimulated 50 foot interval within the Frontier formation) also continues to produce. Production optimization efforts are ongoing on all four wells.

During the second quarter, we drilled the Hageman 11-22 and Hageman 11-22UK wells. Both of these wells were drilled in section 22 of T33N-R71W, Converse County, WY. The Hageman 11-22 well is currently undergoing completion operations, as we attempt to complete the well in the Dakota, Muddy, Mowry, Frontier and potentially, the Niobrara and Steele formations.

While drilling the Hageman 11-22 well, mud log and electronic log analysis indicated potential oil pay in the shallower, normally pressured Teapot and Parkman formations at depths of approximately 7,710’ and 8,200’, respectively. In order to determine whether or not we have a discovery in either or both of these formations, we brought in an additional drilling rig and are completing the Hageman 11-22UK well. We recently fracture stimulated the Teapot formation and after swabbing back frac fluid, we expect to install a pumping unit and place the well on production. Depending on the level of success with this well, we may bring a second drilling rig into the Fetter area under a long term contract and continue drilling wells that target the Teapot and Parkman formations. This drilling activity would be in addition to the current drilling program that targets the deeper, over-pressured formations.

In order to continue the deeper drilling program at Fetter, during the second quarter we, along with RTA and North Finn LLC, signed a 12-month contract to secure a drilling rig for a multi-well drilling program. We have identified, surveyed and permitted a number of drilling locations that would support either vertical or horizontal wells and will continually evaluate the appropriate drilling approach to maximize reserve and cash flow growth.

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

We are in the final stages of drilling and completing the State Deep 7-16 well pursuant to a participation agreement with RTA, whereby RTA has agreed to pay 100% of the costs to drill and complete this well. We are being carried through the tanks in this well and will own a 45% working interest. Upon completion of this well, RTA will earn a 50% working interest in the undrilled acreage, and we will retain a 45% working interest. North Finn LLC will retain the remaining 5% working interest. The drilling and completion operations are project managed by Halliburton Energy Services, Inc.

18

Similar to the Wallis 16-23 well in our Fetter project, the State Deep 7-16 well is designed to evaluate the productive potential of the Dakota, Mowry, Frontier, Niobrara and Steele formations. This initial well has been drilled to total depth of 14,255 feet, and completion and testing operations are continuing.

Krejci Oil Project (Powder River Basin, Wyoming)

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

We have participated in the drilling and completion of four wells so far in the Krejci project. The first two wells drilled are producing, and the latest two wells are shut-in while we evaluate additional stimulation techniques. Although we currently have production from two of the four wells, we do not consider those wells to be commercially successful. Based on information gained from the first four wells, we have participated in the drilling of a fifth well, the Krejci Family Trust 32-1H well.

The Krejci Family Trust 32-1H well has been placed on pump and is currently producing approximately 20 barrels of oil per day as well as returning frac fluids. We expect that as the well cleans up, oil production may increase. We completed the horizontal portion of this well with a swell-packer system, which allowed for multi-stage fracture stimulation. We expect to continue drilling wells at Krejci to further refine the completion and stimulation techniques and we anticipate that near term plans by other operators to drill Mowry wells in the southern Powder River Basin could accelerate the learning curve.

Goliath Bakken Project (Williston Basin, North Dakota)

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

We own an interest in the currently producing Champion 1-25H well that was drilled and completed in the Bakken formation in 2006. This well is a productive well; however we drilled and completed this well using drilling and completion methods that are different than the approach used today by other operators who are completing commercially productive wells. We have performed additional geological and geophysical evaluations, and we believe that by combining our understanding of the Bakken formation within our Goliath project acreage with the drilling and completion approaches used successfully by other operators, we will be able to drill commercially successful wells that target the Bakken formation. Accordingly, we are planning to commence drilling our next Bakken well before year-end 2008.

Our Goliath acreage position offers the opportunity for oil and gas production from formations other than the Bakken, and in late 2007, we participated in the drilling of the Solberg 32-2 well with a non-operated 11.9% working interest (a net revenue interest of approximately 9.5%). This well was drilled to a total depth of approximately 14,400 feet as an offset to a Red River formation discovery well that was drilled and is owned by another operator. The Solberg 32-2 well which was successfully completed in May 2008 at rates averaging 1.45 mmcf/day of natural gas and 75 bbls/day of oil, has recently averaged approximately 1.8 mmcf/day of natural gas and 90 bbls/day of oil.

19

In early 2008, we and other joint interest owners in the Goliath project completed a 10.5 square mile 3-D seismic program in the area around the Solberg 32-2 well. Based on interpretation of the data, we have identified additional potential for production from the Red River formation, and we are planning to drill additional Red River wells. We have permitted and built location for the next well and expect to commence drilling operations during the third quarter 2008, subject to rig availability.

Results of Operations

The following discussion should be read in conjunction with the audited financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007. It also should be read in conjunction with the financial statements and notes thereto included in this report.

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

For the quarter ended June 30, 2008, we recorded a net loss attributable to common stockholders of $945,094 ($0.02 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $695,083 ($0.02 loss per common share, basic and diluted) for the quarter ended June 30, 2007. The $250,011 increase in loss is due to the current quarter’s $300,000 deemed dividend as well as losses on short-term investments which were profitable in the prior year’s corresponding quarter.

For the quarter ended June 30, 2008, we recorded total oil and gas revenues of $937,361 compared with $404,090 for the quarter ended June 30, 2007. The $533,271 increase from the 2007 quarter is attributable to both higher oil and gas prices and higher sales volumes as shown in the table below:

	Three months ended
	June 30,
	2008			2007
Oil sold (barrels)		4,866			4,501
Average oil price	$	114.91		$	59.40
Oil revenue	$	559,135		$	267,365
Gas sold (mcf)		34,712			23,695
Average gas price	$	10.90		$	5.77
Gas revenue	$	378,226		$	136,725
Total oil and gas revenues	$	937,361		$	404,090
Less lease operating expenses		(295,830	)		(149,587	)
Less oil & gas amortization expense		(420,000	)		(177,000	)
Less accretion of asset retirement obligation		(8,247	)		(6,120	)
Producing revenues less direct expenses		213,284			71,383
Less depreciation of office facilities		(19,087	)		(15,739	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(1,101,105	)		(1,168,960	)
Add other revenue		—			12,000
Loss from operations	$	(951,908	)	$	(1,146,316	)
Total barrels of oil equivalent (“boe”) sold		10,651			8,450
Lease operating expense per boe sold	$	27.77		$	17.70
Amortization expense per boe sold	$	39.43		$	20.95

20

For the quarters ended June 30, 2008 and 2007, we incurred $1,101,105 and $1,168,960, respectively, in general and administrative expenses.

The Six-month Period ended June 30, 2008 Compared with the Six-month Period ended June 30, 2007

We recorded net loss attributable to common stockholders of $2,265,519 ($0.05 per common share, basic and diluted) for the six-month period ended June 30, 2008, as compared to net loss attributable to common stockholders of $1,560,442 ($0.04 per common share, basic and diluted) for the six-month period ended June 30, 2007. The approximately $700,000 increase in loss is largely attributable to the approximately $700,000 unfavorable change (before tax effects) in other income and losses relating to short-term investments.

For the six months ended June 30, 2008, we recorded total oil and gas revenues of $1,445,165 compared with $799,590 for the six months ended June 30, 2007. The $645,575 increase from the six months ended June 30, 2007, is attributable to both higher oil and gas prices and greater sales volumes as shown in the table below:

	Six months ended June 30,
	2008			2007
Oil sold (barrels)		7,894			8,835
Average oil price	$	102.23		$	55.47
Oil revenue	$	806,966		$	490,094
Gas sold (mcf)		63,928			50,715
Average gas price	$	9.98		$	6.10
Gas revenue	$	638,199		$	309,496
Total oil and gas revenues	$	1,445,165		$	799,590
Less lease operating expenses		(550,605	)		(252,736	)
Less oil & gas amortization expense		(710,000	)		(400,818	)
Less accretion of asset retirement obligation		(16,332	)		(11,605	)
Producing revenues less direct expenses		168,228			134,431
Less depreciation of office facilities		(37,591	)		(31,250	)
Less amortization of other intangible asset		(90,000	)		(90,000	)
Less general and administrative expenses		(2,491,313	)		(2,301,802	)
Add other revenue		—			12,000
Income (loss) from operations		(2,450,676	)		(2,276,621	)
Total barrels of oil equivalent (“boe”) sold		18,549			17,287
Lease operating expense per boe sold	$	29.68		$	14.62
Amortization expense per boe sold	$	38.28		$	23.19

21

General and administrative expenses for the six months ended June 30, 2008 increased $189,511 (8.23%) over the same six-month period in 2007. The major changes in general and administrative expenses were (1) a $411,000 increase in employee compensation arising from an increase in the number of employees and the payment of a greater number of annual bonuses in early 2008 than paid in early 2007 and (2) a $185,000 decrease in external accounting, auditing and legal expenses relating to compliance with SEC reporting requirements.

We did not incur federal or state income tax liabilities for 2007 and through the first six months of 2008. We expect to incur nominal or no income tax liabilities for the remainder of 2008. Should we have federal taxable income for 2008, we can reduce such income by 90% using our federal net operating loss carryforward, which approximated $15 million at December 31, 2007.

Dividends on preferred stock for the 2008 period declined slightly from the 2007 period due to conversion of a small number of preferred shares into common stock. On July 22, 2008, all preferred stock converted to common stock and ended subsequent payments of preferred stock dividends.

Liquidity and Capital Resources

At June 30, 2008, we had $7.8 million in working capital. We had cash and cash equivalents at June 30, 2008 of $6.1 million. Working capital includes investments in Auction Rate Preferred Shares (ARPS), which had a fair value of $5,336,000 at June 30, 2008. Liquidity of the ARPS is discussed more fully in Note 6 to the financial statements contained in this Form 10-Q.

In the first six months of 2008, we incurred nearly $11 million of capital expenditures, as further explained in Note 4 of the accompanying financial statements. We currently anticipate capital expenditures for the last six months of 2008 to be approximately $9 million. We intend to fund these capital expenditures, other commitments and working capital requirements primarily with existing capital and expected improved cash flow from operations, as well as selling down our ownership interests in core area projects or selling out of certain peripheral projects. We may also fund these capital expenditures with the sale of debt or equity, although there is no assurance that debt or equity sales will be available to us on favorable terms.

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

Net Cash Used By Operating Activities — Our net cash used by operating activities increased by $30,113 (from $912,943 for the six months ended June 30, 2007, to $943,056 for the six months ended June 30, 2008. The 3% net increase arises from several offsetting factors such as increased revenues partially offset by increased expenses and partially offset by delays in receiving payment of revenues on new wells’ production until royalty ownerships are confirmed.

Net Cash Provided (Used) By Investing Activities — During the six months ended June 30, 2008, we provided a net $4.6 million from investing activities as compared with $3.4 million used in the six months ended June 30, 2007. The $8.0 million increase in cash is primarily due to $12.1 million in redemptions and sales of short-term investments in equity securities during the six months ended June 30, 2008.

Net Cash Provided By Financing Activities — In the six-months ended June 30, 2008, our only financing activities were to borrow $8.6 million secured by our ARPS investments and repay the loan by late June using proceeds from redemptions of some ARPS. During the six months ended June 30, 2007, we received $26.9 million in cash provided from the sale of common stock in a public offering and from exercise of warrants and stock options.

22

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

Because of our relatively low level of current oil and gas production, we are not exposed to a great degree of market risk relating to the pricing applicable to our oil and natural gas production. However, our ability to raise additional capital at attractive pricing, our future revenues from oil and gas operations, our future profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. We expect oil and gas price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.

Operating Cost Risk

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

Interest Rate Risk

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

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, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

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

23

PART II.
OTHER INFORMATION

Item 1A . RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the risk factors discussed in Part I, “Item 1A Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. There have been no material changes in our risk factors from those disclosed in our Annual Report on Form 10-K.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

American Oil & Gas, Inc. held its annual meeting of shareholders on June 30, 2008. At the meeting, five individuals were re-elected as Directors pursuant to the following votes:

	Shares Voted
Nominee	For		Against		Abstain
Patrick D. O’Brien		23,316,424		402,408		49,642
Andrew P. Calerich		22,850,708		865,138		52,628
M.S. (“Moni”) Minhas		23,525,203		191,443		51,828
Nick DeMare		20,788,137		2,928,659		51,678
Jon R. Whitney		23,073,528		642,968		51,978

Shareholders also ratified the appointment of HEIN & ASSOCIATES LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2008, with 23,688,331 votes for ratification, 36,076 votes against and 44,067 votes abstaining.

As disclosed on Form 8-K filed July 25, 2008, Mr. Minhas resigned on July 22, 2008, as a director; and the Board elected Scott Hobbs to serve as a director on the Board. Mr. Minhas did not resign due to any disagreement with the Company on any matter relating to the Company’s operations, policies, disclosures and/or practices.

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

24

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	August 8, 2008
/s/ Joseph B. FeitenJoseph B. Feiten	Chief Financial Officer	August 8, 2008

25

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

26