Form 10-Q

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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, 2010


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

For the transition period from to

Commission File No. 1-31900

AMERICAN OIL & GAS INC.

(Exact name of registrant as specified in its charter)


Nevada		88-0451554

(State or jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1050 17^th Street, Suite 2400, Denver, CO		80265

(Address of principal executive offices)		(Zip Code)

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

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

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

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

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

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

The total shares of $.001 Par Value Common Stock outstanding at August 10, 2010 were 61,004,656.

PART I


ITEM 1.		FINANCIAL STATEMENTS

AMERICAN OIL & GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)


	June 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	50,071,553		$	40,632,284
Short-term investment		1,750,000			2,925,000
Accounts receivable		6,390,679			564,533
Well equipment inventory		5,013,031			1,269,774
Prepaid expenses		177,771			149,991
Current deferred tax assets		76,763			—

Total current assets		63,479,797			45,541,582

PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $58,983,403 at 6/30/10 and $35,611,363 at 12/31/09)		86,494,596			44,454,942
Other property and equipment		430,577			406,273

Total property and equipment		86,925,173			44,861,215
Less-accumulated depreciation, depletion and amortization		(6,761,144	)		(5,771,547	)

Net property and equipment		80,164,029			39,089,668
OTHER ASSETS
Drilling prepayments		445,718			—
Intangible asset, net of accumulated amortization		—			60,000
Other		80,652			80,652

	$	144,170,196		$	84,771,902

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	11,203,559		$	1,032,248
Income taxes payable		200,000			—

Total current liabilities		11,403,559			1,032,248

LONG-TERM LIABILITIES
Asset retirement obligations		151,308			436,487
Deferred income taxes		6,444,763			—

Total long-term liabilities		6,596,071			436,487

COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS’ EQUITY
Preferred stock, $.001 par value, authorized 24,100,000 shares; no outstanding shares at 06/30/10 and 12/31/09		—			—
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding — 60,814,656 shares at 6/30/10, 57,472,399 shares at 12/31/09		60,815			57,472
Additional paid-in capital		137,364,064			122,267,594
Accumulated deficit		(11,316,313	)		(39,096,899	)
Accumulated other comprehensive income		62,000			75,000

Total equity		126,170,566			83,303,167

	$	144,170,196		$	84,771,902

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

AMERICAN OIL & GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATION
(UNAUDITED)


	Three months ended						Six months ended
	June 30						June 30
	2010			2009			2010		2009
REVENUES:
Oil and gas sales	$	2,417,564		$	517,478		$	3,277,535	$	823,152


OPERATING EXPENSES:
Lease operating		623,862			270,250			865,271		569,925
General and administrative		1,361,273			1,412,805			3,364,002		3,044,351
Depletion, depreciation and amortization		738,897			285,172			1,049,598		462,315
Impairment of oil & gas properties		—			—			—		2,100,000
Impairment of well equipment inventory		173,785			156,139			173,785		156,139
Accretion of asset retirement obligation		2,895			10,567			13,108		20,220

		2,900,712			2,134,933			5,465,764		6,352,950

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

INCOME (LOSS) FROM OPERATIONS		(483,148	)		(1,617,455	)		34,211,771		(5,529,798	)

OTHER INCOME (LOSS):
Investment income		67,020			17,337			98,815		38,317

INCOME (LOSS) BEFORE INCOME TAXES		(416,128	)		(1,600,118	)		34,310,586		(5,491,481	)
Income tax provision -current		—			—			200,000		—
Income tax provision (benefit) -deferred		(162,000	)		—			6,330,000		—

NET INCOME (LOSS)		(254,128	)		(1,600,118	)		27,780,586		(5,491,481	)


NET INCOME (LOSS) PER SHARE:
Basic	$	0.00		$	(0.03	)	$	0.47	$	(0.11	)
Diluted	$	0.00		$	(0.03	)		0.46	$	(0.11	)
Weighted average common shares outstanding:
Basic		60,719,700			48,307,399			59,160,407		48,273,382
Diluted		60,719,700			48,307,399			60,391,569		48,273,382

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

AMERICAN OIL & GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)


	Six months ended
	June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	27,780,586		$	(5,491,481	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Gain on sale of oil and gas assets		(36,400,000	)		—
Deferred income taxes		6,330,000			—
Depletion, depreciation and amortization		1,049,598			462,315
Share-based compensation expenses		574,413			598,052
Impairment of oil and gas properties		—			2,100,000
Impairment of well equipment inventory		173,785			156,139
Accretion of asset retirement obligations		13,108			20,220

Changes in assets and liabilities:
Decrease (increase) in receivables		(1,164,104	)		352,328
Decrease (increase) in prepaid expenses		(27,780	)		17,971
Decrease (increase) in well equipment inventory		(3,917,042	)		(676,696	)
Increase (decrease) in accounts payable and accrued liabilities		4,169,836			(126,256	)

Net cash used in operating activities		(1,417,600	)		(2,587,408	)


CASH FLOWS FROM INVESTING ACTIVITIES
Cash proceeds from sale of oil and gas properties		46,181,289			—
Cash paid for oil and gas property acquisition, exploration & development		(36,771,048	)		(8,470,823	)
Drilling prepayments		(445,718	)		—
Proceeds from redemptions and sales of short-term investments		1,200,000			1,575,000
Cash paid for office equipment		(24,304	)		(33,118	)

Net cash provided (used) by investing activities		10,140,219			(6,928,941	)


CASH FLOWS FROM FINANCING ACTIVITIES
Stock option exercises		716,650			—

Net cash provided by financing activities		716,650			—

NET INCREASE (DECREASE) IN CASH		9,439,269			(9,516,349	)
CASH, BEGINNING OF PERIODS		40,632,284			23,269,725

CASH, END OF PERIODS	$	50,071,553		$	13,753,376


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

SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Oil and gas properties acquired for stock	$	13,804,000		$	—
Net increase in payables for capital expenditures	$	6,201,475		$	—

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

AMERICAN OIL & GAS INC.

Notes to Condensed Consolidated Financial Statements
(UNAUDITED)
June 30, 2010

NOTE 1 — COMPANY AND BUSINESS

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

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

As further discussed in Note 12 Subsequent Events, Hess Corporation (NYSE: HES) has agreed to acquire American pursuant to a July 27, 2010 merger agreement approved by the Boards of Directors of both companies in an all-stock transaction, subject to approval by American’s stockholders.

NOTE 2 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

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

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

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

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

ASSET RETIREMENT OBLIGATIONS — Our asset retirement obligations (“ARO”) relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of our oil and gas properties. The following table reflects the change in ARO for the three-month and six-month periods ended June 30, 2010 and June 30, 2009:


	Three months ended						Six months ended
	June 30,						June 30,
	2010			2009			2010			2009
Beginning asset retirement obligation	$	117,466		$	440,615		$	436,488		$	430,687
Liabilities incurred		36,958			44,555			51,217			53,366
Liabilities settled		—			—			(341,709	)		—
Revisions in estimated liabilities		(6,011	)		(3,623	)		(7,796	)		(12,159	)
Accretion		2,895			10,567			13,108			20,220

Ending asset retirement obligation	$	151,308		$	492,114			151,308		$	492,114

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

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

NOTE 3 — PROPERTY AND EQUIPMENT

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


	June 30,			December 31,
	2010			2009
Oil and gas properties, full cost method
Unevaluated costs, not yet subject to amortization	$	58,983,403		$	35,611,363
Evaluated costs		27,511,193			8,843,579

		86,494,596			44,454,942
Less accumulated amortization		(6,460,016	)		(5,510,016	)

Net carrying value of oil and gas properties		80,034,580			38,944,926
Cost of other property and equipment		430,577			406,273
Less accumulated depreciation and amortization		(301,128	)		(261,531	)

Net property and equipment	$	80,164,029		$	39,089,668

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

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

Sales of Oil & Gas Properties

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

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

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

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

Unevaluated Oil and Gas Properties

Our $58,983,403 of capitalized unevaluated costs at June 30, 2010, substantially consisted of (i) $51.9 million of costs of acreage and wells-in-progress at our Goliath Project in North Dakota and (ii) approximately $4 million in Bigfoot undeveloped acreage and approximately $1 million in costs of wells drilled or in progress, but not yet evaluated at Bigfoot. Included in capital additions for the six-month period ended June 30, 2010 were $0.5 million of internal land department and geologist costs directly associated with the acquisition, exploration and development of oil and gas properties.

‘Ceiling’ Impairment

We use the full-cost accounting method, which requires recognition of an impairment of oil and gas properties when the total capitalized costs (net of related deferred income taxes) exceed a “ceiling” as described on page F-9 of our amended Annual Report on Form 10-K as of December 31, 2009. We had recognized a $2,100,000 impairment for the six-month period ended June 30, 2009.

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


	Six-month Period
	Ended June 30,
	2010		2009
Amortization of costs for evaluated oil and gas properties	$	950,000	$	334,000
Amortization of Intangible Asset		39,598		90,000
Depreciation of office equipment, furniture and software		60,000		38,315

Total DD&A expense	$	1,049,598	$	462,315

NOTE 4 — SIGNIFICANT CHANGES IN PROVED RESERVE ESTIMATES

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


	Oil (bbls)			Gas (mcf)
Proved reserves at December 31, 2009		147,510			956,550
Less proved reserves of properties sold 3/31/10		(22,957	)		(392,601	)
Less production for six months ended 6/30/10		(46,262	)		(51,284	)
Proved reserve additions, six months ended 6/30/10		1,177,297			2,583,459
Net revisions		132,599			70,484

Proved reserves at June 30, 2010		1,388,187			3,166,608

Percentage net change in proved reserves		841	%		231	%

Proved reserve additions relate primarily to our interests in three recently completed North Dakota wells and three proved undeveloped locations directly offsetting our Ron Viall 1-25H well.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves increased from approximately $2.5 million at December 31, 2009 to approximately $32 million at June 30, 2010.

NOTE 5 — SHORT-TERM INVESTMENTS

Our short-term investments of $1,750,000 at June 30, 2010 and $2,925,000 at December 31, 2009 were comprised of auction-rate preferred shares (“ARPS”) issued by closed-end mutual funds. ARPS are a form of auction-rate securities (“ARS”) that were bought and sold at par value prior to March 2008 at special auctions held every 7 days or 28 days and paying variable-rate dividends, with the rate re-determined at the auctions. By March 2009, there were no parties willing to buy ARPS at par value at the auctions, i.e., the auction system collapsed. The ARPS are preferred shares with no maturity date and with no right for the holder to ‘put’ the securities to the ARPS issuer (the closed-end mutual fund) for redemption. Since March 2008, many issuers of ARPS have redeemed some or all of their ARPS at par value, and several large investment banks and brokerage firms (generally in settlement with customers or with government agencies) have bought back their customers’ ARPS at par value.

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


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

As of March 31, 2010		3,150,000			2,950,000
Less redemption in May 2010		(1,200,000	)		(1,200,000	)

As of June 30, 2010	$	1,950,000		$	1,750,000

On August 6, 2009, American filed with the Financial Industry Regulatory Authority (“FINRA”) a statement of claim against Jefferies & Company, Inc. (“Jefferies”), as American’s broker with regards to the ARPS. The statement of claim seeks in arbitration to have Jefferies (i) purchase at par value American’s remaining unredeemed ARPS, (ii) reimburse American for consequential damages (approximating $150,000 to date) and for American’s legal costs in the arbitration and (iii) pay American approximately $1 million in interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions. The arbitration hearing is scheduled currently to take place in December 2010.

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

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

At June 30, 2010, the ARPS’ $1,950,000 total par value exceeded their $1,750,000 total carrying value (i.e., estimated fair value) by $200,000. The $200,000 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 $100,000 temporary unrealized gain recorded (net of $38,000 related deferred income taxes) in Other Comprehensive Income. Fair value, by definition, is before transaction costs in selling the ARPS (See Note 6).

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

NOTE 6 — FAIR VALUE MEASUREMENTS

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

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

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

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

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

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


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

As of June 30, 2010
Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (“ARPS”)	$	1,750,000	$	—	$	—	$	1,750,000
Liabilities	$	—	$	—	$	—	$	—

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

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

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

NOTE 7 — INCOME TAXES

We account for income taxes under the provisions of 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.

For the six-month period ended June 30, 2010, we recorded a $200,000 current provision for estimated alternative minimum tax and a $6,330,000 deferred income tax provision, net of a $7 million reversal of the deferred tax asset valuation allowance. We currently estimate that our effective income tax rate for the year ending December 31, 2010 will approximate 20% (and 39% excluding the effect of the reversal of the deferred tax asset valuation allowance).

We file annual US federal income tax returns and have filed annual income tax returns for the states of Colorado, Montana, North Dakota and Utah. We have done business in Wyoming, but Wyoming does not impose corporate income taxes. We believe that as of August 12, 2010, we are no longer subject to income tax examinations by tax authorities for years before 2005 for Colorado and before 2006 for federal, Montana, North Dakota and Utah income tax returns. Income taxing authorities have conducted no formal examinations of our past federal and state income tax returns and supporting records. In March and April 2009, the Utah State Tax Commission conducted a limited review of our franchise tax returns for 2005, 2006 and 2007, but the review did not become a formal examination or audit, and the Commission issued no notice of any taxes, penalties or interest due.

On January 1, 2007, we adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). We found no significant uncertain tax positions as of any date as of June 30, 2010.

Our policy is to recognize interest related to unrecognized tax benefits in interest expense and to recognize tax penalties in operating expense. However, given our substantial net operating loss carryforwards, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2010.

NOTE 8 — EQUITY

Common Stock

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

	•		On January 26, 2010, we issued to each of our three independent directors 7,519 shares of common stock pursuant to our 2006 Stock Incentive Plan, with 2,506 shares vesting immediately and 5,013 shares vesting when the individual is no longer a director.

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

	•		A Director exercised his option, buying 12,500 shares of our common stock, at a $2.38 exercise price per share.

	•		Our CFO exercised his option, buying 68,000 shares of our common stock, at an exercise price of $2.00 per share.

	•		Four non-officer employees exercised options to purchase a total of 121,400 shares of our common stock, at an exercise price of $2.00 per share.

	•		For the quarter ended March 31, 2010, Additional Paid-In Capital increased by $315,499 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of (i) $174,762 in share-based compensation related to stock options, (ii) $50,734 related to accruals for granted stock vesting after grant and (iii) $90,003 relating to stock granted to directors with limited vesting restrictions.

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

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

	•		Effective March 31, 2010 with the closing of the sale of certain Powder River Basin oil and gas properties, we increased Additional Paid-In Capital by $13,804,000 in recognition of the sale fulfilling all obligations of North Finn LLC for its right to receive 2,900,000 restricted shares of our common stock, as discussed further in Note 3. In May 2010, North Finn LLC formally exercised its option and received the 2,900,000 shares.

Warrants

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

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

The four warrants (each for 25,000 shares) mentioned above were the only outstanding warrants at June 30, 2010.

Stock Options

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

Other Comprehensive Income

During the six months ended June 30, 2010, Other Comprehensive Income increased by $25,000 (to $100,000) to reflect a change in the fair value of short-term investments and decreased by $38,000 (to $62,000) in recognition of deferred income taxes relating to the $100,000 gain on short-term investments.

NOTE 9 — EARNINGS PER SHARE

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


	Three months ended June 30						Six months ended June 30
	2010			2009			2010		2009
Net income (loss)	$	(254,128	)	$	(1,600,118	)	$	27,780,586	$	(5,491,481	)
Adjustments for dilution		—			—			—		—

Net income (loss) adjusted for dilution effects	$	(254,128	)	$	(1,600,118	)	$	27,780,586	$	(5,491,481	)


Basic Weighted Average Common Shares		60,719,700			48,307,399			59,160,407		48,273,382
Add dilutive effects of options and warrants		—			—			1,231,162		—

Diluted Weighted Ave. Shares Outstanding		60,719,700			48,307,399			60,391,569		48,273,382


Net income (loss) per common share, basic	$	0.00		$	(0.03	)	$	0.47	$	(0.11	)
Net income (loss) per common share, diluted	$	0.00		$	(0.03	)	$	0.46	$	(0.11	)

NOTE 10 — MATERIAL RELATED PARTY TRANSACTIONS

We had no material related party transactions during the six-month period ended June 30, 2010.

NOTE 11 — COMMITMENTS AND CONTINGENCIES

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

American has agreed to merge with Hess as described in Note 12. American, the members of American’s board of directors and Hess are named as defendants in putative class action lawsuits brought by certain American stockholders challenging American’s proposed merger with Hess. The lawsuits were filed in state and federal courts in Colorado and in state court in Nevada. The lawsuits generally allege that the members of American’s board of directors, aided and abetted by American and Hess, breached their fiduciary duties to American’s stockholders by entering into the agreement and plan of merger for the sale of American to Hess for what plaintiffs claim to be inadequate consideration and pursuant to what plaintiffs claim to be an inadequate process. The lawsuits seek, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms or to rescind the merger to the extent already implemented.

NOTE 12 — SUBSEQUENT EVENTS

Agreement and Plan of Merger

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

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

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

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

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

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

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

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

In addition, in connection with the Merger, Hess committed (subject to the terms and conditions of a customary commitment letter) to provide the Company with a secured short term revolving credit facility of $30 million to help finance the Company’s planned exploration and production activities and other working capital needs prior to the Closing Date.

See Note 11 for discussion of lawsuits filed against American with regard to the merger agreement.


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

On March 31, 2010, we sold all of our oil and gas interests in the Fetter and Krejci projects located in the Power River Basin, Wyoming and received approximately $46.2 million in sales proceeds on March 31 and an additional $1.7 million in June, 2010. As a result of the sale, our primary focus area is now our Goliath Bakken and Three Forks focused project located in the Williston Basin, North Dakota where, as of June 30, 2010, we control approximately 85,000 net acres.

The Williston Basin has become one of the most actively drilled basins in the continental United States. Recent advancements in drilling, completion and stimulation technologies used by other operators have resulted in commercially successful Bakken and Three Forks wells. We have recently commenced drilling operations that utilize these advanced technologies.

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


WELL NAME	LOCATION	STATUS

Tong Trust 1-20H WI=25.3% NRI=20.2%	Sec. 20 — T157N-R96W Williams County, ND	Commenced Production March 2010. Workover operations are underway to repair damaged production tubing and install a rod-pump.

Ron Viall 1-25H WI=94% NRI=75.2%	Sec. 25 — T156N-R98W Williams County, ND	Commenced production May 2010. Initial Production rate (“IP rate”) of 2,844 BOE. Average daily rate for initial 30 days of production of 987 BOE. Total cumulative production at August 11, 2010 of 56,062 BOE (41,079 bbls of oil and 90 mmcf of natural gas).

Summerfield 15-15H WI=35% NRI=28.4%	Sec. 15 — T147N-R96W Dunn County, ND	Commenced production May 2010. IP rate of 2,799 BOE. Average daily rate for initial 30 days of production of 1,046 BOE. Total cumulative production at August 11, 2010 of 60,568 BOE (51,347 bbls of oil and 56 mmcf of natural gas).

Bergstrom 15-23H WI=95% NRI=76%	Sec. 23 — T156N-R98W Williams County, ND	36-stage hydraulic fracture stimulation completion operation recently completed. The Bergstrom well produced 3,049 BOE (2,395 Bbls of oil and 3.9 mmcf of natural gas) during an early 24 hour flow-back period.

Johnson 15-35H WI=81% NRI=64.8%	Sec. 35 — T156N-R98W Williams County, ND	35-stage hydraulic fracture stimulation completion operation underway.

Hickel 15-35H WI=61.5% NRI=49.2%	Sec. 35 — T157N-R97W Williams County, ND	Drilling operations concluded on July 27, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. No date has been set to commence completion operations, as completion crews are presently unavailable.


WELL NAME	LOCATION	STATUS

Hodenfield 15-33H WI=51.4% NRI=41.1%	Sec. 33 — T157N-R97W Williams County, ND	Drilling operations concluded on August 5, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. No date has been set to commence completion operations, as completion crews are presently unavailable.

Hodenfield 15-7H WI=46% NRI=36.8%	Sec. 7 — T157N-R97W Williams County, ND	Ensign drilling rig 88 has been rigged down after installing the completion assembly that is expected to facilitate a 35-stage completion assembly. No date has been set to commence completion operations, as completion crews are unavailable.

Bergstrom 2-27H WI=72.9% NRI=58.3%	Sec. 27 — T156N-R98W Williams County, ND	Ensign drilling rig 24 commenced drilling on August 15, 2010.

Olson 15-36H WI=68.2% NRI=54.5%	Sec. 36 — T157N-R98W Williams County, ND	Nabors drilling rig 486 commenced drilling on August 12, 2010.

Hodenfield 15-23H WI=37.7% NRI=30.2%	Sec. 23 — T157N-R98W Williams County, ND	Building of access road and drilling location is underway in preparation for Ensign Rig 88 to move in and commence drilling within the next ten days.

Reid 3-3H WI=35.6% NRI=28.5%	Sec. 3 — T157N-R97W Williams County, ND	Unit drilling rig 234 will be brought in under a long term contract to drill this well, followed by other wells. Drilling operations are expected to commence in late-August

Results of Operations

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

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

For the quarter ended June 30, 2010, we recorded a net loss of $254,128 ($0.00 per share, basic and diluted), as compared to a net loss of $1,600,118 ($0.03 loss per common share, basic and diluted) for the quarter ended June 30, 2009. The $1,345,990 decrease in net loss is primarily due to a $1.9 million increase in oil and gas revenues.

For the quarter ended June 30, 2010, we recorded total oil and gas revenues of $2,417,564 compared with $517,478 for the quarter ended June 30, 2009. The $1,900,086 increase from the 2009 quarter is attributable to a 612% increase in oil production and significantly higher oil and gas prices, partially offset by a decline in gas sales. Oil and gas sales and production costs and other components of income from operations are summarized in the following table:


	Three months ended
	June 30,
	2010			2009
Oil sold (barrels)		38,442			5,401
Average oil price	$	62.12		$	44.88

Oil revenue	$	2,387,980		$	242,383


Gas sold (mcf)		5,794			82,023
Average gas price	$	5.11		$	3.35

Gas revenue	$	29,584		$	275,095


Total oil and gas revenues	$	2,417,564		$	517,478
Less lease operating expenses		(623,862	)		(270,250	)
Less oil & gas amortization expense		(704,000	)		(221,000	)
Less accretion of asset retirement obligation		(2,895	)		(10,567	)
Less impairment of well equipment inventory		(173,785	)		(156,139	)
Plus gain on sale of oil and gas properties		—			—

Income (loss) from oil & gas operations		913,022			(140,478	)
Less depreciation of office facilities		(19,897	)		(19,172	)
Less amortization of other intangible asset		(15,000	)		(45,000	)
Less general and administrative expenses		(1,361,273	)		(1,412,805	)

Income (loss) from operations	$	(483,148	)	$	(1,617,455	)


Total barrels of oil equivalent (“boe”) sold		39,408			19,072
Revenue per boe sold	$	61.35		$	27.13
Lease operating expense per boe sold	$	15.83		$	14.17
Amortization expense per boe sold	$	17.86		$	11.59

For the quarters ended June 30, 2010 and June 30, 2009, we incurred $1,361,273 and $1,412,805, respectively, in general and administrative expenses. Total costs decreased due to approximately $500,000 in non-recurring financial advisory services incurred in the 2009 period. Personnel compensation increased by $261,000 in the 2010 period compared with the 2009 period.

The Six-month Period ended June 30, 2010 Compared with the Six-month Period ended June 30, 2009

For the six months ended June 30, 2010, we recorded net income of $27,780,586 ($0.47 per share, basic and $0.46 per share, diluted), as compared to a net loss of $5,491,481 ($0.11 loss per common share, basic and diluted) for the six months ended June 30, 2009. The $33.3 million increase in net income is primarily due to a $36.4 million gain on the March 31, 2010 sale of most of our Wyoming oil and gas properties.

For the six months ended June 30, 2010, we recorded total oil and gas revenues of $3,277,535 compared with $823,152 for the six months ended June 30, 2009. The $2,454,383 increase from the 2009 period is attributable to a 404% increase in oil production and significantly higher oil and gas prices, partially offset by a decline in gas sales. Oil and gas sales and production costs and other components of income from operations are summarized in the following table:


	Six months ended June 30,
	2010			2009
Oil sold (barrels)		46,262			9,179
Average oil price	$	63.64		$	40.33

Oil revenue	$	2,944,322		$	370,192


Gas sold (mcf)		51,284			133,437
Average gas price	$	6.50		$	3.39

Gas revenue	$	333,213		$	452,960


Total oil and gas revenues	$	3,277,535		$	823,152
Less lease operating expenses		(865,271	)		(569,925	)
Less oil & gas amortization expense		(950,000	)		(334,000	)
Less accretion of asset retirement obligation		(13,108	)		(20,220	)
Less impairment of materials & supplies inventory		(173,785	)		(156,139	)
Less impairment of oil and gas assets		—			(2,100,000	)
Plus gain on sale of oil and gas properties		36,400,000			—

Producing revenues less direct expenses		37,675,371			(2,357,132	)
Less depreciation of office facilities		(39,598	)		(38,315	)
Less amortization of other intangible asset		(60,000	)		(90,000	)
Less general and administrative expenses		(3,364,002	)		(3,044,351	)

Income (loss) from operations		34,211,771		$	(5,529,798	)

Total barrels of oil equivalent (“boe”) sold		54,809			31,419
Revenue per boe sold	$	59.80		$	26.20
Lease operating expense per boe sold	$	15.79		$	18.14
Amortization expense per boe sold	$	17.33		$	10.63

For the six months ended June 30, 2010 and June 30, 2009, we incurred $3,364,002 and $3,044,351, respectively, in general and administrative expenses. Total costs increased by $319,651, primarily due to increased employee compensation, including $150,000 in special employee bonuses for the successful sale of certain Wyoming properties in March 2010. Those bonuses were to all employees, excluding the four employees who also are directors or large shareholders.

Liquidity and Capital Resources

At June 30, 2010 and December 31, 2009, we had working capital of $52.1 million and $44.5 million, respectively. We had cash and cash equivalents at June 30, 2010 of $50.1 million.

For the calendar year ending December 31, 2010, including capital expenditures in the six months ended June 30, 2010 of $36.8 million, we anticipate spending a total of approximately $88 million in capital expenditures, consisting primarily of (i) approximately $63 million drilling and completing North Dakota wells to the Bakken formation or Three Forks formation at our Goliath Project and (ii) approximately $22 million for North Dakota lease acquisitions and extensions. Including wells already drilled or drilled and completed, we expect our 2010 drilling program to consist of drilling 25 gross (14.5 net) wells at a total net cost of approximately $49 million. At this time, due to the tightness of completion crews, we expect to be able to complete only five gross (four net) wells in 2010 at a total net cost of approximately $14 million.

In connection with the proposed Merger with Hess, Hess committed (subject to the terms and conditions of a customary commitment letter) to provide us with a secured short term revolving credit facility of $30 million to help finance our planned exploration and production activities and other working capital needs prior to closing of the Merger.

As a result of our 2010 drilling program, we expect increased revenues from operations in 2010, compared to 2009, for the last six months of the year. We anticipate using (i) cash currently on hand, (ii) cash from operations, (iii) advance payments for drilling and completion costs from working interest partners and (iv) the $30 million credit facility from Hess Corporation to pay for capital expenditures in 2010.

If the merger with Hess is not completed, we expect to need additional financing to repay our borrowings from Hess and for working capital. We have no commitments for financing, and the availability of financing is not assured. Any such financing may be on terms that are not advantageous to us. All of our assets will serve as collateral for repayment of the borrowings from Hess. If we are unable to obtain financing and to timely repay Hess, our properties and other assets could be at risk of foreclosure.

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

Net Cash Provided (Used) By Operating Activities — Our net cash used by operating activities decreased by $1,169,808 (from $2,587,408 net cash used for operating activity for the six-month period ended June 30, 2009 to $1,417,600 cash used by operations for the six-month period ended June 30, 2010). Our oil and gas revenues increased by $2.5 million in the 2010 period compared with the 2009 period, but cash spent for well equipment inventory at third-party yards increased by $3.2 million for the 2010 period compared with the 2009 period. Well equipment inventory at third party yards is carried as a current asset.

Net Cash Provided (Used) In Investing Activities — During the six-month period ended June 30, 2010, investing activities provided a net $10.1 million in cash as compared with $6.9 million of cash used by investing activities in the six-month period ended June 30, 2009. The $17 million increase in provided cash is primarily due to (i) the $46.2 million received in March 2010 on the sale of oil and gas properties in the Powder River Basin in Wyoming, less (ii) our $28 million increase in capital expenditures at our Goliath Project (consisting of approximately $18 million for lease acquisitions and extensions and approximately $10 million for drilling and completion of wells).

Net Cash Provided By Financing Activities — During the six-month periods ended June 30, 2010 and June 30, 2009, the only financing activities were $716,650 in cash received in the 2010 period relating to stock option exercises.


Item 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

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

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

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

Operating Cost Risk

During 2008 and 2009, we have generally experienced fluctuations in operating costs (including costs of drilling and completing wells) which impact our cash flow from operating activities and profitability. We expect our drilling activity in 2010 to be focused on drilling oil wells with long laterals in the Bakken and/or Three Forks formations in North Dakota. The North Dakota Williston Basin is currently one of the most actively drilled basins in the continental United States. There are currently upwards of 150 drilling rigs in operation targeting the Bakken and Three Forks formations. We are already experiencing increasing costs and difficulty in securing drilling and completion services. We are also experiencing significant increases in costs for these services. For example, we were recently alerted by the company that provides our completion services, that it will be very difficult to provide completion services and if completion services become available, to expect an approximate 35% increase in costs for the completion services. This would increase completion costs from approximately $3 million to close to $4 million per well.

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

Interest Rate Risk

At June 30, 2010, we had no interest-bearing debt or credit facilities. Short-term interest rates were less than 1% per annum on our $73.9 million of cash and cash-equivalent investments at June 30, 2010. Short-term dividend rates on our $1,950,000 par value in Auction Rate Preferred Shares approximated 0.8% per annum and are at rates which vary with short-term commercial paper and US LIBOR rates. An increase in short-term interest rates would be favorable to us in 2010, increasing our investment income in proportion to our short-term investments and cash-equivalent investments.


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

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

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

American has agreed to merge with Hess as described in Note 12 to the Financial Statements in Part I. Eleven shareholder lawsuits styled as class actions have been filed against American and its board of directors challenging American’s proposed merger with Hess. All eleven lawsuits also name Hess as a defendant. Six of the lawsuits name both Hess and Merger Sub. The lawsuits are as follows:


PLAINTIFF	DEFENDANTS	COURT	FILED
Buckman, Richard	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, Nick DeMare, Scott Hobbs and Hess Corporation	1^ST Judicial District Court for Nevada, Carson City	7/29/2010
Luvara, Joseph V.	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, Nick DeMare, Scott Hobbs and Hess Corporation	1^ST Judicial District Court for Nevada, Carson City	7/29/2010
Thurston, James	Patrick D. O’Brien, Andrew P. Calerich, Nick DeMare, C. Scott Hobbs, Jon R. Whitney, American Oil & Gas, Inc., Hess Corporation and Hess Investment Corp.	District Court, Denver County, Colorado	7/30/2010
Veigel, Jeffrey	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, Nick DeMare, C. Scott Hobbs and Hess Corporation	District Court, Denver County, Colorado	7/30/2010
Finkel, Morton	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, Nick DeMare, C. Scott Hobbs, Hess Corporation and Hess Investment Corp.	U.S. District Court, District of Colorado	7/30/2010
Cobb, Edgar	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, Nick DeMare, Scott Hobbs and Hess Corporation	U.S. District Court, District of Colorado	8/02/2010
Veigel, Jeffrey	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, Nick DeMare, C. Scott Hobbs and Hess Corporation	U.S. District Court, District of Colorado	8/3/2010
Feinman, Jeffrey P.	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, Nick DeMare, C. Scott Hobbs, Hess Corporation and Hess Investment Corp.	U.S. District Court, District of Colorado	8/3/2010
Speight, David	Patrick D. O’Brien, Andrew P. Calerich, Joseph B. Feiten, Nick DeMare, Jon R. Whitney, C. Scott Hobbs, American Oil & Gas, Inc., Hess Corporation and Hess Investment Corp.	1^ST Judicial District Court for Nevada, Carson City	8/5/2010
Kane, Ronald J.	American Oil & Gas, Inc., Patrick D. O’Brien, Andrew P. Calerich, Jon R. Whitney, C. Scott Hobbs, Nick DeMare, Hess Corp. and Hess Investment	District Court, Clark County, Nevada	8/6/2010
Smitherman, Roger	Patrick D. O’Brien, Andrew P. Calerich, Nick DeMare, C. Scott Hobbs, Jon R. Whitney, American Oil & Gas, Inc., Hess Corporation and Hess Investment Corp.	2^nd Judicial District Court for Nevada, Washoe County	8/10/2010

The lawsuits generally allege that the members of American’s board of directors, aided and abetted by American and Hess, breached their fiduciary duties to American’s stockholders by entering into the agreement and plan of merger for the sale of American to Hess for what plaintiffs claim to be inadequate consideration and pursuant to what plaintiffs claim to be an inadequate process. The lawsuits seek, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms or to rescind the merger to the extent already implemented.


Item 6.		EXHIBITS


Exhibit No.		Description

10(i)		Agreement and Plan of Merger dated as of July 27, 2010 among Hess Corporation, Hess Investment Corp. and American Oil & Gas Inc. (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on July 29, 2010)
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


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements			3

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

Condensed Consolidated Statements of Operation — Three and Six Months Ended June 30, 2010 and 2009			4

Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2010 and 2009			5

Notes to Condensed Consolidated Financial Statements			6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15

Item 3. Quantitative and Qualitative Disclosures about Market Risks			19

Item 4. Controls and Procedures			20

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			21

Item 1A. Risk Factors			21

Item 6. Exhibits			21

Signatures			22

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


Signatures	Title	Date

/s/ Patrick D. O’Brien Patrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors	August 16, 2010

/s/ Joseph B. Feiten	Chief Financial Officer	August 16, 2010
Joseph B. Feiten	(principal financial officer and principal accounting officer)

Large accelerated filer o

Accelerated filer o

Non-accelerated filer o*

Smaller reporting company þ

(*Do not check if a smaller reporting company)


Item 1.		LEGAL PROCEEDINGS