United States Securities And Exchange Commission

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2007

OR

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

For the transition period from  _____  to  _____ 

Commission File No. 1-31900

AMERICAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

Large accelerated filer o Accelerated filer þ Non-accelerated filer o

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

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

The total shares of $.001 Par Value Common Stock outstanding at November 7, 2007 were 46,261,559.

1

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

PART I.    FINANCIAL INFORMATION
	Item 1.	Financial Statements	3
		Consolidated Balance Sheets — September 30, 2007 and December 31, 2006	3
		Consolidated Statements of Income — Three and Nine Months Ended September 30, 2007 and 2006	4
		Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2007 and 2006	5
		Notes to Consolidated Financial Statements	6
		Summary of Significant Accounting Policies	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 6.	Exhibits	24
	Signatures		24
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

	September 30,			December 31,
	2007			2006
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	22,774,511		$	7,488,474
Short-term investment		725,800			8,456,400
Trade receivables		770,263			336,188
Receivable for sale of oil and gas properties		—			777,461
Prepaid expenses		200,171			402,287
Equipment inventory		40,904			40,904
Deferred income taxes		432,409			—
Total current assets		24,944,058			17,501,714
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $42,600,948 at 9/30/07 and $33,263,390 at 12/31/06)		52,970,119			41,424,253
Other property and equipment		322,252			295,485
Total property and equipment		53,292,371			41,719,738
Less-accumulated depreciation, depletion and amortization		(3,442,212	)		(2,598,581	)
Net property and equipment		49,850,159			39,121,157
OTHER ASSETS
Goodwill		11,670,468			11,670,468
Other intangible asset, net of accumulated amortization		465,000			600,000
Drilling prepayments		125,832			233,058
Other		30,385			10,000
	$	87,085,902		$	69,136,397
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	934,420		$	1,964,000
Asset retirement obligations		32,396			40,321
Deferred income taxes		—			2,172,785
Preferred dividends payable		112,608			479,342
Total current liabilities		1,079,424			4,656,448
LONG-TERM LIABILITIES
Asset retirement obligations		272,738			194,947
Deferred income taxes		1,413,365			2,197,329
Total long-term liabilities		1,686,103			2,392,276
COMMITMENTS AND CONTINGENCIES (Note 12)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value; authorized 400,000 shares; issued and outstanding — 138,000 shares at 9/30/07 and 250,000 at 12/31/06; redemption value of $7,564,608 at 9/30/07 and $13,979,342 at 12/31/06		138			250
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding — 46,261,559 shares at 9/30/07 and 38,927,114 shares at 12/31/06		46,262			38,927
Additional paid-in capital		87,808,601			59,174,874
Accumulated deficit		(2,782,835	)		(799,993	)
Accumulated other comprehensive income (loss)		(751,791	)		3,673,615
		84,320,375			62,087,673
	$	87,085,902		$	69,136,397

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

3

AMERICAN OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006
REVENUES
Oil and gas sales	$	780,963		$	216,347		$	1,580,553		$	2,046,232
Other revenues		—			—			12,000			1,530,000
		780,963			216,347			1,592,553			3,576,232
OPERATING EXPENSES
Lease operating		213,708			56,300			466,444			222,093
General and administrative		969,845			963,992			3,271,647			2,795,311
Depletion, depreciation and amortization		447,381			187,715			969,449			896,871
Accretion of asset retirement obligation		6,537			6,556			18,142			8,343
Impairment		—			860,000			—			860,000
		1,637,471			2,074,563			4,725,682			4,782,618
INCOME (LOSS) FROM OPERATIONS		(856,508	)		(1,858,216	)		(3,133,129	)		(1,206,386	)
OTHER INCOME
Gain on sale of oil and gas properties		—			—			—			7,159,470
Gain on sale of securities		—			—			108,059			—
Investment income		368,148			122,954			733,718			293,481
		368,148			122,954			841,777			7,452,951
INCOME (LOSS) BEFORE INCOME TAXES		(488,360	)		(1,735,262	)		(2,291,352	)		6,246,565
Income tax expense-current		—			—			—			—
Income tax expense (reduction) — deferred		(220,000	)		(473,587	)		(767,000	)		2,806,870
NET INCOME (LOSS)		(268,360	)		(1,261,675	)		(1,524,352	)		3,439,695
Less dividends on preferred stock		(149,040	)		(272,219	)		(453,490	)		(807,780	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(417,400	)	$	(1,533,894	)	$	(1,977,842	)	$	2,631,915
NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	(.01	)	$	(.04	)	$	(.05	)	$	.07
Diluted	$	(.01	)	$	(.04	)	$	(.05	)	$	.07
Weighted average common shares outstanding:
Basic		46,250,379			37,049,751			43,734,060			36,835,697
Diluted		46,250,379			37,049,751			43,734,060			37,298,736

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)

	Nine months ended Sept. 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(1,524,352	)	$	3,439,695
Adjustments to reconcile to net cash provided by operating activities:
Share-based compensation expenses		879,879			1,280,152
Depletion, depreciation and amortization		969,449			896,871
Accretion of asset retirement obligations		18,142			8,343
Gains on sales of oil & gas properties		—			(7,159,470	)
Gain on sales of short-term investments (Note 10)		(108,059	)
Deferred income taxes		(767,000	)		2,806,870
Service fee in the form of a convertible note		—			(1,530,000	)
Impairment provision		—			860,000
Changes in non-cash current assets and liabilities:
Decrease (increase) in receivables		(434,075	)		1,126,272
Decrease (increase) in advances and prepaid expenses		202,116			(45,215	)
Increase (decrease) in accounts payable and accrued liabilities		(334,475	)		266,752
Net cash provided (used) by operating activities		(1,098,375	)		1,950,270
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties		(12,093,224	)		(12,667,666	)
Proceeds from the sale of oil and gas properties		777,461			14,359,662
Partial sale of investment in equity securities (Note 10)		808,059			—
Drilling prepayments		—			(1,088,616	)
Cash paid for office equipment		(26,767	)		(145,630	)
Cash paid for other long-term assets		—			(10,000	)
Net cash provided (used) by investing activities		(10,534,471	)		447,750
CASH FLOWS FROM FINANCING ACTIVITIES
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			129,960
Net cash provided by financing activities		26,918,883			129,960
NET INCREASE IN CASH		15,286,037			2,527,980
CASH, BEGINNING OF PERIOD		7,488,474			6,022,822
CASH, END OF PERIOD	$	22,774,511		$	8,550,802
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest expense and income taxes incurred	$	—		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH ACTIVITIES
Conversion of preferred stock into common stock	$	6,048,000		$	—
Share-based compensation expense	$	879,879		$	1,280,152
Share-based consideration to acquire oil and gas properties	$	—		$	13,167,000
Property sales proceeds in the form of a receivable	$	—		$	2,484,362
Preferred dividends paid in shares of common stock	$	820,224		$	1,080,000
Drilling prepayments applied to drilling costs	$	107,226		$	—
Service fee received in the form of a convertible note (Note 10)	$	—		$	1,530,000
Property sold in exchange for a convertible note (Note 10)	$	—		$	1,080,000
Conversion of notes into investment in equity securities (Note 10)	$	—		$	2,610,000

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)
September 30, 2007

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 nine-month period ended September 30, 2007 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/A for the year ended December 31, 2006.

USE OF ESTIMATES — As further discussed on page F-8 of Form 10-K/A for the year ended December 31, 2006, 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-9 through F-13 of Form 10-K/A for the year ended December 31, 2006.

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 September 30, 2007 and September 30, 2006, 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. See Note 3 regarding proved reserve estimates at September 30, 2007.

RECENT ACCOUNTING PRONOUNCEMENTS — As of October 31, 2007, there have been no recent accounting pronouncements relevant to the Company in addition to those discussed on pages F-12 and F-13 of Form 10-K/A for the year ended December 31, 2006.

In February 2006, the FASB issued SFAS 155, Accounting for Certain Hybrid Financial Instruments, which eliminates the exemption from applying SFAS 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the instrument’s form. SFAS 155 allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event. We do not currently have Hybrid Financial Instruments to which SFAS 155 relates. We adopted SFAS 155 effective January 1, 2007, but adoption did not have a material impact on our financial statements.

In March 2006, the FASB issued SFAS 156, Accounting for Servicing of Financial Assets, which requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities to be initially measured at fair value. We do not have servicing assets or servicing liabilities to which SFAS 156 relates. We adopted SFAS 156 effective January 1, 2007 but adoption did not have a material effect on our financial statements.

In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48), effective for the Company on January 1, 2007. FIN 48 clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on measurement, classification, interim accounting and disclosure. We adopted FIN 48 effective January 1, 2007, but adoption did not have a material impact on our financial statements.

GAS BALANCING — As of September 30, 2007 and December 31, 2006, 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 2006 consolidated financial statements have been reclassified to conform to the 2007 financial statement presentation. Such reclassifications have had no effect on net income (loss).

Note 3 — Significant Changes in Proved Reserve Estimates

Our proved reserves at September 30, 2007 were estimated internally by management. The estimates are approximately 12% greater than at December 31, 2006, as shown in the following table:

							Total barrels
							of oil
	Oil (bbls)			Gas (mcf)			equivalent
Proved reserves at December 31, 2006		91,850			809,847			226,825
Less 2007 year-to-date production		(16,057	)		(102,060	)		(33,067	)
Proved reserve additions		19,307			11,731			21,262
Proved reserve revisions		(18,117	)		339,884			38,530
Proved reserves at September 30, 2007		76,983			1,059,402			253,550

7

Although partially offset by downward revisions in other oil and gas properties, the primary reason for the increase in reserves is an upward revision in proved oil and gas reserves for our 23.125% working interest in the Sims 15-26 horizontal well drilled in 2007 at our Fetter project. The well is still undergoing production tests and in late October underwent staged artificial fracture stimulation of the producing formation. Our September 30, 2007 estimates of the well’s proved (i.e., reasonably certain) reserves are prior to establishing sustained production. Such estimation (based on limited production tests and other drilling data) is not as reliable as estimation based on several months of production history. Such production history establishes the actual initial production rate and better indicates the future production decline rates. The future estimation of Sims 15-26 proved reserves as of December 31, 2007 is expected to utilize such production history, and those proved reserve estimates might be significantly greater or less than the well’s proved reserve estimates as of September 30, 2007. Our September 30, 2007 estimates of proved reserves for the Company do not recognize any proved undeveloped reserves, such as for undrilled well sites offsetting the Sims 15-26 well.

Note 4 — Property and Equipment

Property and equipment at September 30, 2007, consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization	$	42,600,948
Evaluated costs		10,369,171
		52,970,119
Office equipment, furniture and software		322,252
		53,292,371
Less accumulated depreciation, depletion and amortization		(3,442,212	)
Property and equipment	$	49,850,159

Our major projects are Fetter, West Douglas, Krejci and Goliath and are described more fully in our Form 10-K/A for 2006. The following table presents the capitalized oil and gas properties’ costs and net additions therein for the nine months ended September 30, 2007, with the unevaluated costs by major project:

	Capitalized Costs (in millions)						Acres
Project (State)	12/31/06		Additions		9/30/07		Gross		Net & WI		*
Fetter Project, Powder River Basin (WY)	$	18.7	$	0.3	$	19.0		58,300		52,100 (69	%)
West Douglas Project, Powder River Basin (WY)		3.7		0.3		4.0		55,100		47,400 (45	%)
Douglas Project, Powder River Basin (WY)		0.8		0.0		0.8		14,800		14,300 (90	%)
Krejci Oil Project, Powder River Basin (WY)		2.3		5.7		8.0		132,500		126,600 (45	%)
Goliath Project, Williston Basin (ND)		6.6		0.4		7.0		88,500		65,400 (50	%)
Other projects		1.2		2.6		3.8
Total unevaluated costs	$	33.3	$	9.3	$	42.6
Evaluated Costs	$	8.2	$	2.2	$	10.4

* Net acres represent the proportion of gross surface acreage for which we and our working interest partners have leased the underlying mineral rights for exploration and production. Our average working interest percentage of the net acres is shown in parentheses. For the Fetter project, the average 69% effective working interest shown is that which we effectively will own after RTA earns its 25% working interest in Fetter net acreage by completing two wells currently being drilled at Fetter.

8

The West Douglas Project acreage extends to its east within four miles of the Fetter Project acreage. The Douglas Project acreage lies largely between the West Douglas and Fetter Projects or in the townships immediately north of Fetter acreage. After RTA earns its 50% working interest in West Douglas acreage by completing a well in late 2007, our effective working interest in West Douglas acreage will become 45%.

Of the $19 million of unevaluated costs in our Fetter project, we anticipate that approximately $5 million will be moved to evaluated costs in late 2007 or early 2008 upon the completion and testing of the Hageman 16-36HR well and the Wallis 6-23 well that are currently being drilled by RTA to earn into the Fetter Project. We estimate that the remaining $14 million will be reclassified as evaluated costs as additional wells are drilled within the Fetter Project. The $19 million of costs equates to a cost per net leased acre that is substantially below values recently paid at auction to acquire lease acreage at Fetter.

The first well at our West Douglas Project was drilled this fall to a depth of 14,220 feet, with initial analysis indicating potential pay in up to five separate formations. Completion and testing are underway.

At our Krejci Project, located in Niobrara County, Wyoming, four horizontal Mowry wells have been drilled and various completion attempts have been performed. The costs of the first two wells (drilled in 2006) are classified as evaluated costs. The $8.0 million in unevaluated costs for the Krejci Prospect includes $5.1 million in costs of the third and fourth wells. They were drilled in 2007 and are undergoing completion and production testing. We anticipate that those new wells will be evaluated for proved reserves in late 2007 or early 2008, whereupon approximately $5.3 million in drilling and lease acquisition costs incurred by September 30, 2007 will be reclassified as evaluated and become a part of our full cost pool’s amortization base. The remaining $2.7 million in unevaluated costs consists primarily of lease acquisition costs, which likely will be moved to evaluated as additional wells are drilled and evaluated or as lease costs otherwise become impaired.

The $7.0 million in unevaluated costs for the Goliath Project are primarily for lease acquisitions. The acquisitions began in October 2005. Wells continue to be drilled within and near the leased acreage.

At September 30, 2007, oil and gas property costs, net of accumulated amortization, totaled $49,619,103. Such costs, net of related deferred income taxes, exceeded the full cost ceiling limitation by approximately $20,000 using oil and gas prices at September 30, 2007. However, as provided in Topic 12 of the SEC Staff Accounting Bulletins, the excess was not charged against earnings because subsequent increases in oil and gas prices in October indicated that capitalized costs were not impaired at September 30, 2007.

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

	Nine-month Period
	Ended September 30,
	2007		2006
Amortization of costs for evaluated oil and gas properties	$	786,818	$	740,639
Amortization of Other Intangible Asset		135,000		135,000
Depreciation of office equipment, furniture and software		47,631		21,232
Total DD&A expense	$	969,449	$	896,871

9

Note 5 — Asset Retirement Obligations

Our asset retirement obligations (“ARO”) relate primarily to the estimated costs we will expend when our existing oil and gas wells or properties are abandoned in the future. Such costs are for activities such as plugging and capping the wells, removing equipment and restoring surface areas. The following table reflects the change in ARO for the three-month and nine-month periods ended September 30, 2007 and September 30, 2006:

	Three months ended					Nine months ended
	September 30,					September 30,
	2007			2006		2007			2006
Beginning asset retirement obligation	$	276,011		$	112,269	$	235,268		$	117,011
Liabilities incurred		70,822			111,073		131,970			112,287
Liabilities settled		—			—		(22,898	)		(7,745	)
Revisions in estimated liabilities		(48,236	)		34,801		(57,348	)		34,801
Accretion		6,537			6,556		18,142			8,345
Ending asset retirement obligation	$	305,134		$	264,699	$	305,134		$	264,699
Current portion of obligation, end of period	$	32,396		$	177,527	$	32,396		$	177,527

Note 6 — 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, 2007, our weighted average statutory income tax rate (federal and state combined) will approximate 36.5% and our effective income tax rate will approximate 33.5%. The effective rate differs from the statutory rate due to a rate reduction for permanent differences, offset in part by a small increase in the effective rate arising from adjusting estimated deferred income tax liabilities to conform with the 2006 federal and state income tax returns filed in September 2007. The permanent differences primarily relate to stock options granted to employees and to excess percentage depletion.

Deferred income tax reductions of $220,000 and $473,587 were reported for the three-month periods ended September 30, 2007 and 2006, respectively. We did not incur federal or state income tax liabilities for 2006 and do not expect to owe income taxes for 2007.

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”). In implementing FIN 48, we found no significant uncertain tax positions.

10

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 2007 since such adjustments would very likely simply reduce our net operating loss carryforwards.

Note 7 — Earnings per Share

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

For the three-month and nine-month periods ended September 30, 2007, there are no adjustments for dilution because of the periods’ net losses (rather than net income) to common shareholders. Securities outstanding at September 30, 2007 that could in the future potentially dilute basic net income per share for common stockholders are described in Note 8 and include (i) preferred stock convertible into 1,242,000 common shares, (ii) warrants for 1,027,980 shares, (iii) outstanding stock options for 2,570,000 shares (of which 1,387,125 were exercisable at September 30, 2007), and (iv) an option for 2,900,000 common shares in exchange for certain oil and gas properties.

The following table summarizes the calculations of basic and diluted earnings per share for the three-month and seven-month periods ended September 30, 2007 and 2006:

	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006
Net income (loss) to common stockholders	$	(417,400	)	$	(1,533,894	)	$	(1,977,842	)	$	2,631,915
Adjustments for dilution		—			—			—			—
Net income adjusted for effects of dilution	$	(417,400	)	$	(1,533,894	)	$	(1,977,842	)	$	2,631,915
Basic Weighted Ave. Common Shares Outstanding		46,250,379			37,049,751			43,734,060			36,835,697
Add dilutive effects of options and warrants		—			—			—			463,039
Add dilutive effects of convertible preferred stock		—			—			—			—
Diluted Weighted Ave. Common Shares Outstanding		46,250,379			37,049,751			43,734,060			37,298,736
Net income per common share — basic	$	(0.01	)	$	(0.04	)	$	(0.05	)	$	0.07
Net income per common share — diluted	$	(0.01	)	$	(0.04	)	$	(0.05	)	$	0.07

Note 8 — Equity

COMMON STOCK — The following material changes occurred during the three-month period ended September 30, 2007 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 July 22, 2007, we paid a semi-annual dividend payment of $298,080 by issuing 46,318 common shares, which shares were valued at $6.4356 per share in accordance with methodology prescribed in the Certificate Of Designation Of Rights, Preferences And Privileges Of Series AA Preferred Stock.

• Additional Paid-In Capital increased by an additional $272,635 for recognition, in accordance with SFAS 123R, of (a) $223,315 in share-based compensation related to stock options and (b) $49,320 in share-based compensation related to shares granted and vesting over time.

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• We granted 9,600 shares of common stock for investor relation services for the twelve months ending June 30, 2008. The shares are held in escrow by the Company until June 30, 2008.

The following material changes occurred during the six-month period ended June 30, 2007 with regard to our common stock:

• In January 2007, holders of 112,000 shares of our Series AA convertible preferred stock converted those shares into 1,008,000 shares of 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, 2007, we paid a semi-annual dividend payment of $522,144 by issuing 84,837 common shares, which shares were valued at $6.1547 per share in accordance with methodology prescribed in the Certificate Of Designation Of Rights, Preferences And Privileges Of Series AA Preferred Stock.

• In February 2007, we paid a total of 5,000 shares of restricted common stock to our new Vice-President of Land on his first day of employment. We valued these shares at $5.84 per share, which was the closing price of our common stock on the date of payment, and charged $29,200 to compensation expense.

• In April, 2007, we sold a total of 6,001,390 shares of common stock at a price of $4.75 per share, adding $28,500,601 to Additional Paid in Capital. We paid and charged against Additional Paid-in Capital a $1,624,876 placement fee, a $45,000 AMEX listing fee, $161,570 in other offering fees and $125,019 in related legal and accounting fees.

• In April and May of 2007, we received $368,746 from the exercise of employee stock options for 79,300 shares of common stock.

• On June 15, 2007, we granted 100,000 restricted and escrowed shares of common stock to our new Vice President of Exploration that vest after five years of service or upon a change in control.

• For the quarter ended March 31, 2007, Additional Paid-In Capital increased by an additional $298,814 for recognition, in accordance with SFAS 123R, of (a) $277,939 in share-based compensation related to stock options, (b)$17,955 in share-based compensation related to common shares granted and vesting over time, and (c) $2,920 in share-based compensation related to 4,000 shares granted to our new Vice-President of Land and vesting over the year ending February 12, 2008.

• For the quarter ended June 30, 2007, Additional Paid-In Capital increased by an additional $301,194 for recognition, in accordance with SFAS 123R, of (a) $250,569 in share-based compensation related to stock options, (b) $21,964 in net excess tax benefits relating to stock option exercises and (c) $28,661 in share-based compensation related to shares granted and vesting over time.

Share-based compensation expense for the nine months ended September 30, 2007 totaled $879,879, which consisted of (a) $751,822 related to stock option values recognized over vesting periods, (b) $98,857 related to grants of escrowed common stock recognized over the escrow periods and (c) $29,200 for vested common share grants to new employees.

PREFERRED STOCK — At September 30, 2007, there are a total of 138,000 shares of Series AA Convertible Preferred Stock (“Preferred Stock”) outstanding. We are obligated to pay an 8% annual dividend on the Preferred Stock in cash or in equivalent shares of common stock, at our discretion. Each share of Preferred Stock is convertible into nine shares of common stock for a total of 1,242,000 common shares, which is a conversion rate of $6.00 per share.

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

OTHER COMPREHENSIVE INCOME — During the nine months ended September 30, 2007, Other Comprehensive Income decreased by $4,425,406 to a $751,791 loss to reflect a decline in the fair value of short-term investments, net of related deferred income taxes, as further discussed in Note 10.

WARRANTS — The table below reflects the status of warrants outstanding at September 30, 2007, held by others to acquire our common stock:

Issue Date	Common Shares		Exercise Price		Expiration Date
July 22, 2005		671,880	$	6.00	December 31, 2007
July 22, 2005		281,250	$	6.00	July 21, 2008
September 15, 2003		20,000	$	1.15	September 15, 2008
July 23, 2003 to September 24, 2003		54,850	$	0.75	July 24, 2008 to September 24, 2008
		1,027,980

At September 30, 2007, the per-share weighted average exercise price of outstanding warrants was $5.63 per share, and the weighted average remaining contractual life was five months.

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. Up to 2,500,000 shares of common stock are authorized under the Plan. At September 30, 2007, options to purchase 21,990 shares were available to be granted pursuant to the 2004 Plan.

The Company’s 2006 Stock Incentive Plan (the “2006 Plan”) authorizes up to 1,500,000 shares of common stock for issuance 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 September 30, 2007, options to purchase 996,400 shares were available to be granted pursuant to the 2006 Stock Incentive Plan.

Stock Options as of September 30, 2007

In January 2006, the Company entered into a participation agreement with North Finn LLC (“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 the Company’s 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, the Company has an option to require North Finn to exchange those property interests in return for the 2,900,000 shares. North Finn has not exercised its option nor made a commitment to exercise under the Emerging Issues Task Force Interpretation 96-18, whereby no value is currently recognized in our financial statements with respect to North Finn’s option. The option and the participation agreement are discussed in Note 12 Commitments and Contingencies.

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Other than the aforementioned North Finn option, outstanding stock options at September 30, 2007, are those granted under the Company’s 2004 Plan or 2006 Plan. The following table summarizes the status of stock options outstanding under the 2004 Plan and 2006 Plan:

				Weighted Avg.
	Number of			Exercise
	Shares			Price
Options outstanding — December 31, 2006 (985,498 exercisable)		2,186,000		$	3.60
Options granted in the nine months ended September 30, 2007		699,000		$	5.80
Less options forfeited in the nine months ended September 30, 2007		(235,700	)	$	5.03
Less options exercised in the nine months ended September 30, 2007		(79,300	)	$	4.65
Options outstanding — September 30, 2007 (1,305,875 exercisable)		2,570,000		$	4.06

The weighted-average, grant-date estimated fair value of stock options granted during the quarter ended September 30, 2007 was $1.70 per underlying common share. The following valuation models and key model assumptions were used for the significant options granted in the nine-month periods ended September 30, 2007 and September 30, 2006:

	September 30,	September 30,
	2007	2006
Model	Modified Binomial	Black-Scholes
Option life (in years)	4 to 5	5 to 8
Annual volatility over option life	35%	33% to 63%
Annual volatility for black-out periods	0%	33% to 63%
Risk-free interest rate	4.7% to 5.1%	4.5% to 5.2%
Pre-vesting forfeiture rate	0%	0%
Dividend yield	0%	0%
Intrinsic Value /share that urges exercise	$2.00 to $2.16	n/a for model

The reduction in expected option life reflects reduction in vesting terms and other changes in contractual terms found in options granted in 2007 compared with those granted in the 2006 period.

The Company has a policy of prohibiting executive officers and directors from buying or selling Company stock during four “black-out periods” of the year, except pursuant to a pre-arranged stock trading plan under SEC Rule 10b5-1. Such black-out periods 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. On occasion, the Company may extend or add to the black-out periods. Company employees are also prohibited from trading during periods when there exists material non-public information, which given the early stage nature of our drilling activity, could further restrict employees, officers and directors from trading in our stock. Consequently, their stock options’ value is 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 “triggering 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. The $2.00 to $2.16 triggering intrinsic value per share assumption for options granted in the nine months ended September 30, 2007 equates to approximately an $8.00 per share stock price.

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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 becomes significant.

The following table presents additional information related to the stock options outstanding at September 30, 2007 under the 2004 Plan and 2006 Plan:

	Exercise		Remaining
	price		contractual		Number of shares
	per share		life (years)		Outstanding		Exercisable
	$	1.25		2.4		403,000		403,000
	$	2.38		3.2		100,000		100,000
	$	2.48		3.3		80,000		80,000
	$	3.66		5.1		750,000		375,000
	$	4.30		5.2		9,000		3,000
	$	4.57		5.4		9,000		3,000
	$	4.66		4.6		60,000		40,000
	$	4.95		8.7		250,000		90,000
	$	4.98		6.1		200,000		90,000
	$	5.15		6.7		30,000		—
	$	5.80		4.9		75,000		50,000
	$	5.84		7.7		400,000		80,000
	$	6.03		5.4		195,000		73,125
	$	6.70		6.8		9,000		—
						2,570,000		1,387,125
Weighted Ave. remaining contractual life					5.4 years		4.5 years
Aggregate intrinsic value, Sept. 30, 2007					$	4,466,270	$	3,520,090

Note 9 — Material Related Party Transactions

We had no material related party transactions during the nine-month period ended September 30, 2007.

Note 10 — Short-term Investment

In March 2006 we received $2,610,000 of convertible notes as consideration for the sale of oil and gas properties and for a property finder’s fee. We converted the notes into the stock of a privately-held company that in May 2006 merged into publicly traded PetroHunter Energy Corporation, whereby we acquired 5,220,000 unregistered shares of PetroHunter common stock, valued at $2,610,000 ($0.50 per share). The stock became saleable in transactions exempt from registration starting in late May 2007. In June 2007, we sold 1,400,000 shares for $808,059, realizing a gain of $108,059.

In accordance with Statement of Financial Accounting Standards No. 115, unregistered shares that are reasonably expected to be sold within one year are recorded at the trading price of registered, marketable shares. At December 31, 2006, when PetroHunter common stock had a closing price of $1.62 per share, we carried the investment at $8,456,000 ($1.62 per share) and reflected in Other Comprehensive Income the associated unrealized gain of $3,673,615, net of $2,172,785 deferred income tax liability. At September 30, 2007, when PetroHunter common stock had a closing price of $0.19 per share, we carried the 3,820,000 unsold shares at $725,800 ($0.19 per share) or $1,184,200 below our cost of the 3,820,000 shares.

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Under generally accepted accounting principles, the $1,184,200 loss is to be reflected in Other Comprehensive Income (in Equity) if our management views the decline in fair value to $0.19 as temporary. The loss is to be reflected in the statement of operations if our management views the $0.31 price decline below cost ($0.50/share) as “other than temporary” during the future time period in which we expect to sell the investment. Our management views the $0.31 price decline below cost as temporary whereby the unrealized $1,184,200 loss, net of the associated $432,409 deferred tax asset, is reflected in other comprehensive income. Classification of the price decline as temporary at September 30, 2007 is based primarily on the following considerations: (a) the decline below cost occurred entirely in the third quarter of 2007; (b) the price recovered to $.30 to $.36 per share in late October; (c) PetroHunter has recently brought in a new CEO and new CFO and announced the sale of some properties; (d) we sold 500,000 PetroHunter shares in the three days ended October 25, 2007 for prices ranging from $0.25 to $0.30, and we do not plan to sell any additional shares in the fourth quarter absent further price increases; and (e) while we expect to sell the remaining shares by September 30, 2008, we can do so entirely after March 31, 2008 under Rule 144(k).

At year-end, our management may conclude, based on new facts and circumstances, that any unrealized loss at December 31, 2007, is “other-than-temporary” and recognize such unrealized loss in the fourth quarter of 2007.

Note 11 — Investment Income from Cash Equivalents

We earned investment income of $733,718 for the nine months ended September 30, 2007, by investing excess cash in short-term instruments with daily, 7-day and 28-day maturities, yielding the equivalent of approximately 4.6% to 6.5% per annum. The investments were made through a major US bank and a large US brokerage firm.

Note 12 — 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 we believe we have complied with the various laws and regulations, new rulings and interpretations may require us 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 will fund 60% of North Finn’s future 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 had 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.

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

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

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

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

This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. There are a number of risks and uncertainties that could cause our actual results to differ materially from those indicated by such forward-looking statements. These risks and uncertainties include, but are not limited to, those described in this report, in Part II, “Item 1A. Risk Factors,” those described in our annual report on Form 10-K/A for the year ended December 31, 2006, and those described from time to time in our future reports filed with the SEC.

Overview

We are an independent oil and gas exploration and production company, engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States. The following oil and gas exploration/development project updates should be read in conjunction with our annual report on Form 10-K/A for our fiscal year ended December 31, 2006.

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Fetter Project — Powder River Basin, Wyoming

At our Fetter project, we have recently concluded an approximate 50 day preliminary production test at the Sims 15-26H well. During the production test, natural gas was flowed primarily into the sales line from the unstimulated 1,165 foot horizontal lateral that was drilled and cased into the Frontier formation, one of several prospective formations in the Fetter Field. The production test included periods of intentionally flowing the well at high and low rates and designed shut in periods to evaluate pressure response. During the 50 day production test, including shut-in days, the well produced a total of approximately 168 million cubic feet of gas (mmcfg) into the sales line, and an additional 12 mmcfg was flared. The well also produced approximately 4,575 bbls of high gravity oil. Staged artificial fracture stimulation procedures are currently being performed on the Frontier formation which will be followed by frac fluid recovery operations (clean up) and additional testing. Because of the high BTU content of the natural gas, and the high liquid content (approximately three gallons per mcf), we received a price at the wellhead for August natural gas sales of $6.07 per mcf.

At the Hageman 16-34HR well, the curve that transitions the wellbore from vertical to horizontal has been drilled and cased, and the horizontal wellbore is currently being drilled in the Frontier formation in a manner designed to replicate the Sims 15-26H well. We expect to drill a lateral length of 2,000’ to 2,500’ before drilling operations are complete and completion operations commence.

We are also currently drilling the Wallis 6-23 well, which is expected to be drilled vertically to a depth of approximately 13,000’ to test the productive potential of up to five different formations in the field — the Steele, Niobrara, Frontier, Mowry and Dakota.

The Wallis 6-23, Sims 15-26H and Hageman 16-34HR wells are being funded by Red Technology Alliance (“RTA”) and project managed by Halliburton Energy Services. We are being carried through the tanks in this phase of the drilling program for a 23.125% working interest in each of the three wells. We currently own a 92.5% working interest in the approximate 52,100 net (58,300 gross) acre Fetter Field acreage position. Upon completion of this initial drilling program, RTA will earn a 25% working interest in the undrilled acreage. We will retain a 69.375% effective working interest in the undrilled acreage, and privately held North Finn LLC will retain the remaining 5.625% working interest.

West Douglas Project — Powder River Basin, Wyoming

In July 2007, we signed a participation agreement allowing RTA to fund 100% of the drilling and, if warranted, the completion costs of a deep test well at our West Douglas project. In return, RTA will earn a 50% working interest in the approximate 47,400 net (55,100 gross) acre position in the West Douglas acreage position. The West Douglas project, which is west of the Fetter Project along the southern basin bounding fault in the Powder River Basin, is part of our greater Douglas project area. This prospect keys off of a well that was drilled to a total depth of 14,500 feet by Amoco in 1981. The Amoco well had positive shows in a number of formations. We recently completed drilling the State Deep 7-16 well to a total depth of 14,220 feet. Information obtained and observed while drilling, combined with electric log analysis, indicates the well has potential pay in up to five separate formations. 4¹/2 inch production casing has been run to total depth and completion and testing operations are underway. We are evaluating the productive potential of a number of formations including the Niobrara, Frontier, Mowry, Muddy and Dakota. We currently own a 90% working interest in the acreage position, and privately held North Finn LLC owns the remaining 10%. We own a 45% carried working interest in the State Deep 7-16 test well and will retain a 45% working interest in the West Douglas undrilled acreage. As with the wells being drilled at Fetter, Halliburton is project manager for the drilling at West Douglas.

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Krejci Oil Project Powder River Basin, Wyoming

At our Krejci project in Niobrara County, Wyoming, we have a 45% working interest in approximately 126,600 net acres (132,500 gross acres). Four horizontal Mowry wells have been drilled and various completion attempts have been performed. All wells thus far have been operated by Austin, Texas based Brigham Exploration. Positive indications from these wells have encouraged Brigham and American to continue drilling to attempt refined drilling and completion methods. We have recently completed evaluating data obtained from the first four wells and are in the final stages of planning the next well that we will drill to further our knowledge and understanding of this play. We own a 45% working interest in these wells; Brigham owns a 50% working interest and is operator; and privately held North Finn LLC owns a 5% working interest.

Goliath Project, Williston Basin, North Dakota

At our Goliath project in Williams County, North Dakota, we have a 50% working interest in approximately 65,400 net acres (88,500 gross acres). We are in the final stages of completing a 3D seismic shoot in order to further understand the potential for production from the Red River formation. We participated with an 11.99% working interest in the recently completed Solberg 32-2 well, which was drilled vertically to a depth of 14,400 feet. A production test of the Winnipeg formation has been concluded with encouraging flow rates. We expect the Red River formation will also be productive in this well and expect to production test the Red River formation soon. The Solberg 32-2 is operated by Denver based Whiting Petroleum Corp. and was drilled as an offset to a discovery well that Whiting drilled earlier this year. Whiting is in the final stages of constructing a natural gas processing plant and pipeline infrastructure and we expect the Solberg 32-2 well will be producing into sales line before year end 2007.

We are also in the process of planning our next well targeting the Bakken formation. In early 2007, we completed a productive well that was drilled into the Bakken formation. We believe changes in the drilling, completion and stimulation methods can be made in order to significantly enhance the production from wells drilled into the Bakken formation.

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/A for the fiscal year ended December 31, 2006. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended September 30, 2007 Compared with the Quarter Ended September 30, 2006.

For the quarter ended September 30, 2007, we recorded a net loss attributable to common stockholders of $417,400 ($0.01 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $1,533,894 ($0.04 loss per common share, basic and diluted) for the quarter ended September 30, 2006. Included in the $1,533,894 net loss for the 2006 quarter is an $860,000 impairment of capitalized oil and gas assets.

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For the quarter ended September 30, 2007, we recorded total oil and gas revenues of $780,963 compared with $216,347 for the quarter ended September 30, 2006. The $564,616 increase from the 2006 quarter is largely attributable to new wells placed on production after September 30, 2006. Oil & gas sales and production costs are summarized in the following table:

	Three months ended September 30,
	2007			2006
Oil sold (barrels)		7,222			2,354
Average oil price	$	67.18		$	60.97
Oil revenue	$	485,185		$	143,520
Gas sold (mcf)		51,345			11,187
Average gas price	$	5.76		$	6.51
Gas revenue	$	295,778		$	72,827
Total oil and gas revenues	$	780,963		$	216,347
Less lease operating expenses		(213,708	)		(56,300	)
Less oil & gas amortization expense		(386,000	)		(132,000	)
Less accretion of asset retirement obligation		(6,537	)		(6,556	)
Less impairment of oil and gas assets		—			(860,000	)
Producing revenues less direct expenses		174,718			(838,509	)
Less depreciation of office facilities		(16,381	)		(10,715	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(969,845	)		(963,992	)
Income (loss) from operations	$	(856,508	)	$	(1,858,216	)
Total barrels of oil equivalent (“boe”) sold		15,780			4,219
Lease operating expense per boe sold	$	13.54		$	13.35
Amortization expense per boe sold	$	24.46		$	31.29

For the quarters ended September 30, 2007 and September 30, 2006, we incurred $969,845 and $963,992 in general and administrative expenses, respectively, including $676,909 and $652,155, respectively, in employee compensation, employee benefits and payroll taxes.

For the quarters ended September 30, 2007 and 2006, we recorded $149,040 and $272,219, respectively in dividends attributable to our outstanding Series AA Convertible Preferred Stock. The decrease in dividends is due to January 2007 conversions (into common stock) of 112,000 of the 250,000 total shares of convertible preferred stock.

The Nine-month Period ended September 30, 2007 Compared with the Nine-month Period ended September 30, 2006

We recorded net loss attributable to common stockholders of $1,977,842 ($0.05 loss per common share, basic and diluted) for the nine-month period ended September 30, 2007, as compared to net income attributable to common stockholders of $2,631,915 ($0.07 income per common share, basic and diluted) for the nine-month period ended September 30, 2006. Included in the net income for 2006 are (i) $7,159,470 in gains ($4.5 million after tax effect) from the sale of oil and gas properties and (ii) $1,530,000 in service fee revenue. For the nine months ended September 30, 2007, we had no recognized gain from property sales and no service fee revenue.

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For the nine months ended September 30, 2007, we recorded total oil and gas revenues of $1,580,553 compared with $2,046,232 for the nine months ended September 30, 2006. The primary reason for the revenue decline is the sale on March 31, 2006 of our interest in the Big Sky producing property that accounted for approximately $1.5 million of 2006 revenues prior to the March 31 sale. Oil & gas sales and production costs are summarized in the table that follows.

	Nine months ended September 30,
	2007			2006
Oil sold (barrels)		16,057			31,161
Average oil price	$	60.74		$	55.38
Oil revenue	$	975,279		$	1,725,630
Gas sold (mcf)		102,060			40,977
Average gas price	$	5.93		$	7.82
Gas revenue	$	605,274		$	320,602
Total oil and gas revenues	$	1,580,553		$	2,046,232
Less lease operating expenses		(466,444	)		(222,093	)
Less oil & gas amortization expense		(786,818	)		(740,639	)
Less accretion of asset retirement obligation		(18,142	)		(8,343	)
Less Impairment of oil and gas assets		—			(860,000	)
Producing revenues less direct expenses		309,149			215,157
Less depreciation of office facilities		(47,631	)		(21,232	)
Less amortization of other intangible asset		(135,000	)		(135,000	)
Less general and administrative expenses		(3,271,647	)		(2,795,311	)
Add other revenue		12,000			1,530,000
Income (loss) from operations	$	(3,133,129	)	$	(1,206,386	)
Total barrels of oil equivalent (“boe”) sold		33,067			37,991
Lease operating expense per boe sold	$	14.11		$	5.85
Amortization expense per boe sold	$	23.79		$	19.50

General and administrative expenses for the nine months ended September 30, 2007 increased $476,336 (17%) over the same nine-month period in 2006. The major changes in general and administrative expenses were (1) a $157,000 increase in financial auditing costs, (2) a $158,000 increase in costs of investor relations and shareholder communications and (3) a $102,000 increase in employee compensation arising from an increase in the number of employees.

We were exempt from paying Alternative Minimum Tax for 2006 but will not be for 2007. However, we expect to not be required to pay income taxes for 2007. For the nine months ended September 30, 2007, our recorded current portion of income tax expense was zero.

For the nine months ended September 30, 2007, we recorded a $767,000 reduction in deferred income taxes and recorded a $2,806,870 provision for the nine months ended September 30, 2006. The $3,573,870 reduction (a 127% decline) in the income tax provision is generally consistent with (and arises primarily from) the $8,537,917 reduction (a 137% decline) in the reported income before income taxes.

We recorded $453,490 and $807,780 in preferred stock dividends for the nine months ended September 30, 2007 and September 30, 2006, respectively. The decrease in dividends is due to the conversion in January 2007 of 112,000 of 250,000 total shares of the convertible preferred stock into common stock of the Company.

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Liquidity and Capital Resources

At September 30, 2007, we had $23.9 million in working capital. We had cash and cash equivalents at September 30, 2007 of $22.8 million.

In April 2007, we received approximately $27 million in cash (after offering costs) from the sale of 6,001,390 shares of our common stock. We intend to use the net proceeds to fund our oil and gas activities and for general corporate purposes.

We currently anticipate capital expenditures for the fourth quarter of 2007 to be approximately $5 million to fund our share of planned oil and gas drilling operations and to fund other known oil and gas related costs such as land and geological costs.

In 2007, RTA paid 100% of the costs to drill and complete (a) three deep wells at Fetter to earn a 75% interest in those three well bores and 25% in the Fetter acreage and (b) one well in the neighboring West Douglas project to earn a 50% interest in that well and the West Douglas acreage. We anticipate drilling additional wells in 2008 at those projects and other projects and paying our proportionate working interest in the additional wells. However, at this time, we do not have firm commitments or plans as to the size of our 2008 drilling programs and as to whether the 2008 drilling program will be funded entirely from existing working capital and cash flow from operations.

For the nine-month periods ended September 30, 2007, and September 30, 2006, our sources and uses of cash were as follows:

Net Cash Provided By Operating Activities — Our net cash provided by operating activities decreased by $3,048,645 (from $1,950,270 provided during the nine months ended September 30, 2006, to $1,098,375 used for the nine months ended September 30, 2007). The decrease was largely due to changes in accounts receivables, payables and other non-cash current assets, as shown in the table below:

	2007									2006
Major components of cash	January 1 to			July 1 to			January 1 to			January 1 to		Change from
provided (used) by operations	June 30			Sept. 30			Sept. 30			Sept. 30		2006
Cash increase (decrease) from changes in non-cash current assets & liabilities	$	(142,809	)	$	(423,625	)	$	(566,434	)	$	1,347,809	$	(1,914,243	)
Net working capital provided (used) by operations		(770,134	)		238,193			(531,941	)		602,461		(1,134,402	)
Cash provided (used) by operations	$	(912,943	)	$	(185,432	)	$	(1,098,375	)	$	1,950,270	$	(3,048,645	)

As shown in the above table, net working capital provided (used) by operations went from a net decrease of $770,134 in the first six months to a net increase of $238,193 in the third quarter. The change is due primarily to (a) third quarter revenues increasing by approximately $377,000 over revenues in the second quarter and (b) increased income from short-term investment of cash from the April 2007 sale of stock.

Net Cash Provided By or Used In Investing Activities — During the nine months ended September 30, 2007, we used a net $10.5 million of cash in investing activities. During the nine months ended September 30, 2006, our investing activities provided a net $0.4 million of cash. The $10.9 million difference is primarily due to the $10.7 million in net proceeds from the sale of our interests in Big Sky on March 31, 2006.

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Net Cash Provided By Financing Activities — During the nine months ended September 30, 2007, we received $26.9 million in cash provided by financing activities — primarily $26.5 million, net of offering costs, for the sale of common stock. During the nine months ended September 30, 2006, we had $129,960 in net cash provided by financing activities — all from the exercise of common stock warrants.

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 commodity 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 continued rising operating costs would negatively impact our oil and gas operations.

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 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.

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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/A for the year ended December 31, 2006, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K/A, are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. There have been no material changes in our risk factors from those disclosed in our 2006 annual report on Form 10-K/A.

Item 6. EXHIBITS

Exhibit No.	Description
10.1	West Douglas Participation Agreement, entered into June 28, 2007, between Red Technology Alliance, North Finn LLC and American Oil & Gas, Inc. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on July 2, 2007.)
31.1	302 Certification of Chief Executive Officer
31.2	302 Certification of Chief Financial Officer
32.1	906 Certification of Chief Executive Officer
32.2	906 Certification of Chief Financial Officer

SIGNATURES

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

Signatures	Title	Date
/s/ Patrick D. O’Brien Patrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors	November 7, 2007
/s/ Joseph B. Feiten Joseph B. Feiten	Chief Financial Officer	November 7, 2007

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