Filed by Bowne Pure Compliance

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the Fiscal Year Ended December 31, 2007


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

COMMISSION FILE NUMBER 001-31900

AMERICAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)


Nevada (State or other jurisdiction of incorporation or organization)		88-0451554 (I.R.S. Employer Identification Number)

1050 17^th Street, Suite 2400 Denver, Colorado 80265
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (303) 991-0173
Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class:		Name of Each Exchange on Which Registered:

Common Stock, $.001 par value per share		American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes þ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
o Yes þ No

Indicate by check mark whether the registrant (1) has 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. þ Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant on June 30, 2007 was $260,578,642.

The number of shares of registrant’s common stock outstanding as of March 10, 2008 was 46,488,077 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement filed under Regulation 14A promulgated by the Securities and Exchange Commission under the Securities Exchange Act of 1934, which definitive proxy statement is to be filed within 120 days after the registrant’s fiscal year ended December 31, 2007, are incorporated by reference in Part III hereof.

PART I

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The statements contained in this annual report on Form 10-K that are not historical are “forward-looking statements,” as that term is defined in Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties.

These forward-looking statements include, among others, the following:

	•		our business and growth strategies,

	•		our oil and natural gas reserve estimates,

	•		our ability to successfully and economically explore for and develop oil and gas resources,

	•		our exploration and development drilling prospects, inventories, projects and programs,

	•		availability and costs of drilling rigs and field services,

	•		anticipated trends in our business,

	•		our future results of operations,

	•		our liquidity and ability to finance our exploration and development activities,

	•		market conditions in the oil and gas industry,

	•		our ability to make and integrate acquisitions, and

	•		the impact of environmental and other governmental regulation.

These statements may be found under “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, “Business and Properties” and other sections of this annual report. Forward-looking statements are typically identified by use of terms such as “may”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the negative of such terms or other comparable terminology, although some forward-looking statements may be expressed differently.

The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this annual report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to a number of factors, including:

	•		the failure to obtain sufficient capital resources to fund our operations,

	•		an inability to replace our reserves through exploration and development activities,

	•		unsuccessful drilling activities,

	•		a decline in oil or natural gas production or oil or natural gas prices,

	•		incorrect estimates of required capital expenditures,

	•		increases in the cost of drilling, completion and gas gathering or other costs of production and operations,

	•		impact of environmental and other governmental regulation, including delays in obtaining permits,

	•		hazardous and risky drilling operations, and

	•		an inability to meet growth projections.

You should also consider carefully the statements under “Risk Factors” and other sections of this annual report, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements.

All forward-looking statements speak only as of the date of this annual report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Item 1: Business

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. We currently control the following:

	•		Approximately 124,000 gross (69,000 net) acres in the Douglas Project area, located in the southern Powder River Basin, Wyoming which includes approximately 56,000 gross (36,000 net) acres in the Fetter Prospect,

	•		Approximately 131,000 gross (49,000 net) acres in the Krejci Project, located in Niobrara County, Wyoming, and

	•		Approximately 79,000 gross (30,000 net) acres in the Goliath Project, located in the Williston Basin, North Dakota.

For more information relating to our operational activities, please see “Item 2: Properties.”

We operate in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of our operations are conducted in the United States. Consequently, we currently report a single industry segment. See “Financial Statements” and “Notes to Consolidated Financial Statements” for financial information about this industry segment.

Competition

We operate in the highly competitive oil and gas areas of acquisition and exploration; areas in which other competing companies have substantially larger financial resources, operations, staffs and facilities. Such companies may be able to pay more for prospective oil and gas properties or prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Proved Reserves

Ryder Scott Company L.P. (“Ryder Scott”), an independent petroleum engineering firm, determined our estimated proved oil and gas reserves as of December 31, 2007, 2006 and 2005 and determined the projected future cash flows from those proved reserves and the present value, discounted at 10% per annum, of those future cash flows (“PV-10 Value”), as summarized in the following table. In estimating reserves, Ryder Scott used the SEC definition of proved reserves. Projected future cash flows are based on economic and operating conditions as of the applicable December 31^st date for 2007, 2006 and 2005. In particular, projected future cash flows reflect oil and gas prices on those December 31^st dates.


	At December 31,
	2007		2006		2005 *
Proved oil reserves (bbls)		96,399		91,850		554,702
Proved NGL reserves (bbls)		53,933		**		**
Proved natural gas reserves (mcf)		1,307,159		809,847		378,213
Future net cash flows (before income taxes)	$	13,727,358	$	6,428,667	$	26,565,846
PV-10 Value	$	8,362,799	$	4,692,808	$	13,798,930


*		Approximately 90% of the reserves PV-10 value at December 31, 2005 related to our Big Sky project, which we sold on March 31, 2006.

**		At December 31, 2006 and 2005, NGL (i.e., natural gas liquids) estimated to be recovered from the produced natural gas were not significant and not separately estimated.

Volumes of reserves actually recovered and cash flows actually received from actual production may differ significantly from the proved reserve estimates and the related projected cash flows, respectively. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Reconciliation of Standardized Measure to PV-10 Value

PV-10 Value is the estimated present value of the future net revenues from our proved oil and natural gas reserves before income taxes discounted using a 10% discount rate. PV-10 Value is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 Value is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV-10 Value is widely used by security analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and natural gas industry calculate PV-10 Value on the same basis. PV-10 Value is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. The table below provides a reconciliation of our standardized measure of discounted future net cash flows to our PV-10 Value.


	At December 31,
	2007		2006		2005
Standardized measure of discounted future net cash flows	$	8,304,799	$	4,598,000	$	13,709,930
Add present value of future income tax discounted at 10%		58,000		94,808		89,000

PV-10 Value	$	8,362,799	$	4,692,808	$	13,798,930

Customers

During fiscal year 2007, we had four major customers: DCP Midstream, L.P., Wyoming Refining Company, Shell Trading (US) Company and Nexen Marketing U.S.A., Inc. Sales to those customers accounted for approximately 81% of oil and gas sales in 2007. During fiscal year 2006 and 2005, we had one major customer: Eighty Eight Oil, LLC. Sales to this customer accounted for approximately 71% and 75% of oil and gas sales in 2006 and 2005, respectively. Because there are other purchasers that are capable of and willing to purchase our oil and gas and because we have the option to change purchasers on our properties if conditions so warrant, we believe that our oil and gas production can be sold in the market in the event that it is not sold to our existing customers.

Environmental Matters

Operations on properties in which we have an interest are subject to extensive federal, state and local environmental laws that regulate the discharge or disposal of materials or substances into the environment and otherwise are intended to protect the environment. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil and criminal penalties and in some cases injunctive relief for failure to comply.

Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose ''strict liability’’ for environmental contamination. These laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of oil and gas production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action, such as closure of inactive pits and plugging of abandoned wells, to prevent pollution from former or suspended operations.

Legislation has been proposed in the past and continues to be evaluated in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as ''hazardous wastes.’’ This reclassification would make these wastes subject to much more stringent storage, treatment, disposal and clean-up requirements, which could have a significant adverse impact on operating costs. Initiatives to further regulate the disposal of oil and gas wastes are also proposed in certain states from time to time and may include initiatives at the county, municipal and local government levels. These various initiatives could have a similar adverse impact on operating costs.

The regulatory burden of environmental laws and regulations increases our cost and risk of doing business and consequently affects our profitability. The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the ''Superfund’’ law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a ''hazardous substance’’ into the environment. These persons include the current or prior owner or operator of the disposal site or sites where the release occurred and companies that transported, disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the federal or state government to pursue such claims.

It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury or property or natural resource damages allegedly caused by the hazardous substances released into the environment. Under CERCLA, certain oil and gas materials and products are, by definition, excluded from the term ''hazardous substances.’’ At least two federal courts have held that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and Recovery Act, or RCRA, which governs the generation, treatment, storage and disposal of ''solid wastes’’ and ''hazardous wastes,’’ certain oil and gas materials and wastes are exempt from the definition of ''hazardous wastes.’’ This exemption continues to be subject to judicial interpretation and increasingly stringent state interpretation. During the normal course of operations on properties in which we have an interest, exempt and non-exempt wastes, including hazardous wastes, that are subject to RCRA and comparable state statutes and implementing regulations are generated or have been generated in the past. The federal Environmental Protection Agency and various state agencies continue to promulgate regulations that limit the disposal and permitting options for certain hazardous and non-hazardous wastes.

We believe that the operator of the properties in which we have an interest are in substantial compliance with applicable laws, rules and regulations relating to the control of air emissions at all facilities on those properties. Although we maintain insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that our insurance will be adequate to cover all such costs, that the insurance will continue to be available in the future or that the insurance will be available at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations. Compliance with environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect on our capital expenditures, earnings or competitive position. We do believe, however, that our operators are in substantial compliance with current applicable environmental laws and regulations. Nevertheless, changes in environmental laws have the potential to adversely affect operations. At this time, we have no plans to make any material capital expenditures for environmental control facilities.

Employees

At December 31, 2007, we had fifteen full time employees. Our employees are not covered by a collective bargaining agreement. We consider our relationship with our employees to be good.

Website and Codes of Ethics

Our website address is http://www.americanog.com. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after electronically filed or furnished to the SEC. Additionally, posted on our website are our Code of Ethics (for senior financial management) and our Code of Business Conduct and Ethics (for all employees, officers and directors) and the Charters for our Audit Committee, our Compensation Committee and our Nominating and Corporate Governance Committee. The codes of ethics and the committee charters are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at 1050 17^th Street, Suite 2400, Denver, Colorado 80265.

Glossary of Abbreviations and Terms

Unless otherwise indicated in this document, oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids so that six Mcf of natural gas are referred to as one barrel of oil equivalent.

AMI. Area of Mutual Interest.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d. One Bbl per day.

Bc/d. Barrels of condensate daily.

Bcf. One Billion cubic feet of natural gas at standard atmospheric conditions.

Bcfe. One billion cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of six Mcf to one Bbl of oil.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Capital Expenditures. Costs associated with exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land related overhead expenditures; delay rentals; producing property acquisitions; other miscellaneous capital expenditures; compression equipment and pipeline costs.

Carried Working Interest. The owner of this type of working interest in the drilling of a well incurs no liability for drilling costs associated with a well until the well is drilled.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed Acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drill Spacing Unit. The gross minimum surface area for the drilling of one well, usually set or approved by local state law or a state agency. For example, the agency may initially require gas wells to be drilled on 640-acre spacing units. If the initial well’s production indicates that four wells are needed to access oil and gas reserves under the 640 acre spacing unit, then the agency may reduce the drill spacing unit to 160 acres to allow four wells per 640 acres.

Exploitation. The continuing development of a known producing formation in a previously discovered field. To make complete or maximize the ultimate recovery of oil or natural gas from the field by work including development wells, secondary recovery equipment or other suitable processes and technology.

Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and Development Costs. The total capital expenditures, including acquisition costs, and exploration and abandonment costs, for oil and gas activities divided by the amount of proved reserves added in the specified period.

Gross Acres. The total surface acres under which we have a working interest in an oil & gas lease.

Gross Wells. Oil and gas wells, as the case may be, in which we have a working interest.

Lease. An instrument which grants to another (the lessee) the exclusive right to enter to explore for, drill for, produce, store and remove oil and natural gas on the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.

Lease Net Acres. Usually synonymous with the term gross acres. In some circumstances, lease net acres may be less than gross acres, such as circumstances where a lease is given by parties having only a portion of the mineral rights to land below a given surface area or a given drill spacing unit. If we have a 50% working interest in leases by owners of 90% of the mineral interests for 100 gross acres, then there are 90 lease net acres and we are said to own 45 net acres relating to the 100 gross acres.

Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.

Mcf/d. One Mcf per day.

Mcfe. One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of six Mcf to one Bbl of oil.

MMcf. One million cubic feet of natural gas.

Net Acres. A net acre is deemed to exist when the sum of our fractional ownership working interests in lease net acres equals one. The number of net acres is the sum of the fractional working interests owned in lease net acres expressed as whole numbers and fractions thereof.

Net Wells. A net well is deemed to exist when the sum of our fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Operator. The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

Participant Group. The individuals and/or companies that, together, comprise the ownership of 100% of the working interest in a specific well or project.

PV-10 value. The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization or federal income taxes, and discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Re-entry. Entering an existing well bore to redrill or repair.

Reserves. Natural gas and crude oil, condensate and natural gas liquids on a net revenue interest basis, found to be commercially recoverable.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

SEC. The United States Securities and Exchange Commission

Undeveloped Acreage. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.

Title to Properties

As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time we acquire leases or enter into other agreements to obtain control over interests in acreage believed to be suitable for drilling operations. In many instances, our partners have acquired rights to the prospective acreage and we have a contractual right to have our interests in that acreage assigned to us. In some cases, we are in the process of having those interests so assigned. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted by independent attorneys. Once production from a given well is established, the operator will prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. We believe that titles to our leasehold properties are good and defensible in accordance with standards generally acceptable in the oil and gas industry.

Item 1A: Risk Factors

You should be aware that the occurrence of any of the events described in this section and elsewhere in this annual report or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, liquidity and results of operations. In evaluating our company, you should consider carefully, among other things, the factors and the specific risks set forth below and in documents we incorporate by reference. This annual report contains “forward-looking statements” that involve risks and uncertainties. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate principally to the securities markets and ownership of our common shares. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline, and you may lose all or part of your investment.

Risks related to our industry, business and strategy

We have a limited operating history in the oil and gas business, and we cannot predict our future operations with any certainty.

Our oil and gas operations commenced in 2003. Our future financial results depend primarily on (1) our ability to discover commercial quantities of oil and gas; (2) the market price for oil and gas; (3) our ability to continue to generate potential exploration prospects; and (4) our ability to fully implement our exploration and development program. We cannot predict that our future operations will be profitable. In addition, our operating results may vary significantly during any financial period. These variations may be caused by significant periods of time between discovery and development of oil or gas reserves in commercial quantities.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

The oil and natural gas industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with sales of our securities, sale of our interest in oil and gas properties and cash generated by operations. We intend to finance our known capital expenditures for 2008 primarily with existing capital and cash flow from operations. We may generate additional capital to fund increases in capital expenditures through any of: 1) the sale of some oil and gas lease interests, 2) additional sales of our securities, and 3) debt financing. We may not be able to obtain equity or debt financing on terms favorable to us, or at all. Our ability to grow our oil and natural gas reserves and cash flow would be severely impacted if we are unable to obtain equity or debt financing as we may not be able to continue to drill all or some of our projects.

Oil and natural gas prices are volatile and a decline in oil and natural gas prices can significantly affect our financial results and impede our growth.

Our revenues, profitability and liquidity are substantially dependent upon prevailing prices for oil and natural gas, which can be extremely volatile. Even relatively modest drops in prices can significantly affect our financial results and impede our growth. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a wide variety of additional factors that are beyond our control, such as the domestic and foreign supply of oil and natural gas; the price of foreign imports; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; technological advances affecting energy consumption; domestic and foreign governmental regulations; and the variations between product prices at sales points and applicable index prices.

We have incurred losses from operations in the past and may do so in the future.

Although we had net income in 2006 and 2005, we incurred a net loss in 2007. Our exploration and development of, and participation in, additional prospects will require additional capital expenditures. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire natural gas and oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

We may be unable to find additional reserves.

Our revenues depend on whether we acquire or find additional reserves. Unless we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Our planned exploration and development projects may not result in significant additional reserves. We may be unable to drill productive wells at low reserve replacement costs.

Our short-term investments consist primarily of auction rate securities that are affected by the current poor credit market which, if conditions worsen, could result in material losses.

As of December 31, 2007, the total amount of our cash and cash equivalents and short-term investments was $20,700,000, consisting of $2,400,000 in cash and cash equivalents and $18,300,000 in short-term investments. Our short-term investments included $17,325,000 of auction rate securities. Our auction rate investments consist of variable-coupon preferred stocks issued by several US-based taxable closed-end mutual funds that invest primarily in corporate securities, and are known as auction market preferred shares (“AMPS”). All of our AMPS are AAA credit-rated by one or more of the major credit rating agencies. Historically, liquidity in AMPS has been provided via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. Dividends on the AMPS are paid on the day after the scheduled auction date.

Recently, these auctions and similar auctions have had insufficient bids to buy the securities from those wishing to sell. Two of the largest groups of taxable closed end mutual funds with AMPS have recently announced plans to use debt to redeem at par value AMPS of their taxable closed end mutual funds. However, the issuer groups of our AMPS (the largest being Calamos funds) have not announced similar plans. The absence of an auction requires the issuer of the AMPS to pay a higher dividend, but does not create a default by the issuer. Dividends are being paid currently on all of our AMPS. To increase our cash balances to approximately $9,600,000, we borrowed $8,600,000 on March 14, 2008 from an affiliate of our broker. The loan is secured by our AMPS investments and matures on September 30, 2008. The note payable bears interest approximating a 5.5% annual rate and that varies with the overnight LIBOR.

We believe that the fair value of our investments in the AMPS continues to approximate the cost at which we acquired these securities. In the event that the U.S. credit crisis worsens or if other issues affect the value of our AMPS investments, we may not be able to recover the full value of our investment in these securities. If we were unable to do so and could not obtain other funding, we could suffer material losses that would have a material adverse effect on our financial condition and business.

We could be adversely impacted by changes in the oil and gas market.

The marketability of our oil and gas production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions, changes in supply and changes in demand all could adversely affect our ability to produce and market oil and natural gas. If market factors were to change dramatically, the financial impact could be substantial because we would incur expenses without receiving revenues from the sale of production. The availability of markets is beyond our control.

Oil and gas operations are inherently risky.

The nature of the oil and gas business involves a variety of risks, including operating hazards such as fires, explosions, cratering, blow-outs, and encountering formations with abnormal pressures. The occurrence of any of these risks could result in losses. The occurrence of any one of these significant events, if it is not fully insured against, could have a material adverse effect on our financial position and results of operations.

We are subject to extensive government regulations.

Our business is affected by numerous federal, state and local laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil and gas industry. These include, but are not limited to:

	•		the prevention of waste,

	•		the discharge of materials into the environment,

	•		the conservation of oil and natural gas,

	•		pollution,

	•		permits for drilling operations,

	•		drilling bonds, and

	•		reports concerning operations, spacing of wells, and the unitization and pooling of properties.

Failure to comply with any laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of injunctive relief, or both. Moreover, changes in any of the above laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

New government regulation and environmental risks could increase our costs.

Many jurisdictions have at various times imposed limitations on the production of oil and gas by restricting the rate of flow for oil and gas wells below their actual capacity to produce. Because current regulations covering our operations are subject to change at any time, we may incur significant costs for compliance in the future.

Our prices may be impacted adversely by new taxes.

The federal, state and local governments in which we operate impose taxes on the oil and gas products we sell. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. In addition, many states have raised state taxes on energy sources and additional increases may occur. We cannot predict whether any of these measures would have an adverse impact on oil and natural gas prices.

Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plans.

We may experience shortages of drilling and completion rigs, field equipment and qualified personnel which may cause delays in our ability to continue to drill, complete, test and connect wells to processing facilities. These costs have sharply increased in various areas. The demand for and wage rates of qualified drilling rig crews generally rise in response to the increased number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which may materially adversely affect our business, financial condition and results of operations.

Shortages of transportation services and processing facilities may result in our receiving a discount in the price we receive for oil and natural gas sales or may adversely affect our ability to sell our oil and natural gas.

We may experience limited access to transportation lines, trucks or rail cars used to transport our oil and natural gas to processing facilities. We may also experience limited access to processing facilities. If either or both of these situations arise, we may not be able to sell our oil and natural gas at prevailing market prices. We may be completely unable to sell our oil and natural gas, which may materially adversely affect our business, financial condition and results of operations.

Risks Related to our Common Stock

Our common stock is illiquid, so investors may not be able to sell any significant number of shares of our stock at prevailing market prices.

The average daily trading volume of our common stock was approximately 223,000 shares per day over the 90-day period ended March 7, 2008. If limited trading of our stock continues, it may be difficult for investors to sell their shares in the public market at any given time at prevailing prices.

Our stock price and trading volume may be volatile, which could result in losses for our stockholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common stock include:

	•		actual or anticipated quarterly variations in our operating results;

	•		changes in expectations as to our future financial performance or changes in financial estimates, if any;

	•		announcements relating to our business or the business of our competitors;

	•		conditions generally affecting the oil and natural gas industry;

	•		the success of our operating strategy; and

	•		the operating and stock performance of other comparable companies.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. If the market price of our common stock declines significantly, you may be unable to resell your shares of common stock at or above the price you acquired those shares. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly.

We may issue preferred stock with rights that are preferential to, and could cause a decrease in the value of, our common stock.

We may issue up to 24.75 million shares of preferred stock without action by our stockholders. Rights or preferences could include, among other things:

	•		the establishment of dividends which must be paid prior to declaring or paying dividends or other distributions to our common stockholders;

	•		greater or preferential liquidation rights which could negatively affect the rights of common stockholders; and

	•		the right to convert the preferred stock at a rate or price which would have a dilutive effect on the outstanding shares of common stock.

Item 1B: Unresolved Staff Comments

The Company has not received any unresolved written comments from the SEC regarding its periodic or current reports not less than 180 days before the end of its fiscal year to which this Form 10-K relates.

Item 2: Properties

Oil and Natural Gas Assets

Our current operations are focused primarily in three main project areas that we call Douglas, Krejci and Goliath. Our Douglas project area includes our Fetter and West Douglas projects. We are also in the early stages of working in additional project areas where we are currently leasing additional acreage and performing geological evaluations. The following is a description and current status of our specific oil and gas projects:

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

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

The Fetter area has a history of various exploration and development attempts. Numerous wells in the area, which have been drilled by others over four decades, have encountered and/or produced natural gas and condensate, including four wells drilled in the 1990’s (owned by others) that are still producing from the Niobrara and Frontier formations. We believe that prior development efforts were negatively affected by various factors including inordinately long single well drill times, drilling techniques, delays in connecting wells that resulted in the potential for significant reservoir damage and low commodity pricing environments.

Prior to our agreement with RTA, we attempted to drill and complete a total of three wells in the Fetter area, and due to mechanical complications, were unable to complete those wells as expected by us. Pursuant to the agreement with RTA, we have successfully drilled and completed two horizontal wells into the target Frontier formation, the Sims 15-26H and the Hageman 16-34HR wells, and we are in the process of completing and testing the Wallis 6-23 well, which is a vertical well designed to test the productive potential of the Dakota, Mowry, Frontier, Niobrara and Steele formations.

The Sims 15-26H continues to produce into sales from the 1,165 foot horizontal lateral that was drilled into the targeted Frontier formation. Since August, the Sims well has cumulatively produced (into the sales line and flaring during early testing) approximately .5 billion cubic feet of natural gas equivalent during which time the well was often shut in or restricted due to testing and routine completion activities. Daily production volumes fluctuate as natural gas production from the well has been affected by the relatively high volume of high gravity oil that is a natural component of the reservoir. Although the oil is a benefit from a revenue generating perspective, the high volume of oil production can prevent the well from producing at optimum rates. We believe that this results in liquid (oil) loading and is the subject of ongoing engineering, reservoir and production optimization analysis. Because of the high BTU content and inclusion of sales of natural gas liquids, which is separate from the oil production, we received a price at the wellhead for January 2008 natural gas sales of approximately $8.06 per mcf.

The Hageman 16-34HR well has been completed and has commenced natural gas production into the sales line from the unstimulated 5,200 total feet of horizontal lateral that was drilled into the targeted Frontier formation. The well is currently recovering several thousand barrels of load water used to stabilize the well prior to completion operations. We expect that once the Hageman well recovers the load water, we will experience similar oil and natural gas ratios and pricing as we are experiencing in the Sims 15-26H well.

The Wallis 16-23 well, which was drilled to a total depth of 13,000 feet, is the first vertical well we drilled in the Fetter project and is designed to test multiple prospective formations utilizing multi-stage frac technology. Our approach is to allow an economic and reserve recovery comparison to be made between a vertical completion, which combines the production from multiple formations, to a single zone horizontal completion, similar to the Sims 15-26H and Hageman 16-34HR well. To date, the Wallis well has been completed and fracture stimulated in the Dakota and Mowry formations. Preliminary testing and evaluation of the Mowry is ongoing after which additional uphole formations, including the Frontier, will be completed. Upon completion and preliminary evaluation of all prospective formations in the well, we expect to commingle and test the Dakota, Mowry and other zones of interest and then place the well on production.

We are currently planning for additional drilling in the Fetter area and may commence the next well as soon as the second quarter 2008. Although exact drilling procedures are not yet finalized, we expect the next wells will be drilled vertically, completing the wells in multiple formations and utilizing multi-stage fracture stimulation technologies. We are also considering acquiring 3D seismic data to assist in further understanding the complex geology in this area.

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

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

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

Krejci Oil Project (Powder River Basin, Wyoming)

Within our Krejci project, we are evaluating the productive potential of the Mowry formation at an approximate depth of 7,500 feet. We are focusing our efforts in and around the Krejci Field in Niobrara County, Wyoming. Our Krejci project area currently encompasses approximately 131,000 gross acres, and we own an average 39.1% working interest in approximately 126,000 lease net acres.

Mowry oil production was established on the prospect in the Krejci Field in the early 1960’s when three wells drilled to the lower Dakota formation were completed in the Mowry formation after excellent oil shows were noted during drilling. These three wells, in which we have no interest, produced commercial quantities of oil without the benefit of modern stimulation techniques. We believe that by employing modern drilling and completion techniques, production rates and ultimate recoveries of wells drilled in this area could be improved.

We have participated in the drilling and completion of four wells so far in the Krejci project. The first two wells drilled are producing, and the latest two wells are shut-in while we evaluate additional stimulation techniques. Although we currently have production from two of the four wells, we do not consider those wells to be commercially successful. Based on information gained from the first four wells, we have participated in the drilling of a fifth well, the Krejci Family Trust 32-1H well, and are in the process of completion and testing. We have made what we consider to be significant changes in the way this well was drilled and will make certain changes to the way the well is completed and stimulated. We expect to continue drilling in this area, and the rate and frequency of drilling will depend on the level of success we experience with each successive well.

Goliath Project (Williston Basin, North Dakota)

Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are primarily targeting the middle member of the Bakken formation in an emerging horizontal drilling play in the North Dakota Williston Basin. In addition to the Bakken formation, we recognize additional opportunity in other formations, and we have drilled a successful well that has been completed in the Red River formation. Our Goliath project area currently encompasses approximately 79,000 gross acres and we own a 50% working interest in approximately 60,000 lease net acres.

In late 2007, we participated in the drilling of the Solberg 32-2 well with a non-operated 11.9% working interest (a net revenue interest of approximately 9.5%). This well was drilled to a total depth of approximately 14,400 feet as an offset to a Red River formation discovery well that was drilled and is owned by another operator. The Solberg 32-2 well tested at a restricted flow rate of approximately 2.1 million cubic feet of natural gas and 408 barrels of condensate (light oil) per day at an average flowing tubing pressure of 2,500 psi on a 13/64ths choke. Additional potentially productive intervals within the Red River formation have not yet been tested, but could be tested and possibly produced at a later date. The local pipeline to allow the Solberg 32-2 well to be put on production is expected to be completed before the end of March 2008.

We and other joint interest owners in the Goliath project have recently completed a 10.5 square mile 3-D seismic program in the area around the Solberg 32-2 well and based on interpretation of the data, we see the potential for at least one additional Red River prospect. We expect to continue evaluating our acreage position for additional Red River prospects while we are evaluating the acreage position for potential production from the Bakken formation.

Oil and Gas Drilling Activities

During 2007, we participated in the drilling of a total of twelve gross (5.51 net) wells. Of these wells, four gross (0.81 net) were productive wells and six gross (2.9 net) are not yet completed for production testing. The other two gross (1.8 net) wells drilled in 2007 were shallow dry holes but extended lease lives. Two (.456 net) of the productive wells, the Sims 15-26H and the Hageman 16-34HR, were drilled in the Fetter project, one (.45 net) productive well, the Mills Trust 1-12H was drilled in our Krejci project and one (.119 net) productive well, the Solberg 32-2 well was drilled in our Goliath project. The wells drilled that have not yet completed production testing include the Wallis 16-23 well at Fetter (.23125 net), the Werner 1-14H and State 1-16H wells at Krejci (total of .90 net), the State Deep 7-16 well at West Douglas (.45 net) and two wells drilled in new areas where we are performing initial evaluation (total of 1.12 net).

During 2006, we participated in the drilling of ten gross (1.9 net) productive wells and two gross (.68 net) unproductive wells. Three (.10 net) of the productive wells were drilled in our Big Sky project, which we sold our interest in with the sale of the Big Sky project in March, 2006. We participated in the drilling of four gross (.32) productive wells, and two (.68 net) unproductive wells in projects we deem as peripheral projects to our main focus areas. In our main focus areas, we drilled the productive State 4-36 well (.54 net) in our Fetter project, we drilled the productive Krejci 3-29 well (.45 net) in our Krejci project and we drilled the productive Champion 1-25 well (.50 net) in our Goliath project.

During 2005, we participated in the drilling of 13 gross (.64 net) productive wells at our Big Sky Project. We participated in the drilling of the Sims 16-26 well at our Fetter Project, which resulted in production of natural gas and liquid hydrocarbon, and the Hageman 16-34 well, where drilling operations were temporarily suspended pending receipt of proper drilling equipment. We participated in two gross unproductive wells during 2005—the Rollman 1-29 and the Strock 1-20. We participated with an 87.5% working interest in the Rollman 1-29 at our South Glenburn Prospect and a 37.5% working interest in the Strock 1-20 well drilled at our Fort Fetterman prospect.

Oil and Gas Wells

The following table sets forth the number of oil and natural gas wells located in the United States in which we had a working interest at December 31, 2007.


Productive Wells as of December 31, 2007
	Gross (a)						Net (b)
Location	Oil		Gas		Total		Oil		Gas		Total
Wyoming		4		6		10		1.99		3.09		5.08
North Dakota		6		—		6		.95		—		.95

Total		10		6		16		2.94		3.09		6.03


(a)		The number of gross wells is the total number of wells in which a working interest is owned.

(b)		The number of net wells is the sum of fractional working interests we own in gross wells expressed as whole numbers and fractions thereof.

Oil and Gas Interests

We currently own interests in the following developed and undeveloped acreage positions. Undeveloped acreage refers to acreage that has not been placed in producing well spacing units. Our net acres are adjusted to include our effective ownership of acreage after RTA earns net acreage in Fetter and West Douglas by completing in the near future all four wells RTA drilled at Fetter and West Douglas in 2007.


	Developed				Undeveloped
State	Gross Acres		Net Acres		Gross Acres		Net Acres
Wyoming		3,840		1,866		324,870		138,907
North Dakota		3,040		800		103,332		32,648
Other neighboring states		—		—		67,644		48,106

Total		6,880		2,666		495,846		219,661

The following table presents the net undeveloped acres that we control, the type of lease and the year the leases are scheduled to expire (absent pre-expiration drilling, production or extension) and excluding leases that are held by production at December 31, 2007:


			Net Undeveloped Acres
	Year of		Fee		State		Federal		Total for
	Expiration		Leases		Leases		Leases		All Leases
Wyoming		2008		2,412		1,291		10,907		14,610	*
		2009		13,703		598		1,375		15,676
		2010		12,952		2,959		5,224		21,135
		2011		8,800		3,213		35,323		47,336
		2012		2,922		1,977		3,061		7,960
		2013		660		—		3,486		4,146
		2014		—		—		6,594		6,594
		2015		—		—		3,936		3,936
		2016		—		—		11,295		11,295
		2017		—		—		1,650		1,650

Total Wyoming				41,449		10,038		82,851		134,338


North Dakota		2008		9,740		—		—		9,740	**
		2009		10,134		457		—		10,591	**
		2010		9,071		1,727		—		10,798
		2011		1,279		—		—		1,279
		2012		7		—		—		7
		2016		—		—		120		120

Total North Dakota				30,231		2,184		120		32,535


Other states		2008		380		—		—		380
		2009		576		—		—		576
		2011		—		—		7,822		7,822
		2012		1,670		35,230		—		36,900
		2016		272		—		—		272

Total, other states				2,898		35,230		7,822		45,950

Total, all states				74,578		47,452		90,793		212,823

Undeveloped, held by production										6,838

Total undeveloped										219,661


*		We have approximately 1,900 net acres in the Fetter and West Douglas projects expiring in 2008 but under lease agreements that allow the working interest owners to extend the lease life for one to three years, at an average cost of approximately $47 per net acre. We plan to extend those leases relating to our 1,900 net acres.


**		Of our 9,740 net acres in North Dakota expiring in 2008, approximately 8,047 net acres relate to lease agreements that give the working interest owners the option to extend the lease life for typically two years (some for one year, some others for three years) at an average cost of approximately $51 per acre. The working interest owners plan to extend the leases. Our share of the extension payments will be approximately $410,000. Of our 10,591 net acres in North Dakota expiring in 2009, approximately 9,700 net acres relate to lease agreements with similar extension options (generally for one year, others for two to three years) at a cost of approximately $30 per acre, equating to a $291,000 cost to us for extending the lease life of our 9,700 net acres.

The types of leases represented in this table are comprised of more than 2,000 separate lease agreements, and no one single lease is considered a material component of our acreage position. Fee leases consist of acreage leased from other individuals or companies that own the mineral rights underlying that acreage position. State leases consist of mineral rights underlying acreage controlled by the particular state where the acreage position is located, while federal leases consist of mineral rights underlying acreage controlled by the federal government and managed by the Bureau of Land Management.

Generally, the lease agreements provide that we pay an annual fee, called a delay rental, to retain these leases until such time that a well has been drilled and is producing from the leased lands. At that time, the leased lands are considered to be “held by production” and the lease continues for as long as oil and/or gas production continues. During the period that there is production, we will pay the lessor a royalty based on the revenues received from production. Generally, fee leases provide for royalties of 12.5% to 25%, and state and federal leases provide for royalties of 12.5%. If the leases do not become held by production within the period set forth in the lease, or if we fail to pay the required delay rental obligations, the lease terminates. Generally, fee leases have terms of three to five years, state leases have terms of five to ten years and federal leases have terms of ten years. If we elect not to pay the yearly delay rental fee, the lease would terminate. We could elect not to pay the delay rental fee if we did not believe an area was promising after completing preliminary work or if we did not have sufficient funds.

Our annual aggregate delay rental obligations, if we desire to continue to keep all our leases in effect, are as follows:


Year	Rental Obligation
2008	$	247,142
2009		239,246
2010		212,479
2011		90,208
2012		46,355
Thereafter		89,136

Production Volumes, Sales Prices and Production Costs

The following table summarizes our net natural gas and oil production volumes, our average sales prices and expenses for the periods indicated. Our production is attributable to our direct interests in producing properties and the production we are allocated from our interest in our drilling programs. For these purposes, our net production will be production that is owned by us either directly or indirectly through our drilling programs, after deducting royalty, limited partner and other similar interests. The lease operating expenses shown relates to our net production.


	Year Ended December 31,
	2007		2006		2005
Production:
Natural gas (MMcf)		139.6		48.2		59.7
Oil (Bbls)		17,267		34,578		78,954
Total equivalents (Bbls)		40,532		42,603		88,910
Average Sales Price Per Unit:
Natural gas (per Mcf)	$	6.09	$	7.53	$	7.31
Oil (per Bbl)	$	64.11	$	54.79	$	53.89
Weighted average (per Boe)	$	48.27	$	52.97	$	52.77
Expenses (per Boe)	$	15.94	$	6.83	$	2.77

Office Facilities

We lease 6,844 square feet at 1050 17^th Street, Suite 2400, Denver, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed. Our obligation to provide aggregate monthly rental payments is as follows:


	Annual Rental
Year	Amount
2008	$	152,564
2009	$	155,986
2010	$	159,408
2011	$	162,820
2012	$	166,252
Thereafter	$	69,866

Item 3: Legal Proceedings

There are no legal proceedings filed, or to our knowledge, threatened against or involving the Company.

Item 4: Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

PART II

Item 5: Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common shares are traded on the American Stock Exchange under the ticker symbol “AEZ.” The table below sets forth the high and low sales prices for our common stock in each quarter of the last two fiscal years.


	Common Stock Price
	High		Low
2006
Quarter ended March 31, 2006	$	5.29	$	3.20
Quarter ended June 30, 2006	$	5.19	$	4.10
Quarter ended September 30, 2006	$	6.55	$	4.57
Quarter ended December 31, 2006	$	8.01	$	4.70

2007
Quarter ended March 31, 2007	$	6.33	$	5.19
Quarter ended June 30, 2007	$	6.78	$	4.30
Quarter ended September 30, 2007	$	6.84	$	5.39
Quarter ended December 31, 2007	$	7.70	$	5.55

On March 10, 2008, the closing sales price for our common stock as reported by AMEX was $4.10 per share.

Holders

As of March 10, 2008, there were approximately 71 holders of record of our common stock.

Dividend Policy

We have not declared a cash dividend on our common stock, and we do not anticipate the payment of future dividends. There are no restrictions that currently limit our ability to pay dividends on our common stock other than those generally imposed by applicable state law.

Issuer Purchases of Equity Securities

We did not repurchase any of our equity securities in 2007.

Performance Graph

As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the assumption that $100 was invested in our common stock at $0.25 per share on January 17, 2003, and $100 was invested in each of the Standard & Poor’s 500 Index and the Standard and Poor’s Small Cap 600 Index-Energy Sector at the closing price on January 17, 2003. January 17, 2003 is the day we changed our name to American Oil & Gas, Inc., to more accurately reflect the expected change in our operational focus to oil and gas exploration and production.


	1/17/03		12/31/03		12/31/04		12/31/05		12/31/06		12/31/07
American Oil & Gas, Inc.	$	100.00	$	275.59	$	1,082.68	$	1,594.49	$	2,562.99	$	2,283.46
S&P Small Cap 600-Energy	$	100.00	$	131.55	$	200.88	$	305.69	$	359.57	$	443.74
S&P 500	$	100.00	$	125.23	$	138.50	$	145.09	$	166.82	$	175.39

Item 6: Selected Consolidated Financial Data

The following table presents selected financial and operating data for the Company as of and for the periods indicated. It should be read in conjunction with “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our financial statements and the related notes and other information included in this annual report. The selected financial data as of December 31, 2007, 2006, 2005, 2004 and 2003 has been derived from our financial statements, which were audited by our independent auditors, and were prepared in accordance with accounting principles generally accepted in the U.S. The historical results presented below are not necessarily indicative of the results to be expected for any future period.


	Year Ended December 31,
	2007			2006			2005		2004			2003
	(in thousands, except per share data)
Statement of Operations Data:
Production Revenues	$	1,957		$	2,257		$	4,691	$	746		$	98
Service fee and other revenues		12			1,530			—		—			—
Operating expenses:
Lease operating expenses		646			291			246		80			38
Impairment expense		—			4,360			—		—			—
Depreciation, depletion and amortization		1,267			1,153			1,532		188			33
Accretion of asset retirement obligation		24			11			6		5			3
General and administrative		4,308			4,009			2,032		945			825

Total operating expenses		6,245			9,824			3,816		1,218			899

Operating income (loss)		(4,276	)		(6,037	)		875		(472	)		(801	)
Other income (expense)
Investment income		1,021			393			204		34			—


	Year Ended December 31,
	2007			2006			2005			2004			2003
	(in thousands, except per share data)
Gain (loss) on sale of securities		(15	)		—			—			—			—
Impairment of securities investment		(952	)		—			—			—			—
Gain on sale of oil and gas properties		—			7,159			—			—			—
Interest expense		(6	)		—			—			—			—

Total other income (expense)		48			7,552			204			34			—

Income (loss) before income taxes		(4,228	)		1,515			1,079			(438	)		(801	)
Income tax provision		1,485			(304	)		(46	)		—			—

Net Income (loss)		(2,743	)		1,211			1,033			(438	)		(801	)
Less: deemed dividend on warrant		(450	)		—			—			—			—
Less: dividends on preferred stock		(603	)		(1,080	)		(479	)		(62	)		(18	)

Net Income (loss) attributable to common stockholders	$	(3,796	)	$	131		$	554		$	(500	)	$	(819	)

Income (loss) per common share:
Basic	$	(0.09	)	$	0.00		$	0.02		$	(0.02	)	$	(0.03	)
Diluted	$	(0.09	)	$	0.00		$	0.02		$	(0.02	)	$	(0.03	)
Weighted average number of common shares outstanding:
Basic		44,384			37,429			34,148			25,211			23,781
Diluted		44,384			38,142			34,956			25,211			23,781
Selected Cash Flow and Other Financial Data:
Net income (loss)	$	(2,743	)	$	1,211		$	1,033		$	(438	)	$	(801	)
Less gains on sales of oil and gas properties		—			(7,159	)		—			—			—
Depreciation, depletion and amortization		1,267			1,153			1,532			188			33
Impairment		—			4,360			—			—			—
Net loss on sales of securities		15			—			—			—			—
Other non-cash items		582			308			466			411			237
Changes in current assets and liabilities		(292	)		1,496			(1,163	)		(567	)		(67	)

Net cash provided (used) by operating activities	$	(1,171	)	$	1,369		$	1,868		$	(406	)	$	(598	)

Purchases of short-term investments in securities	$	28,750		$	—		$	—		$	—		$	—
Cash proceeds from sale of short-term investments	$	12,361		$	—		$	—		$	—		$	—
Capital expenditures	$	16,214		$	16,152		$	14,147		$	2,895		$	1,734
Cash proceeds from sales of oil and gas properties	$	777		$	16,067		$	—		$	1,582		$	—

Balance Sheet Data:
Cash and cash equivalents	$	2,388		$	7,488		$	6,023		$	5,252		$	1,066
Other current assets		19,408			10,013			1,679			313			113
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment		53,402			38,869			24,921			3,481			1,924
Other property and equipment, net of depreciation		230			252			58			6			7
Other assets		12,663			12,514			13,094			—			—

Total assets	$	88,091		$	69,136		$	45,775		$	9,052		$	3,110

Current liabilities		1,831			4,656			1,434			127			426
Long term liabilities		1,383			2,392			2,010			41			31
Stockholders’ equity		84,877			62,088			42,331			8,884			2,653

Total liabilities and stockholders’ equity	$	88,091		$	69,136		$	45,775		$	9,052		$	3,110

Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying financial statements and related notes included elsewhere herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A: Risk Factors,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We focus our oil and natural gas exploration, exploitation and developmental operations on projects located in the western United States. We have funded our operations with a combination of cash received from the sale of our equity, cash flow generated from oil and gas operations, and from proceeds received from the sale of certain of our oil and gas assets. We intend to increase stockholder value by profitably growing reserves and production primarily through drilling operations. Our company began oil and gas operations in January 2003, with the purchase of interests in undeveloped acreage from two private companies—Denver, Colorado based Tower Colombia Corporation (“TCC”) and Casper, Wyoming based North Finn LLC. In April 2005, we completed a merger with TCC and we currently retain a strategic alliance with North Finn. We currently own interests in approximately 503,000 gross (222,000 net) acres primarily in the Powder River Basin of Wyoming and in the Williston Basin of North Dakota. In addition to focusing on drilling within our existing projects, we expect to continue to evaluate opportunities to expand our project portfolio.

We believe that our existing project portfolio provides us with the opportunity to rapidly grow reserves and cash flow if we are able to prove that our acreage positions can be developed in a commercial fashion. A number of unprofitable wells may need to be drilled while we test various drilling, completion and stimulation methods.

We have been able to reduce or eliminate our financial exposure in the initial drilling in our projects by creating joint venture arrangements that provide for others to pay for all or a disproportionate share of the initial drilling costs. This has allowed us to move forward in drilling a greater number of wells than if we were to drill these wells on our own. We expect to continue to use industry relationships to partially or completely fund initial drilling.

Within the main focus areas of our existing project portfolio, we expect the following drilling activity, and our share of the cost of that drilling activity to occur in 2008:


			Approximate			Expected net
	Expected		working			capital
Project	2008 wells		interest			required
						(in millions)
Fetter project — Converse County, WY		3-6		70	%	$	11-21
Krejci project — Niobrara County, WY		1-2		45	%	$	2-4
Goliath project — Williams County, ND		1-2		50	%	$	2-4

Total drilling activity		5-10				$	15-29

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

Liquidity and Capital Resources

We currently do not generate meaningful cash flow from our oil and natural gas operating activities, even though our future depends on our ability to generate oil and natural gas operating cash flow. We recognize that net cash generated from operating activities is a function of production volumes and commodity prices, both of which are inherently volatile and unpredictable, as well as operating efficiency and capital spending. Our business is a depleting one in which each barrel of oil equivalent produced must be replaced or our asset base and capacity to generate revenues in the future will shrink.

Our primary cash requirements are for exploration, development and acquisition of oil and gas properties. We have historically funded our oil and natural gas activities primarily through the sale of our equity, from the sale of certain oil and gas assets and to a lesser extent, internally generated cash flows.

Due to our active oil and natural gas activities, we currently anticipate capital requirements in 2008 to be approximately $22 million. Approximately $15 million is allocated to our expected drilling and production activities; $4 million is allocated to land, and geological and geophysical activities; and $3 million relates to our general and administrative expenses. We expect to be able to fund these capital expenditures, other commitments and working capital requirements with existing capital and expected cash flow from operations. However, we may elect to raise additional capital through the sale of debt or equity. We may expand or reduce our capital expenditures depending on, among other things, the results of future wells, and our available capital.

As of December 31, 2007, we had $17,325,000 in short-term investments in AAA credit-rated Auction Market Preferred Stocks (AMPS) issued by various U.S. mutual funds. These auction rate securities normally provide liquidity via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. Dividends on these securities are paid on the day after the scheduled auction date. Recently, these auctions and similar auctions have had insufficient bids to buy the securities from those wishing to sell. On March 14, 2008, we owned auction-rate securities with a par value of $17,250,000 that we could not immediately liquidate at par value. To increase our cash balances to approximately $9,600,000, we borrowed $8,600,000 on March 14, 2008 from an affiliate of our broker. The loan is secured by our AMPS investments and matures on September 30, 2008. The note payable bears interest currently approximating a 5.5% annual rate. The rate will change with changes in the overnight LIBOR. We plan to pay the interest from the AMPS weekly and monthly dividends, which on average currently approximate a 4.5% annual rate and are typically set at 125% to 150% of LIBOR or AA Commercial Paper rates for the payment month.

We seek to liquidate our AMPS as soon as possible. Our $17,250,000 in AMPS were issued by closed-end taxable US mutual funds investing in corporate securities, rather than muni tax-free securities. Closed-end mutual funds managed by Calamos Advisors LLC (“Calamos”) issued $11,250,000 of our AMPS. On March 3, 2008, Calamos issued a statement that it is evaluating solutions to provide liquidity to AMPS holders and that the solution Calamos settles upon as a sponsor “must address our intent to return dollar for dollar the investment that preferred security holders entrusted to the funds . . .” Eaton Vance and Nuveen, the managers of sixteen similar taxable closed end funds have recently announced that they have arranged debt financing to allow their taxable closed-end mutual funds to redeem fully or begin redeeming their $5.9 billion of AMPS. On March 11, 2008, the Federal Reserve announced a program to provide up to $200 billion in short-term Treasury securities to major Wall Street investment firms and banks.

If we are able to redeem or sell at par value our $11,250,000 in Calamos AMPS in April, we believe we could still borrow $3,000,000 on the remaining $6,000,000 of AMPS. In addition to taking our AMPS for sale at their 7-day and 28-day auctions, we are evaluating other liquidity options. If, and to the extent, we are unable to substantially liquidate the AMPS in 2008, we may need to raise cash by other means to fully fund our future capital expenditures.

Net Cash Provided By Operating Activities

Cash flows provided (used) by operating activities were ($1.2) million, $1.4 million and $1.9 million for the years ended December 31, 2007, 2006, and 2005, respectively. The $2.6 million decrease in operating cash flow in 2007 compared with 2006 is primarily due to a $1.7 million decline in oil and gas revenue receipts (largely arising from the March 31, 2006 sale of our Big Sky project). Cash-basis general and administrative payments increased by $1.1 million in 2007 compared with 2006. Investment income increased $0.6 million in 2007 compared with 2006 from short-term investment of cash proceeds from the sale of our Big Sky project. The decrease in operating cash flow from 2005 to 2006 primarily occurred due to our sale of our Big Sky project in March of 2006.

Net Cash Used In Investing Activities

Our net cash used in investing activities for 2007 was $31.8 million. In 2007 we invested $28.8 million in short-term investments and sold in 2007 $12.4 million of those investments to fund in 2007 a substantial portion of our capital expenditures. Our oil and natural gas operations are capital intensive, and we invest a substantial portion of our available capital in the acquisition, exploration and development of our oil and gas properties. We used during 2007 $16.2 million of cash for capital expenditures relating to our oil and natural gas operations. We received in 2007 approximately $0.8 million in cash relating to a 2006 sale of oil and gas assets. Capital expenditures of $11.4 million were attributable to our share of the drilling and completion of several wells: $1.5 million for completing five wells drilled in 2006, $1.2 million for three wells drilled and substantially completed in 2007, $0.1 million for two shallow dry holes in 2007 and $8.6 million for five wells begun in 2007 and to be completed in 2008. In 2007, RTA paid 100% of the costs of four new wells in which we retained working interests equivalent to 1.1 net wells. Other spending included $4.4 million primarily attributable to acquisitions of additional leases.

During the year ended December 31, 2006, we used $15.9 million relating to our oil and natural gas operations, and we used $240,000 primarily for the acquisition of furniture and equipment relating to our office move. We offset these amounts by selling oil and gas assets for approximately $16.1 million, leaving our net capital used in investing activities for 2006 at $86,000. Capital expenditures of $11.1 million were attributable to the drilling of twelve gross wells, ten of which were successful. Other spending included $4.8 million primarily attributable to land holdings and capitalized G&A.

During the year ended December 31, 2005, we used $14.1 million in investing activities. Capital expenditures of $9.9 million were attributable to the drilling of seventeen gross wells, fifteen of which were successful. Other spending included $4.2 million attributable to land holdings and $56,000 of capital expenditures associated with computer hardware, office furniture and equipment.

Net Cash Provided By Financing Activities

Cash flows provided by financing activities for the year ended December 31, 2007 came primarily from net proceeds from the sale of common stock of $26.6 million with an additional $1.3 million received from the exercise of warrants and options. For the year ended December 31, 2006 cash flows provided by financing activities of $183,000 came from the exercise of warrants and options. For the year ended December 31, 2005, cash flows provided by financing activities totaled $13.1 million. We received $12.9 million in net proceeds from the sale of our series AA convertible preferred stock and received $153,000 from the exercise of common stock warrants exercised in 2005.

Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

We recorded a net loss attributable to common stockholders of $(3,795,912) ($(0.09) per common share, basic and diluted) for the year ended December 31, 2007, as compared to net income attributable to common stockholders of $131,223 ($.00 per common share, basic and diluted) for the year ended December 31, 2006. For 2007, we recognized $12,000 of other revenues but had no gains from property sales, no service fee revenues and no impairment expense. Included in the net income for 2006 are (i) $7,159,470 in gains ($4,431,712 after tax effect) from the sale of oil and gas properties, (ii) $1,530,000 in service fee revenue and (iii) impairment expense of $4,360,000.

Oil and Gas Operations

For 2007, we had total oil and gas revenues of $1,956,508 compared with $2,256,839 for 2006. Oil and gas sales and production costs for each year are summarized in the table that follows. Oil sales volumes decreased in 2007 compared with 2006 due to the sale of our interests in the oil producing wells in the Big Sky project. Gas sales volumes increased in 2007 over 2006 largely due to gas produced and sold from a new well in our Fetter project.


	Year ended December 31,
	2007			2006
Oil sold (barrels)		17,267			34,578
Average oil price	$	64.11		$	54.79

Oil revenue	$	1,107,054		$	1,894,386


Gas sold (mcf)		139,590			48,149
Average gas price	$	6.09		$	7.53

Gas revenue	$	849,454		$	362,453


Total oil and gas revenues	$	1,956,508		$	2,256,839
Less lease operating expenses		(646,000	)		(290,803	)
Less oil & gas amortization expense		(1,021,817	)		(937,821	)
Less accretion of discount		(23,767	)		(11,213	)
Less impairments		—			(4,360,000	)

Producing revenues less direct expenses		264,924			(3,342,998	)
Less intangible asset amortization		(180,000	)		(180,000	)
Less depreciation of office facilities		(65,225	)		(35,412	)
Less general and administrative expenses		(4,307,997	)		(4,009,019	)
Add service fee revenue and other revenues		12,000			1,530,000

Income (loss) from operations	$	(4,276,298	)	$	(6,037,429	)

Total barrels of oil equivalent (“boe”) sold		40,532			42,603
Lease operating expense per boe sold	$	15.94		$	6.83
Amortization expense per boe sold	$	25.21		$	22.01

Impairments

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”. Our initial ceiling test calculation as of December 31, 2007, using oil and gas prices on that date indicated an impairment of our oil and natural gas properties of approximately $1.4 million, net of income tax. However, SEC guidance in applying the ceiling test requires consideration of subsequent price increases prior to the filing of the Form 10-K. With consideration of oil and gas prices at the end of February 2008, the ceiling exceeded total capitalized costs, eliminating the calculated impairment. As a result, we did not recognize an impairment of our oil and natural gas properties at December 31, 2007 under the full-cost method of accounting.

For the year ended December 31, 2006, we recorded an impairment against our evaluated oil and gas properties in the amount of $4.36 million. A substantial portion of the impairment occurred during the fourth quarter and results from being unable to complete the Fetter project State 4-36 well in a fashion as originally planned, which reduced the estimate of proved reserves as of December 31, 2006 for the well. We did not record any impairment for the year ended December 31, 2005.

General and Administrative Expenses

We recorded $4.3 million and $4.0 million in general and administrative expenses for the year ended December 31, 2007 and December 31, 2006, respectively. The $0.3 million increase in 2007 compared with 2006 is due primarily to a $187,000 (7%) net increase in employee compensation and a $109,000 (39%) increase in costs of financial auditing and attestation of internal controls over financial reporting. In 2007, we increased our number of employees from thirteen to fifteen (15%) but reduced employee share-based compensation by $233,000 (19%).

Service Fee Revenue in 2006

In 2006 we received a $1,530,000 convertible note from GSL Energy Corp. as a Service Fee for successfully assisting in acquiring additional Montana lease acreage that was not suitable for our acreage portfolio. We subsequently converted the $1,530,000 note into 3,060,000 shares of GSL common stock at $0.50 per share. GSL subsequently merged into publicly held PetroHunter Energy Corp. We did not generate any service fee revenue in 2007 or in 2005.

Gains on Sales in 2006 of Oil and Gas Properties

We recorded $7.2 million in gains from the sale of oil and gas properties ($4.4 million after tax effect) during the year ended December 31, 2006. The reconciliations of the gains on the sales are as follows:


	Big Sky			Bear Creek			Goliath			Totals
Contract sales price	$	11,500,000		$	1,080,000		$	6,165,520		$	18,745,520
Effective date adjustments		(821,496	)		—			—			(821,496	)

Adjusted sales price		10,678,504			1,080,000			6,165,520			17,924,024
Allocated capitalized costs using the relative fair market value method required under full cost accounting		(6,416,650	)		(648,443	)		(3,699,461	)		(10,764,554	)

Recognized gains on sales of oil and gas properties	$	4,261,854		$	431,557		$	2,466,059		$	7,159,470

Investment Income

We recorded $1,020,712 and $392,930 in investment income for the years ended December 31, 2007 and 2006, respectively. The increase in investment income results from higher short-term interest rates in 2007 and from our short-term investment of approximately $26 million in net cash proceeds from the sale of common stock in April 2007.

Income Taxes

For the year ended December 31, 2007, we recorded a $ (1,484,984) provision for deferred income taxes and recorded a $303,748 provision for the year ended December 31, 2006. The $1,484,984 deferred tax reduction is 35.1% of the $4,228,366 net loss for 2007 as compared to a 36.5% combined statutory rate for federal and state income taxes.

Dividends

For the year ended December 31, 2006, we recorded $1,080,000 million from dividends attributable to our 250,000 shares of Series AA Convertible Preferred Stock, outstanding throughout 2006. For the year ended December 31, 2007, we recorded $602,430 of preferred stock dividends. The 44% decline from 2006 is due to approximately 45% of preferred shares outstanding during 2006 being converted to common stock in early January 2007. In 2007, we recorded $450,000 deemed dividends for the estimated fair value of warrant extensions in 2007. We had no warrant extensions in 2006.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

We recorded net income attributable to common stockholders of $131,223 (income of $0.00 per common share, basic and diluted) for the year ended December 31, 2006, as compared to a net income attributable to common stockholders of $553,629 (income of $.02 per common share, basic and diluted) for the year ended December 31, 2005.

Oil and Gas Operations

For the year ended December 31, 2006, we recorded total oil and gas revenues of $2,256,839 compared with $4,691,381 for the year ended December 31, 2005. The primary reason for the revenue decline is the sale on March 31, 2006 of our interest in the Big Sky producing property that accounted for substantially all of our revenues in 2005 through March 31, 2006. Oil and gas sales and production costs are summarized in the table that follows.


	Year ended December 31,
	2006			2005
Oil sold (barrels)		34,578			78,954
Average oil price	$	54.79		$	53.89

Oil revenue	$	1,894,386		$	4,254,944


Gas sold (mcf)		48,149			59,733
Average gas price	$	7.53		$	7.31

Gas revenue	$	362,453		$	436,437


Total oil and gas revenues	$	2,256,839		$	4,691,381
Less lease operating expenses		(290,803	)		(246,134	)
Less oil & gas amortization expense		(937,821	)		(1,406,856	)
Less accretion of discount		(11,213	)		(5,608	)
Less impairments		(4,360,000	)		—

Producing revenues less direct expenses		(3,342,998	)		3,032,783
Less intangible asset amortization		(180,000	)		(120,000	)
Less depreciation of office facilities		(35,412	)		(5,555	)
Less general and administrative expenses		(4,009,019	)		(2,032,256	)
Add service fee revenue		1,530,000			—

Income (loss) from operations	$	(6,037,429	)	$	874,972

Total barrels of oil equivalent (“boe”) sold		42,603			88,910
Lease operating expense per boe sold	$	6.83		$	2.77
Amortization expense per boe sold	$	22.01		$	15.82

General and administrative expenses

We recorded $4.0 million and $2.0 million in general and administrative expenses for the year ended December 31, 2006 and December 31, 2005, respectively. The primary differences is $1.2 million recorded for the year ended December 31, 2006 pursuant to our January 1, 2006 adoption of FAS 123(R) share based payments; an increase in salaries and salaries related expense of $600,000 which results from increasing the number of full time employees hired to support our expanding oil and gas operations, from eight employees at December 31, 2005, to thirteen employees at December 31, 2006; and an increase in accounting and audit related expenses of $151,000 due to our implementation of controls and procedures required pursuant to Sarbanes-Oxley.

Investment Income

We recorded $304,000 and $46,000 in investment income for the years ended December 31, 2006 and 2005, respectively. In 2006 and 2005, we typically invested our excess cash in short term investments and money market accounts. The increase in investment income results from a higher excess cash balance and from higher interest rates in 2006 over 2005.

Income Taxes

For the year ended December 31, 2006, we recorded a $303,748 provision for deferred income taxes and recorded a $46,245 provision for the year ended December 31, 2005. The $303,748 provision reflects a projected 20% effective deferred tax rate for 2006. The effective rate is lower than the 38.1% statutory rate due primarily to percentage depletion in excess of cost depletion.

Preferred Dividends

For the year ended December 31, 2006, we recorded $1.08 million from dividends attributable to our outstanding Series AA Convertible Preferred Stock, which was outstanding for the full year. For the year ended December 31, 2005, we recorded $478,498 in preferred dividends attributable to our outstanding Series AA Convertible Preferred Stock, which was represents dividends payable from July 22, 2005 through December 31, 2005 and $844 from our then outstanding Series A Convertible Preferred Stock. The Series A Convertible Preferred Stock was converted into common shares during January 2005.

Critical Accounting Policies and Estimates

Full Cost Accounting Method

We use the full cost method of accounting for our oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee costs and general and administrative costs (less any reimbursements for such costs), incurred for the purpose of acquiring and finding oil and gas are capitalized. Unevaluated property costs are excluded from the amortization base until we have made a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to the full cost pool and thereby subject to amortization. Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. We amortize our investment in oil and gas properties through DD&A using the units of production method. Under the units of production method, the quarterly provision for DD&A is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period, and applying the respective rate to the net cost of proved oil and gas properties, including future development costs. We capitalize the portion of salaries, general and administrative expenses that are attributable to our acquisition, exploration and development activities. Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (based on period-end hedge adjusted commodity prices and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. This comparison is referred to as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows.

Revenue Recognition

We record revenues from the sales of natural gas and oil when in the month that delivery to the customer has occurred and title has transferred. This occurs when natural gas or oil has been delivered to a pipeline or a tank lifting has occurred. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. However, differences have been insignificant.

Natural Gas Imbalances

We may have an interest with other producers in certain properties, in which case we use the sales method to account for natural gas imbalances. Under this method, revenue is recorded on the basis of natural gas we actually sell. In addition, we may record revenue for our share of natural gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. We also reduce revenue for other owners’ natural gas we sell that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over-and under-produced gas balancing positions are considered in our proved reserves. As of December 31, 2007 and 2006 our produced natural gas volumes were in balance.

Asset Retirement Obligation

Our accounting for asset retirement obligations is governed by SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The adoption of SFAS No. 143 requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. As required by SFAS No. 143, our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

Stock-based Compensation

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), which revises SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. We adopted the provisions of the new standard effective January 1, 2006. Prior to the adoption of SFAS No. 123(R), we used the intrinsic value method in accordance with APB Opinion No. 25 and the disclosure only provisions of SFAS No. 123. We recorded non-cash stock-based compensation of $1.5 million, $414,000, and $406,000 in 2006, 2005 and 2004, respectively.

Recently Issued Accounting Pronouncements

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

In September 2006, the FASB issued SFAS 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-1 and FSP 157-2, which amend SFAS 157. FSP 157-1 amends SFAS 157 to exclude certain lease transactions accounted for under other accounting pronouncements. FSP 157-2 delays the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We are adopting SFAS 157 effective January 1, 2008 except the effective date is January 1, 2009 for certain nonfinancial assets and liabilities as provided in FSP 157-2. Management does not expect the adoption to have a material effect on our financial statements.

In September 2006, the FASB issued SFAS 158, Employers’ Accounting for Defined Benefit Pensions and other Postretirement Plans. We do not have postretirement plans.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies to all entities and is effective for fiscal years beginning after November 15, 2007. We elected not to adopt the fair value option for assets and liabilities held on the January 1, 2008 effective date. We do not expect SFAS 159 to have a material impact on our financial statements.

In December 2007 the FASB issued SFAS 160, Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB 51, which establishes accounting and reporting standards with regards to non-controlling interests, previously known as minority interests. We are required to adopt SFAS No. 160 on January 1, 2009, but we have no non-controlling interests. We do not expect SFAS 160 to have a material impact on our financial statements.

In December 2007 the FASB issued SFAS 141(Revised 2007), Business Combinations, which significantly changes the financial accounting and reporting of many business combination transactions, with an emphasis on valuing at fair value as of the acquisition date the related acquired assets and liabilities and any non-controlling interests of the acquired business. We are required to adopt SFAS 141(R) on January 1, 2009, and it would apply prospectively, i.e., to any acquisitions we make on or after that date.

Item 7A: Quantitative and Qualitative Disclosures about Market Risk

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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
American Oil & Gas, Inc.

We have audited the consolidated balance sheets of American Oil & Gas, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Oil & Gas, Inc. as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), American Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 14, 2008 expressed an unqualified opinion on the effectiveness of American Oil & Gas, Inc.’s internal control over financial reporting.

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado
March 14, 2008

F-2

AMERICAN OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2007 AND 2006


	2007			2006
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,388,219		$	7,488,474
Short-term investments		18,302,900			8,456,400
Trade receivables		566,789			336,188
Receivable for sale of oil and gas properties		—			777,461
Prepaid expenses		149,440			402,287
Inventory		40,904			40,904
Current deferred tax assets		347,658			—

Total current assets		21,795,910			17,501,714

PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $40,937,747 at 12/31/07 and $33,263,390 at 12/31/06)		56,987,732			41,424,253
Other property and equipment		338,614			295,485

Total property and equipment		57,326,346			41,719,738
Less accumulated depreciation, depletion and amortization		(3,694,805	)		(2,598,581	)

Net property and equipment		53,631,541			39,121,157

INTANGIBLE AND OTHER ASSETS
Goodwill		11,670,468			11,670,468
Other intangible asset		420,000			600,000
Drilling prepayments		542,876			233,058
Other assets		30,385			10,000

	$	88,091,180		$	69,136,397

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	1,568,806		$	1,964,000
Asset retirement obligations		—			40,321
Deferred income taxes		—			2,172,785
Preferred dividends payable		261,648			479,342

Total current liabilities		1,830,454			4,656,448

LONG-TERM LIABILITIES
Asset retirement obligations		323,369			194,947
Deferred income taxes		1,060,003			2,197,329

Total long-term liabilities		1,383,372			2,392,276

COMMITMENTS AND CONTINGENCIES (Note 13)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value, authorized 400,000 shares; issued and outstanding: 138,000 shares at 12/31/07 and 250,000 shares at 12/31/06; redemption value of $7,713,648 at 12/31/07 and $13,979,342 at 12/31/06		138			250
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding shares: 46,434,063 at 12/31/07 and 38,927,114 at 12/31/06		46,434			38,927
Additional paid-in capital		89,426,687			59,174,874
Accumulated deficit		(4,595,905	)		(799,993	)
Accumulated other comprehensive income		—			3,673,615

Total equity		84,877,354			62,087,673

	$	88,091,180		$	69,136,397

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

F-3

AMERICAN OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005


	2007			2006			2005
REVENUES
Oil and gas sales	$	1,956,508		$	2,256,839		$	4,691,381
Service fee and other revenues		12,000			1,530,000			—

Total revenues		1,968,508			3,786,839			4,691,381

OPERATING EXPENSES
Lease operating		646,000			290,803			246,134
General and administrative		4,307,997			4,009,019			2,032,256
Depletion, depreciation and amortization		1,267,042			1,153,233			1,532,411
Accretion of asset retirement obligation		23,767			11,213			5,608
Impairments		—			4,360,000			—

Total operating expenses		6,244,806			9,824,268			3,816,409



INCOME (LOSS) FROM OPERATIONS		(4,276,298	)		(6,037,429	)		874,972


OTHER INCOME
Gains on sales of oil and gas properties		—			7,159,470			—
Gain (loss) on sale of securities		(14,518	)		—			—
Impairment of securities investment		(952,100	)		—			—
Interest expense		(6,162	)		—			—
Investment income		1,020,712			392,930			204,244

Total other income		47,932			7,552,400			204,244

INCOME (LOSS) BEFORE INCOME TAXES		(4,228,366	)		1,514,971			1,079,216
Income tax expense —current		—			—			—
Income tax expense (reduction) —deferred		(1,484,984	)		303,748			46,245

NET INCOME (LOSS)		(2,743,382	)		1,211,223			1,032,971
Less dividends on preferred stock		(602,530	)		(1,080,000	)		(479,342	)
Less deemed dividends on warrant extensions		(450,000	)		—			—

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(3,795,912	)	$	131,223		$	553,629


NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	(0.09	)	$	0.00		$	0.02
Diluted	$	(0.09	)	$	0.00		$	0.02

Weighted average common shares outstanding:
Basic		44,383,861			37,428,506			34,148,065
Diluted		44,383,861			38,142,011			34,955,624

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

F-4

AMERICAN OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005


	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(2,743,382	)	$	1,211,223		$	1,032,971
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Gains on sales of oil and gas properties		—			(7,159,470	)		—
Service fee received in the form of a convertible note		—			(1,530,000	)		—
Depletion, depreciation and amortization		1,267,042			1,153,233			1,532,411
Accretion of asset retirement obligation		23,767			11,213			5,608
Deferred income taxes		(1,484,984	)		303,748			46,245
Share-based compensation		1,091,677			1,522,219			413,764
Impairment provision		—			4,360,000			—
Unrealized loss on investment in securities		952,100			—			—
Net loss on sales of securities		14,518			—			—
Changes in current assets and current liabilities:
Decrease (increase) in trade receivables		(230,601	)		1,145,355			(1,222,695	)
Decrease (increase) in yard inventory		—			—			(40,904	)
Decrease (increase) in advances and prepaid expenses		252,847			(245,812	)		(745,425	)
Increase (decrease) in accounts payable and accrued liabilities		(314,090	)		596,935			845,933

Net cash provided (used) by operating activities		(1,171,106	)		1,368,644			1,867,908


CASH FLOWS FROM INVESTING ACTIVITIES
Cash purchases of short-term investments in securities		(28,750,000	)		—			—
Cash proceeds from sale of short-term investments		12,360,482			—			—
Cash proceeds from sales of oil and gas properties		777,461			16,066,563			—
Cash paid for oil and gas properties		(15,841,067	)		(15,913,075	)		(14,091,540	)
Cash paid for office equipment and software		(43,129	)		(229,178	)		(55,913	)
Drilling prepayments and other long-term assets		(330,203	)		(10,000	)		—

Net cash used in investing activities		(31,826,456	)		(85,690	)		(14,147,453	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of preferred stock		—			—			13,499,927
Proceeds from sale of common stock		28,506,602			—			—
Cash paid for stock offering and issuance costs		(1,956,465	)		(2,283	)		(584,980	)
Proceeds from warrant exercise		705,025			55,508			152,600
Proceeds from employee stock option exercise		642,145			24,800			—
Proceeds from stock option exercises by a consultant		—			104,673			—
Preferred dividends paid in cash		—			—			(18,864	)
Cash received from acquired company		—			—			1,795

Net cash provided by financing activities		27,897,307			182,698			13,050,478


NET INCREASE (DECREASE) IN CASH		(5,100,255	)		1,465,652			770,933
CASH, BEGINNING OF YEAR		7,488,474			6,022,822			5,251,889

CASH, END OF YEAR	$	2,388,219		$	7,488,474		$	6,022,822

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

F-5

AMERICAN OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

FOR YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005


											Additional			Comprehensive Income
	Preferred			Stock			Common		Stock		Paid-in			Accumulated			Accumulated			Total
	Shares			Amount			Shares		Amount		Capital			Deficit			Other Income			Equity
December 31, 2004 Balances		67,000		$	67			29,153,702	$	29,154	$	10,339,039		$	(1,484,001	)		—			8,884,259
Series A Preferred Stock conversion		(67,000	)		(67	)		670,000		670		(603	)								—
Sale of Series AA Preferred Stock		250,000			250							13,499,677									13,499,927
Costs of preferred stock offering												(1,160,524	)								(1,160,524	)
Warrants issued for placement costs												575,544									575,544
Stock issued for Tower merger								5,800,000		5,800		15,190,200									15,196,000
Shares issued for oil prospect								675,000		675		4,184,325									4,185,000
Shares issued to Director								37,500		37		195,212									195,249
Warrants exercised at $1.09 / share								140,000		140		152,460									152,600
Options for investor relations service												77,264									77,264
Warrants for oil project consulting												31,564									31,564
Deferred compensation recognized												141,250									141,250
Net income															1,032,971						1,032,971
Dividends, Series A Preferred Stock															(844	)					(844	)
Accrued dividends, Series AA Pref.															(479,342	)					(479,342	)

December 31, 2005 Balances		250,000		$	250			36,476,202	$	36,476	$	43,225,408		$	(931,216	)		—		$	42,330,918
Accrued dividends, Series AA Pref.															(1,080,000	)					(1,080,000	)
Series AA preferred stock dividends paid in common stock								239,493		240		1,079,760									1,080,000
Shares issued for oil and gas properties								2,050,000		2.050		13,074,667									13,076,717
Shares to new employees								20,000		20		96,280									96,300
Stock option exercised by employee								10,000		10		24,790									24,800
Stock options exercised by consultant								32,010		32		104,641									104,673
Warrants exercised								46,004		46		55,462									55,508
Shares issued for consulting services								26,405		26		123,285									123,311
Deferred stock-based compensation								27,000		27		(27	)								—
Deferred compensation recognized												71,820									71,820
Stock option compensation expense												1,230,788									1.230.788
Warrant issued for properties												88,000									88,000
Comprehensive income:
Net income															1,211,223
Unrealized gain on short-term investment, net of tax																		3,673,615
Total comprehensive income																					4,884,838

December 31, 2006 Balances		250,000		$	250			38,927,114	$	38,927	$	59,174,874		$	(799,993	)	$	3,673,615		$	62,087,673
Conversion of preferred to common		(112,000	)		(112	)		1,008,000		1,008		(896	)								—
Accrued dividends, Series AA Pref.															(602,530	)					(602,530	)
Series AA preferred stock dividends paid in common stock								131,155		131		820,093									820,224
Sale of stock at $4.75/share for cash								6,001,390		6,001		28,500,601									28,506,602
Cash paid for stock offering costs												(1,956,465	)								(1,956,465	)
Exercise of employee stock options								134,300		134		642,011									642,145
Exercise of warrants								117,504		118		704,907									705,025
Deemed dividends on warrant extensions												450,000			(450,000	)					—
Share-based compensation:
Stock option expense												914,301									914,301
Deferred stock-based compensation								109,600		110		(110	)								—
Accrued stock-based compensation												148,176									148,176
Common stock granted & issued								5,000		5		29,195									29,200
Comprehensive income (loss):
Net loss															(2,743,382	)
Decline in unrealized gain on short- term investment, net of tax																		(3,673,615	)
Total comprehensive loss																					(6,416,997	)

December 31, 2007 Balances		138,000		$	138			46,434,063	$	46,434	$	89,426,687		$	(4,595,905	)	$	—		$	84,877,354

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

F-6

AMERICAN OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

ORGANIZATION

American Oil & Gas, Inc. is an independent energy company engaged in the acquisition, exploration and development of crude oil and natural gas reserves and production in the western United States. In these Notes, the terms “Company”, “American”, “we”, “us”, “our” and terms of similar import refer to American Oil & Gas, Inc.

Our operations are currently focused in Wyoming and North Dakota. We own a wholly-owned subsidiary, Tower American Corporation, for conducting our oil and gas exploration and production operations in Colorado. We do not anticipate operating outside the United States. The Company’s resources and assets are reported as one operating segment. Our fiscal year end is December 31.

We were incorporated on February 15, 2000, under the laws of the State of Nevada. We began oil and gas operations in January 2003, with the acquisition of undeveloped oil and gas prospects in Montana and Wyoming from Tower Colombia Corporation and North Finn, LLC. In April 2005, we acquired Tower Colombia Corporation.

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 expected oil and gas prices can reduce the value of our oil and gas properties.

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable.

BASIS OF PRESENTATION

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles, or GAAP. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 2 describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our financial statements are the following:

	•		estimates of proven (i.e., reasonably certain) oil and gas reserve quantities, which affect the calculations of amortization and impairment of capitalized costs of oil and gas properties;

	•		estimates of the fair value of oil and gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;

	•		estimates of the fair value of stock options at date of grant; and

	•		the assumption required by GAAP that proved reserves and generally proved reserve value for measuring capitalized cost impairment be based on the prices of oil and gas at the end of the reporting period.

The estimated fair values of our unevaluated oil and gas properties affect the calculation of gain on the sale of material properties and affect our assessment as to whether portions of unevaluated capitalized costs are impaired, which also affects the calculation of recorded amortization and impairment expense with regards to our capitalized costs of oil and gas properties.

F-7

The fair value of stock options at the date of grant to employees is based on judgment as to expected future volatility of our common stock and expected future choices by employees as to when options are exercised.

Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

CASH AND CASH EQUIVALENTS — For purposes of reporting cash flows, we consider cash equivalents to be all highly liquid investments with a maturity of three months or less at the time of purchase. On occasion, the Company may have cash in banks in excess of federally insured amounts.

FAIR VALUE — The carrying amounts reported in the consolidated balance sheets for cash, accounts receivable, prepaid expenses, accounts payable and accrued liabilities approximate fair value because of the immediate or short-term maturity of these financial instruments.

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

ACCOUNTS RECEIVABLE AND CREDIT POLICIES — We have certain trade receivables consisting of oil and gas sales obligations due under normal trade terms. Our management regularly reviews trade receivables and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. At December 31, 2007 and 2006, management had determined no allowance for uncollectible receivables was necessary.

ASSET RETIREMENT OBLIGATIONS — When we incur an obligation for future asset retirement costs, we record as a liability and as a cost of the acquired asset the present value of the estimated future asset retirement obligation. For example, when we drill a well, we record a liability and an asset cost for the present value of estimated costs we will incur at the end of the well’s life to plug the well, remove surface equipment and provide restoration of the well site’s surface. Over time, accretion of the liability is recognized as an operating expense, and the capitalized cost is amortized over the expected useful life of the related asset. Our asset retirement obligations (“ARO”) relate primarily to 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 years ended December 31, 2007 and 2006:


	2007			2006
Asset retirement obligation beginning of year	$	235,268		$	117,011
Liabilities incurred		162,733			81,831
Liabilities settled		(22,898	)		(7,745	)
Accretion		23,767			11,213
Revisions in estimated liabilities		(75,501	)		32,958

Asset retirement obligation end of year	$	323,369		$	235,268

Current portion of obligation end of year	$	—		$	40,321

OIL AND GAS PROPERTIES — We use the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development (including costs of unsuccessful exploration) are capitalized within cost centers, generally by country. At December 31, 2007 and 2006, all of the Company’s oil and gas properties and operations are located in one cost center, the United States.

F-8

Under the full cost method, no gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and unless the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center.

Capitalized costs of oil and gas properties evaluated as having, or not having, proved reserves are amortized in the aggregate by country using the unit-of-production method based upon estimated proved oil and gas reserves. The costs of properties not yet evaluated are not amortized until evaluation of the property. For amortization purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Amortizable costs include estimates of future development costs of proved undeveloped reserves.

Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unevaluated properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, the excess is charged to earnings as an impairment expense, net of its related reduction of the deferred income tax provision. The present value of estimated future net cash flows is computed by applying period-end oil and gas prices of oil and natural gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. SEC guidance allows the ceiling to be increased for subsequent events occurring reasonably before the filing date of the affected financial statements and indicative that capitalized costs were not impaired at period-end. Such subsequent events are increased oil and gas prices and the proving up of additional reserves on properties owned at period-end. The present value of proved reserves’ future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet (following SEC Staff Accounting Bulletin No. 106).

As discussed in Note 3, we sold on March 31, 2006, a property having approximately 90% of our proved reserves and production prior to the sale. As is consistent for full cost accounting companies, the related revenues and expenses for 2006 associated with the property sold were reflected as continuing operations since we did not sell our entire U.S. full cost pool.

OTHER PROPERTY AND EQUIPMENT — We record at cost any long-lived tangible assets that are not oil and gas property. Depreciation is recorded using the straight-line method over the estimated useful lives of the related assets of three to five years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. We have not recognized any impairment losses on non oil and gas long-lived assets.

IMPAIRMENT — Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment and Disposal of Long-Lived Assets, requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas properties accounted for using the full cost method of accounting (which we use) are excluded from this requirement but continue to be subject to the full cost method’s impairment rules.

BUSINESS COMBINATIONS — We account for business combinations in accordance with SFAS 141, Business Combinations, whereby combinations of companies not previously under common control are regarded as a purchase by the acquiring or surviving company. The purchase is recorded at fair value with the purchase price allocated to the acquired company’s assets and liabilities at their estimated fair values. Goodwill is recognized to the extent the acquired company’s fair value exceeds the net fair value of its assets and liabilities, including intangible assets with limited life. We recognized goodwill in our 2005 acquisition of Tower Colombia Corporation, as more fully discussed in Note 5.

F-9

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

We have only one business segment, oil and gas exploration and production. Within that segment we have only one reporting unit. Accordingly, the fair value of our one reporting unit generally approximates the fair value of our company’s stock. Since recording goodwill in 2005 through December 31, 2007, the fair value of the Company’s outstanding preferred and common stock has substantially exceeded the carrying value (i.e., book value) of stockholders’ equity for the Company, and no impairment of recorded goodwill existed in 2005, 2006 or 2007 under the accounting rules of SFAS 142.

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

INCOME TAXES — We account for income taxes under the provisions of SFAS No. 109, Accounting for Income Taxes. Under the asset and liability method of SFAS 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

REVENUE RECOGNITION AND GAS BALANCING — We recognize oil and gas revenues from our interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. We use the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2007 and 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.

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.

CONCENTRATION OF CREDIT RISK — Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash. We maintain cash assets at one financial institution. We periodically evaluate the credit worthiness of financial institutions, and maintain cash accounts only in large high quality financial institutions. We believe that credit risk associated with cash is remote. The Company is exposed to credit risk in the event of nonpayment by counter parties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counter parties is subject to continuing review.

SHARE-BASED COMPENSATION — Effective January 1, 2006, we adopted SFAS 123 (R), Share-Based Payment, on a modified prospective basis, as discussed further in Note 7. SFAS 123(R) requires publicly-held companies to recognize in their statements of operations the grant-date fair value of stock options and other equity-based compensation to employees, consistent with the rules under SFAS 123 for options to non-employees.

For 2005 we accounted for employee stock options using the intrinsic value method of accounting prescribed under Accounting Principles Board Opinion No. 25, as allowed by SFAS 123, before its revision by SFAS 123(R). A stock option’s intrinsic value is the fair value of the underlying stock, if any, in excess of the option exercise price to acquire the stock. We typically granted employee stock options with an exercise price equal to the stock’s market price at date of grant, whereby such options had an intrinsic value of zero when granted. Accordingly, for 2005, we recognized no compensation expense for employee stock options which had zero intrinsic value at date of grant, but we did recognize compensation expense for the estimated fair value of stock options and warrants when granted to non-employees as compensation.

F-10

OFF BALANCE SHEET ARRANGEMENTS — We have no off balance sheet arrangements.

SEGMENT REPORTING — We follow SFAS 131, Disclosure about Segments of an Enterprise and Related Information, which amended the requirements for a public enterprise to report financial and descriptive information about its reportable operating segments. Operating segments, as defined in the pronouncement, are components of an enterprise about which separate financial information is available that is evaluated regularly by the Company in deciding how to allocate resources and in assessing performance. The financial information is required to be reported on the basis that is used internally for evaluating segment performance and deciding how to allocate resources to segments. The Company operates in one segment, oil and gas producing activities.

COMPREHENSIVE INCOME — For 2005, there are no adjustments necessary to the net income (loss) as presented in the accompanying consolidated statements of operations to derive comprehensive income in accordance with SFAS 130, “Reporting Comprehensive Income.” For 2006 and 2007, comprehensive income is disclosed in the Consolidated Statements of Shareholders’ Equity.

RECLASSIFICATION — Certain amounts in the 2005 and 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).

RECENT ACCOUNTING PRONOUNCEMENTS

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

In September 2006, the FASB issued SFAS 158, Employers’ Accounting for Defined Benefit Pensions and other Postretirement Plans. We do not have postretirement plans.

F-11

NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at December 31, 2007, 2006 and 2005 consisted of the following:


	2007			2006			2005
Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization	$	40,937,747		$	33,263,390		$	17,843,133
Evaluated costs		15,774,514			7,958,908			8,600,696
Asset retirement costs		275,471			201,955			104,093

		56,987,732			41,424,253			26,547,922
Furniture, equipment and software		338,614			295,485			68,023

		57,326,346			41,719,738			26,615,945
Less accumulated depreciation, depletion and amortization		(3,694,805	)		(2,598,581	)		(1,636,246	)

Property and equipment	$	53,631,541		$	39,121,157		$	24,979,699

Unevaluated Oil and Gas Properties

Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation. The following table shows, by year incurred, the unevaluated oil and gas property costs (net of transfers to evaluated costs and net of sales proceeds) excluded from the amortization computation:


	Net Costs
Year Incurred	Incurred
Year ended December 31, 2007	$	13,026,504
Year ended December 31, 2006		15,308,590
Year ended December 31, 2005		11,957,919
Prior to 2005		644,734

	$	40,937,747

Costs associated with unevaluated properties are primarily lease acquisition costs but include $9.5 million of costs for wells-in-progress, which at March 11, 2008 are in the process of being evaluated. Five of the wells-in-progress, with a total cost of $8.6 million at December 31, 2007 are anticipated to be evaluated by June 30, 2008.

F-12

Prospect leasing and acquisition normally require one to three years, and the subsequent evaluation normally requires an additional one to three years.

Our major projects are Fetter, West Douglas, Krejci and Goliath. The following table presents the unevaluated capitalized oil and gas properties’ costs and net change for 2007, by major project:


								Approximate Acres 12/31/07
	Capitalized Costs (in millions)							(Unaudited)
Project (State)	12/31/06		Net Change			12/31/07		Gross		Lease Net*		Our Net *
Fetter Project, Powder River Basin (WY)	$	18.7	$	(4.3	)	$	14.4		53,125		50,730		34,811
West Douglas Project, Powder River Basin (WY)		3.7		0.5			4.2		53,808		49,743		20,722
Douglas Project, Powder River Basin (WY)		0.8		0.1			0.9		14,231		13,912		11,636
Krejci Oil Project, Powder River Basin (WY)		2.3		6.9			9.2		129,314		124,565		48,743
Goliath Project, Williston Basin (ND)		6.6		0.4			7.0		77,508		59,117		29,559
Other projects		1.2		4.0			5.2		167,860		151,055		74,190

Total unevaluated costs and acres	$	33.3	$	7.6		$	40.9		495,846		449,122		219,661


*		Lease 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 net acres’ amount is the product of the lease net acres times our average effective working interest percentage. For the Fetter project, the average effective working interest is that which we effectively will own once RTA earns its 25% working interest in Fetter unevaluated acreage by completing two wells drilled at Fetter in 2007. Two wells have been completed, and we expect RTA to finish completion of the third well by April 30, 2008. The West Douglas Project acreage extends to its east within four miles of the Fetter Project acreage. The Douglas Project acreage lies largely in the townships immediately north of the Fetter acreage. After RTA earns its 50% working interest in West Douglas acreage by completing a well drilled in late 2007, our effective working interest in West Douglas acreage will average 41.7%.

The 2007 $4.3 million net decrease in unevaluated costs in our Fetter project reflects additions net of $5.3 million reclassified as evaluated costs. We estimate that the remaining $14.4 million will be reclassified as evaluated costs as additional wells are drilled within the Fetter Project. The $14.4 million 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 of all formations is expected to conclude within 60 days.

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 $9.2 million in unevaluated costs for the Krejci Prospect includes $5.3 million in costs of the third and fourth wells, drilled in 2007. The two wells are shut-in while we evaluate additional stimulation techniques. We anticipate that those new wells will be evaluated for proved reserves in 2008, whereupon approximately $5.5 million in drilling and lease acquisition costs incurred by December 31, 2007 will be reclassified as evaluated and become a part of our full cost pool’s amortization base. The remaining $3.7 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 and a recent 3-D seismic program in the area. The acquisitions began in October 2005. Wells continue to be drilled within and near the leased acreage.

F-13

Information relating to the Company’s costs incurred in its oil and gas operations during the year ended December 31, 2007, 2006 and 2005 are summarized as follows:


	2007		2006		2005
Property acquisition costs, unproved properties	$	4,395,467	$	19,887,879	$	13,906,210
Property acquisition costs, proved properties		—		163,569		210,000
Exploration costs		11,364,497		9,285,354		7,011,666
Asset retirement costs		73,516		86,649		70,701
Development costs		—		691,626		2,932,459

	$	15,833,480	$	30,115,077	$	24,131,036

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Exploration costs include the costs of geological and geophysical activity, and drilling and equipping exploratory wells. Development costs include drilling and other costs incurred within a proved area of oil and gas. We review and determine the cost basis of drilling prospects on a drilling location basis.

Significant Property Sales in 2006

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

In April 2006, we sold our 8,653 net acres in unproved Montana leases referred to as the Bear Creek prospect. Our lease interests were sold to privately owned MAB Resources in exchange for a convertible $1,080,000 note from GSL Energy Corp., a private affiliate of MAB Resources. That same month we converted the note into 2,160,000 shares of GSL common stock. In May 2006, GSL merged into a publicly-traded company whereby as of December 31, 2006 we owned (in lieu of the $1,080,000 note receivable) 2,160,000 unregistered shares of the merged company renamed PetroHunter Energy Corporation (See Note 4).

In May 2006, we sold to Teton Energy Corporation for $6.2 million a 25% working interest in our Goliath project. The project consisted of unproved leases of approximately 58,000 gross acres in the Williston Basin of North Dakota. Teton paid us $2.46 million in cash at closing and is paying an additional $3.69 million as we incur that amount of costs in drilling and completing the project’s first two wells. At December 31, 2006, Teton owed us $777,461 of the $3.69 million.

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


	Big Sky			Bear Creek			Goliath			Totals
Contract sales price	$	11,500,000		$	1,080,000		$	6,165,520		$	18,745,520
Effective date adjustments		(821,496	)		—			—			(821,496	)

Adjusted sales price		10,678,504			1,080,000			6,165,520			17,924,024
Allocated capitalized costs using the relative fair market value method required under full cost accounting		(6,416,650	)		(648,443	)		(3,699,461	)		(10,764,554	)

Recognized gains on sales of oil and gas properties	$	4,261,854		$	431,557		$	2,466,059		$	7,159,470

F-14

Significant Property Acquisitions in 2006

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 has incurred in jointly owned project areas after the effective date of August 1, 2005.

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

On September 1, 2006, we issued 2,050,000 shares of common stock to SunStone Oil & Gas, LLC (based in Oklahoma City) in exchange for all its interests in the Fetter Project. The acquired interests equate to approximately 13,300 net undeveloped acres and 320 net developed acres. The acquisition raised our project ownership interest from 67.5% to 92.5% in lease rights on approximately 53,000 net acres. On September 1, 2006, our stock closed at $6.38 per share, and that price sets the total value of the acquisition at $13,079,000.

Impairment of Oil and Gas Properties

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 in Note 2. Our initial ceiling test calculation as of December 31, 2007, using oil and gas prices on that date indicated an impairment of our oil and natural gas properties of approximately $1.4 million, net of income tax. However, SEC guidance in applying the ceiling test allows consideration of subsequent price increases prior to the filing of the Form 10-K. With consideration of oil and gas prices at the end of February 2008, the ceiling exceeded total capitalized costs, eliminating the calculated impairment. As a result, we did not recognize an impairment of our oil and natural gas properties at December 31, 2007.

We recognized ceiling test impairments at September 30, 2006 and at December 31, 2006, totaling $4,360,000 and related reductions in deferred income taxes totaling $1,663,000. A substantial portion of the 2006 impairments occurs from being unable to complete the Fetter Project State 4-36 well in a fashion as originally planned, reducing the estimate of proved reserves for the well. To a lesser extent, the initial low reserve value attributable to the Goliath project Champion 1-25 well and the costs associated with two unsuccessful wells at our peripheral North Walker Creek prospect also contributed to the impairments in 2006.

Amortization Rate

Amortization of oil and gas property is calculated quarterly based on the quarter’s production in barrels of oil equivalent (“boe”) times an amortization rate. The amortization rate is an amortization base divided by the boe sum of proved reserves at the end of the quarter and production during the quarter. The amortization base consists of (i) the capitalized evaluated oil and gas costs at the end of the quarter before recording any impairment at quarter’s end, plus (ii) estimated future development costs for the proved reserves, less (iv) accumulated amortization at the beginning of the quarter. For 2007, 2006 and 2005, the annual average amortization rates were $25.21, $22.01 and $15.82, respectively, per boe. The amortization rate at December 31, 2007 was $31.45 per boe of proved reserves.

The following table shows by type of asset the Depreciation, Depletion and Amortization (“DD&A”) expense for the years ended December 31, 2007, 2006 and 2005:


	2007		2006		2005
Amortization of costs for evaluated oil and gas properties	$	1,021,817	$	937,821	$	1,406,856
Depreciation of office equipment, furniture and software		65,225		35,412		5,555
Amortization of Other Intangible Asset (Note 5)		180,000		180,000		120,000

Total DD&A expense	$	1,267,042	$	1,153,233	$	1,532,411

F-15

NOTE 4 — SHORT-TERM INVESTMENTS

Our short-term investments at December 31, 2007 were comprised of unregistered shares of PetroHunter common stock and auction-rate securities and at December 31, 2006 unregistered shares of PetroHunter common stock:


	As of December 31,
	2007		2006
PetroHunter common shares owned		4,445,000		5,220,000

Average cost per share	$	0.43	$	0.50
Fair value per share	$	0.22	$	1.62
Carrying value (at fair value)	$	977,900	$	8,456,400
Auction-rate securities at fair value		17,325,000		—

Total, short-term investments	$	18,302,900	$	8,456,400

PetroHunter Common Stock

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 October 2007, we sold an additional 500,000 shares, realizing a loss of $122,577. On November 2, 2007 when PetroHunter stock closed at $0.24 per share, we exchanged production payment rights in unproved oil property owned by PetroHunter for 1,125,000 additional unregistered shares of PetroHunter common stock.

In accordance with SFAS 115, our investments in PetroHunter common stock are classified as investments held for sale. Those 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 December 31, 2007, when PetroHunter common stock had a closing price of $0.22 per share, we carried the 4,445,000 unsold shares at $977,900 ($0.22 per share). Management believes the unrealized loss of $952,100 at December 31, 2007 is other-than-temporary, and we recognized the loss in our Consolidated Statement of Operations for 2007.

Auction-rate Securities

At December 31, 2007, we had invested in twelve AAA credit-rated, variable-coupon preferred stocks in closed-end mutual funds. These auction market preferred shares (“AMPS”) normally provide liquidity via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. Dividends on these securities are paid on the day after the scheduled auction date. We classified these auction-rate securities at December 31, 2007 as trading securities under SFAS 115. Since these securities trade at their par values, no gains or losses are recorded. At December 31, 2007, the fair value of these investments approximated the cost at which we acquired the securities.

Recently, these auctions and similar auctions have had insufficient bids to buy the AMPS from those wishing to sell, as further discussed in Note 14, Subsequent Events.

F-16

NOTE 5 — GOODWILL AND OTHER INTANGIBLE ASSET

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

In the merger, we recognized a $900,000 other intangible asset. It relates to non-compete provisions and performance-based compensation terms reflected in five-year employment agreements with TCC’s three owners, who serve as officers of American. The $900,000 asset is amortized over five years, beginning in April 2005, on a straight-line basis, equating to a $15,000 monthly amortization expense.

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.

Income tax expenses and effective income tax rates for the years ended December 31 consist of the following:


	2007			2006			2005
Current taxes	$	—		$	—		$	—
Deferred taxes		(1,484,984	)		303,748			46,245
Valuation allowance		—			—			—

Income tax expense (reduction)	$	(1,484,984	)	$	303,748		$	46,245


Income (loss) before income taxes	$	(4,228,366	)	$	1,514,971		$	1,079,216
Effective income tax rate		35.1	%		20.0	%		4.3	%

The effective income tax rate for the years ended December 31 differs from the U.S. Federal statutory income tax rate as follows:


	2007			2006			2005
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
State income taxes		1.5	%		3.1	%		3.5	%
Permanent differences:
Compensation using qualified stock options		(3.3	%)
Excess percentage depletion		1.5	%		(22.0	%)		—
Other		0.1	%		7.7	%		2.9	%
Change in average state tax rate		0.3	%		(3.8	%)		—
Increase (decrease) in valuation allowance		—			—			(37.1	%)

Effective income tax rate		35.1	%		20.0	%		4.3	%

F-17

The components of the deferred tax assets and liabilities as of December 31 are as follows:


	2007			2006			2005
Current deferred tax asset (liability):
Unrealized gain (loss) on investment in PetroHunter (Note 4)	$	347,658		$	(2,172,785	)	$	—
Less asset valuation allowance		—			—			—

Current deferred tax asset (liability)	$	347,658		$	(2,172,785	)	$	—


Long-term deferred tax assets (liabilities):
Deferred tax assets:
Federal and state net operating loss carryovers	$	5,731,713		$	1,219,868		$	1,462,000
Oil and gas property amortization		454,771			753,000			443,000
Compensation using non-qualified stock options		341,452			118,369			29,000
Other		—			88,080			—

		6,527,936			2,179,317			1,934,000
Less: valuation allowance		—			—			—

Long-term deferred tax asset	$	6,527,936		$	2,179,317		$	1,934,000

Deferred tax liabilities:
Intangible drilling costs and other exploration costs capitalized for financial reporting purposes	$	(7,572,033	)	$	(4,376,646	)	$	(3,530,323	)
Other		(15,906	)		—			(297,258	)

Total long-term deferred tax liabilities		(7,587,939	)		(4,376,646	)		(3,827,581	)

Long-term deferred tax asset		6,527,936			2,179,317			1,934,000

Net long-term deferred tax asset (liability)	$	(1,060,003	)	$	(2,197,329	)	$	(1,893,581	)

The Company has approximately $15,500,000 in net operating loss carryovers as of December 31, 2007. The net operating losses may offset against taxable income through the year ended December 2028. A portion of the net operating loss carryover begins to expire in 2026.

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

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

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 — ADOPTION OF SFAS 123(R) SHARE-BASED PAYMENT

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

Under the modified prospective transition method, results for prior periods have not been restated, and compensation costs recognized in the year ended December 31, 2006 include (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123; and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R).

The adoption of SFAS 123(R) resulted in share-based compensation expense of $1,091,677 for 2007 and $1,522,219 for 2006. The $1,091,677 for 2007 consisted of $914,300 for stock options, $148,177 in accrued compensation for stock granted but held in escrow or not yet vested and $29,200 in common stock issued to a new employee. The $1,522,219 for 2006 consisted of $1,230,787 for stock options, $195,132 in common stock issued for consulting services and $96,300 in common stock issued to new employees.

Share-based compensation expense increased basic and diluted loss per share for 2007 by $0.02. Share-based compensation expense decreased basic and diluted income per share for 2006 by $0.04 per share, respectively.

F-18

For 2005 we applied the intrinsic value method of accounting for stock options as prescribed by APB 25. Since all options granted in 2005 had an exercise price equal to the closing market price of the underlying common stock on the grant date, no compensation expense was recognized for options granted to employees. If compensation expense had been recognized based on the estimated fair value of each option granted in accordance with the provisions of SFAS 123 as amended by Statement of Financial Accounting Standard 148, our net income and net income per share would have been reduced to the following pro-forma amounts for the year ended December 31, 2005:


	2005
Net income (loss) — as reported	$	553,629
Add stock based compensation included in reported net loss		413,764
Deduct stock based compensation expense determined under the fair value method		(841,566	)

Pro forma net loss	$	125,827


Net income (loss) per common share — Basic:
As reported	$	0.02

Pro forma	$	—


Net income (loss) per common share — Diluted:
As reported	$	0.02

Pro forma	$	—

For the fair value method, we used the following stock option pricing models and model assumptions:


	2007	2006	2005
	Modified	Black-	Black-
Pricing Model:	Binomial	Scholes	Scholes
Expected option life (in years)	4-5	5-8	5.0
Risk-free interest rate	4.7%-5.1%	4.5% to 5.2%	2.6% to 4.5%
Dividend yield	0%	N/A	N/A
Annual Volatility over option life	35%	33% to 63%	47% to 78%
Volatility in black-out periods	0%	33% to 63%	47% to 78%
Pre-vesting forfeiture rate	0%	0%	0%
Intrinsic value/share that urges exercise	$2.00 to $2.16	n/a for this model	n/a for this model

The Company has a policy of prohibiting its employees 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 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 2007 equated to approximately an $8.00 per share stock price.

NOTE 8 — STOCKHOLDERS’ EQUITY

PREFERRED STOCK

We are authorized to issue up to 25 million shares of $.001 par value preferred stock, the rights and preferences of which are to be determined by the Board of Directors at or prior to the time of issuance.

F-19

Series AA Convertible Preferred Stock

On July 22, 2005, we sold to accredited investors, a total of 250,000 Units for $13,500,000, with each Unit consisting of one share of Series AA Convertible Preferred Stock (“Preferred Stock”) and warrants to purchase shares of its $.001 par value common stock. This private placement was pursuant to exemptions from registration under the Securities Act of 1933, including but not limited to, Sections 3(b) and 4(2), as well as Rule 506 of Regulation D under the Securities Act of 1933. The Units were sold without a general solicitation pursuant to Blue Sky limited offering exemptions and were issued with a legend restricting resale. 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 registered common stock for a total of 2,250,000 shares, which is a conversion rate of $6.00 per share. We also issued warrants to purchase 2.7 shares of common stock for each share of Preferred Stock, which resulted in warrants to purchase a total of 675,000 shares of registered common stock exercisable at $6.00 per share. We extended the expiration date of the warrants to June 30, 2008. We can call the warrants if the daily weighted average trading price of its common stock averages at least $7.40 for 25 consecutive trading days.

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. In connection with the funding, we paid placement fees of $510,000 and issued 3-year warrants to purchase 281,250 shares of common stock at an exercise price of $6.00 per share. The warrants are valued at $575,544, using the Black-Scholes option pricing model.

Series A Convertible Preferred Stock

The Series A Convertible Preferred Stock issued in 2003 automatically converted into 670,000 shares of common stock in January 2005.

COMMON STOCK

Our Consolidated Statements of Shareholders’ Equity provides a listing of changes in the common shares outstanding from December 31, 2004 through December 31, 2007. Further explanation of these changes is provided below:

	•		On September 1, 2006, we issued 2,050,000 shares of our common stock to SunStone Oil and Gas, LLC in exchange for Sunstone’s 25% working interests in the Fetter project, increasing our Fetter ownership interests from 67.5% to 92.5%.

	•		During 2005 we issued 37,500 shares and during 2004 we issued 50,000 shares of our common stock to a Director for serving as Director, Designated Financial Expert and as Chairman of the Audit Committee. The shares were paid to a company wholly owned by the Director, and the shares were valued at $195,249 and $85,126, respectively, based on the non-discounted trading price of our common stock as of the date of issuance.

WARRANTS

In July 2005, in conjunction with the sale of Series AA Convertible Stock, we issued investor warrants to purchase a total of 675,000 shares of registered common stock exercisable at $6.00 per share. The warrants were to expire on January 21 2007 (18 months from the closing date). In 2007, we have extended the expiration date of these warrants to June 30, 2008 and recognized deemed dividends based on the fair value of the warrant extensions, using Black-Scholes. We also issued 3-year placement warrants to purchase 281,250 shares of common stock at an exercise price equal to the exercise price for the investor warrants of $6.00 per share.

In August 2006, we acquired a small working interest in the Fetter project in exchange for a warrant to acquire 100,000 shares of common stock for $4.90 per share, with the warrant expiring on February 9, 2007. The expiration date was extended to April 9, 2007 in exchange for a first right of refusal to acquire other interests in the general Fetter area held by the warrant holder. The warrant was not exercised and expired on April 9, 2007.

F-20

The table below reflects the status of warrants outstanding at December 31, 2007 held by others to acquire our common stock:


	Common		Exercise		Expiration
Issue Date	Shares		Price		Date
July 22, 2005		554,376	$	6.00	June 30, 2008
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

		910,476

At December 31, 2007, the per-share weighted average exercise price of outstanding warrants was $5.58 per share, and the weighted average remaining contractual life was 6.3 months.

The table below reflects the status of outstanding warrants at December 31, 2006:


	Common		Exercise		Expiration
Issue Date	Shares		Price		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
August 10, 2006		100,000	$	4.90	April 9, 2007

		1,127,980

At December 31, 2006, the per-share weighted average exercise price of outstanding warrants was $5.48 per share, and the weighted average remaining contractual life was 1.1 years.

STOCK OPTIONS

Under our 2004 Stock Option Plan (the “Plan”), stock options may be granted at an exercise price not less than the fair market value of our common stock at the date of grant. Options may be granted to key employees and other persons who contribute to our success. We have reserved 2,500,000 shares of common stock for issuance under the Plan. At December 31, 2007, 2006 and 2005, options to purchase 21,990 shares, 271,990 shares and 1,040,900 shares, respectively, were available to be granted pursuant to the 2004 Plan.

At the Company’s Annual Stockholders meeting in August 2006, the stockholders approved the Company’s 2006 Stock Incentive Plan. The 2006 Plan provides for up to 1,500,000 additional shares of common stock that may be issued to employees, directors and other persons who provide services to the Company. Issuance of those shares may be by stock option awards, restricted stock awards or restricted stock unit awards. At December 31, 2007 and 2006, options to purchase 996,400 and 1,500,000 shares, respectively, were available to be granted pursuant to the 2006 Plan.

Stock Options as of December 31, 2007

In January 2006, the Company entered into a participation agreement with North Finn (“North Finn”). An element of that agreement is that North Finn has an option until July 31, 2012 to receive 2,900,000 shares of 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 AICPA Emerging Issues Task Force Interpretation 96-18, whereby the value of North Finn’s option is not currently recognized in our financial statements. The option and the participation agreement are discussed in Note 13 Commitments and Contingencies.

F-21

Other than the aforementioned North Finn option, outstanding stock options are those granted under the Company’s 2004 Stock Option Plan or the 2006 Stock Incentive Plan. The following table summarizes the status of stock options outstanding under those Plans:


	Number of			Weighted Avg.
	Shares			Exercise Price
Options outstanding — December 31, 2004 (176,000 exercisable)		403,000		$	1.25
Options granted during 2005		1,056,010		$	3.58

Options outstanding — December 31, 2005 (640,009 exercisable)		1,459,010		$	2.94
Options granted during 2006		769,000		$	4.83
Less options exercised during 2006		(42,010	)	$	3.27

Options outstanding — December 31, 2006 (985,498 exercisable)		2,186,000		$	3.60
Options granted during 2007		699,000		$	5.89
Less options forfeited during 2007		(235,700	)	$	5.03
Less options exercised during 2007		(134,300	)	$	4.78

Options outstanding — December 31, 2007 (1,359,500 exercisable)		2,515,000		$	4.04

The weighted-average, grant-date estimated fair value of stock options granted during the years ended December 31, 2007, 2006 and 2005 were $1.65, $2.30 and $1.83, respectively, per underlying common share. We estimated the fair values using the Black-Scholes stock option pricing model or a Modified Binomial model, as further discussed in Note 7.

The following table presents additional information related to the stock options outstanding at December 31, 2007 under the 2004 Plan and 2006 Plan:


Exercise		Remaining
price		contractual		Number of shares
per share		life (years)		Outstanding		Exercisable
$	1.25		2.1		403,000		403,000
$	2.38		3.0		100,000		100,000
$	2.48		3.0		80,000		80,000
$	3.66		4.8		750,000		375,000
$	4.30		4.9		9,000		6,000
$	4.57		5.1		9,000		3,000
$	4.66		4.3		20,000		—
$	4.95		8.5		250,000		90,000
$	4.98		5.8		200,000		90,000
$	5.15		6.4		30,000		—
$	5.80		4.6		60,000		35,000
$	5.84		7.4		400,000		80,000
$	6.03		5.1		195,000		97,500
$	6.70		6.6		9,000		—

					2,515,000		1,359,500

Weighted Ave. remaining contractual life				5.2 years		4.3 years
Aggregate intrinsic value, December 31, 2007				$	4,420,670	$	3,286,984

The total estimated unrecognized compensation cost from unvested stock options as of December 31, 2007 was $1,813,429, which is expected to be recognized over a weighted average period of approximately 2.2 years.

SHARE-BASED COMPENSATION EXPENSE

Stock options accounted for the majority of share-based compensation expense in 2007 and 2006:


	2007		2006		2005
Share-based compensation expense:
For stock option grants	$	914,300	$	1,230,788	$	77,264
For stock granted but in escrow or unvested		148,177		71,846		141,250
For stock granted with immediate vesting		29,200		219,585		195,250

Total	$	1,091,677	$	1,522,219	$	413,764

Total share-based compensation for income tax returns	$	187,424	$	52,700	$	—

F-22

We had granted 129,600 shares of common stock that were either held in escrow or not vested as of December 31, 2007. They arose from the following stock grants in 2007 for services:

•

On February 12, 2007, we granted and issued 5,000 shares of common stock to our new Vice President of Land. The shares were valued at $29,200 reflecting the $5.84 per share closing price of the stock at the date of grant. We also granted him 20,000 additional shares that vest 4,000 shares per year on February 12, 2008 through 2012.

•

On June 15, 2007, we granted and issued in escrow 100,000 shares of common stock for our new Vice President of Exploration. The shares vest after five years of employment or upon a change of control of the Company.

•

On June 18, 2007, we granted and issued in escrow 9,600 shares of common stock for contractor services during the subsequent twelve months. The shares are to be removed from escrow upon the satisfactory completion of services on June 18, 2008.

Compensation expense for stock grants is recognized over the vesting period and computed as the number of shares granted times the stock closing price at date of grant.

NOTE 9 — EARNINGS PER SHARE

The following table summarizes the calculations of basic and diluted net income (loss) per common share for the years ended December 31, 2007, 2006 and 2005:


	2007			2006		2005
Net income to common stockholders	$	(3,795,912	)	$	131,223	$	553,629
Adjustments for dilution		—			—		—

Net income adjusted for effects of dilution	$	(3,795,912	)	$	131,223	$	553,629


Basic Weighted Ave. Common Shares		44,383,861			37,428,506		34,148,065
Add dilutive effects of options and warrants		—			713,505		807,559
Add dilutive effects of convertible preferred stock		—			—		—

Diluted Weighted Ave. Common Shares Outstanding		44,383,861			38,142,011		34,955,624


Net income per common share — basic	$	(0.09	)	$	0.00	$	0.02
Net income per common share — diluted	$	(0.09	)	$	0.00	$	0.02

NOTE 10 — EMPLOYEE BENEFIT PLANS

We maintain and sponsor health care plans and a contributory 401(k) plan for our employees. Our direct costs related to these plans were $264,918, $205,712 and $83,002 for the years ended December 31, 2007, 2006 and 2005, respectively.

NOTE 11 — RELATED PARTY TRANSACTIONS

Approximately one month prior to our merging with Tower Colombia Corporation on April 21, 2005, we approved and entered into an agreement with TCC pursuant to which TCC provided, effective as of January 17, 2005, certain management services, including, but not limited to, human resource management, asset management services, and accounting and data management services for a monthly management fee of $30,000. We paid TCC a total of $90,000 pursuant to this agreement from the period January 16, 2005 through the April 21, 2005. This management services agreement terminated on the closing date of the merger. In addition to the management fee paid to TCC, during 2005, we also reimbursed TCC for its share of costs relating to oil and gas operations of $2,888 and for payroll related costs of $66,643.

In 2006 and 2005, we paid $58,907 and $75,416 to Tower Energy Corporation (“TEC”) for our share of administrative related expenditures, primarily the sharing of office space which TEC had leased. Payments to TEC ended in July 2006 in conjunction with American replacing TEC as the Tenant on the office lease. Patrick O’Brien and American vice president Bob Solomon each own 50% of TEC.

NOTE 12 — SUPPLEMENTAL INFORMATION TO THE STATEMENTS OF CASH FLOWS


	2007		2006		2005
Supplemental Schedule of Cash Flow Information
Cash paid for interest expense	$	6,162	$	—	$	—
Cash paid for income taxes incurred	$	—	$	—	$	—

Supplemental Disclosures of Non-Cash Activities
Conversion of preferred stock into common stock	$	6,048,000	$	770,500	$	—
Share-based compensation expense	$	1,091,677	$	1,522,219	$	413,764
Preferred stock dividends paid in common stock	$	820,224	$	1,080,000	$	—
Common stock issued to acquire oil and gas properties	$	—	$	13,079,000	$	4,211,911

F-23


	2007		2006		2005
Service fee received in the form of a convertible note	$	—	$	1,530,000	$	—
Oil and gas properties sold in exchange for a convertible note	$	—	$	1,080,000	$	—
Notes converted into PetroHunter common stock	$	—	$	2,610,000	$	—
Oil and gas interests exchanged for PetroHunter common stock	$	270,000	$	—	$	—
Common stock issued to acquire Tower Colombia Corp.	$	—	$	—	$	15,196,000
Warrants issued for financing costs	$	—	$	—	$	575,544
Warrants issued for oil and gas property consulting	$	—	$	—	$	31,564
Warrant issued to acquire oil and gas properties	$	—	$	88,000	$	—

NOTE 13 — COMMITMENTS AND CONTINGENCIES

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

North Finn Option

On January 5, 2006, we entered into a participation agreement with North Finn, LLC (“North Finn”). Under the agreement, we 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 has incurred in jointly owned project areas after the effective date of August 1, 2005.

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

Office Lease

The Company had a sublease agreement, and shared common office space, with Tower Energy Corporation, a related entity, for rent of its general corporate office facilities. In March 2006, the Company signed an amendment to the lease agreement whereby the Company leased and occupied new office space starting in May 2006. Upon occupying the new office space, the Company became the Tenant under the lease. The Company is obligated to pay the following minimum future rental commitments under the noncancelable operating lease of office space:


	Office Lease
Year	Obligations
2008	$	152,564
2009		155,986
2010		159,408
2011		162,820
2012		166,252
Thereafter		69,866

Delay Rentals

In conjunction with the Company’s working interests in undeveloped oil and gas prospects, the Company must pay approximately $247,000 in delay rentals during the fiscal year ending December 31, 2008 to maintain the right to explore these prospects. The Company continually evaluates its leasehold interests, therefore certain leases may be abandoned by the Company in the normal course of business.

F-24

NOTE 14 — SUBSEQUENT EVENTS

At December 31, 2007, we had $17,325,000 in short-term investments in AAA credit-rated, Auction Market Preferred Stocks (AMPS) issued by various U.S. mutual funds. These auction rate securities normally provide liquidity via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. Dividends on these securities are paid on the day after the scheduled auction date. Recently, these auctions and similar auctions have had insufficient bids to buy the securities from those wishing to sell. On March 14, 2008, we owned auction-rate securities with a par value of $17,250,000 that we could not immediately liquidate at par value. To increase our cash balances to approximately $9,600,000, we borrowed $8,600,000 on March 14, 2008 from an affiliate of our broker. The loan is secured by our AMPS investments and matures on September 30, 2008. It bears interest currently approximating a 5.5% annual rate. The rate will change with changes in the overnight LIBOR. We plan to pay the interest from the AMPS weekly and monthly dividends, which on average currently approximate a 4.5% annual rate and are typically set at 125% to 150% of LIBOR or AA Commercial Paper for the payment month.

If we are able to redeem or sell at par value our $11,250,000 in Calamos AMPS in the near future, we believe we could still borrow $3,000,000 on the remaining $6,000,000 of AMPS. In addition to taking our AMPS for sale at their 7-day and 28-day auctions, we are exploring other liquidity options. If, and to the extent, we are unable to substantially liquidate the AMPS in 2008, we may need to raise cash by other means to fully fund our future capital expenditures.

NOTE 15 — INFORMATION REGARDING PROVED OIL AND GAS RESERVES (UNAUDITED)

The information presented below regarding the Company’s oil and gas reserves were prepared by independent petroleum engineering consultants. All reserves are located within the continental United States.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. The determination of oil and gas reserves is highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.

The complete definition of proved oil and gas reserves appears at Regulation S-X 4-10 (a) (2) (3) and (4). The complete definition of proved developed oil and gas reserves appears at Regulation S-X 4-10 (a) (4), 17 CFR 210. 4-10(a)(4).

Estimated net quantities of proved developed and undeveloped reserves of oil and gas for the year ended December 31, 2007, 2006 and 2005 are presented in tables below.


December 31, 2007	Oil (BBLS)			NGL (BBLS)			Gas (MCF)
Beginning of year		91,850			—			809,847
Revisions of previous quantity estimates		(32,906	)		23,937			28,388
Extensions, discoveries and improved recoveries		54,722			30,307			608,514
Sales of reserves in place		—			—			—
Production		(17,267	)		(311	)		(139,590	)

End of year		96,399			53,933			1,307,159


Proved developed reserves at end of year		91,106			53,933			1,277,755

The 2007 net downward revision in oil reserves is attributable to our interest in the Champion 1-25H well in North Dakota. The well was drilled in late 2006, with excellent shows of oil and significant oil production in February 2007, supportive of proved reserves using the volumetric method and analogy. Subsequent production rates in the fourth quarter of 2007 were substantially less than in February. Reserves were substantially reduced pending further analysis and work on the well.

Proved reserves of natural gas liquids (“NGL”) were insignificant for 2006 and 2005 and were not separately estimated for proved reserves as of December 31, 2006 and 2005. At December 31, 2007, proved reserves of natural gas liquids accounted for 18% of total proved reserves’ future revenues of $19.8 million for the December 31, 2007 Standardized Measure disclosed later in this Note.

F-25


December 31, 2006	Oil (BBLS)			Gas (MCF)
Beginning of year		554,702			378,213
Revisions of Previous quantity estimates		(35,347	)		136,378
Extensions, discoveries and improved recoveries		76,347			505,832
Sales of reserves in place		(469,274	)		(162,387	)
Production		(34,578	)		(48,189	)

End of year		91,850			809,847


Proved developed reserves at end of year		86,361			713,236

Revisions in 2006 related primarily to two wells. The Rogers 1-11H well location drilled in early 2006 was assigned proved undeveloped reserves at 12-31-05 that were revised when actual production demonstrated greater gas reserves and less oil reserves. The Bear Creek Unit #1 well’s production in 2006 justified an increase in its proved gas reserves. Sales of reserves in place in 2006 related to the proved reserves of our Big Sky property interests sold in March 2006. Extensions, discoveries and improved recoveries relate to new wells at our Fetter, Goliath and Krejci projects.


December 31, 2005	Oil (BBLS)			Gas (MCF)
Beginning of year		321,710			346,270
Revisions of Previous quantity estimates		4,208			18,958
Extensions, discoveries and improved recoveries		307,773			116,067
Sales of reserves in place		—			(43,585	)
Production		(78,989	)		(59,497	)

End of year		554,702			378,213


Proved developed reserves at end of year		320,698			307,000

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES

Future net cash flows presented below are computed using year-end prices and costs. Future corporate overhead expenses and interest expense have not been included.


	2007			2006			2005
Future cash inflows	$	19,840,019		$	10,421,519		$	35,159,955
Future costs:
Production		(5,792,739	)		(3,276,852	)		(5,768,802	)
Development		(319,922	)		(716,000	)		(2,825,307	)
Future income tax expense		(101,000	)		(230,912	)		(706,000	)

Future net cash flows		13,626,358			6,197,755			25,859,846
10% discount factor		(5,321,559	)		(1,599,755	)		(12,149,916	)

Standardized measure of discounted future net cash flows relating to proved reserves	$	8,304,799		$	4,598,000		$	13,709,930

F-26

The principal sources of changes in the standardized measure of discounted future net cash flows during the years ended December 31, 2007, 2006 and 2005 are as follows:


	2007			2006			2005
Beginning balance	$	4,598,000		$	13,709,930		$	5,432,119
Sales and transfers of oil and gas produced		(1,310,508	)		(1,966,036	)		(4,466,663	)
Net changes in prices and production costs		1,228,973			(1,637,000	)		3,640,869
Sales of minerals in place		—			(10,800,000	)		(135,472	)
Extensions and discoveries		4,549,423			3,814,000			6,611,421
Development costs incurred during the year		716,000			519,000			1,649,396
Changes in estimated future development costs		0			0			(16,255	)
Revisions in previous quantity estimates		(1,917,123	)		821,000			178,586
Accretion of discount		409,034			161,000			565,612
Change in income taxes		31,000			(6,200	)		135,000
Change in rates of production and other		0			(17,694	)		115,317

Ending balance	$	8,304,799		$	4,598,000		$	13,709,930

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of SFAS 69. Future cash inflows were computed by applying current prices at year-end to estimated future production. Future production and development costs (including the estimated asset retirement obligation) are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved oil and gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the present value of the Company’s oil and gas properties.

Standardized Measure Changes in 2007. The aforementioned 2007 downward revision in the proved reserves of the Champion 1-25H well reduced the December 31, 2007 standardized measure by approximately $2.0 million. The $4.5 million standardized measure increase in 2007 includes $3.6 million for our 18.3% and 18.8% carried net revenue interests in the two wells drilled by RTA at Fetter in the second half of 2007, i.e., the Hageman 16-34H-R and the Wallis 6-23, respectively.

Standardized Measure Changes in 2006. As disclosed in Note 3, the Company sold all of its interests in the Big Sky project on March 31, 2006. The sold interests accounted for approximately 88% of the standardized measure at December 31, 2005. Accretion for 2006 shown above does not relate to those proved reserves at December 31, 2005 attributable to the Big Sky interests.

NOTE 16 — SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)


2007	First			Second			Third			Fourth
Revenues	$	395,500		$	416,090		$	780,963		$	375,955
Loss from operations	$	(1,130,305	)	$	(1,146,316	)	$	(856,508	)	$	(1,143,169	)
Net loss	$	(709,949	)	$	(546,043	)	$	(268,360	)	$	(1,219,030	)
Loss per common share:
Basic	$	(0.02	)	$	(0.02	)	$	(0.01	)	$	(0.04	)
Diluted	$	(0.02	)	$	(0.02	)	$	(0.01	)	$	(0.04	)


2006	First			Second		Third			Fourth
Revenues	$	1,570,852		$	1,789,033	$	216,347		$	210,607
Income (loss) from operations	$	(168,752	)	$	820,582	$	(1,858,216	)	$	(4,831,043	)
Net income (loss)	$	2,469,655		$	2,231,715	$	(1,261,675	)	$	(2,228,472	)
Earnings per common share:
Basic	$	0.06		$	0.05	$	(0.04	)	$	(0.06	)
Diluted	$	0.06		$	0.05	$	(0.04	)	$	(0.06	)

The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each quarterly period’s computation is based on the weighted average number of shares outstanding during that quarterly period.

F-27

Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A: Controls and Procedures

Disclosure Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Evaluations have been performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a—15(e) and 15d—15(e) of the Exchange Act). Based upon those evaluations, management, including the Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2007 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realties that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives and the Chief Executive Officer and the Chief Financial Officer, as of December 31, 2007, have concluded that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

Management’s Annual Report on Internal Control over Financial Reporting

In regards to internal control over financial reporting, our management is responsible for the following:

	•		establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934), and

	•		assessing the effectiveness of internal control over financial reporting.

The Company’s internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and affected by our Board of Directors, management and other personnel. It was designed to provide reasonable assurance to our management, Board of Directors and external users regarding the fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that:

	•		pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets,

	•		provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors, and

	•		provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.

Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based upon the assessment, management believes that, as of December 31, 2007, our internal control over financial reporting is effective based on those criteria.

HEIN & ASSOCIATES, LLP, the independent registered public accounting firm that audited our financial statements included in this Annual Report on Form 10-K, has also audited our management’s assessment of the effectiveness of the Company’s internal control over financial reporting and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 as stated in their report included herein.

Changes in Internal Control over Financial Reporting

During 2007, our management regularly evaluated the Company’s internal controls over financial reporting and discussed these matters with our independent accountants and our audit committee. Based on these evaluations and discussions, our management considered what revisions, improvements, or corrections were necessary in order to ensure that our internal controls were effective as our operations and financial reporting requirements changed over time. As a result, we have made significant progress implementing enhancements and corrective actions to our internal controls related to enhancing certain general computer controls over the past year.

We anticipate that implementation of these enhancements will continue through 2008. The principal focus of these enhancements is related to general computer controls which include documenting and adhering to comprehensive system development methodologies when performing system application implementations and upgrades.

There have been no other significant changes in internal controls, or other factors that could significantly affect internal controls, that occurred during the fourth quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
American Oil & Gas, Inc.

We have audited American Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). American Oil & Gas, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting (Item 9A). Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, American Oil & Gas, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of American Oil & Gas, Inc. as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income for each of the three years in the period ended December 31, 2007 and our report on those statements dated March 14, 2008 expressed an unqualified opinion.

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado
March 14, 2008

Item 9B: Other Information

Not applicable.

PART III

Item 10: Directors, Executive Officers and Corporate Governance

See “Executive Officers, Board of Directors, Committees of the Board,” and Section 16(a) “Beneficial Ownership Reporting Compliance” in the American Oil & Gas, Inc. Proxy Statement (“Proxy Statement”), for the Annual Meeting of Stockholders of the Company (to be filed with the SEC within 120 days after the end of the Company’s fiscal year ended December 31, 2007) which is incorporated herein by reference.

Our Code of Ethics can be found on our internet website located at www.americanog.com. If we amend the Code of Ethics or grant a waiver, including an implicit waiver, from the Code of Ethics, we intend to disclose the information on our internet website. This information will remain on the website for at least 12 months.

Item 11: Executive Compensation

Information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation,” and is hereby incorporated by reference thereto.

Item 12: Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this item will be contained in the Proxy Statement under the caption “Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and is incorporated herein by reference.

Item 13: Certain Relationships and Related Transactions, and Director Independence

Information required by this item will be contained in the Proxy Statement under the caption “Certain Transactions” and “Corporate Governance” and is hereby incorporated by reference thereto.

Item 14: Principal Accountant Fees and Services

Information required by this item will be contained in the Proxy Statement under the caption “Auditors’ Fees,” and is hereby incorporated by reference thereto.

PART IV

Item 15: Exhibits, Financial Statement Schedules

(a)(1) Financial Statements (included in Item 8 to this Form 10-K)


	Form 10-K Page
Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2007 and 2006		F-3

Consolidated Statements of Operations for years ended December 31, 2007, 2006 and 2005		F-4

Consolidated Statements of Cash Flows for years ended December 31, 2007, 2006 and 2005		F-5

Consolidated Statements of Stockholders’ Equity and Comprehensive Income for years ended December 31, 2007, 2006 and 2005		F-6

Notes to Consolidated Financial Statements	F-7 to F-27

(a)(2) All other schedules have been omitted because the required information is inapplicable or is shown in the Notes to the Financial Statements.

(a)(3) Exhibits required to be filed by Item 601 of Regulation S-K.


Exhibit No.		Description

2(1)		Agreement and Plan of Merger with Tower Colombia Corporation dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

3(i)		Articles of Incorporation of the Company, as amended.

3(ii)		Certificate of Designation of Series A Preferred Stock. (Incorporated by reference from the Company’s Amendment No. 2 to Form SB-2, filed on January 31, 2005.)

3(iii)		Bylaws of the Company (as revised on December 20, 2007). (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on December 21, 2007.)

3(iv)		Certificate of Designation of Series AA 8% Preferred Stock. (Incorporated by reference from the Company’s Amendment No. 1 to Form S-3, filed on March 6, 2006.)

10(i)*		2004 Stock Option Plan. (Incorporated by reference from the Company’s Definitive Proxy Statement, filed on June 16, 2004)

10(ii)		Form of Warrant Certificate issued as part of the private placement completed on July 22, 2005. (Incorporated by reference from the Company’s Registration Statement on Form S-3, filed on October 4, 2005.)

10(iii)		Form of Placement Agent Warrant Certificate issued in connection with the private placement completed on July 22, 2005. (Incorporated by reference from the Company’s Registration Statement on Form S-3, filed on October 4, 2005.)

10(iv)		January 17, 2003 Purchase and Sale Agreement by and between the Company, Tower Colombia Corporation and North Finn, LLC. (Incorporated by reference from the Company’s Form 8-K, filed on February 3, 2003.)

10(v)		January 17, 2003 Participation Agreement by and between the Company, Tower, North Finn, and the principals of Tower and North Finn. (Incorporated by reference from the Company’s Form 10-KSB for the calendar ending December 31, 2002, filed on March 31, 2003.)

10(vi)		Model Form Operating Agreement dated February 18, 2003. (Incorporated by reference from the Company’s Form 10-KSB/A, filed on November 18, 2003.)

10(vii)*		Employment Agreement between the Company and Andrew P. Calerich dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

10(viii)*		Employment Agreement between the Company and Patrick D. O’Brien dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)


Exhibit No.		Description

10(ix)*		Employment Agreement between the Company and Bobby G. Solomon dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

10(x)*		Employment Agreement between the Company and Kendell V. Tholstrom dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

10(xi)		Participation Agreement between the Company and North Finn LLC dated January 5, 2006. (Incorporated by reference from the Company’s Form 10-KSB for the fiscal year ended December 31, 2005.)

10(xii)*		Employment Agreement between the Company and Joseph B. Feiten. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on August 31, 2006.)

10(xiii)*		Stock Option Agreement between the Company and Joseph B. Feiten. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on August 31, 2006.)

10(xiv)		Purchase and Sale Agreement, dated September 1, 2006, between SunStone Oil & Gas, LLC and the Company. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on September 6, 2006.)

10(xv)		Registration Rights Agreement, dated September 1, 2006, by and among the Company and the investors listed therein. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on September 6, 2006.)

10(xvi)		Purchase and Sale Agreement dated March 31, 2006 by and between the Company and Enerplus Resources (USA) Corporation. (Incorporated by reference from the Company’s Quarterly Report on Form 10-QSB for the period ended September 30, 2006.)

10(xvii)		Participation Agreement dated January 17, 2007 among the Company, Red Technology Alliance LLC and North Finn LLC. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on January 23, 2007.)

10(xviii)*		2006 Stock Incentive Plan (Incorporated by reference to the Company’s Definitive Proxy Statement, as amended, filed on July 26, 2006)

10(xix)		Form of Stock Option Agreement for awards under 2006 Stock Incentive Plan (Incorporated by reference to the Company’s Current Report on Form 8-K filed on April 5, 2007).

10(xx)		Placement Agency Agreement dated April 11, 2007 by and between the Company and A.G. Edwards & Sons, Inc. and C.K. Cooper & Company (Incorporated by reference to the Company’s Current Report on Form 8-K filed on April 12, 2007).

10(xxi)		Form of Subscription Agreement (Incorporated by reference to the Company’s Current Report on Form 8-K filed on April 12, 2007).


Exhibit No.		Description

10(xxii)*		Employment Agreement dated June 15, 2007 by and between the Company and Peter Loeffler (Incorporated by reference to the Company’s Current Report on Form 8-K filed on June 19, 2007).

10(xxiii)		Participation Agreement dated June 25, 2007 by and among Red Technology Alliance, LLC, the Company and North Finn, LLC (Incorporated by reference to the Company’s Current Report on Form 8-K filed on July 3, 2007).

10(xxiv)		Promissory Note and Security Agreement dated March 14, 2008 by and between the Company and Jefferies Group, Inc.

21(i)		Subsidiary List.

23(i)		Consent of Independent Petroleum Engineers and Geologists

23(ii)		Consent of Independent Registered Public Accounting Firm

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*		Management contracts or compensatory plans or arrangements

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, this 14th day of March, 2008.


	American Oil & Gas, Inc.
	/s/ Andrew P. Calerich
	Andrew P. Calerich
	President

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Patrick D. O’Brien	Chief Executive Officer and Chairman	March 14, 2008
Patrick D. O’Brien	(Principal Executive Officer)

/s/ Andrew P. Calerich	President and Director	March 14, 2008
Andrew P. Calerich

/s/ Joseph B. Feiten	Chief Financial Officer	March 14, 2008
Joseph B. Feiten	(Principal Financial Officer)

/s/ M.S. (“Moni”) Minhas	Director	March 14, 2008
M.S. (“Moni”) Minhas

/s/ Nick DeMare	Director	March 14, 2008
Nick DeMare

/s/ Jon R. Whitney	Director	March 14, 2008
Jon R. Whitney

Exhibit Index


Exhibit No.		Description

2(1)		Agreement and Plan of Merger with Tower Colombia Corporation dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

3(i)		Articles of Incorporation of the Company, as amended.

3(ii)		Certificate of Designation of Series A Preferred Stock. (Incorporated by reference from the Company’s Amendment No. 2 to Form SB-2, filed on January 31, 2005.)

3(iii)		Bylaws of the Company (as revised on December 20, 2007). (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on December 21, 2007.)

3(iv)		Certificate of Designation of Series AA 8% Preferred Stock. (Incorporated by reference from the Company’s Amendment No. 1 to Form S-3, filed on March 6, 2006.)

10(i)*		2004 Stock Option Plan. (Incorporated by reference from the Company’s Definitive Proxy Statement, filed on June 16, 2004)

10(ii)		Form of Warrant Certificate issued as part of the private placement completed on July 22, 2005. (Incorporated by reference from the Company’s Registration Statement on Form S-3, filed on October 4, 2005.)

10(iii)		Form of Placement Agent Warrant Certificate issued in connection with the private placement completed on July 22, 2005. (Incorporated by reference from the Company’s Registration Statement on Form S-3, filed on October 4, 2005.)

10(iv)		January 17, 2003 Purchase and Sale Agreement by and between the Company, Tower Colombia Corporation and North Finn, LLC. (Incorporated by reference from the Company’s Form 8-K, filed on February 3, 2003.)

10(v)		January 17, 2003 Participation Agreement by and between the Company, Tower, North Finn, and the principals of Tower and North Finn. (Incorporated by reference from the Company’s Form 10-KSB for the calendar ending December 31, 2002, filed on March 31, 2003.)

10(vi)		Model Form Operating Agreement dated February 18, 2003. (Incorporated by reference from the Company’s Form 10-KSB/A, filed on November 18, 2003.)

10(vii)*		Employment Agreement between the Company and Andrew P. Calerich dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

10(viii)*		Employment Agreement between the Company and Patrick D. O’Brien dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

10(ix)*		Employment Agreement between the Company and Bobby G. Solomon dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)


Exhibit No.		Description

10(x)*		Employment Agreement between the Company and Kendell V. Tholstrom dated effective April 21, 2005. (Incorporated by reference from the Company’s Post-Effective Amendment No. 1 to Form SB-2, filed on April 27, 2005.)

10(xi)		Participation Agreement between the Company and North Finn LLC dated January 5, 2006. (Incorporated by reference from the Company’s Form 10-KSB for the fiscal year ended December 31, 2005.)

10(xii)*		Employment Agreement between the Company and Joseph B. Feiten. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on August 31, 2006.)

10(xiii)*		Stock Option Agreement between the Company and Joseph B. Feiten. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on August 31, 2006.)

10(xiv)		Purchase and Sale Agreement, dated September 1, 2006, between SunStone Oil & Gas, LLC and the Company. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on September 6, 2006.)

10(xv)		Registration Rights Agreement, dated September 1, 2006, by and among the Company and the investors listed therein. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on September 6, 2006.)

10(xvi)		Purchase and Sale Agreement dated March 31, 2006 by and between the Company and Enerplus Resources (USA) Corporation. (Incorporated by reference from the Company’s Quarterly Report on Form 10-QSB for the period ended September 30, 2006.)

10(xvii)		Participation Agreement dated January 17, 2007 among the Company, Red Technology Alliance LLC and North Finn LLC. (Incorporated by reference from the Company’s Current Report on Form 8-K filed on January 23, 2007.)

10(xviii)*		2006 Stock Incentive Plan (Incorporated by reference to the Company’s Definitive Proxy Statement, as amended, filed on July 26, 2006)

10(xix)		Form of Stock Option Agreement for awards under 2006 Stock Incentive Plan (Incorporated by reference to the Company’s Current Report on Form 8-K filed on April 5, 2007).

10(xx)		Placement Agency Agreement dated April 11, 2007 by and between the Company and A.G. Edwards & Sons, Inc. and C.K. Cooper & Company (Incorporated by reference to the Company’s Current Report on Form 8-K filed on April 12, 2007).

10(xxi)		Form of Subscription Agreement (Incorporated by reference to the Company’s Current Report on Form 8-K filed on April 12, 2007).

10(xxii)*		Employment Agreement dated June 15, 2007 by and between the Company and Peter Loeffler (Incorporated by reference to the Company’s Current Report on Form 8-K filed on June 19, 2007).

10(xxiii)		Participation Agreement dated June 25, 2007 by and among Red Technology Alliance, LLC, the Company and North Finn, LLC (Incorporated by reference to the Company’s Current Report on Form 8-K filed on July 3, 2007).

10(xxiv)		Promissory Note and Security Agreement dated March 14, 2008 by and between the Company and Jefferies Group, Inc.

21(i)		Subsidiary List.


		Page

PART I

Item 1:	Business		3

Item 1A:	Risk Factors		9

Item 1B:	Unresolved Staff Comments		12

Item 2:	Properties		12

Item 3:	Legal Proceedings		18

Item 4:	Submission of Matters to a Vote of Security Holders		18

PART II

Item 5:	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		18

Item 6:	Selected Consolidated Financial Data		20

Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 7A:	Quantitative and Qualitative Disclosures about Market Risk		30

Item 8:	Financial Statements and Supplementary Data		F-1

Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		32

Item 9A:	Controls and Procedures		32

Item 9B:	Other Information		35

PART III

Item 10:	Directors, Executive Officers and Corporate Governance		35

Item 11:	Executive Compensation		35

Item 12:	Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		35

Item 13:	Certain Relationships and Related Transactions, and Director Independence		35

Item 14:	Principal Accountant Fees and Services		35

PART IV

Item 15:	Exhibits, Financial Statement Schedules		35

Exhibit 3 (i)
Exhibit 10.24
Subsidiary List
Consent of Independent Petroleum Engineers and Geologists
Consent of Independent Registered Public Accounting Firm
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


NAME		POST OFFICE ADDRESS

Resident Agents of Nevada, Inc.		711 S. Carson St., Suite 4 Carson City, Nevada 89701


NAME		POST OFFICE ADDRESS

Dr. Anchana Chayawatana		295/42 Ngarmwongwan 23 Road Nonthaburi 11000 Thailand

Lt. Dr. Somdul Manpiankarn		237/466 Soi Saitong, Tiwanon Rd. Nonthaburi 11000 Thailand

Dr. Bancha Luengaram		240/28 Charansanitwong Rd. Bangkoknoi, Bangkok 10700 Thailand



		/s/ Patricia A. Bozin
		Patricia A. Bozin, Sole Incorporator for
		Resident Agents of Nevada, Inc.



		/s/ Patricia A. Bozin
		Patricia A. Bozin for Resident Agents of Nevada, Inc.



	By	/s/ Sandra L. Miller
		Sandra L. Miller
		Resident Agents of Nevada, Inc. Resident Agents


Subsidiary		State of Incorporation

Tower American Corporation		Colorado


/s/ Patrick D. O’Brien

Patrick D. O’Brien Chief Executive Officer


/s/ Joseph B. Feiten

Joseph B. Feiten Chief Financial Officer