10-K

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, 2008


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		88-0451554
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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		NYSE Alternext U.S. (formerly 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

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, 2008 was $147,860,526.

The number of shares of registrant’s common stock outstanding as of March 10, 2009 was 48,307,399 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, 2008, 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:

•

significant unforeseen events that have global or national impact such as (1) major political disruptions, (2) extended economic depression, and (3) technological breakthroughs in producing oil and natural gas or in producing alternative forms of energy,

•

unanticipated future changes in oil or natural gas prices and

•

other uncertainties inherent in the exploration and production of oil and natural gas.

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 acquiring oil and gas mineral leases and the exploration and development of crude oil and natural gas reserves and production in the US Rocky Mountain region. At December 31, 2008, we controlled the following:

•

Approximately 53,000 gross (34,000 net) acres in the Fetter Project area, located in the southern Powder River Basin, Wyoming,

•

Approximately 128,000 gross (52,000 net) acres in the Krejci Project, located in Niobrara County, Wyoming,

•

Approximately 87,000 gross (33,000 net) acres in the Goliath Project, located in the Williston Basin, North Dakota, and

•

Approximately 175,000 gross (112,000 net) acres in the Bigfoot Project, located in the U.S. Rocky Mountain area.

We have a management team experienced in building large acreage positions in the Rocky Mountain region. In many instances, these areas have been overlooked by other companies and have resulted in the ability to acquire substantial project size at relatively low cost. In September and October of 2008, we sold two non-core acreage positions for $31.7 million in cash, which exceeded by $23 million our direct costs for the properties sold. Recognized gain in 2008 was limited to $16.5 million under full cost accounting rules. 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.

Although commodity prices have significantly decreased in the prior months, we believe we can establish commercial production in our focus areas at current commodity price levels. We anticipate accomplishing this by significantly reducing the cost to drill and complete wells, controlling costs to operate producing wells and by enhancing production. We are already experiencing decreases in service costs, and we expect that service costs will continue to decrease for 2009.

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.

We begin 2009 with:

•

Over $25.6 million in working capital ($0.53/share), including $23.3 million in cash and $5.4 million in short term investments,

•

No long term debt,

•

Approximately 259,000 net undeveloped acres of oil and gas leases of which only approximately 8,000 acres would expire in 2009, even if we drill no wells in 2009,

•

Improved opportunity for drilling commercially successful wells within the Fetter and Goliath projects, even at current commodity prices when taking into consideration current and expected further decreases in service costs, and

•

Plans to drill several shallow gas wells at our new Bigfoot project that could be commercially successful under existing gas price conditions.

•

Little employee turnover in 2008 and no turnover of officers or key managers,

In light of the low oil and gas prices currently and the uncertainties of price recovery and financial market recovery, we expect in 2009, to maintain a substantial portion of our cash in U.S. Treasuries and similar low risk, liquid investments, and we are planning to spend approximately $15 million in 2009 for base case capital projects and operating expenses.

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, 2008, 2007, and 2006 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 2008, 2007 and 2006. In particular, projected future cash flows reflect oil and gas prices on those December 31^st dates.


	At December 31,
	2008		2007		2006
Proved oil reserves (bbls)		75,610		96,399		91,850
Proved NGL reserves (bbls)		11,139		53,933		*
Proved natural gas reserves (mcf)		1,147,074		1,307,159		809,847
Future net cash flows (before income taxes)	$	4,675,700	$	13,727,358	$	6,428,667
PV-10 Value	$	2,950,787	$	8,362,799	$	4,692,808


*		At December 31, 2006, 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 at 10% per annum. 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,
	2008		2007		2006
Standardized measure of discounted future net cash flows	$	2,944,869	$	8,304,799	$	4,598,000
Add present value of future income tax discounted at 10%		5,918		58,000		94,808

PV-10 Value	$	2,950,787	$	8,362,799	$	4,692,808

Customers

During 2008, we had three major customers: DCP Midstream LLC, Wyoming Refining Company and Shell Trading (US) Company, accounting for 63% of oil and gas sales. During 2007, we had four major customers: DCP Midstream LLC, Wyoming Refining Company, Shell Trading (US) Company and Nexen Marketing U.S.A., Inc., accounting for approximately 81% of oil and gas sales in 2007. 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 but in some circumstances a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

During 2006, we had one major customer: Eighty Eight Oil, LLC. Sales to this customer accounted for approximately 71% of oil and gas sales in 2006 and related to properties we sold in 2006.

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 operators 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, 2008, we had seventeen 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 barrel 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 barrel of oil.

MMcf. One million cubic feet of natural gas.

MMcfe. One million cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of six Mcf to one barrel of oil.

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.

NGL. Natural gas liquids.

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 re-completion.

Re-entry. Entering an existing well bore to re-drill 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, others 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, an extensive 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. To better appreciate this discussion of risks, we encourage you to first read the descriptions of our business and assets in Item 2 “Properties” of this Part I and read Part 2 of this Form 10-K.

Risks related to our industry, business and strategy

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

Although we had net income in 2006, we incurred a net loss in 2007 and in 2008. Our future financial results depend primarily on our ability to discover commercial quantities of oil and gas and 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.

Oil and natural gas prices are volatile and have substantially declined in recent months. The recent decline has adversely affected our financial results. Further price declines or even continuation of current low oil and natural gas prices could significantly affect our future 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. Our operations are focused on oil and gas exploration and production in the Rocky Mountain region of the United States. Regional oil and gas prices may vary from national prices due to regional factors such as regional gas production being constrained by regional gas pipeline capacity.

The current global and US economic and financial crises may have impacts on our business and financial condition that we currently cannot predict

The current global and US economic recessions, credit crisis and related turmoil in national and global financial systems have substantially contributed to the dramatic decrease in oil and gas prices in the second half of 2008 and in the first three months of 2009. The price declines have adversely affected US oil and gas producers including us. The economic downturn and decline in oil and gas prices are providing declines in drilling costs and increased availability of field equipment, but those cost reductions may only partially mitigate the adverse effects of lower oil and gas prices.

Uncertainties as to the extent, duration and impacts of the global and US crises increase uncertainties and risks for us. With the general economic and financial crises, (i) our ability to access capital markets is more restricted now than a year ago and may be restricted in the future when we may like, or need, to raise financing, (ii) our suppliers, customers and business partners may be unable to meet their obligations to us, (iii) we may be unable to profitably sell, extend or explore oil and gas lease rights we currently own and (iii) we may face unanticipated challenges to our business and financial condition. Unexpected bankruptcies of financial institutions or unexpected illiquidity of funds in cash-equivalent investments, such as money market funds, may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis.

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 certain oil and gas properties and, to a lesser extent, from cash generated by operations. We intend to finance our known capital expenditures for 2009 primarily with existing capital. We currently do not generate meaningful cash flow from our oil and natural gas production, even though our future depends on our ability to generate oil and natural gas operating cash flow. We may generate additional capital to fund increases in capital expenditures through any of: (i) the sale of some oil and gas lease interests, (ii) additional sales of our securities and/or (iii) 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 may 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 gas operations are inherently risky.

The nature of the oil and gas business involves a variety of risks, particularly the risk of drilling wells that are found to be unable to produce any oil and gas or unable to produce and sell oil and gas at prices sufficient to repay the costs of the wells and the costs of producing the wells. As we have experienced in 2006 and in 2008, we may in the future recognize substantial impairment expenses when uneconomic wells and declines in oil and gas prices result in impairments of the capitalized costs of our oil and gas properties.

The oil and gas business also includes 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 currently conduct our oil and gas activities in joint ventures with other oil and gas companies, whereby one of the other companies serves as the joint venture’s operator for the day-to-day management of the venture. Under terms of joint operating agreements, the operator is required to carry stated levels and types of casualty and liability insurance. In addition, we carry our own casualty and liability insurance for our interests in such ventures and carry additional insurance against well blow-outs and other unusual risks in the drilling, completion and operation of oil and gas wells. However, there may still be fires, blow-outs and other events that result in losses not fully covered by our insurance.

We may be unable to find additional reserves.

Our revenues depend on whether we find or acquire additional reserves. Unless we conduct successful exploration and development activities, or acquire properties, our proved reserves will decline. Our future oil and natural gas reserves and production as well as our cash flow and income are dependent on our ability to efficiently develop and exploit our current reserves and economically find or acquire additional reserves. Our planned exploration and development projects may not result in significant additional reserves, and we may be unable to drill productive wells at low reserve replacement costs.

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.

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. Concerns of global warming may result in changes to laws and regulations that increase the cost of oil and gas operations and decrease the use and demand for crude oil and natural gas. 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, compliance in the future may require us to incur significant costs or activity restrictions.

Our operations and financial condition may be impacted adversely by new taxes and changes to tax laws.

The federal, state and local governments in which we operate impose taxes on the oil and gas products we sell and for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. U.S. President Obama has recently proposed sweeping changes in federal laws on the income taxation of small oil and gas exploration and production companies such as us. President Obama has proposed to eliminate allowing small US oil and gas companies from (i) deducting intangible US well costs as incurred and (ii) taking percentage depletion deductions. Many states have raised state taxes on energy sources and additional increases may occur. Changes to the law could adversely affect our business and our financial results.

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.

As we have encountered at times in the past, we or our joint venture operators 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. At times in the past, 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.

As we have experienced at times in the past, 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.

We could be adversely impacted by customer(s) and industry partners unable to meet their obligations.

Substantially all of our accounts receivable arise from oil and natural gas sales or joint interest billings to third parties in the oil and gas industry. Our financial results could be adversely impacted by one or more of such third parties being unable to meet their obligations to us.

Risks Related to our Common Stock

Our common stock is thinly traded, 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 172,000 shares per trading day over the 90-day period ended March 6, 2009. 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.

We meet normal exchange guidelines for the continuation of trading of our common stock, but unexpected de-listing may occur.

The Company trades on the NYSE Alternext U.S. exchange (i.e., the American Stock Exchange, which was acquired by the New York Stock Exchange in 2008). NYSE Alternext U.S. continues to use the AMEX Corporate Guide on criteria as to whether the exchange should “de-list” a listed company. Under that Guide, the exchange has the right, at its discretion, to cease trading the stock of any company but normally considers de-listing of a company’s common stock in one of four general cases, none of which we believe is true for us:

the listed company has stockholders equity of less than $6 million or if the Exchange believes it questionable that the issuer will be able to continue operations or meet its obligations as they mature;

the listed company has less than 200,000 shares outstanding (excluding shares held by insiders and controlling shareholders);

the listed company has sold its operating assets and ceased to be an operating company or its shares have no value; and

the listed company fails to comply with Listing Requirements of the exchange or with SEC requirements.

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:

	•		conditions generally affecting the oil and natural gas industry, such as declines in the prices of oil and gas,

	•		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,

	•		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 debt or preferred stock with rights that are preferential to, and could cause a decrease in the value of, our common stock.

We may issue debt and/or up to 24.1 million shares of preferred stock without action by our stockholders. Rights or preferences of the debt or preferred shares could include, among other things:

•

the establishment of principal and interest obligations or dividends which must be paid prior to declaring or paying dividends or other distributions to our common stockholders,

•

a security interest in some or all of our assets that could be foreclosed in the event of default of a loan agreement or similar instrument,

•

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

•

the right to convert the debt or 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 four main project areas that we call Fetter, Goliath, Krejci and Bigfoot. We sold in 2008 our interests in our West Douglas project. The following is a description and current status of our specific oil and gas projects:

Fetter Project (Powder River Basin, Wyoming)

Our Fetter project currently encompasses approximately 53,000 gross acres. During 2008, Red Technology Alliance, LLC (RTA) completed a drilling program pursuant to a Participation Agreement with us, whereby RTA paid 100% of the costs to drill and complete two horizontal wells and one vertical well in the Fetter project area. We were carried through the tanks in these wells and own a 23.125% working interest in each of the three wellbores. RTA retained a 75% working interest in those three wellbores and by drilling and completing those wells, earned a 25% working interest in the remaining Fetter project undrilled acreage. Pursuant to the Participation Agreement, our ownership at Fetter decreased from a 92.5% working interest in approximately 49,000 net lease acres to a 69.375% working interest, giving us approximately 34,000 total net acres at Fetter. North Finn LLC retains the remaining 5.625% working interest. The drilling and completion operations have been project managed by Halliburton Energy Services, Inc.

The most recent well drilled at Fetter, the Sims 7-25 well (SWNE Sec 25-T33N-R71W Converse County, WY), cost substantially less (under $3 million) to drill and complete and in January 2009 had much better initial production from the Frontier formation (approximately two mmcfe/day), than any prior vertical well completed in the field. However, at 2008 drilling cost rates, at current oil and gas prices and with production only from the Frontier formation, the well would not be a commercial success that provides a profit after well costs. Our goal is to further reduce the drilling and completion costs for these types of vertical wells and to enhance production to the point where the wells will be commercially successful, even in the current commodity pricing environment.

We expect to drill three to six additional vertical wells in the Fetter project during 2009. We also expect to be able to commingle production from the Niobrara formation with production from the Frontier formation to enhance production and reserves.

Although prior drilling efforts have confirmed productive potential exists in the Mowry formation, successful completion in this formation remains challenging. We expect to focus on completing wells in the Mowry formation again at a later date. By focusing on the completing wells in the Frontier and Niobrara formations, we anticipate being able to better build reserves and cash flow in the near-term.

The Fetter project has been particularly challenging, from the drilling and completion of wells and managing production from those wells, to designing the appropriate gathering system and accommodating pipeline interruptions. However, we feel that we have made significant progress in overcoming those obstacles, and we anticipate that in the near term, we could begin to drill commercially successful wells that would enable us to grow reserves and cash flow. Specifically, as a result of prior drilling efforts, we believe we now understand the appropriate drilling and completion procedures that could result in lower costs and higher production rates. We have recently expanded the field compression capabilities in our gathering system that should enable us to consistently deliver natural gas to purchaser(s) of our gas. Although the Fetter project is primarily a natural gas field, the gas wells also produce a high-quality oil. We are in the process of installing artificial lift systems in the wells that we expect will allow the wells to better lift the high quality oil up the well, adding to revenues and proved reserves while reducing the risk of the oil collecting in the wells in ways that can reduce or block the flow of natural gas from the wells.

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

On October 27, 2008, we sold approximately 28,000 net undeveloped leasehold acres in the West Douglas and greater Douglas project areas and approximately 3,000 net undeveloped leasehold acres located in the western edge of our Fetter project, and received approximately $26.4 million in sales proceeds.

Goliath Bakken Project (Williston Basin, North Dakota)

Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are primarily targeting the middle member of the Bakken formation in the North Dakota Williston Basin. Our Goliath project area currently encompasses approximately 87,000 gross acres, and we own a 50% working interest in approximately 65,000 lease net acres. Our acreage position lies directly west and adjacent to the Nesson Anticline.

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

We do not expect to expend substantial capital within the Goliath project during 2009. In October 2008, we and other partners entered into an agreement with Red Technology Alliance, LLC (“RTA”) for RTA to drill in 2009 at RTA’s cost two to four horizontal wells to test the Bakken formation on our Goliath acreage block. Under the agreement, RTA would earn a 50% working interest in the wells and a 40% working interest in 50% to 100% of undeveloped acreage in the block. Termination of this agreement does not result in significant payments to us. In late February 2009, RTA notified us that it wishes to renegotiate the terms. If we do not agree on new terms, we plan to attempt to enter into an arrangement with another outside industry participant to pay for a substantial portion or all of one or more horizontal wells within our Goliath project acreage whereby the outside participant would earn a partial ownership interest in the Goliath project.

We expect that recent advancements in drilling and completion techniques that have resulted in successful Bakken wells by other operators west of the Nesson Anticline, will be incorporated into future drilling at Goliath. We also expect that future drilling will be designed to provide important reservoir and geological data from other prospective formations in the project area including the Three Forks/Sannish, Madison, Nisku, Duperow, Interlake, Stonewall, Red River and Winnipeg.

We have been successful in drilling and completing wells in the Red River formation and in late 2007, we participated in 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.

In early 2008, we and other joint interest owners in the Goliath project completed a 10.5 square mile 3-D seismic program in the area around the Solberg 32-2 well. Based on interpretation of the data, we have identified additional potential for production from the Red River formation, and have drilled the Viall #30-1 well. This well has been completed in the Red River formation, and we expect the well to be connected to the sales line and begin production during the second quarter 2009.

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 128,000 gross (approximately 52,000 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 five wells so far in the Krejci project. Three of the wells drilled are producing, and two wells are shut-in while we evaluate additional stimulation techniques. Although we currently have production from three of the five wells, we do not consider those wells to be commercially successful. Other companies are now either drilling or planning to drill wells targeting the Mowry formation in the southern Powder River Basin, and we will be watching the level of success these other companies have with their drilling, stimulation and completion operations. Accordingly, we do not expect to continue drilling new wells at Krejci in the near term, but expect to commence drilling again if other companies are successful in completing commercially successful wells in the Mowry formation and we believe we can replicate that success within our Krejci project area.

Bigfoot Project (Rocky Mountain Region)

We owned at December 31, 2008, approximately 112,000 net acres in a project that we call Bigfoot. This is a shallow natural gas project located in the Rocky Mountain region. This project remained in the lease acquisition stage at December 31, 2008. We expect to acquire additional 2D seismic data, drill test wells and acquire additional leasehold in the Bigfoot area during 2009.

Oil and Gas Drilling Activities

During 2008, we participated in the drilling of a total of eight gross (2.58 net) wells. Of these wells, five gross (0.85 net) were productive wells and two gross (1.04 net) were not yet completed for production testing. The other gross (.69 net) well was the Hageman 11-22UK shallow well drilled in the Fetter project that resulted in non-commercial quantities of oil. The productive wells include the Hageman 11-22 well (.69 net) which was drilled in our Fetter project and four gross (.19 net) oil wells drilled in the Williston Basin of North Dakota. The two wells still in progress at December 31, 2008 were the Sims 7-25 well (.69 net) at Fetter and the Viall #30-1 well (.35 net) in our Goliath project. The Sims 7-25 was completed and placed on production in January 2009. The Viall #30-1 was completed in late February of 2009 and expected to be placed on production.

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.

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, 2008.


Productive Wells as of December 31, 2008
	Gross (a)						Net (b)
Location	Oil		Gas		Total		Oil		Gas		Total
Wyoming		2		9		11		0.72		3.41		4.13
North Dakota		9		1		10		0.79		0.10		0.89

Total		11		10		21		1.51		3.51		5.02


(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

The table below presents the approximate gross acres and our approximate net acres as to our interests in oil and gas mineral leases as of December 31, 2008. See the accompany glossary on pages 7 to 9 for the meaning of the terms gross acres, net acres, developed acreage and undeveloped acreage.


	Developed Acres				Undeveloped Acres				Total Acres
Project	Gross		Net		Gross		Net		Gross		Net
Fetter (Wyoming)		4,520		1,944		48,592		31,995		53,112		33,939
Krejci (Wyoming)		1,280		576		126,996		51,699		128,276		52,275
Goliath (North Dakota)		8,320		956		79,155		31,665		87,475		32,621
Bigfoot (U.S. Rocky Mtn. area)		0		0		174,841		111,912		174,841		111,912
Other (WY, ND, Montana)		1,320		312		103,799		31,698		105,119		32,010

Total		15,440		3,788		533,383		258,969		548,823		262,757

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 and production, which extend lease life). The leases would expire sooner absent payments of annual delay rentals and (in some cases for fee leases) payments at our option to extend the lease life beyond its primary term. Following the table below is a table of the rental and extension payments by year required (absent pre-expiration drilling and production).


		Net Undeveloped Acres
	Year of	Fee		State		Federal		Total for
	Expiration	Leases		Leases		Leases		All Leases
Wyoming	2009		4,894		360		1,310		6,564
	2010		7,896		1,893		3,584		13,373
	2011		10,498		3,713		21,089		35,300
	2012		3,550		2,174		4,615		10,339
	2013		332		—		3,410		3,742
	2014		243		—		6,416		6,659
	2015		—		—		3,161		3,161
	2016		—		—		7,943		7,943
	2017		—		—		2,070		2,070
	2018		—		—		12,781		12,781

Total Wyoming			27,413		8,140		66,379		101,932


North Dakota	2009		379		457		0		836
	2010		16,439		1,687		0		18,126
	2011		10,056		—		—		10,056
	2012		3,022		—		—		3,022
	Later		52		—		120		172

Total North Dakota			29,948		2,144		120		32,212


Bigfoot Project	2009		—		—		—		—
	2010		—		1,781		—		1,781
	2011		16,862		150		—		17,012
	2012		9,920		37,417		—		47,337
	2013		1,749		21,169		—		22,918
	2014		19,571		—		—		19,571
	Later		3,060		—		233		3,293

Total Bigfoot Project			51,162		60,517		233		111,912

Other (Montana)	2009		480		—		—		480

Total, all states			109,003		70,801		66,732		246,536


Other undeveloped (primarily lease rights held by production)									12,433

Total undeveloped									258,969

The types of leases represented in this table are comprised of approximately 4,000 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, with some fee leases allowing us to pay at the end of the primary term a stated amount per acre to extend the term another one to three 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 (or elect not to pay the extension fee, if any), then the lease would terminate absent drilling and production. We could elect not to pay the delay rental fee (or extension 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 rentals and extension fees, if we desire to continue to keep all our leases in effect, are as follows:


	Delay		Extension
	Rentals		Fees		Total
2009	$	191,765	$	416,742	$	608,507
2010	$	194,358	$	133,385	$	327,743
2011	$	131,247	$	328,107	$	459,354
2012	$	79,335	$	29,314	$	108,649
2013	$	50,861	$	0	$	50,861
2014	$	39,015	$	15,300	$	54,315
Thereafter	$	70,860	$	0	$	70,860

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,
	2008		2007		2006
Production:
Natural gas (MMcf)		173.1		139.6		48.2
Oil (Bbls)		19,221		17,267		34,578
Total equivalents (Bbls)		48,076		40,532		42,603
Average Sales Price Per Unit:
Natural gas (per Mcf)	$	7.06	$	6.09	$	7.53
Oil (per Bbl)	$	86.96	$	64.11	$	54.79
Weighted average (per Boe)	$	60.21	$	48.27	$	52.97
Expenses (per Boe):	$	26.60	$	15.94	$	6.83

Office Facilities

In 2008 we were in a long-term lease of 6,844 square feet of office space at 1050 17^th Street, Suite 2400, Denver, Colorado. Starting on or about June 1, 2009, our lease will include an additional 5,617 square feet of adjoining office space. We believe that our facilities will be adequate for our operations and that we can obtain additional leased space if needed. With the additional space, our obligation to provide aggregate monthly rental payments is as follows:


Year	Annual Rental Amount
2009	$	260,837
2010	$	340,790
2011	$	347,020
2012	$	353,251
2013	$	148,270
Thereafter	$	—

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 2008.

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 NYSE Alternext U.S. (formerly 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
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

2008
Quarter ended March 31, 2008	$	5.95	$	3.00
Quarter ended June 30, 2008	$	5.00	$	2.75
Quarter ended September 30, 2008	$	3.98	$	2.00
Quarter ended December 31, 2008	$	2.81	$	0.62

On March 6, 2009, the closing sales price for our common stock as reported by NYSE Alternext U.S. (formerly the American Stock Exchange) was $0.61 per share.

Holders

As of March 6, 2009, there were approximately 57 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 2008.

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 $0.70 per share on December 31, 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 December 31, 2003.


			S&P Small Cap
	AEZ		600 Energy		S&P 500
12/31/2003	$	100.00	$	100.00	$	100.00
12/31/2004	$	392.86	$	152.71	$	110.74
12/31/2005	$	578.57	$	232.38	$	116.05
12/31/2006	$	930.00	$	273.34	$	133.65
12/31/2007	$	828.57	$	337.33	$	140.57
12/31/2008	$	114.29	$	182.07	$	91.95

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, 2008, 2007, 2006, 2005 and 2004 have 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 US. The historical results presented below are not necessarily indicative of the results to be expected for any future period.


	Year Ended December 31,
	2008			2007			2006			2005			2004
	(in thousands, except per share data)
Statement of Operations Data:
Production Revenues	$	2,895		$	1,957		$	2,257		$	4,691		$	746
Service fee and other revenues		—			12			1,530			—			—
Operating expenses:
Lease operating expenses		1,279			646			291			246			80
General and administrative		4,372			4,308			4,009			2,032			945
Depreciation, depletion and amortization		1,466			1,267			1,153			1,532			188
Accretion of asset retirement obligation		33			24			11			6			5
Property impairments		24,310			—			4,360			—			—
Goodwill impairment		11,670			—			—			—			—

Total operating expenses		43,130			6,245			9,824			3,816			1,218

Gain on sales of oil and gas properties		16,500			—			7,159			—			—

Operating income (loss)		(23,735	)		(4,276	)		1,122			875			(472	)
Other income (expense)
Investment income		511			1,021			393			204			34
Gain (loss) on sale of securities		(369	)		(15	)		—			—			—
Impairment of securities investment		(300	)		(952	)		—			—			—
Interest expense		(107	)		(6	)		—			—			—

Total other income (expense)		(265	)		48			393			204			34

Income (loss) before income taxes		(24,000	)		(4,228	)		1,515			1,079			(438	)
Income tax benefit (provision)		468			1,485			(304	)		(46	)		—

Net Income (loss)		(23,532	)		(2,743	)		1,211			1,033			(438	)
Dividends on preferred stock		(328	)		(603	)		(1,080	)		(479	)		(62	)
Deemed dividends on warrant extensions		(300	)		(450	)		—			—			—

Net Income (loss) attributable to common stockholders	$	(24,160	)	$	(3,796	)	$	131		$	554		$	(500	)

Income (loss) per common share:
Basic	$	(0.51	)	$	(0.09	)	$	0.00		$	0.02		$	(0.02	)
Diluted	$	(0.51	)	$	(0.09	)	$	0.00		$	0.02		$	(0.02	)
Weighted average number of common shares outstanding:
Basic		47,104			44,384			37,429			34,148			25,211
Diluted		47,104			44,384			38,142			34,956			25,211

Selected Cash Flow and Other Financial Data:
Net income (loss)	$	(23,532	)	$	(2,743	)	$	1,211		$	1,033		$	(438	)
Less: gains on sales of oil and gas properties		(16,500	)		—			(7,159	)		—			—
Add back: Property impairments		24,310			—			4,360			—			—
Add back: Goodwill impairment		11,670			—			—			—			—
Depreciation, depletion and amortization		1,466			1,267			1,153			1,532			188
Net loss on sales of securities		369			15			—			—			—
Other non-cash items		525			582			308			466			411
Changes in current assets and liabilities		58			(292	)		1,496			(1,163	)		(567	)

Net cash provided (used) by operating activities	$	(1,634	)	$	(1,171	)	$	1,369		$	1,868		$	(406	)

Cash provided (used) by:
Proceeds from sale of stock	$	—		$	28,507		$	—		$	13,500		$	6,025
Purchases of short-term investments	$	—		$	(28,750	)	$	—		$	—		$	—
Sales/redemptions, short-term investments	$	12,184		$	12,361		$	—		$	—		$	—
Capital expenditures	$	(21,420	)	$	(16,214	)	$	(16,152	)	$	(14,147	)	$	(2,895	)
Sales of oil and gas properties	$	31,695		$	777		$	16,067		$	—		$	1,582
Short-term loans	$	10,925		$	—		$	—		$	—		$	—
Repayment of short-term loans	$	(10,925	)	$	—		$	—		$	—		$	—

Balance Sheet Data:
Cash and cash equivalents	$	23,270		$	2,388		$	7,488		$	6,023		$	5,252
Other current assets		6,770			19,408			10,013			1,679			313
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment		35,660			53,402			38,869			24,921			3,481
Other property and equipment, net of depreciation		182			230			252			58			6
Other assets		1,507			12,663			12,514			13,094			—

Total assets	$	67,389		$	88,091		$	69,136		$	45,775		$	9,052

Current liabilities	$	4,390		$	1,831		$	4,656		$	1,434		$	127
Long term liabilities		431			1,383			2,392			2,010			41
Stockholders’ equity		62,568			84,877			62,088			42,331			8,884

Total liabilities and stockholders’ equity	$	67,389		$	88,091		$	69,136		$	45,775		$	9,052

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. Some of the factors that could cause or contribute to such differences are 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.” Many of these factors 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, (i) cash received from the sale of our equity, and (ii) proceeds received from the sale of certain of our oil and gas assets, and 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. At December 31, 2008, we owned interests in approximately 550,000 gross (263,000 net) acres primarily in the Powder River Basin of Wyoming, in the Williston Basin of North Dakota and in our Bigfoot project in the Rocky Mountain region. 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.

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 2009:

Approximate

Expected net

Expected

working

capital

Project

2009 wells

interest

required

(in millions)

Fetter project — Converse County, WY

3 to 6

5 to 10

Goliath project — Williams County, ND

0 to 2

0 to 3

Bigfoot project

5 to 50

1 to 6

Total drilling activity

8 to 58

6 to 19

While our base case drilling activity would result in drilling costs of approximately $6 million, we may expand drilling activity to as much as $19 million, if project economics and general economic conditions support the more aggressive drilling program. If we elect to expand drilling activities, we may need to access additional capital. We have no third-party commitments to provide additional capital and there is no assurance such capital will be available to us, or if available, that the terms will be favorable to us. We may access capital from equity and/or debt offerings.

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.

Impact of Current Economic Conditions

The global and national economic and financial crises and the significant fall in oil and gas prices during the last few months of 2008, combined with the risk that oil and gas prices may not recover in 2009 impacts us in many ways, most notably: (i) decreasing our revenue as oil and gas is produced, (ii) potentially decreasing the value of our proved reserves and the value of our oil & gas leases, (iii) potentially decreasing the opportunities in 2009 to profitably drill wells, and (iv) significantly contributing, we believe, to our operating losses in 2008 and to the decline in our stock price from $2.61 per share at September 30, 2008 to $0.80 per share at December 31, 2008 and $0.61 per share on March 6, 2009. However, we do believe that the weakness in oil and gas prices should provide us with the opportunity to experience significant decreases in service costs relating to drilling, completing and operating oil and gas wells. We anticipate that by combining decreases in services costs with enhanced production from our focus areas, we could drill commercially successful wells, even at current commodity price levels.

We begin 2009 with:

•
Over $25.6 million in working capital ($0.53/share), including $23.3 million in cash and $5.4 million in short term investments,

•
No long term debt,

•
Approximately 259,000 net undeveloped acres of oil and gas leases of which only approximately 8,000 acres would expire in 2009, even if we drill no wells in 2009,

•
Improved opportunity for drilling commercially successful wells within the Fetter and Goliath projects, even at current commodity prices when taking into consideration current and expected further decreases in service costs, and

•
Plans to drill several shallow gas wells at our new Bigfoot project that could be commercially successful under existing gas price conditions.

•
Little employee turnover in 2008 and no turnover of officers or key managers,

Results of Operations

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

For the year ended December 31, 2008, we recorded a net loss attributable to common stockholders of $(24,159,614) ($(0.51) per common share, basic and diluted) for the year ended December 31, 2008, as compared to 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.

Oil and Gas Operations

For 2008, we had total oil and gas revenues of $2,894,589 compared with $1,956,508 for 2007. Oil and gas sales and production costs for each year are summarized in the table that follows. Oil sales volumes increased in 2008 compared with 2007 due to increased production from new North Dakota wells producing in the Bakken formation and from oil produced in conjunction with gas production from Fetter gas wells. Gas sales volumes increased in 2008 over 2007 largely due to new wells in late 2007 and in 2008 at Fetter and in North Dakota.


	Year Ended December 31,
	2008			2007
Oil sold (barrels)		19,221			17,267
Average oil price	$	86.96		$	64.11

Oil revenue	$	1,671,451		$	1,107,054


Gas sold (mcf)		173,129			139,590
Average gas price	$	7.06		$	6.09

Gas revenue	$	1,223,138		$	849,454


Total oil and gas revenues	$	2,894,589		$	1,956,508
Less lease operating expenses		(1,278,668	)		(646,000	)
Less oil & gas amortization expense		(1,210,000	)		(1,021,817	)
Less accretion of discount		(32,936	)		(23,767	)
Less impairments of oil and gas properties		(24,310,000	)		—
Plus gain on sale of oil and gas properties		16,500,000			—

Income (loss) from oil and gas operations		(7,437,015	)		264,924
Less general and administrative expenses		(4,372,202	)		(4,307,997	)
Less intangible asset amortization		(180,000	)		(180,000	)
Less depreciation of office facilities		(75,772	)		(65,225	)
Less impairment of goodwill		(11,670,468	)		—
Add service fee revenue and other revenues		—			12,000

Income (loss) from operations	$	(23,735,457	)	$	(4,276,298	)

Total barrels of oil equivalent (“boe”) sold		48,076			40,532
Oil and gas revenue per boe sold	$	60.21		$	48.27
Lease operating expense per boe sold	$	26.60		$	15.94
Amortization expense per boe sold	$	25.17		$	25.21

Impairments 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 of oil and gas properties (net of related deferred income tax liability) exceed a “ceiling”. In 2008, we recorded $24,310,000 of such impairments in the last four months of the year, primarily due to (1) approximately $9.6 million of costs of three Krejci wells evaluated in September 2008 in excess of their ceiling value, (2) approximately $5.3 million due to declines in oil and gas prices in the last five months of 2008 impacting ceiling components of wells with new proved reserves in 2008 and wells with proved reserves at December 31, 2007, (3) approximately $5 million for the cost of the Hageman 11-22 well at Fetter in excess of its ceiling value and (4) approximately $3.8 million for performance revisions of proved reserves during 2008. Such impairments are not reversed in the future to the extent the future ceiling exceeds the future capitalized costs of oil and gas property net of related deferred income tax liability. Additional impairments might arise in the future.

Gain on Sales in 2008 of Oil and Gas Properties

We recorded $16.5 million in gain ($10.7 million after tax effect) from the October 2008 sale, for $26.4 million cash, of (a) our West Douglas and Douglas acreage located west and northwest of our Fetter project and (b) a small western portion of our Fetter project, where that portion bordered Douglas acreage and lease rights previously held by the buyer. In September 2008, we sold for $5.3 million cash our interests in the Narraguinnep project in Colorado and credited the gain to the full cost pool since non-recognition of the gain did not significantly alter the relationship between capitalized costs and proved oil and gas properties. The combined taxable gains from the sales totaled approximately $26.5 million.

Impairment of goodwill

In 2005 we recorded $11,670,468 of goodwill in the acquisition, by merger, of Tower Colombia Corporation (“TCC”). At December 31, 2008, we recognized an $11,670,468 full and permanent impairment of the goodwill in accordance with SFAS 142, Goodwill and Other Intangible Assets, as further explained in Note 6 of our consolidated financial statements contained in this Form 10-K. The goodwill was not an asset for income tax reporting, and its impairment did not reduce income taxes or increase deferred tax assets.

Other Income (Loss)

The table below summarizes the Other Income (Loss) section of our Consolidated Statements of Operations for the year ended December 31, 2008 and the year ended December 31, 2007:


	2008			2007
Investment income from auction rate preferred shares and cash sweeps	$	511,599		$	1,020,712
Impairment of auction rate preferred shares		(300,000	)		—
Interest expense, due to illiquidity in 2008 of auction rate preferred shares		(107,047	)		—

Net income of auction rate preferred shares and cash sweeps		104,552			1,020,712
Losses on unregistered PetroHunter common stock sold in 2007 and 2008		(369,172	)		(966,618	)
Other interest expense		—			(6,162	)

Total other income (loss)	$	(264,620	)	$	47,932

In 2008, we sold all remaining shares of PetroHunter common stock and had redeemed or sold at par value $11,575,000 of auction rate preferred shares. At December 31, 2008, we owned $5,750,000 in auction rate preferred shares, with an estimated fair value of $5,450,000 and we had $23.3 million in cash and cash equivalents. Substantially all of the $23.3 million was held in cash accounts at Wells Fargo Bank, N.A. We expect that for most of 2009 approximately $10 million of the $23.3 million will be invested in a portfolio of U.S. Treasuries and highly liquid securities managed by a Wells Fargo affiliate. We anticipate liquidating our remaining auction rate preferred shares before December 31, 2009, with some shares redeemed by their issuers and other shares sold in private sales at a loss approximating the recognized impairment of $300,000.

Income Taxes

For the year ended December 31, 2008, we recorded a $468,345 income tax reduction (consisting of a $244,000 current income tax provision and a $712,345 deferred income tax benefit). The $468,345 income tax reduction is 2% of the $24 million Loss Before Income Taxes for 2008. The 2% effective income tax rate is substantially less than the 36.5% combined statutory income tax rate for federal and state income taxes in 2008. The rate reduction is attributable to (i) recognition at December 31, 2008 of a deferred tax asset valuation allowance of $4,752,308 and (ii) inability to ever deduct for income taxes the $11,670,468 goodwill impairment expense for financial reporting. If in the future, facts and circumstances indicate that all or a portion of the deferred tax asset is likely to be realized, then the $4,752,308 valuation allowance would be correspondingly reduced and a deferred tax benefit correspondingly recognized.

Dividends

Preferred dividends for the year ended December 31, 2008 were $327,882, compared with $602,530 for 2007. The decrease was due to the mandatory conversion of preferred shares into common shares on July 22, 2008. We recognized deemed dividends of $300,000 and $450,000 in 2008 and 2007, respectively, for the fair value of extensions of certain warrants as described in Note 9 of the accompanying audited financial statements. We had no preferred shares outstanding at December 31, 2008 and do not anticipate issuing shares in 2009. We may have, but do not anticipate having, extensions of warrants in 2009.

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	)
Plus gain on sale of oil and gas properties		—			7,159,470

Income from oil and gas operations		264,924			3,816,472
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	)	$	1,122,041

Total barrels of oil equivalent (“boe”) sold		40,532			42,603
Oil and gas revenue per boe sold	$	48.27		$	52.97
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 allows for 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 years 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 2008 or 2007.

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 $602,530 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.

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 2009 to be approximately $15 million. Approximately $6 million is allocated to our expected drilling and production activities; $6 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.

At December 31, 2008, we had cash and cash equivalents of $23.3 million consisting primarily of cash held in Wells Fargo bank accounts, as compared to $2.4 million at December 31, 2007. Working capital was $25.6 million as of December 31, 2008, as compared to $20.0 million at December 31, 2007. We may generate additional capital to fund increases in capital expenditures through any of (i) the sale of some oil and gas lease interests, (ii) additional sales of our securities, and (iii) 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.

At December 31, 2008, we had $5,750,000 par value ($5,450,000 fair value) in short-term investments in Auction-Rate Preferred Stocks (ARPS) issued by eight taxable US closed-end funds. These ARPS pay dividends every 7 or 28 days at variable rates that approximate 150% of 30-day US LIBOR rates. ARPS normally provide liquidity via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. ARPS auctions and similar auctions have had insufficient bids to buy the ARPS from those wishing to sell, whereby (starting in mid-February 2008 and for the foreseeable future) holders of ARPS have been unable to sell ARPS in the auction process. Since the auction failures, ARPS are liquidated by either (a) redemption at par value at the option of the issuing fund, (b) purchase at par value by a bank or broker (who marketed the ARPS), usually in a settlement with government agencies, or (c) sale in a secondary market at a discount to par value.

Since December 31, 2008, through March 6, 2009, closed-end funds have redeemed at par value or announced redemptions approximating $175,000 of our ARPS. We hold another $2,325,000 of ARPS in Calamos closed-end funds that received on February 10, 2009 an SEC exemption allowing the funds to use debt to redeem their remaining ARPS. However, the Calamos funds have not yet announced such redemptions and might not do so in 2009. We anticipate liquidating all of our auction rate preferred shares in 2009, with some shares redeemed by their issuers and other shares sold in private sales at a loss approximating the recognized impairment of $300,000.

Net Cash Provided By Operating Activities

Cash flows provided (used) by operating activities were ($1.6 million), ($1.2 million) and $1.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. The additional $0.4 million in cash outflow in 2008 compared with 2007 is due in part to a $0.6 million decline in cash from investment income net of interest expense as we reduced our short-term investments in 2008 by $12.8 million to provide funds for capital expenditures. In both 2007 and 2008, cash spent for lease operating expenses and for general and administrative expenses exceeded cash from oil and gas revenues by approximately $1.9 million.

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.

Net Cash Used In Investing Activities

In 2008, investing activities provided $22.5 million in cash. In September and October, 2008, we sold small portions of our acreage holdings for a total of $31.7 million in cash; we received $12.2 million in sales and redemptions of short-term investments and we spent $20.6 million investing in oil and gas property acquisition, exploration and development. Note 3 to our consolidated financial statements contained in this Form 10-K provides further information on changes in capitalized costs by project. In late 2008, we spent $0.7 million on well pipe and tubing expected to be used in completing wells in 2009.

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.

Net Cash Provided By Financing Activities

For the year-ended 2008, cash flows from financing activities were $8.6 million borrowed in March 2008, repaid within three months and $2.325 million borrowed in September and repaid within two months. We borrowed these funds from our broker when the broker was unable to liquidate our short-term investments in ARPS at par value.

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.

Contractual Obligations as of December 31, 2008

In addition to the $4,390,618 of current liabilities incurred as of December 31, 2008 as reflected on our consolidated balance sheet of that date, we have the following contractual obligations and commitments as of December 31, 2008:


			Payment due by period
			Total		2009		2010-2012		2013-2014		After 2014
Long-term debt			$	—	$	—	$	—	$	—	$	—
Capital lease obligations				—		—		—		—		—
Lease of office space				1,450,168		260,837		1,041,061		148,270		—
Asset retirement obligations	(a	)		—		—		—		—		—
Development of proved reserves	(b	)		270,000		270,000		—		—		—
Other well drilling & completion	(b	)		860,000		860,000		—		—		—
Equipment inventory orders	(b	)		410,000		410,000		—		—		—

Total			$	2,990,168	$	1,800,837	$	1,041,061	$	148,270	$	—


(a)		The asset retirement obligations liability of $430,686 at December 31, 2008 is a discounted present value of estimated future retirement obligations, excluding cost reductions for the salvaging of equipment when wells are retired. The estimated asset retirement obligations, net of associated estimated equipment salvage value, in total and by future periods is zero. Our estimated total asset retirement obligations, without reduction for equipment salvage value, is approximately $604,000 at current prices. The timing of the $604,000 is $0 in 2009, $344,000 in the three year period 2010 through 2012, $79,000 in the two-year period 2013 to 2014 and $181,000 after 2014. In many cases, timing will change as factors (such as future changes in oil and gas prices) change the economic lives of our wells.

(b)		These three categories show estimates of the costs of obligations at December 31, 2008 to participate in (1) completion of wells with proved reserves, (2) the drilling or completion of other wells in progress at December 31, 2008 and one well to be drilled in 2009 and (3) the purchase of well casing and tubing to have on hand for use in some of the other wells planned to be drilled in 2009.

Critical Accounting Policies and Estimates

Management’s discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principals generally accepted in the United States of America. Such accounting principles allow in some cases for the adoption of accounting policies that are not uniformly followed by all companies in a given industry. For example, we have adopted the full cost accounting method for oil and gas exploration and production activities. Many of our competitors use the full cost accounting method while other competitors use the successful efforts method. Our significant accounting policies are summarized in Note 2 of our consolidated financial statements contained herein. Financial statement preparation also involves the use of estimates, such as the estimation of proved oil and gas reserves. We believe the following to be the most critical of our significant accounting policies and our estimates in the preparation of our financial statements.

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.

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 a ‘ceiling’ 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 (at period-end rates) to be incurred in developing and producing the proved reserves and assuming continuation of economic conditions existing at period-end. 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).

Estimates of Proved Oil and Gas Reserves

Estimates of our proved oil and gas reserves have significant impact on the carrying value of our oil and gas properties, the related property amortization expense and related property impairment expense. 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.

Estimates of Fair Values of Unevaluated and Evaluated Properties

Company management estimates the fair values of unevaluated properties, by project, as one key consideration in the quarterly management assessment of whether capitalized costs of unevaluated properties are impaired. Company management also must estimate the fair value of oil and gas properties when we sell properties and the gain on sale must be determined under the full cost accounting method by allocating to the sale a portion of the total capitalized cost of the U.S. cost center on the basis of the fair value of the properties sold and the fair values of all properties owned (evaluated and unevaluated) immediately prior to the sale. Company management routinely estimates fair value of properties in the course of negotiating (1) the acquisition or disposition of properties and (2) participation agreements with third-parties to pay for a disproportionate share of well costs to earn a portion of lease rights. Estimation of fair values of oil and gas properties, particularly an aggregation or project of unevaluated properties, can be difficult and is often based on assumptions that must be subjectively determined and will change with various factors including (i) the passage of time, (ii) changes in oil and gas prices, (iii) drilling results, (iv) changes in drilling cost rates and (v) estimated probability of exploration success.

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).

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.

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, 2008 and 2007, our produced natural gas volumes were in balance.

Recently Issued Accounting Pronouncements

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 adopted 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 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.

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. The adoption’s impact on our consolidated financial statements will be largely dependent on the nature of any business combinations completed after the adoption.

In March 2008 the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities — an Amendment of FASB Statement No. 133, which requires disclosures of objectives for using derivative instruments. The statement is effective for us beginning January 1, 2009, but we do not expect SFAS 161 will have a material impact on our financial statements.

On December 31, 2008, the SEC published changes to its rules and interpretations with regards to disclosures by oil and gas exploration companies, effective for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. Key changes include changes to the oil and gas prices used to estimate proved reserves, permitting the disclosure of probable and possible reserves and the use of new technology for determining reserve classification. We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

Item 7A: Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

In 2008, oil and gas prices were generally more volatile than in 2007 and 2006. Average oil prices per barrel for our proved reserves approximated $81.60 at December 31, 2007, $130 at June 30, 2008, $90 at September 30, 2008 and $27.50 at December 31, 2008. Proved reserve average natural gas prices per mcf as of the same dates were approximately $6.40, $9.70, $5.94 and $5.00, respectively. If December 31, 2008 oil and gas prices had been double their actual prices, the $24 million loss for 2008 would likely have been approximately $8 million due simply to the higher year-end oil and gas prices eliminating the need for the $5.4 million ceiling impairment for the fourth quarter of 2008 and likely eliminating the $11.7 million goodwill impairment.

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

Operating Cost Risk

During 2007 and 2008, we have generally experienced rising operating costs (including drilling costs) which impacts our cash flow from operating activities and profitability. With the decline in oil and gas prices in recent months, we have seen a reduction in drilling activity in the Rocky Mountain region where our properties are located, and we are beginning to see significant decreases in drilling costs, but little or no reduction in oil and gas production costs other than production taxes (which are generally levied as a percentage of revenue). If oil and gas prices were to recover to levels seen in December 2007, we anticipate the reductions in drilling activity and drilling cost rates will substantially reverse and may fully reverse and continue to rise.

In the case of our Fetter property, where the latest vertical well cost less than half (and has substantially more reserves) than a vertical Fetter well drilled earlier in 2008, the substantial economic improvements are due to drilling and completing the wells differently and not to reductions in rates charged by subcontractors for the use of their drilling rigs and services. We expect to see improvements due to rate reductions in Fetter wells drilled in 2009.

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

Interest Rate Risk

At December 31, 2008, we had no interest-bearing debt or credit facilities. Short-term interest rates on our $23 million of cash-equivalent investments were less than 1% per annum at December 31, 2008. Short-term dividend rates on our $5,450,000 in Auction Rate Preferred Shares approximated 1% per annum and are at rates approximating 150% of 30-day US LIBOR rates. An increase in short-term interest rates would be favorable to us, increasing our investment income in proportion to our short-term investments and cash-equivalent investments.

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 subsidiary as of December 31, 2008 and 2007, and the related consolidated statements of operations, cash flows and stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2008. 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 audits 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. and subsidiary as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

We have also 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, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 13, 2009 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 13, 2009

F-2

AMERICAN OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2008 AND 2007


	2008			2007
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	23,269,725		$	2,388,219
Short-term investments		5,450,000			18,302,900
Accounts receivable		1,186,749			566,789
Prepaid expenses		133,360			149,440
Current deferred tax assets (net of valuation allowance, Note 7)		—			347,658

Total current assets		30,039,834			21,755,006

PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $31,837,965 at 12/31/08 and $40,937,747 at 12/31/07)		40,456,632			56,987,732
Other property and equipment		366,354			338,614

Total property and equipment		40,822,986			57,326,346
Less accumulated depreciation, depletion and amortization		(4,980,578	)		(3,694,805	)

Net property and equipment		35,842,408			53,631,541

INTANGIBLE AND OTHER ASSETS
Goodwill		—			11,670,468
Other intangible asset		240,000			420,000
Drilling prepayments		—			542,876
Equipment inventory for use on new wells		1,236,591			40,904
Deferred income tax assets (net of valuation allowance, Note 7)		—			—
Other assets		30,385			30,385

	$	67,389,218		$	88,091,180

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	4,286,618		$	1,568,806
Income taxes payable		104,000			—
Preferred dividends payable		—			261,648

Total current liabilities		4,390,618			1,830,454

LONG-TERM LIABILITIES
Asset retirement obligations		430,686			323,369
Deferred income taxes		—			1,060,003

Total long-term liabilities		430,686			1,383,372

COMMITMENTS AND CONTINGENCIES (Note 13)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value, authorized 400,000 shares; issued and outstanding: None at 12/31/08 and 138,000 shares at 12/31/07; redemption value of $7,713,648 at 12/31/07		—			138
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding shares: 47,875,899 at 12/31/08 and 46,434,063 at 12/31/07		47,876			46,434
Additional paid-in capital		91,275,557			89,426,687
Accumulated deficit		(28,755,519	)		(4,595,905	)
Accumulated other comprehensive income		—			—

Total equity		62,567,914			84,877,354

	$	67,389,218		$	88,091,180

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, 2008, 2007 AND 2006


	2008			2007			2006
REVENUES
Oil and gas sales	$	2,894,589		$	1,956,508		$	2,256,839
Service fee and other revenues		—			12,000			1,530,000

Total revenues		2,894,589			1,968,508			3,786,839

OPERATING EXPENSES
Lease operating and gas processing		1,278,668			646,000			290,803
General and administrative		4,372,202			4,307,997			4,009,019
Depletion, depreciation and amortization		1,465,772			1,267,042			1,153,233
Accretion of asset retirement obligation		32,936			23,767			11,213
Impairments of oil and gas properties		24,310,000			—			4,360,000
Impairment of goodwill		11,670,468			—			—

Total operating expenses		43,130,046			6,244,806			9,824,268

GAIN ON SALE OF OIL & GAS PROPERTIES		16,500,000			—			7,159,470

INCOME (LOSS) FROM OPERATIONS		(23,735,457	)		(4,276,298	)		1,122,041


OTHER INCOME (LOSS)
Investment income		511,599			1,020,712			392,930
Impairment of securities investment		(300,000	)		(952,100	)		—
Loss on sale of securities		(369,172	)		(14,518	)		—
Interest expense		(107,047	)		(6,162	)		—

Total other income (loss)		(264,620	)		47,932			392,930

INCOME (LOSS) BEFORE INCOME TAXES		(24,000,077	)		(4,228,366	)		1,514,971

Income tax expense —current		244,000			—			—
Income tax expense (reduction) —deferred		(712,345	)		(1,484,984	)		303,748

Income tax provision (reduction)		(468,345	)		(1,484,984	)		303,748

NET INCOME (LOSS)		(23,531,732	)		(2,743,382	)		1,211,223
Less dividends on preferred stock		(327,882	)		(602,530	)		(1,080,000	)
Less deemed dividends on warrant extensions		(300,000	)		(450,000	)		—

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(24,159,614	)	$	(3,795,912	)	$	131,223


NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	(0.51	)	$	(0.09	)	$	0.00
Diluted	$	(0.51	)	$	(0.09	)	$	0.00

Weighted average common shares outstanding:
Basic		47,104,025			44,383,861			37,428,506
Diluted		47,104,025			44,383,861			38,142,011

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, 2008, 2007 AND 2006


	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(23,531,732	)	$	(2,743,382	)	$	1,211,223
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Gain on sales of oil and gas properties		(16,500,000	)		—			(7,159,470	)
Impairments of oil and gas properties		24,310,000			—			4,360,000
Impairment of goodwill		11,670,468			—			—
Service fee received in the form of a convertible note		—			—			(1,530,000	)
Depletion, depreciation and amortization		1,465,772			1,267,042			1,153,233
Accretion of asset retirement obligation		32,936			23,767			11,213
Deferred income taxes		(712,345	)		(1,484,984	)		303,748
Share-based compensation		904,006			1,091,677			1,522,219
Unrealized loss on investment in securities		300,000			952,100			—
Net loss on sales of securities		369,172			14,518			—
Changes in current assets and current liabilities:
Decrease (increase) in accounts receivable		(164,227	)		(230,601	)		1,145,355
Decrease (increase) in inventory held as a current asset		40,904			—			—
Decrease (increase) in advances and prepaid expenses		16,080			252,847			(245,812	)
Increase (decrease) in accounts payable and accrued liabilities		164,991			(314,090	)		596,935

Net cash provided (used) by operating activities		(1,633,975	)		(1,171,106	)		1,368,644


CASH FLOWS FROM INVESTING ACTIVITIES
Cash proceeds from sales of oil and gas properties		31,695,279			777,461			16,066,563
Cash purchases of short-term investments in securities		—			(28,750,000	)		—
Cash proceeds from redemption of short-term investments		11,500,000			—			—
Cash proceeds from sale of short-term investments		683,728			12,360,482			—
Cash paid for oil and gas properties		(20,612,267	)		(15,841,067	)		(15,913,075	)
Cash paid for office equipment and software		(27,740	)		(43,129	)		(229,178	)
Cash paid for equipment inventory		(780,157	)		—			—
Drilling prepayments and other long-term assets		—			(330,203	)		(10,000	)

Net cash provided (used) by investing activities		22,458,843			(31,826,456	)		(85,690	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowings		10,925,900			—			—
Repayment of short-term borrowings		(10,925,900	)		—			—
Proceeds from sale of common stock		—			28,506,602			—
Cash paid for stock offering and issuance costs		—			(1,956,465	)		(2,283	)
Proceeds from warrant exercise		56,638			705,025			55,508
Proceeds from employee stock option exercise		—			642,145			24,800
Proceeds from stock option exercises by a consultant		—			—			104,673

Net cash provided by financing activities		56,638			27,897,307			182,698


NET INCREASE (DECREASE) IN CASH		20,881,506			(5,100,255	)		1,465,652
CASH, BEGINNING OF YEAR		2,388,219			7,488,474			6,022,822

CASH, END OF YEAR	$	23,269,725		$	2,388,219		$	7,488,474

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, 2008, 2007 AND 2006


											Additional			Comprehensive Income
	Preferred			Stock			Common		Stock		Paid-in			Accumulated			Accumulated			Total
	Shares			Amount			Shares		Amount		Capital			Deficit			Other Income			Equity
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 $2,172,785 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
Conversion of preferred to common		(138,000	)	$	(138	)		1,242,000		1,242		(1,104	)								—
Accrued dividends, Series AA Pref.															(327,882	)					(327,882	)
Series AA preferred stock dividends paid in common stock								130,986		131		589,399									589,530
Exercise of warrants								64,850		65		56,573									56,638
Deemed dividends on warrant extensions												300,000			(300,000	)					—
Share-based compensation:
Stock option expense												735,286									735,286
Accrued stock-based compensation												151,000									151,000
Common stock granted and issued								4,000		4		17,716									17,720
Comprehensive income (loss):
Net loss															(23,531,732	)					(23,531,732	)

December 31, 2008 Balances		—		$	—			47,875,899	$	47,876	$	91,275,557		$	(28,755,519	)	$	—		$	62,567,914

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, 2008 and 2007 and for the years ended December 31, 2008, 2007 and 2006

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 primarily 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;

•

estimates as to the future realization of deferred income tax assets; 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. The Company typically has 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, 2008 and 2007, management had determined no allowance for uncollectible receivables was necessary.

Accounts receivable of $1,186,749 at December 31, 2008 consisted of $496,152 from sales of oil and gas, $497,493 from joint interest billings to other oil and gas companies who participate with us in acquiring and exploration of oil and gas leases and $193,104 other receivables. Accounts receivable of $566,789 at December 31, 2007 consisted of $291,773 from sales of oil and gas, $229,100 from joint interest billings to other oil and gas companies who participate with us in acquiring and exploration of oil and gas leases and $45,916 in accrued income from short-term investments.

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, 2008 and 2007:


	2008			2007
Asset retirement obligation beginning of year	$	323,369		$	235,268
Liabilities incurred		101,638			162,733
Liabilities settled		(51,996	)		(22,898	)
Accretion		32,936			23,767
Revisions in estimated liabilities		24,739			(75,501	)

Asset retirement obligation end of year	$	430,686		$	323,369

Current portion of obligation end of year	$	—		$	—

F-8

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 directly associated with property acquisition, exploration and development (including costs of unsuccessful exploration) are capitalized within cost centers or cost “pools”, generally by country. At December 31, 2008 and 2007, all of the Company’s oil and gas properties and operations were located in one cost center, the United States. Internal costs that are capitalized, such as land department salaries, are limited to costs directly identifiable with acquisition, exploration and development activities for the Company’s account and exclude indirect costs and costs related to production or general corporate overhead.

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 non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves of the cost center. Measuring the significance of the alteration often requires calculating the gain or loss by allocating a portion of the cost center’s total capitalized costs to the properties sold based on either (1) the proportion of the fair value of the properties sold to the total fair values (at approximately the time of sale) of the cost center’s properties immediately preceding the sale or (2) the proportion of proved reserves of the properties sold to the total proved reserves (at approximately the time of sale) of the cost center’s properties immediately preceding the sale. The first cost allocation method is required if there are substantial economic differences between the properties sold and the properties retained. If not, the second cost allocation method is required.

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. 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. The costs of properties not yet evaluated are not amortized until evaluation of the property. We make such evaluations for a well and associated lease rights when it is determined whether or not the well has proved oil and gas reserves. Other unevaluated properties are evaluated for impairment as of the end of each calendar quarter based upon various factors at the time, including drilling plans, drilling activity, management’s estimated fair values of lease rights by project, and remaining lives of leases. Capitalized land department costs directly relating to lease acquisitions and maintenance of lease records for our thousands of leases are evaluated for impairment by reclassifying over twelve calendar quarters and by limiting the unevaluated capitalized land department costs to no more than 15% of other unevaluated costs. Capitalized land department costs are initially capitalized 1/12^th to evaluated costs and 11/12^ths to unevaluated costs, with reclassification to evaluated costs being made evenly over the subsequent eleven calendar quarters.

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.

F-9

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.

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. At December 31, 2008, goodwill was fully impaired, as discussed in Note 6.

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, 2008 and 2007, our gas production was in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.

Major Customers: During 2008, we had three major customers: DCP Midstream LLC, Wyoming Refining Company and Shell Trading (US) Company, accounting for 63% of oil and gas sales. During 2007, we had four major customers: DCP Midstream LLC, Wyoming Refining Company, Shell Trading (US) Company and Nexen Marketing U.S.A., Inc., accounting for approximately 81% of oil and gas sales in 2007. 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, but in some circumstances a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

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 substantially all 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. 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.

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

F-10

PRINCIPLES OF CONSOLIDATION — Our consolidated financial statements include the accounts of our wholly-owned subsidiary Tower American Corporation. All significant intercompany accounts and intercompany balances have been eliminated.

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.

RECLASSIFICATION — Certain amounts in the 2006 and 2007 consolidated financial statements have been reclassified to conform to the 2008 financial statement presentation. Such reclassifications have had no effect on net income (loss).

RECENT ACCOUNTING PRONOUNCEMENTS

F-11

NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at December 31, 2008 and 2007 consisted of the following:


	2008			2007
Oil and gas properties, full cost method
Unevaluated costs, not yet subject to amortization	$	31,837,965		$	40,937,747
Evaluated costs		8,268,815			15,774,514
Asset retirement costs		349,852			275,471

		40,456,632			56,987,732
Furniture, equipment and software		366,354			338,614

		40,822,986			57,326,346
Less accumulated depreciation, depletion and amortization		(4,980,578	)		(3,694,805	)

Property and equipment	$	35,842,408		$	53,631,541

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, 2008	$	6,662,088
Year ended December 31, 2007		4,100,451
Year ended December 31, 2006		12,458,843
Year ended December 31, 2005		8,287,001
Prior to 2006		329,582

	$	31,837,965

Costs associated with unevaluated properties are primarily lease acquisition costs but include $1.9 million of costs for wells-in-progress, which at March 1, 2009 remain unevaluated or were not found to be dry holes. Costs for wells-in-progress were incurred in 2008 except for a Wyoming well substantially drilled in 2007 that was deepened in late 2008 and is being completed in 2009. All costs incurred prior to 2007 related to unproved property acquisition costs and related delay rentals, primarily for our Fetter and Goliath projects. There are no unevaluated costs relating to significant development activities. We anticipate that all of the $1.9 million of costs for wells-in-progress will be reclassified in 2009 as evaluated costs. Reclassification of other unproved property costs to evaluated costs is largely dependent on (i) how quickly we drill on the unevaluated property, (ii) the results of such drilling, (iii) if third-parties pay drilling costs to earn a portion of our interest and (iv) quarterly assessments of such costs for impairments.

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, Goliath, Krejci and Bigfoot. The following table presents the unevaluated capitalized oil and gas properties’ costs and net change for 2008, by major project:


	Capitalized Costs (in millions)							Approximate Acres 12/31/08 (Unaudited)
Project (State)	12/31/07		Net Change			12/31/08		Gross		Lease Net*		Our Net *
Fetter Project, Powder River Basin (WY)	$	14.5		0.2			14.7		48,592		44,856		31,995
Goliath Project, Williston Basin (ND)		7.0		0.7			7.7		79,155		63,421		31,665
Bigfoot		0.8		2.5			3.3		174,841		151,353		111,912
Krejci Oil Project, Powder River Basin (WY)		9.1		(6.7	)		2.4		126,996		121,937		51,699
Other unevaluated costs		2.7		1.1			3.8		103,799		92,493		31,698
West Douglas (WY), sold in 2008		4.2		(4.2	)		0		0		0		0
Douglas Project (WY), sold in 2008		0.9		(.9	)		0		0		0		0
Narraguinnep (CO), sold in 2008		1.7		(1.7	)		0		0		0		0

Total unevaluated costs and acres	$	40.9		(9.0	)		31.9		533,383		474,060		258,969


*		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.

F-12

The 2008 $0.2 million increase in unevaluated costs in our Fetter project reflects $2.2 million of additions net of $2.0 million reclassified as evaluated costs (including $1.5 million relating to a small western portion of Fetter sold with West Douglas and Douglas acreage). We estimate that the remaining $14.7 million will be reclassified as evaluated costs as additional wells are drilled within the Fetter Project. The $14.7 million equates to a cost per net leased acre that is substantially below the value received for the far western portion sold in October.

The 2008 $0.7 million increase in unevaluated costs in our Goliath project relates to additional lease acquisition costs. The 2008 $2.5 million increase for the Bigfoot project was for acquisition of additional leases with minor costs to prepare for the drilling of several shallow gas wells in 2009. The 2008 $6.7 million decrease for the Krejci oil project were costs reclassified as evaluated costs, largely relating to three wells completed and tested in 2008. The 2008 $1.1 million increase in unevaluated costs for Other projects is for our costs in two Wyoming wells in which we hold minority working interests. Those two wells are unevaluated as of March 1, 2009.

In 2008, we capitalized to the full cost center, $96,000 as our internal geologist’s costs directly associated with acquired properties and $420,000 of internal land department costs directly associated with property acquisition, exploration (including lease record maintenance) and development. Capitalized land department costs are initially capitalized 1/12^th to evaluated costs and 11/12^th to unevaluated costs, with reclassification to evaluated made evenly over the subsequent eleven calendar quarters. In 2007 and 2006, capitalization of internal costs was insignificant.

Sales of Oil & Gas Properties

In October 2008, we sold for $26.4 million cash approximately 35,100 net acres of non-core unproved acreage and other unproved property, consisting of all our interests in a twelve township block that included our West Douglas project, the western edge of our Fetter project and other Douglas acreage not in the Fetter or West Douglas projects. Under the full cost accounting method, we recognized a $16,500,000 gain on the sale, by allocating cost to the properties sold based on their relative total fair value to the estimated fair value of the full cost pool immediately preceding the sale.

Under the full cost accounting method, gain on property sales is not recognized unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves of the cost center. Non-recognition of the $16.5 million gain would have reduced the amortization base to zero, significantly altering the relationship, whereby non-recognition was not allowed under full cost accounting. Since the properties sold had no proved reserves, and a significant portion of retained properties did, then under the full cost accounting method, the sale’s gain was based on allocating a portion of the US cost center’s capitalized costs to the properties sold based on the relative total fair value of the properties sold to the estimated total fair value of the US cost center’s properties immediately preceding the sale.

In September 2008, we sold for $5.3 million cash our interests in the Narraguinnep project in Colorado and credited the gain to the full cost pool since non-recognition of the gain did not significantly alter the relationship between capitalized costs and proved oil and gas reserves, with consideration that after impairment recognition, the capitalized costs at September 30, 2008 would be the same whether the gain was recognized or not.

F-13

Property Acquisition, Exploration and Development Costs

Information relating to the Company’s costs incurred in its oil and gas operations during the year ended December 31, 2008, 2007 and 2006 is summarized as follows:


	2008		2007		2006
Property acquisition costs, unproved properties	$	6,275,102	$	4,395,467	$	19,887,879
Property acquisition costs, proved properties		—		—		163,569
Exploration costs		13,563,077		11,364,497		9,285,354
Asset retirement costs		74,381		73,516		86,649
Development costs		3,042,469		—		691,626

	$	22,955,029	$	15,833,480	$	30,115,077

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.

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. Due to significant declines in oil and gas prices in the second half of 2008, along with unsuccessful exploration in the same six months, we recognized at September 30, 2008 and December 31, 2008 a total of $24,310,000 ($15.4 million, net of an $8.9 million increase in net deferred tax assets) in impairments of oil and gas properties. Other transactions, along with valuation allowances, reduced net deferred tax assets at December 31, 2008 to zero as further discussed in Note 7.

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.

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 2008, 2007 and 2006, the annual average amortization rates were $25.17, $25.21, and $22.01, respectively, per boe. After impairment recognition, the amortization rate at December 31, 2008 was $10.94 per boe of proved reserves.

F-14

The following table shows by type of asset the Depreciation, Depletion and Amortization (“DD&A”) expense for the years ended December 31, 2008, 2007 and 2006:


	2008		2007		2006
Amortization of costs for evaluated oil and gas properties	$	1,210,000	$	1,021,817	$	937,821
Depreciation of office equipment, furniture and software		75,772		65,225		35,412
Amortization of Other Intangible Asset (Note 6)		180,000		180,000		180,000

Total DD&A expense	$	1,465,772	$	1,267,042	$	1,153,233

The $1,210,000 amortization in 2008 reflects a reclassification of $840,000 from amortization expense (as reported at September 30, 2008) to property impairment expense, consistent with classification and computations in 2007 where quarterly amortization was computed after quarterly property impairment.

NOTE 4 — SHORT-TERM INVESTMENTS

Our short-term investments at December 31, 2008 were comprised of Auction Rate Preferred Shares (“ARPS”) and at December 31, 2007, were comprised of ARPS and unregistered shares of PetroHunter common stock.:


	As of December 31,
	2008		2007
ARPS at fair value	$	5,450,000	$	17,325,000
PetroHunter common stock (at fair value)		—		977,900

Total, short-term investments	$	5,450,000	$	18,302,900

At December 31, 2007, we owned 693 shares of Auction Rate Preferred stock ($17,325,000 total par value) in several closed-end taxable mutual funds. At that time, the ARPS could be readily sold at par value at auctions occurring every seven to twenty-eight days. Starting in mid February of 2008, the auctions failed, and ARPS are liquidated by either (a) redemption at par value at the option of the issuing fund, (b) purchase at par value by the broker, usually in a settlement with government agencies, or (c) sale in a secondary market at a discount to par value. During 2008, we acquired no additional ARPS, and we sold at our carrying cost (which was par value) $75,000 of ARPS and had redeemed $11,500,000 of ARPS at par value. We had no gain or loss on the sales or redemptions in 2008.

At December 31, 2008, our remaining ARPS had a total par value of $5,750,000, and are classified as available-for-sale under SFAS 115, whereby temporary unrealized gains and losses are recorded in accumulated other comprehensive income. Unrealized losses expected to be permanent are reflected in the consolidated statement of operations. Company management estimated the ARPS to have a fair value at December 31, 2008 of $5,450,000 and viewed the $300,000 loss as permanent, recognizing the loss in the consolidated statement of operations, based on management’s expectation that it would liquidate all of its ARPS before the end of 2009, with a significant portion being redeemed at par value and the remainder sold at a discount approximating the $300,000 loss.

The ARPS have a Triple-A credit rating and, under Federal law, must be redeemed by the fund to the extent the fund’s net assets have at the end of any month a fair value of less than 200% of the par value of the ARPS. For example, if a fund has net assets with a fair value of $192 million and ARPS with a $100 million par value, the fund could sell $10 million of asset to redeem $10 million of its ARPS so as to have $182 million of assets and $90 million of ARPS, restoring the asset coverage ratio to more than 200% of ARPS par value.

Management’s estimate of the ARPS’ fair value at December 31, 2008 considered several factors, particularly as to the likelihood and timing of future liquidity of such ARPS at par value. Such factors include the following:

•

Filings in 2008 by four Calamos closed-end funds (in which we hold $2,325,000 of ARPS) requesting the SEC to grant exemptive relief to allow the funds to use debt to redeem all remaining outstanding ARPS, particularly the amended filing of December 18, 2008 citing the October 23, 2008 SEC order granting exemptive relief in response to a very similar request by Eaton Vance closed-end funds,

•

Various other public statements in 2008 by Calamos management showing a goal and desire to provide remaining ARPS holders liquidity at par value as soon as possible,

•

Pre 12/31/08 announcements of the January 2, 2009 redemptions at par value of $175,000 of ARPS we held in funds other than the Calamos funds,

•

A third-party appraisal as to the December 15, 2008 fair value of approximately $3 million of the non-Calamos ARPS we held on December 15, 2008,

•

The Calamos amended filing of January 14, 2009, the February 10, 2009 SEC order granting the requested exemptive relief, and the February 13, 2009 Calamos statement regarding the SEC order, and

•

February 3 and 6, 2009 letters from the Securities Industry and Financial Markets Association (calling for federal assistance to allow ARPS, such as those we hold, to be liquidated at par value as soon as possible) sent to Federal Reserve Chairman Bernanke, to Treasury Secretary Geithner and to the Chairman of the US House of Representatives Committee on Financial Services.

F-15

At December 31, 2007, we owned 4,445,000 shares of PetroHunter common stock carried at a fair value of $977,900 ($0.22 per share). We sold those shares during the three-month period ended May 30, 2008 for a net realized loss of $369,172 before any related income tax benefit. We had no other gain or loss from sale of short-term investments in 2008.

Our $14,518 loss on sale of securities for the year ended December 31, 2007 related entirely to the sale of 1,900,000 shares of PetroHunter stock having a cost basis of $0.50 per share. In June 2007, we sold 1,400,000 shares for $808,059, realizing a gain of $108,059. We sold 500,000 shares in October 2007 for $127,423, realizing a loss of $122,577. During 2007, we sold at par value at no gain or loss $11,425,000 of auction rate preferred shares. During 2006, we had no sales of short-term investments.

NOTE 5 — FAIR VALUE MEASUREMENTS

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

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

•

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

•

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

•

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

At December 31, 2007, our financial assets measured at fair value consisted of $18,302,900 of short-term investments discussed in Note 4. Their fair values were based on Level 1 inputs. We had no financial liabilities at December 31, 2008, 2007 and 2006 carried at fair value. At December 31, 2008, our financial assets measured at fair value were as follows:


	Total at
	December 31,		Level 1		Level 2		Level 3
	2008		Inputs		inputs		inputs
Financial Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares (See Note 4)	$	5,450,000	$	—	$	—	$	5,450,000

The following table reflects the activity for financial assets measured at fair value using Level 3 inputs:


	2008		2007		2006
Beginning balance	$	—	$	—	$	—
Transfers in (out) of Level 3		5,750,000		—		—
Net purchases (sales)		—		—		—
Net decrease in value		300,000		—		—

Ending balance	$	5,450,000	$	—	$	—

F-16

The key Level 3 inputs as to the fair value of our ARPS at December 31, 2008 were as follows:

	•		Recognition that the ARPS we own pay dividends every 7 or 28 days at variable short-term rates that approximate 150% of 30-day LIBOR US rates,

	•		The assumption that the $2,325,000 of Calamos ARPS we owned would be redeemed at par value sometime in 2009 whereby their estimated fair value at December 31, 2009, was their $2,325,000 par value,

	•		The redemption of $125,000 of ARPS on January 2, 2009 at par value,

	•		The other ARPS ($3,300,000 par value) we owned at December 31, 2008 could be redeemed or sold at par value by 2011, and the expected future dividend rates (most set a premium or multiple of 30-day LIBOR or 30-day commercial paper) would increase from 1.28% at December 31, 2008 to approximately 3% to 4% on average prior to liquidity at par value, whereby their fair value at December 31, 2008 would approximate 90% of par value due to the expected inability to liquidate the ARPS at par value until 2011, offset in part by the dividend yield varying at a premium to benchmark rates of short-term instruments.

NOTE 6 — GOODWILL AND OTHER INTANGIBLE ASSET

In 2005 we recorded $11,670,468 of goodwill in the acquisition, by merger, of Tower Colombia Corporation (“TCC”). At December 31, 2008, we recognized an $11,670,468 full and permanent impairment of the goodwill in accordance with SFAS 142, Goodwill and Other Intangible Assets. The goodwill was not an asset for income tax reporting, and its impairment did not reduce income taxes or increase deferred tax 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. In 2005, 2006, and 2007 and in 2008 through September 30, 2008, the fair value of the Company’s outstanding preferred and common stock substantially exceeded the carrying value (i.e., book value) of stockholders’ equity for the Company, and no impairment of recorded goodwill existed prior to the three-month period ended December 31, 2008 under the accounting rules of SFAS 142. As of December 31, 2008, the fair value of the Company’s outstanding stock was substantially below the book value of stockholders’ equity, and further analysis indicated that goodwill was fully impaired whereby we recognized at December 31, 2008 a permanent impairment charge for the entire $11,670,468 of goodwill.

In the aforementioned 2005 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 continue to 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 7 — INCOME TAXES

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

F-17

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


	2008			2007			2006
Current taxes	$	244,000		$	—		$	—
Deferred taxes		(5,464,653	)		(1,484,984	)		303,748
Valuation allowance		4,752,308			—			—

Income tax expense (reduction)	$	(468,345	)	$	(1,484,984	)	$	303,748


Income (loss) before income taxes	$	(24,000,077	)	$	(4,228,366	)	$	1,514,971
Effective income tax rate		2.0	%		35.1	%		20.0	%

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


	2008			2007			2006
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
State income taxes		1.6	%		1.5	%		3.1	%
Permanent differences:
Goodwill impairment		(17.8	%)		—			—
Compensation using qualified stock options		(0.5	%)		(3.3	%)
Excess percentage depletion		2.0	%		1.5	%		(22.0	%)
Change in valuation allowance		(19.8	%)		—			—
Change in average state tax rate		0.0	%		0.3	%		(3.8	%)
Other		1.5	%		0.1	%		7.7	%

Effective income tax rate		2.0	%		35.1	%		20.0	%

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


	2008			2007			2006
Current deferred tax asset (liability):
Unrealized gain (loss) on short-term investments	$	109,749		$	347,658		$	(2,172,785	)
Less asset valuation allowance		(109,749	)		—			—

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


Long-term deferred tax assets (liabilities):
Deferred tax assets:
Oil & gas property costs’ tax basis in excess of basis for financial reporting	$	4,073,868		$	—		$	—
Oil and gas property amortization		51,373			454,771			753,000
Federal and state net operating loss carryovers		171,696			5,731,713			1,219,868
Compensation using non-qualified stock options and stock grants		364,887			341,452			118,369
Other		—			—			88,080

		4,661,824			6,527,936			2,179,317
Less: valuation allowance		(4,642,559	)		—			—

Long-term deferred tax asset	$	19,265		$	6,527,936		$	2,179,317


Deferred tax liabilities:
Oil and gas property costs’ carrying value for financial reporting in excess of tax basis	$	—		$	(7,572,033	)	$	(4,376,646	)
Other		(19,265	)		(15,906	)		—

Total long-term deferred tax liabilities		(19,265	)		(7,587,939	)		(4,376,646	)

Long-term deferred tax asset		19,265			6,527,936			2,179,317

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

F-18

At December 31, 2008, our oil and gas properties’ aggregate tax basis exceeded carrying value for financial reporting purposes (exclusive of accumulated depreciation, depletion and amortization) by approximately $11 million, resulting in a deferred tax asset of approximately $4.75 million. Tax basis can vary from financial reporting carrying value for many reasons, e.g., (a) tax law requires (and in some cases allows) capitalization of certain well costs that are expensed as impairments under full cost accounting, (b) tax law allows the immediate expensing of intangible well costs that are capitalized for financial reporting under full cost accounting and (c) financial reporting carrying value may reflect reductions for gains on property sales that are not recognized for financial reporting but are recognized for income tax reporting. Under full cost accounting, we recognized $16.5 million of gain on property sales in 2008, but we had $26.5 million in taxable gain for those same property sales.

The $171,696 deferred tax asset at December 31, 2008 relates to state net operating loss carryforwards. We currently expect to fully deduct in 2008 our $15.3 million of federal income tax net operating loss carryforwards and to deduct in 2008 approximately $1.3 million of excess percentage depletion (including $1 million carried forward from 2007). To do so, we plan to file our 2008 federal income tax return reflecting the allowed option to capitalize approximately $11.5 million of 2008 intangible drilling and completion costs. Due to the federal Alternative Minimum Tax and to tax law limitations on using net operating loss carryforwards and percentage depletion carryforwards, $10 million of such carryforwards can be less valuable than $10 million of future amortization of capitalized intangible costs.

For federal income tax purposes, exploration and production companies usually deduct when incurred all intangible costs of drilling and completing wells. However, such companies are allowed the annual option of capitalizing portions of such costs and amortizing the capitalized costs over sixty months or over oil and gas reserves. We anticipate that amortization of the $11.5 million of capitalized intangible costs will not significantly reduce future percentage depletion, which current tax law generally limits to the respective producing property’s income net of the amortization. We anticipate that any changes in the next few years in federal income tax law with regards to percentage depletion are likely to reduce the tax benefits of future percentage depletion.

We expect to file our 2008 federal income tax return in September 2009. At that time, we will have more information to consider as to the possible effects in 2009 and later years of capitalizing particular wells’ intangible costs in 2008, and we may choose to file the return with significantly less capitalization of 2008 intangible drilling costs, resulting in significantly greater net operating loss carryforward and percentage depletion carryforward at December 31, 2008. If we were to file the return with no capitalization of 2008 intangible drilling costs, we estimate that our income tax payments for 2008 would decrease by approximately $190,000 and our deferred tax assets before valuation allowance would decrease by approximately $450,000 and our percentage depletion carryforward at December 31, 2008 would increase by $1.3 million (equivalent to approximately $500,000 in potential tax benefits).

At December 31, 2008, we recognized valuation allowances reducing the carrying value of net deferred tax assets to zero. SFAS 109 provides that a valuation allowance is recognized if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In consideration of many factors, primarily the current depressed U.S. and world economies, the recent significant declines in oil and gas prices, the existing tax law allowing us future tax deductions in excess of actual costs (i.e., excess percentage depletion) and the inherent uncertainties of exploring for oil and gas, we recognized the valuation allowances. As circumstances change in the future, we may reduce deferred tax asset valuation allowances.

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 2004 for Colorado and for 2005 for all other returns. Income taxing authorities have conducted no formal examinations of our past federal and state income tax returns and supporting records, with the exception of the Utah State Tax Commission, which informed us on March 2, 2009 of its initiating examinations of our franchise tax returns for 2005, 2006 and 2007. We expect the Utah examination will result in little or no payments of penalties, interest and additional taxes.

F-19

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 or in 2008.

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 at December 31, 2007, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2008 since such adjustments would very likely simply reduce our net operating loss carryforwards.

NOTE 8 — SUPPLEMENTAL INFORMATION TO THE STATEMENTS OF CASH FLOWS


	2008		2007		2006
Supplemental Schedule of Cash Flow Information
Cash paid for interest expense	$	107,047	$	6,162	$	—
Cash paid for income taxes incurred	$	140,000	$	—	$	—

Supplemental Disclosures of Non-Cash Activities
Conversion of preferred stock into common stock	$	7,452,000	$	6,048,000	$	770,500
Share-based compensation expense	$	904,006	$	1,091,677	$	1,522,219
Preferred stock dividends paid in common stock	$	589,530	$	820,224	$	1,080,000
Net increase in payables for capital expenditures	$	2,200,387		134,807		—
Net drilling prepayments applied to incurred drilling costs	$	542,876		—		410,427
Common stock issued to acquire oil and gas properties	$	—	$	—	$	13,079,000
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	$	—
Warrant issued to acquire oil and gas properties	$	—	$	—	$	88,000

NOTE 9 — STOCKHOLDERS’ EQUITY

PREFERRED STOCK

We are authorized to issue up to 24.1 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.

Series A Convertible Preferred Stock

The 67,000 shares of Series A Convertible Preferred Stock issued in 2003 automatically converted into 670,000 shares of common stock in January 2005.

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”). Each share of Preferred Stock was convertible into nine shares of registered common stock for a total of 2,250,000 shares, which was a conversion rate of $6.00 per share. In 2007, 112,000 shares were converted into 1,008,000 shares of common stock. On July 22, 2008, the remaining 138,000 shares of Series AA Convertible Preferred Stock automatically converted into 1,242,000 shares of common stock.

F-20

We were obligated to pay an 8% annual dividend on the Preferred Stock, which at our discretion was paid in equivalent shares of common stock.

COMMON STOCK

Our Consolidated Statements of Shareholders’ Equity provides a listing of changes in the common shares outstanding from December 31, 2005 through December 31, 2008.

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 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 a Black-Scholes valuation model. We also issued in July 2005 placement warrants expiring on July 21, 2008, to purchase 281,250 shares of common stock at an exercise price of $6.00 per share. On June 30, 2008, we extended to June 30, 2009, the expiration dates of both the warrants for 675,000 shares and for 281,250 shares. Using a Black-Scholes valuation model, we estimated the fair value of the June 2008 extensions to be $300,000 and recognized in June 2008 a $300,000 deemed dividend for the warrant extensions

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

The table below reflects the status of warrants outstanding at December 31, 2008 held by others to acquire our common stock:

Common

Exercise

Expiration

Issue Date

Price

Date

April 16, 2008

50,000

7.00

April 16, 2013

July 22, 2005

835,626

6.00

September 30, 2009

885,626

At December 31, 2008 the per-share weighted average exercise price of outstanding warrants was $6.06 per share, and the weighted average remaining contractual life was 11.5 months.

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.

F-21

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 reserved 2,500,000 shares of common stock for issuance under the Plan. At December 31, 2008, 2007 and 2006, options to purchase 2,690 shares, 192,690 shares and 271,990 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, 2008, 2007 and 2006, options to purchase 649,400 shares, 981,400 shares and 1,500,000 shares, respectively, were available to be granted pursuant to the 2006 Plan.

Stock Options as of December 31, 2008

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.

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, 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
Options granted during 2008, excluding 11/5/08 option exchanges		640,000		$	3.38
Less options forfeited during 2008		(43,250	)	$	3.98
Less options expiring during 2008		(74,750	)	$	5.55
Options terminated in 11/5/2008 option exchanges		(1,768,000	)	$	4.49
Options granted in 11/5/2008 option exchanges		1,768,000		$	2.00

Options outstanding — December 31, 2008 (991,333 exercisable)		3,037,000		$	2.42

The weighted-average, grant-date estimated fair value of stock options granted during the years ended December 31, 2008, 2007 and 2006 were $0.68, $1.65, and $2.30, respectively, per underlying common share. We estimated the fair values using both the Black-Scholes stock option pricing model and a Modified Binomial model.

On November 5, 2008, our Board of Directors granted for twelve employees who are not members of the Board an exchange (or amendment) of their old stock options with an average exercise price of $4.47 for an equal number of new stock options with an exercise price of $2.00 per share. The closing price of our common stock on November 5, 2008 was $1.55 per share. The new stock options generally vest annually over the next five years of employment, and expire five years after vesting. The old stock options were 37% vested, with the remainder vesting on average within 2.5 years. The old options typically expired five years after vesting. The total future incremental compensation cost arising from the option exchange was $668,350, i.e., the difference between the $977,984 fair value of the new options and the $258,134 fair value of the old options on November 5, 2008.

F-22

Excluded from the exchanges were our outside directors, our CEO, our President, and two of our Vice Presidents. At December 31, 2008, those four senior officers each owned between 2% and 5.3% (and collectively owned 17.5 %) of our outstanding common stock.

The purpose of the option exchanges was to restore the employee stock option program’s value in retaining employees and in aligning employee interests with shareholder interests. The exchanges also provide a uniform exercise price for all employees hired in the past three years. While other companies’ option exchange programs in recent months have typically set the new options’ exercise price at the stock’s market price, the Board and management believed the interests of employees and shareholders would be best served with a $2.00 exercise price.

The following table presents additional information related to the stock options outstanding at December 31, 2008 under the 2004 Plan and 2006 Plan:


	Exercise		Remaining
	price		contractual		Number of shares
	per share		life (years)		Outstanding		Exercisable
	$	1.25		1.4		403,000		403,000
	$	2.00		8.0		1,768,000		0
	$	2.38		4.6		100,000		100,000
	$	3.29		6.3		100,000		25,000
	$	3.34		6.6		6,000		0
	$	3.37		5.3		30,000		0
	$	3.66		3.8		500,000		333,333
	$	6.03		4.1		130,000		130,000

						3,037,000		991,333

Weighted average exercise price per share					$	2.42	$	2.85
Weighted Ave. remaining contractual life					6.1 years		3.0 years
Aggregate intrinsic value, December 31, 2008					$	—	$	—

The total estimated unrecognized compensation cost from unvested stock options as of December 31, 2008 was $1,855,668, which is expected to be recognized over a weighted average period of approximately 2.9 years.

The following valuation models and key model assumptions were used for the significant options granted in 2008, 2007 and 2006:


	2008	2007	2006
Primary Model (Both Black-Scholes and modified binomial were used in	Modified	Modified	Black-
2008 and 2007.)	Binomial	Binomial	Scholes
Option life (in years)	4 to 5	4 to 5	5-8
Expected annual volatility over option life	45%	35%	33% to 63%
Risk-free interest rate	2.3% to 2.5%	4.7% to 5.1%	4.5% to 5.2%
Pre-vesting forfeiture rate	10% to 12%	0%	0%
Dividend yield	0%	0%	0%
Intrinsic Value /share that urges exercise	$2.00	$2.00 to $2.16	n/a for model

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

F-23

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

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

SHARE-BASED COMPENSATION EXPENSE

Stock options accounted for the majority of share-based compensation expense in 2008, 2007 and 2006:


	2008		2007		2006
Share-based compensation expense:
For stock option grants	$	735,286	$	914,300	$	1,230,788
For stock granted but in escrow or unvested		168,720		148,177		71,846
For stock granted with immediate vesting		—		29,200		219,585

Total	$	904,006	$	1,091,677	$	1,522,219

Total share-based compensation for income tax returns	$	17,720	$	771,424	$	52,700

We had granted 116,000 shares of common stock that were either held in escrow or not vested as of December 31, 2008. 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. At December 31, 2008, 16,000 shares were not vested.

	•		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.

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.

On January 14, 2009, we granted an aggregate of 427,500 shares of restricted common stock pursuant to the 2006 Stock Incentive Plan to certain employees, officers and directors of the Company. In February 2009 we issued 4,000 shares to a Vice President as granted in February 2007. These events increased to 48,307,399 the shares of the Company’s outstanding common stock and decreased to 217,900 the shares available under the 2006 Stock Incentive Plan.

NOTE 10 — 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, 2008, 2007 and 2006:


	2008			2007			2006
Net income (loss) to common stockholders	$	(24,159,614	)	$	(3,795,912	)	$	131,223
Adjustments for dilution		—			—			—

Net income (loss) adjusted for effects of dilution	$	(24,159,614	)	$	(3,795,912	)	$	131,223


Basic Weighted Ave. Common Shares		47,104,025			44,383,861			37,428,506
Add dilutive effects of options and warrants		—			—			713,505
Add dilutive effects of convertible preferred stock		—			—			—

Diluted Weighted Ave. Common Shares Outstanding		47,104,025			44,383,861			38,142,011


Net income per common share — basic	$	(0.51	)	$	(0.09	)	$	0.00
Net income per common share — diluted	$	(0.51	)	$	(0.09	)	$	0.00

F-24

NOTE 11 — 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 $370,513, $264,918 and $205,712 for the years ended December 31, 2008, 2007 and 2006, respectively.

NOTE 12 — RELATED PARTY TRANSACTIONS

We had no related party transactions in 2008 or in 2007. In 2006 we paid $58,907 to Tower Energy Corporation (“TEC”) for our share of administrative related expenditures, primarily the sharing of office space which TEC had leased. Our CEO Patrick O’Brien and our vice president Bob Solomon each own 50% of TEC.

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.

Under the participation agreement, the Company and North Finn each has the right (an option), during specified time periods, to trigger the transfer to us 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.

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.

F-25

Office Lease


	Annual Rental
Year	Amount
2009	$	260,837
2010	$	340,790
2011	$	347,020
2012	$	353,251
2013	$	148,270
Thereafter	$	—

Delay Rentals and Lease Extension Fees

In conjunction with the Company’s working interests in undeveloped oil and gas prospects, the Company typically must pay an annual delay rental during the primary term of each lease to keep the lease in effect during the primary term, absent drilling and production on the lease. Some of the leases have provisions at the option of the working interest owners to extend the primary term (generally from one to three years) by paying extension fees.

Our annual aggregate delay rentals and extension fees, if we desire to continue to keep all our leases in effect, are as follows:


	Delay		Extension
	Rentals		Fees		Total
2009	$	191,765	$	416,742	$	608,507
2010	$	194,358	$	133,385	$	327,743
2011	$	131,247	$	328,107	$	459,354
2012	$	79,335	$	29,314	$	108,649
2013	$	50,861	$	0	$	50,861
2014	$	39,015	$	15,300	$	54,315
Thereafter	$	70,860	$	0	$	70,860

The Company continually evaluates its leasehold interests, therefore certain leases may be abandoned by the Company in the normal course of business.

NOTE 14 — 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) (3), 17 CFR 210. 4-10(a)(3).

F-26

Estimated net quantities of proved developed and undeveloped reserves of oil and gas for the year ended December 31, 2008, 2007 and 2006 are presented in tables below.


December 31, 2008	Oil (BBLS)			NGL (BBLS)			Gas (MCF)
Beginning of year		96,399			53,933			1,307,159
Revisions of previous quantity estimates		(48,242	)		(43,832	)		(580,707	)
Extensions, discoveries and improved recoveries		46,674			7,221			556,652
Sales of reserves in place		—			—			—
Production		(19,221	)		(6,183	)		(136,030	)

End of year		75,610			11,139			1,147,074


Proved developed reserves at end of year		75,610			11,139			987,574

The majority of the reserve revisions are attributable to two Fetter gas wells drilled in the second half of 2007, which had high initial production rates in late 2007 but experienced production difficulties in the Spring of 2008 and had minimal estimated proved reserves at December 31, 2008. The downward revisions would also include loss of proved reserves due to the significantly lower oil and gas prices at December 31, 2008 compared with at December 31, 2007. The additions for extensions, discoveries and improved recoveries are largely attributable to (i) small working interests we have in four new North Dakota oil wells producing from the Bakken formation and (ii) 67% to 69.4% working interests we have in two gas wells drilled at Fetter in 2008.


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 were not separately estimated for proved reserves as of December 31, 2006.


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.

F-27

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.


	2008			2007			2006
Future cash inflows	$	8,102,093		$	19,840,019		$	10,421,519
Future costs:
Production		(3,156,973	)		(5,792,739	)		(3,276,852	)
Development		(269,420	)		(319,922	)		(716,000	)
Future income tax expense		(19,953	)		(101,000	)		(230,912	)

Future net cash flows		4,655,747			13,626,358			6,197,755
10% discount factor		(1,710,878	)		(5,321,559	)		(1,599,755	)

Standardized measure of discounted future net cash flows relating to proved reserves	$	2,944,869		$	8,304,799		$	4,598,000

The principal sources of changes in the standardized measure of discounted future net cash flows during the years ended December 31, 2008, 2007 and 2006 are as follows:


	2008			2007			2006
Beginning balance	$	8,304,799		$	4,598,000		$	13,709,930
Sales and transfers of oil and gas produced		(1,615,291	)		(1,310,508	)		(1,966,036	)
Net changes in prices and production costs		(2,970,196	)		1,228,973			(1,637,000	)
Sales of minerals in place		—			—			(10,800,000	)
Extensions and discoveries		2,055,573			4,549,423			3,814,000
Development costs incurred during the year		57,000			716,000			519,000
Changes in estimated future development costs		130,663			—			—
Revisions in previous quantity estimates		(3,754,276	)		(1,917,123	)		821,000
Accretion of discount		684,515			409,034			161,000
Change in income taxes		52,082			31,000			(6,200	)
Change in other		—			—			(17,694	)

Ending balance	$	2,944,869		$	8,304,799		$	4,598,000

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 Company’s proved oil and gas properties.

F-28

Standardized Measure Changes in 2008.

The $3.0 million decrease in the standardized measure due to changes in prices and production costs is largely due to the 2008 decline in oil, gas and NGL prices. The December 31, 2008 proved reserves reflected average oil, gas and NGL prices of $27.54/bbl, $5.04/mcf, $21.53/bbl as compared with $81.61/bbl, $6.38/mcf, and $67.38/bbl, respectively for proved reserves at December 31, 2007. The $3.0 million decrease is measured by the changes in prices and costs applied to the proved reserve quantities at December 31, 2008 and does not include any decrease for the reduction in proved reserves due to price declines (i) shortening the economic life of wells and (ii) eliminating proved undeveloped reserves where development is not economical at current prices.

The $2.0 million increase due to extensions and new discoveries is largely attributable to (i) small working interests we have in four new North Dakota oil wells producing from the Bakken formation and (ii) 67% to 69.4% working interests we have in two gas wells drilled at Fetter in 2008.

The $3.75 million decrease due to reserve revisions is largely attributable to (i) reserve reductions for two Fetter gas wells (the Hageman 16-34H-R and the Wallis 6-23) drilled in the second half of 2007, which had high initial production rates in late 2007 but experienced production difficulties in the Spring of 2008 and had minimal estimated proved reserves at December 31, 2008 and (ii) loss of some proved developed and undeveloped reserves due to the significantly lower oil and gas prices at December 31, 2008 compared with at December 31, 2007.

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 15 — SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)


2008	First			Second			Third			Fourth
Revenues	$	507,804			937,361			1,159,621			289,803
Income (loss) from operations	$	(1,498,768	)		(951,908	)		(19,333,989	)		(1,950,792	)
Net income (loss)	$	(1,320,425	)		(945,094	)		(12,780,287	)		(9,113,808	)
Earnings per common share:
Basic	$	(0.03	)		(0.02	)		(0.27	)		(0.19	)
Diluted	$	(0.03	)		(0.02	)		(0.27	)		(0.19	)


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	)

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-29

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, 2008 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, 2008, 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, 2008. 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, 2008, 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, 2008 as stated in their report included herein.

Changes in Internal Control over Financial Reporting

During 2008, 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.

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, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) 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 (c) 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, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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. and subsidiary as of December 31, 2008 and 2007 and the related consolidated statements of operations, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2008, and our report dated March 13, 2009 expressed an unqualified opinion.

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado
March 13, 2009

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, 2008) 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, 2008 and 2007		F-3
Consolidated Statements of Operations for years ended December 31, 2008, 2007 and 2006		F-4
Consolidated Statements of Cash Flows for years ended December 31, 2008, 2007 and 2006		F-5
Consolidated Statements of Stockholders’ Equity and Comprehensive Income for years ended December 31, 2008, 2007 and 2006		F-6
Notes to Consolidated Financial Statements		F-7 to F-29

(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	(i)	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. (Incorporated by reference from the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.)

	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)	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.)

	3	(iv)	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.)

	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.)


Exhibit No.			Description

	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.)

	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. (Incorporated by reference to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.)

	10	(xxv)	Letter Agreement dated August 22, 2008 for the property sale closed October 27, 2008. (Incorporated by reference to the Company’s Current Report on Form 8-K filed on October 28, 2008.)

	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

Exhibit Index


Exhibit No.			Description

	2	(i)	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. (Incorporated by reference from the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.)

	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)	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.)

	3	(iv)	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.)

	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. (Incorporated by reference to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.)

	10	(xxv)	Letter Agreement dated August 22, 2008 for the property sale closed October 27, 2008. (Incorporated by reference to the Company’s Current Report on Form 8-K filed on October 28, 2008.)

	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


	Page
PART I

Item 1: Business		4

Item 1A: Risk Factors		10

Item 1B: Unresolved Staff Comments		15

Item 2: Properties		15

Item 3: Legal Proceedings		20

Item 4: Submission of Matters to a Vote of Security Holders		20

PART II

Item 5: Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		21

Item 6: Selected Consolidated Financial Data		22

Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 7A: Quantitative and Qualitative Disclosures about Market Risk		35

Item 8: Financial Statements and Supplementary Data		F-1

Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		37

Item 9A: Controls and Procedures		37

Item 9B: Other Information		40

PART III

Item 10: Directors, Executive Officers and Corporate Governance		40

Item 11: Executive Compensation		40

Item 12: Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		40

Item 13: Certain Relationships and Related Transactions, and Director Independence		40

Item 14: Principal Accounting Fees and Services		40

PART IV

Item 15: Exhibits, Financial Statement Schedules		40

Exhibit 21(i)
Exhibit 23(i)
Exhibit 23(ii)
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


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


Signature	Title	Date

/s/ Patrick D. O’Brien Patrick D. O’Brien	Chief Executive Officer and Chairman (Principal Executive Officer)	March 13, 2009

/s/ Andrew P. Calerich Andrew P. Calerich	President and Director	March 13, 2009

/s/ Joseph B. Feiten Joseph B. Feiten	Chief Financial Officer (Principal Financial Officer)	March 13, 2009

/s/ Nick DeMare Nick DeMare	Director	March 13, 2009

/s/ C. Scott Hobbs Scott Hobbs	Director	March 13, 2009

/s/ Jon R. Whitney	Director	March 13, 2009
Jon R. Whitney


Subsidiary		State of Incorporation

Tower American Corporation		Colorado


/s/ Patrick D. O’Brien
Patrick D. O’Brien
Chief Executive Officer