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EX-31.2 - EXHIBIT 31.2 - AMERICAN OIL & GAS INCc97729exv31w2.htm
EX-99.1 - EXHIBIT 99.1 - AMERICAN OIL & GAS INCc97729exv99w1.htm
EX-32.1 - EXHIBIT 32.1 - AMERICAN OIL & GAS INCc97729exv32w1.htm
EX-32.2 - EXHIBIT 32.2 - AMERICAN OIL & GAS INCc97729exv32w2.htm
EX-31.1 - EXHIBIT 31.1 - AMERICAN OIL & GAS INCc97729exv31w1.htm
EX-21.(I) - EXHIBIT 21(I) - AMERICAN OIL & GAS INCc97729exv21wxiy.htm
EX-23.(I) - EXHIBIT 23.(I) - AMERICAN OIL & GAS INCc97729exv23wxiy.htm
EX-23.(II) - EXHIBIT 23.(II) - AMERICAN OIL & GAS INCc97729exv23wxiiy.htm
Table of Contents

 
 
UNITED STATES
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, 2009
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 001-31900
AMERICAN OIL & GAS INC.
(Exact name of registrant as specified in its charter)
     
Nevada
(State or other jurisdiction of
incorporation or organization)
  88-0451554
(I.R.S. Employer
Identification Number)
1050 17th 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 Amex (formerly the 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o Not required.
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 o   Non-accelerated filer þ   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, 2009 was $31,658,346. The number of shares of registrant’s common stock outstanding as of March 8, 2010 was 57,562,956 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, 2009, are incorporated by reference in Part III hereof.
 
 

 

 


 

AMERICAN OIL & GAS INC.
FORM 10-K
TABLE OF CONTENTS
         
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 Exhibit 21(i)
 Exhibit 23.(i)
 Exhibit 23.(ii)
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2
 Exhibit 99.1
As used in this document, “American”, “Company”, “we”, “us” and “our” refer to American Oil & Gas Inc. and its subsidiary.

 

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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 downturns, 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.

 

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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. We were incorporated in the State of Nevada on February 15, 2000.
Our management team has focused on building large acreage positions in the Rocky Mountain region and performing initial drilling and completion activities in an attempt to establish commercial production in these areas. We anticipate we may need to drill multiple uneconomic wells to understand the best way to drill, complete and stimulate wells and establish commercial production. In order to reduce or eliminate our financial exposure in early drilling, we typically use industry joint venture relationships and allow other companies to pay for all or a disproportionate share of initial drilling costs in return for an ownership position in these areas. We have also, at times, sold out of our ownership in certain areas in order to redeploy capital into project areas that we feel offer a better risk-to-reward profile.
In conjunction with the strategy, we signed a letter of intent in February 2010 to sell our acreage positions (approximately 97,000 net acres in 170,000 gross acres), including productive and non-productive wellbores, in the Powder River Basin of Wyoming (areas we call Fetter and Krejci). We expect to close on this sale by March 31, 2010 and to receive approximately $44 million.
Currently, in addition to the Power River Basin acreage expected to be sold shortly, we control the following:
   
Approximately 111,000 gross (76,000 net) acres in our Goliath Project, located in the Williston Basin, North Dakota and
   
Approximately 213,000 gross (131,000 net) acres in our Bigfoot Project, located in the U.S. Rocky Mountain area.
Our proved oil and gas reserves are summarized in Item 2 Properties of this Annual Report on Form 10-K.
We are now devoting much of our human and financial resources in the Williston Basin of North Dakota, where we are focusing on the potential for production from the Bakken and Three Forks formations in the Goliath project area. We have been managing this project since October 2005, when we made our initial acreage acquisition of approximately 25,000 net acres. Through continued leasing, and three separate transactions in late 2009, we now control approximately 76,000 net acres in the Goliath project.
Our 76,000 net acre position is expected to be reduced by approximately 7,500 net acres through a joint venture agreement with another company that agreed to pay 100% of the cost to drill, complete, stimulate and equip an approximate 20,000’ total measured depth Bakken well at Goliath. As of March 14, 2010, this well has been drilled, completed and recently fracture stimulated, and in a few days we should have initial production rates. Additional drilling is underway at Goliath, as we continue to evaluate the area for commercial production.
We have attempted to retain a strong balance sheet, and at December 31, 2009, we had over $40 million in cash and no debt.
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.

 

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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.
Customers
The table below shows for the calendar years 2009, 2008 and 2007 the percentages of our oil and gas revenues for major customers, i.e., those who each account for more than 10% of the year’s oil and gas sales:
                         
Major Customers   2009     2008     2007  
DCP Midstream LLC
    38 %     31 %     36 %
Wyoming Refining Company
    23 %     15 %     13 %
Shell Trading (US) Company
    10 %     17 %     19 %
Nexen Marketing U.S.A., Inc.
                    13 %
 
                 
Total
    71 %     63 %     81 %
 
                 
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.
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.

 

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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 (“EPA”) and various state agencies continue to promulgate regulations that limit the disposal and permitting options for certain hazardous and non-hazardous wastes.
The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Senate has not passed proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily carbon dioxide emissions from power plants. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could impact our future operations. Our operations are not currently adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. However, future laws or regulations could result in substantial expenditures or reduced demand for oil or natural gas.
The federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. EPA has recently deemed carbon dioxide (“CO2”) to be a public danger which presumably will lead to regulation in a manner similar to other pollutants. EPA has recently initiated rulemaking for inventory of CO2 and other greenhouse gases. 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.

 

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Seasonality
Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and warmer summer months but decrease during the spring and fall months (“shoulder months”). Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter and summer requirements during the shoulder months, which can lessen seasonal demand fluctuations.
Employees
At December 31, 2009, 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 17th 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.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
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. A working interest in the drilling and/or completion of well(s) for which the owner (the carried party) has another party (the carrying party) not owning the working interest paying the working interest’s portion of specified drilling and/or completion costs, pursuant to a prior agreement between the carried and carrying parties. Such an agreement might provide that the carrying party receive from the carried party working interest(s) in other undrilled acreage in consideration for paying the carried party’s share of well drilling and completion costs.
Completion. The installation of permanent equipment for the production of oil or natural gas.

 

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Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
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.

 

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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.
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. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. Proved oil and gas reserves as defined by the SEC in SEC S-X Regulation 4-10(a), summarized as follows:
The estimated quantities of crude oil and natural gas (and, in some cases, natural gas liquids) which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (i) from a given date forward, from known reservoirs, and under existing economic and operating conditions, operating methods, and government regulations and (ii) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that contract renewal is reasonably certain. Effective for proved reserve estimates of a given date on or after December 31, 2009, existing economic conditions with regards to a crude oil or natural gas selling price is the average price during the twelve-month period prior to the given date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. For proved reserve of a given date prior to December 31, 2009, the assumed future crude oil or natural gas selling price is the spot price at the given date unless such price was defined by contractual arrangements, excluding escalations based upon future 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.

 

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Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
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
SEC Definition of Proved Reserves. See above the definition of Proved Reserves.
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. 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. Our business operations could also be affected by additional factors that apply to all companies operating in the United States and globally, as well as other risks that are not presently known to us or that we currently consider to be immaterial to our operations. 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.

 

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Risks related to our industry, business and strategy
We have incurred losses from operations in the past and may do so in the future.
We incurred a net loss in 2007, 2008 and 2009. Our future financial results depend primarily on our ability to discover commercial quantities of oil and gas and to 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 fluctuated in the two years ended December 31, 2009. Price declines or sustained periods of relatively low prices in the Rocky Mountain region of the United States 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. Oil and natural gas prices are volatile and have substantially fluctuated in the two years ended December 31, 2009. 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. Price declines or sustained periods of relatively low prices in the Rocky Mountain region of the United States could significantly affect our future financial results and impede our growth.
Our operations are subject to governmental risks that may impact our operations.
Our operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:
   
Climate-Change Legislation. Climate-change legislation establishing a “cap-and-trade” plan for green-house gases (GHGs) has been approved by the U.S. House of Representatives. It is not possible at this time to predict whether or when the U.S. Senate may act on climate-change legislation.
   
EPA Regulation of GHG emissions. The U.S. Environmental Protection Agency (EPA) has also taken recent action related to GHGs. Based on recent developments; the EPA now purports to have a basis to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act.

 

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Tax Legislation. 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. The U.S. President’s Fiscal Year 2011 Budget Proposal includes provisions that would, if enacted, make significant changes to United States tax laws. These changes include, but are not limited to (i) eliminating the immediate deduction for intangible drilling and development costs and (ii) eliminating the percentage depletion deduction. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to the laws could adversely affect our business and our financial results.
   
Federal Regulations regarding Hydraulic Fracturing. The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.
   
Federal Legislation regarding derivatives. The U.S. Congress is currently considering derivatives reform legislation focusing on expanding Federal regulation surrounding the use of financial derivative instruments, including credit default swaps, commodity derivatives and other over-the-counter derivatives. Among the recommendations included in the proposals are the requirements for centralized clearing or settling of such derivatives as well as the expansion of collateral margin requirements for certain derivative market participants.
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 expect to finance our known capital expenditures for 2010 primarily with existing capital and with proceeds from the expected sale of our Fetter and Krejci properties. 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 2008 and 2009, 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.

 

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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.
Our leases may expire before we are able to dill.
Typically, we own the rights to drill for oil and natural gas by leasing these rights from the mineral owners. All of our leases have lease expiration deadlines and to the extent we do not drill or extend these leases, they will expire and we will no longer own the rights to drill for and produce hydrocarbons.
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. Government concerns of major global climate change and 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.
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.

 

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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.
The current global and US economic and financial recessions may have impacts on our business and financial condition that we currently cannot predict.
The global and US economic recessions, credit crisis and related turmoil in national and global financial systems that begin in 2008 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 adversely affected US oil and gas producers including us.
Uncertainties as to the extent, duration and impacts of the global and US recessions increase uncertainties and risks for us. With the general economic and financial crises, (i) our ability to access capital markets 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.
Risks Related to our Common Stock
Our common stock has historically been thinly traded, so investors may not be able to sell any significant number of shares of our stock at prevailing market prices.
Although the average daily trading volume of our common stock was approximately 840,000 shares per trading day over the 90-day period ended March 4, 2010, there is no assurance that the average daily volume will remain at this level. If limited trading of our stock returns, it may be difficult for investors to sell their shares in the public market at any given time at prevailing prices.

 

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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 or failure 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 upon 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.

 

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Item 2: Properties
Oil and Natural Gas Assets
Goliath Bakken and Three Forks Project (Williston Basin, North Dakota)
Our operations are focused primarily in our Goliath Project. Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are targeting both the middle member of the Bakken formation and the Three Forks formation in the North Dakota portion of the Williston Basin. Through three separate transactions in 2009, we now control approximately 76,000 net (111,000 gross) acres in the Goliath project.
The Williston Basin has become one of the most actively drilled basins in the continental United States. Recent advancements in drilling, completion and stimulation technologies used by other operators have resulted in commercially successful Bakken and Three Forks wells. We have recently commenced drilling operations that utilize these advanced technologies.
In December 2009, we commenced drilling the Tong Trust 1-20H well pursuant to a participation agreement with Halliburton Energy Services, Inc. (“Halliburton”), which has extensive experience in Bakken and Three Forks drilling and completion activities. Pursuant to the agreement, Halliburton has the opportunity to earn 25% of our working interest in an approximate 26,400 net acre portion of Goliath by funding 100% of our interest in a one well drill-to-earn arrangement. We are carried for and will retain 30% of our original interest in the well and the drill site spacing unit. Halliburton will also pay us up to an additional $1.1 million as part of the agreement. The Tong Trust was drilled and very recently underwent a 25-stage fracture stimulation treatment. We expect results of fracture stimulation treatment to be available by the end of March, 2010.
In February 2010, we commenced drilling the Ron Viall 1-25H well at Goliath, and we expect results from this well could be available in mid to late April, 2010. We have contracted the drilling rig that drilled the Tong Trust and Ron Viall wells for an additional five-well program, and we expect to retain the rig for more drilling, if we are successful in establishing commercial production from this initial program.
Although the majority of acreage we control in the Williston Basin is located in and around our Goliath project in Williams County, we own a small number of leases in other areas of the Basin. Occasionally, we will participate in wells that we will drill or that will be drilled by other operators. For example, on March 10, 2010, we began drilling the Summerfield 15-15H well in Dunn County, ND. We have agreed to retain the rig used to drill the Summerfield well for at least two additional wells within our core Goliath project acreage after drilling of the Summerfield well is completed.
Our base case drilling program for 2010, beyond the Tong Trust and Ron Viall wells, at Goliath includes drilling up to seven gross (approximately five net) wells.
Bigfoot Project (Rocky Mountain Region)
We currently control approximately 213,000 gross (131,000 net) acres in a project that we call Bigfoot. This is a shallow natural gas project located in the Rocky Mountain region. We are primarily targeting a formation that is less that 2,000’ deep and have drilled a series of test wells for less than $100,000 per well. We expect to continue to drill test wells as we evaluate the commercial viability of this area.
Fetter and Krejci Projects (Powder River Basin in Wyoming)
At December 31, 2009, we controlled approximately 170,000 gross (97,000 net) acres in properties expected to be sold by March 31, 2010, pursuant to a letter of intent signed in February 2010. Substantially all of these properties are in our Fetter Project and Krejci Project.

 

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Oil and Gas Reserves
Proved Oil and Gas 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, 2009, 2008, and 2007 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 and as further discussed in the Ryder Scott report, Exhibit 99.1 to this filing:
                         
    At December 31,  
(All of our proved reserves are in the United States)   2009     2008     2007  
Proved Developed Oil and Gas Reserves:
                       
Oil reserves (bbls)
    64,418       75,610       91,106  
NGL reserves (bbls)
    *     11,139       53,933  
Natural gas reserves (mcf)
    645,308       987,574       1,277,755  
Total proved developed (boe, at 6 mcf per barrel)
    171,969       251,345       357,998  
Proved Undeveloped Oil and Gas Reserves:
                       
Oil reserves (bbls)
    83,092             5,293  
NGL reserves (bbls)
    *            
Natural gas reserves (mcf)
    311,242       159,500       29,404  
Total proved undeveloped (boe, at 6 mcf per barrel)
    134,966       26,583       10,194  
Total Proved Oil and Gas Reserves:
                       
Oil reserves (bbls)
    147,510       75,610       96,399  
NGL reserves (bbls)
    *     11,139       53,933  
Natural gas reserves (mcf)
    956,550       1,147,074       1,307,159  
Total proved (boe, at 6 mcf per barrel)
    306,935       277,928       368,192  
Future net cash flows (before income taxes)
  $ 4,552,487     $ 4,675,700     $ 13,727,358  
PV-10 Value
  $ 2,485,018     $ 2,950,787     $ 8,362,799  
     
*  
At December 31, 2009, NGL (i.e., natural gas liquids) estimated to be recovered from the produced natural gas were not separately estimated by Ryder Scott since Ryder Scott’s estimates of proved natural gas reserves at December 31, 2009 are estimated gas volumes expected to be sold prior to gas processing for extraction of the natural gas liquids.
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 31st date for 2009, 2008 and 2007, except that, consistent with new SEC rules, for December 31, 2009 future oil and gas prices reflect a simple average of prices for the well or property on the first day of the twelve months in the calendar year 2009.
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.
Probable and Possible Reserves
New SEC Rules allow for certain disclosures of estimated probable and possible reserves starting as of December 31, 2009. We have not prepared such estimates as of December 31, 2009 nor engaged an independent petroleum engineering firm to estimate probable or possible reserves.

 

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Internal Controls over Reserve Estimation
Since we began oil and gas activity in 2003, our proved reserves at December 31st have been estimated by Ryder Scott Company, one of the largest and oldest independent petroleum engineering firms in the United States. For the company’s estimation procedures, credentials and statement of independence, see the Ryder Scott report filed herein as Exhibit 99.1.
Bob Solomon, a company vice president since April 2005, provides company data (such as well ownership interest, oil and gas prices received, and well operating costs) to Ryder Scott and is the primary company employee responsible for reviewing Ryder Scott use of our data and Ryder Scott estimation of our reserves. Mr. Solomon has over thirty years experience in the U.S. oil and gas exploration and production industry. He has an MBA from Stanford and a bachelor’s degree in industrial engineering from the Georgia Institute of Technology. Bob Solomon and our CEO Pat O’Brien have worked together since 1980 and co-founded three privately held petroleum companies. Mr. Solomon prepares our internal quarterly reserve estimates for our financial statements filed on Form 10-Q. His internal reserve estimate and the Ryder Scott reserve estimates are subject to review by Mr. O’Brien and our Manager of Operations, each of whom have petroleum engineering degrees and over thirty years of experience in the oil and gas industry.
Our CFO, Joe Feiten, reviews the company data provided to Ryder Scott and reviews with Mr. Solomon the preliminary Ryder Scott reserve estimates and the financial inputs reflected in the estimates. Mr. Feiten calculates the disclosed changes in reserve estimates and the disclosed changes in the Standardized Measure relating to proved oil and gas reserves. Mr. Feiten has over thirty years experience in oil and gas accounting, with several years working with petroleum engineers with regards to the estimation and auditing of proved reserves. He served in 1988 and 1989 as the co-director of the petroleum engineering consulting group at Coopers & Lybrand, which merged with Price Waterhouse in 1998. From 1991 to 1998, all Coopers & Lybrand petroleum engineering reports were required to be reviewed by Mr. Feiten prior to release. Mr. Feiten oversaw development of Coopers & Lybrand’s software for calculating changes in standardized measure and changes in proved reserves.
Our company codes of business conduct and ethics, as well as our employee hotline, are three general internal controls for preventing and detecting errors or fraud by our employees responsible for the reserve estimation procedures and disclosure in our filings with the SEC.
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 relating to proved oil and gas reserves. 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,  
    2009     2008     2007  
Standardized measure of discounted future net cash flows
  $ 2,477,866     $ 2,944,869     $ 8,304,799  
Add present value of future income tax discounted at 10%
    7,152       5,918       58,000  
 
                 
PV-10 Value
  $ 2,485,018     $ 2,950,787     $ 8,362,799  
 
                 

 

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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, 2009, other than the approximate 97,000 net acres being sold in March 2010. See the glossary in Item 1 for the meaning of the terms gross acres, net acres, developed acreage and undeveloped acreage.
Approximate Acreage at December 31, 2009, other than the 97,000 net acres
(primarily Fetter and Krejci projects) to be sold in March 2010
                                                 
    Developed Acres     Undeveloped Acres     Total Acres  
Project   Gross     Net     Gross     Net     Gross     Net  
Goliath (North Dakota)*
    3,000       1,000       106,000       73,000       109,000       74,000  
Bigfoot (U.S. Rocky Mountain area)**
                213,000       131,000       213,000       131,000  
Other (WY, ND)
    2,000       600       21,000       12,000       23,000       12,600  
 
                                   
Total
    5,000       1,600       340,000       216,000       345,000       217,600  
 
                                   
For properties not being sold in March 2010, 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 not held by production  
    Year of     Fee     State     Federal     Total for  
    Expiration     Leases     Leases     Leases     All Leases  
Goliath (North Dakota)*
    2010       17,555       2,243             19,798  
 
    2011       16,215                   16,215  
 
    2012       173                   173  
 
    2013       2,499                   2,499  
 
  Later       32,578       1,728       172       34,478  
 
                               
Total Goliath
            69,020       3,971       172       73,163  
 
                               
 
                                       
BigFoot**
    2010       235       1,959             2,194  
 
    2011       3,276                   3,276  
 
    2012       9,659       37,918             47,577  
 
    2013       2,015       21,169             23,184  
 
  Later       53,049       240       1,644       54,933  
 
                               
Total BigFoot
            68,234       61,286       1,644       131,164  
 
                               
 
                                       
Other (WY & ND)
  After 2013       113             11,456       11,569  
 
                               
 
                                       
Total of the above
            137,367       65,257       13,272       215,896  
 
                                 
 
                                       
Other undeveloped and rounding
                                    104  
 
                                     
Total undeveloped
                                    216,000  
 
                                     

 

*The Goliath net acreage totals do not include approximately 1,800 gross (1,350 net) acres from the State of North Dakota lease sale subsequent to December 31, 2009. As of February 5, 2010, our total Goliath net acres approximate 76,000 net acres.
** BigFoot acreage totals do not include approximately 19,000 gross (14,500 net) acres that are Federal leases pending issuance.
The types of leases represented in this table are comprised of approximately 2,500 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.

 

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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% to 16.67%. 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. In some cases before the fee lease expires, we have negotiated extensions in the form of a new fee lease upon expiration of the old fee lease. 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 absent well production, are as follows:
                         
    Delay     Extension        
    Rentals     Fees     Total  
2010
  $ 121,513     $ 6,560,031     $ 6,681,544  
2011
  $ 74,464     $ 588,553     $ 663,017  
2012
  $ 32,827     $ 284,307     $ 317,134  
2013
  $ 10,565     $ 29,557     $ 40,122  
2014
  $ 10,325     $     $ 10,325  
2015
  $ 10,325     $ 68,222     $ 78,547  
2016
  $ 5,085     $     $ 5,085  
Thereafter
  $ 1,043     $     $ 1,043  
Production Sales Volumes, Sales Prices and Production Costs
Our company’s oil and gas production and proved reserves are located solely in the United States. The table below summarizes our oil and gas production, average sales price and average production costs per barrel of oil equivalent for the three most recent fiscal years, in total for the Company and separately for each of the two fields containing more than 15% of our proved reserves at December 31, 2009. The two fields were the Fetter field in Converse County, Wyoming, and the Bear Creek field in Dunn County, North Dakota, in which we had 23% and 28%, respectively, of our proved reserves at December 31, 2009.
The following table summarizes our net natural gas and oil production sales volumes, our average sales prices and operating expenses for the periods indicated. Our production is attributable to our direct interests in producing properties after deducting royalty interests and similar interests. The lease operating expenses shown relate to our net production.
                         
    Year Ended December 31,  
For the Company in Total   2009     2008     2007  
Our Share of Produced Volumes Sold:
                       
Natural gas (MMcf)
    222.6       173.1       139.6  
Oil (Bbls)
    20,026       19,221       17,267  
Total equivalents barrels (boe, 6 mcf = 1 boe)
    57,120       48,076       40,532  
Average Sales Price Per Unit:
                       
Natural gas (per Mcf)
  $ 3.72     $ 7.06     $ 6.09  
Oil (per Bbl)
  $ 52.75     $ 86.96     $ 64.11  
Weighted average (per Boe)
  $ 33.00     $ 60.21     $ 48.27  
Lease Operating Expenses (per Boe):
                       
Production and ad valorem taxes per BOE
  $ 3.82     $ 6.60     $ 5.50  
Other lease operating expenses per BOE
  $ 15.20     $ 20.00     $ 10.44  
Total lease operating expenses per BOE
  $ 19.02     $ 26.60     $ 15.94  

 

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    Year Ended December 31,  
For the Fetter Field   2009     2008     2007  
Our Share of Produced Volumes Sold:
                       
Natural gas (MMcf)
    195.0       131.8       109.2  
Oil (Bbls)
    8,084       4,996       5,317  
Total equivalents barrels (boe, 6 mcf = 1 boe)
    40,576       26,969       23,521  
Average Sales Price Per Unit:
                       
Natural gas (per Mcf)
  $ 3.63     $ 6.51     $ 6.28  
Oil (per Bbl)
  $ 51.62     $ 80.90     $ 64.87  
Weighted average (per Boe)
  $ 27.70     $ 46.80     $ 43.80  
Lease Operating Expenses (per Boe):
                       
Production and ad valorem taxes per BOE
  $ 3.37     $ 5.49     $ 5.09  
Other lease operating expenses per BOE
  $ 12.16     $ 12.62     $ 5.27  
Total lease operating expenses per BOE
  $ 15.53     $ 18.11     $ 10.36  
For the Bear Creek field, we had no share of production from that field in the three years ended December 31, 2009 and our proved reserves are undeveloped.
Oil and Gas Drilling Activities
During 2009, we drilled eleven gross (8.25 net) shallow gas wells at Bigfoot, acquired interests in ten gross (0.6 net) wells previously drilled at Goliath and sold interests in three gross (1 net) wells previously drilled at Goliath. In early 2009, we completed and placed on production the Sims 7-25 well (.69 net) at Fetter. In the fourth quarter of 2009, Halliburton Energy Services, Inc. (“Halliburton”) paid for the re-completion and fracing of the Niobrara formation in five wells at Fetter, earning a limited 80% net profit interest in the five wells’ oil production from the Niobrara.
In December 2009, we began drilling the Tong Trust 1-20H well at Goliath, for which Halliburton is paying 100% of our 84.3% share of drilling, completion and fracing costs and receiving 70% of our share in revenues in the well, whereby we have a carried working interest of 25.3%. In early 2010, the Tong Trust 1-20H well was drilled 9,000 feet laterally through the Bakken formation. The well is scheduled to be fracture stimulated and completed in March 2010.
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 Viall #30-1 was completed in late February of 2009.
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) were not by year-end 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 had 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 (1.12 net) drilled outside our major projects.

 

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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, 2009.
                                                 
Productive Wells as of December 31, 2009  
    Gross (a)     Net (b)  
Location   Oil     Gas     Total     Oil     Gas     Total  
Wyoming*
    7       9       16       2.07       4.39       6.46  
North Dakota
    10       2       12       0.83       0.23       1.06  
 
                                   
Total
    17       11       28       2.90       4.62       7.52  
 
                                   
 
                                               
* WY wells to be sold in March 2010
    7       7       14       2.07       3.44       5.51  
     
(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.
Delivery Commitments
We have no commitments to provide a fixed and determinable quantity of oil or gas in the near future under existing contracts or agreements.
Office Facilities
In 2009 we were in a long-term lease of 12,461 square feet of office space at 1050 17th Street, Suite 2400, Denver, Colorado. 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:
         
    Annual Rental  
Year   Amount  
2010
  $ 340,790  
2011
  $ 347,020  
2012
  $ 353,251  
2013
  $ 148,270  
Thereafter
  $  
Item 3: Legal Proceedings
From time to time, we are involved in various legal proceedings, including the matter discussed below. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
On August 6, 2009, American filed with the Financial Industry Regulatory Authority (“FINRA”) a statement of claim against Jefferies & Company, Inc. (“Jefferies”), as American’s broker with regards to auction rate preferred shares discussed in Notes 5 and 6 of American’s financial statements contained in this Form 10-Q. The statement of claim seeks in arbitration to have Jefferies (i) purchase at par value American’s remaining unredeemed ARPS, (ii) reimburse American for consequential damages (approximating $130,000 to date) and for American’s legal costs in the arbitration and (iii) pay American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions.

 

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Item 4: [Reserved]
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 Amex 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  
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  
 
               
2009
               
Quarter ended March 31, 2009
  $ 1.15     $ 0.50  
Quarter ended June 30, 2009
  $ 1.59     $ 0.65  
Quarter ended September 30, 2009
  $ 2.05     $ 0.79  
Quarter ended December 31, 2009
  $ 4.50     $ 1.81  
On March 8, 2010, the closing sales price for our common stock as reported by NYSE Amex (formerly the American Stock Exchange) was $5.81 per share.
Holders
On March 8, 2010, there were approximately 52 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 2009.

 

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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 $2.75 per share on December 31, 2004, 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, 2004.
(PERFORMANCE GRAPH)
                         
            S&P Small Cap        
    AEZ     600 Energy     S&P 500  
12/31/2004
  $ 100.00     $ 100.00     $ 100.00  
12/31/2005
  $ 147.27     $ 152.17     $ 104.85  
12/31/2006
  $ 236.73     $ 179.00     $ 120.97  
12/31/2007
  $ 210.91     $ 220.90     $ 127.29  
12/31/2008
  $ 29.09     $ 119.23     $ 82.63  
12/31/2009
  $ 152.73     $ 195.43     $ 102.14  

 

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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 on Form 10-K. The selected financial data as of December 31, 2009, 2008, 2007, 2006 and 2005 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,  
    2009     2008     2007     2006     2005  
    (in thousands, except per share data)  
Statement of Operations Data:
                                       
Production Revenues
  $ 1,885     $ 2,895     $ 1,957     $ 2,257     $ 4,691  
Service fee and other revenues
                12       1,530        
Operating expenses:
                                       
Lease operating expenses
    1,086       1,279       646       291       246  
General and administrative
    5,271       4,372       4,308       4,009       2,032  
Depreciation, depletion and amortization
    971       1,466       1,267       1,153       1,532  
Accretion of asset retirement obligation
    40       33       24       11       6  
Property impairments
    4,500       24,310             4,360        
Inventory impairments
    566                          
Goodwill impairment
          11,670                    
 
                             
Total operating expenses
    12,434       43,130       6,245       9,824       3,816  
 
                             
Gain on sales of oil and gas properties
          16,500             7,159        
 
                             
Operating income (loss)
    (10,549 )     (23,735 )     (4,276 )     1,122       875  
Other income (expense)
                                       
Investment income
    58       511       1,021       393       204  
Loss on sale of securities
          (369 )     (15 )            
Impairment of securities investment
          (300 )     (952 )            
Interest expense
          (107 )     (6 )            
 
                             
Total other income (expense)
    58       (265 )     48       393       204  
 
                             
Income (loss) before income taxes
    (10,491 )     (24,000 )     (4,228 )     1,515       1,079  
Income tax benefit (provision)
    150       468       1,485       (304 )     (46 )
 
                             
Net Income (loss)
    (10,341 )     (23,532 )     (2,743 )     1,211       1,033  
Dividends on preferred stock
          (328 )     (603 )     (1,080 )     (479 )
Deemed dividends on warrant extensions
          (300 )     (450 )            
 
                             
Net Income (loss) attributable to common stockholders
  $ (10,341 )   $ (24,160 )   $ (3,796 )   $ 131     $ 554  
 
                             
Income (loss) per common share:
                                       
Basic
  $ (0.21 )   $ (0.51 )   $ (0.09 )   $ 0.00     $ 0.02  
Diluted
  $ (0.21 )   $ (0.51 )   $ (0.09 )   $ 0.00     $ 0.02  
Weighted average number of common shares outstanding:
                                       
Basic
    48,516       47,104       44,384       37,429       34,148  
Diluted
    48,516       47,104       44,384       38,142       34,956  

 

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    Year Ended December 31,  
    2009     2008     2007     2006     2005  
    (in thousands, except per share data)  
Selected Cash Flow and Other Financial Data:
                                       
Net income (loss)
  $ (10,341 )   $ (23,532 )   $ (2,743 )   $ 1,211     $ 1,033  
Less: gains on sales of oil and gas properties
          (16,500 )           (7,159 )      
Add back: Property impairments
    4,500       24,310             4,360        
Add back: Goodwill impairment
          11,670                    
Depreciation, depletion and amortization
    971       1,466       1,267       1,153       1,532  
Net loss on sales of securities
          369       15              
Other non-cash items
    1,075       525       582       308       466  
Changes in current assets and liabilities
    67       722       (292 )     1,496       (1,163 )
 
                             
Net cash provided (used) by operating activities
  $ (3,728 )   $ (2,414 )   $ (1,171 )   $ 1,369     $ 1,868  
 
                             
Cash provided (used) by:
                                       
Proceeds from sale of stock
  $ 31,500     $     $ 28,507     $     $ 13,500  
Purchases of short-term investments
  $     $     $ (28,750 )   $     $  
Sales/redemptions, short-term investments
  $ 2,600     $ 12,184     $ 12,361     $     $  
Capital expenditures
  $ (12,188 )   $ (20,640 )   $ (16,214 )   $ (16,152 )   $ (14,147 )
Sales of oil and gas properties
  $ 712     $ 31,695     $ 777     $ 16,067     $  
Short-term loans
  $     $ 10,925     $     $     $  
Repayment of short-term loans
  $     $ (10,925 )   $     $     $  
       
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 40,632     $ 23,270     $ 2,388     $ 7,488     $ 6,023  
Other current assets
    4,910       8,007       19,408       10,013       1,679  
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment
    38,945       35,660       53,402       38,869       24,921  
Other property and equipment, net of depreciation
    145       182       230       252       58  
Other assets
    140       270       12,663       12,514       13,094  
 
                             
Total assets
  $ 84,772     $ 67,389     $ 88,091     $ 69,136     $ 45,775  
 
                             
Current liabilities
  $ 1,032     $ 4,390     $ 1,831     $ 4,656     $ 1,434  
Long term liabilities
    437       431       1,383       2,392       2,010  
Stockholders’ equity
    83,303       62,568       84,877       62,088       42,331  
 
                             
Total liabilities and stockholders’ equity
  $ 84,772     $ 67,389     $ 88,091     $ 69,136     $ 45,775  
 
                             

 

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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 Rocky Mountain region of the United States. At December 31, 2009, we owned interests in approximately 514,000 gross (320,600 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 the Powder River Basin, our major projects are Fetter and Krejci. In the Williston Basin, our major project is Goliath, where we are drilling lateral wells to the Bakken and Three Forks oil formations. 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 expect to finance our known capital expenditures for 2010 primarily with existing capital and with proceeds from the expected sale, discussed below, of our Fetter and Krejci properties.
In order to retain a strong balance sheet, we have sold equity and used joint venture agreements with other industry companies to limit or eliminate our financial exposure in early drilling, and we have divested a portion or all of certain project areas for cash.
Subsequent to December 31, 2009, we signed a letter of intent to sell our ownership in our Fetter and Krejci projects, which includes both producing and non-producing well-bores and undeveloped acreage, for approximately $44 million in cash. This transaction, along with existing capital, should provide us with adequate capital to move forward with a base case drilling program through 2010. If we establish commercial production from the drilling program, we would expect to use cash flow from our newly producing wells to help fund drilling and completion of additional wells. We may desire to accelerate and expand the 2010 drilling program within our Goliath area. In so doing, we may need outside sources of funding.
Our base case drilling program for 2010 would include drilling within our Goliath area seven to nine gross (four to six net) wells at a net cost to us of as much as $40 million and drilling within our Bigfoot area six to ten gross (five to seven net) wells at a net cost to us of approximately $1 million dollars. We expect to spend in 2010 approximately ten million dollars in managing our Goliath acreage position.
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. In order to reduce capital exposure, we may also enter into additional joint venture agreements.
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.
Results of Operations
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
For the year ended December 31, 2009, we recorded a net loss attributable to common stockholders of $(10,341,380) [$(0.21) per common share, basic and diluted] for the year ended December 31, 2009, as compared to 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.

 

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Oil and Gas Operations
For 2009, we had total oil and gas revenues of $1,885,136 compared with $2,894,589 for 2008. Oil and gas sales and production costs for each year are summarized in the table that follows. Oil sales volumes increased in 2009 compared with 2008 due primarily to increased production from new North Dakota wells producing in the Bakken formation but in which we held small interests. Gas sales volumes increased in 2009 over 2008 largely due to production of new wells at Fetter completed in late 2008 and early 2009.
Oil and gas revenues decreased in 2009 compared with 2008 due to significant declines in both oil and gas prices since mid 2008, with substantial recovery by December 2009 of oil and gas prices, for our production. In the first quarter of 2009, our oil and gas production sold on average for $33.83/bbl and $3.46/mcf, respectively, whereas in the fourth quarter of 2009, average prices had risen to $66.62/bbl and $5.15/mcf, respectively.
                 
    Year Ended December 31,  
    2009     2008  
Oil sold (barrels)
    20,026       19,221  
Average oil price
  $ 52.75     $ 86.96  
 
           
Oil revenue
  $ 1,056,466     $ 1,671,451  
 
           
 
               
Gas sold (mcf)
    222,561       173,129  
Average gas price
  $ 3.72     $ 7.06  
 
           
Gas revenue
  $ 828,670     $ 1,223,138  
 
           
 
               
Total oil and gas revenues
  $ 1,885,136     $ 2,894,589  
Less lease operating expenses
    (1,086,539 )     (1,278,668 )
Less oil & gas amortization expense
    (714,000 )     (1,210,000 )
Less accretion of asset retirement obligations
    (39,873 )     (32,936 )
Less impairments of oil and gas properties
    (4,500,000 )     (24,310,000 )
Less impairments of materials and supplies inventories
    (565,991 )      
Plus gain on sale of oil and gas properties
          16,500,000  
 
           
Income (loss) from oil and gas operations
    (5,021,267 )     (7,437,015 )
Less general and administrative expenses
    (5,270,873 )     (4,372,202 )
Less intangible asset amortization
    (180,000 )     (180,000 )
Less depreciation of office facilities
    (76,968 )     (75,772 )
Less impairment of goodwill
          (11,670,468 )
 
           
Income (loss) from operations
  $ (10,549,108 )   $ (23,735,457 )
 
           
Total barrels of oil equivalent (“boe”) sold
    57,120       48,076  
Oil and gas revenue per boe sold
  $ 33.00     $ 60.21  
Lease operating expense per boe sold
  $ 19.02     $ 26.60  
Amortization expense per boe sold
  $ 12.50     $ 25.17  
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” as explained on page F-9 of this filing. 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. The $4,500,000 of impairments in 2009 includes $550,000 recorded at December 31, 2009. There would have been no impairment at December 31, 2009 if ceiling values had reflected oil and gas prices at December 31, 2009, rather than the new requirement of using twelve-month historical average prices.
In 2008, we recorded $24,310,000 of ceiling 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.

 

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Impairments of Materials and Supplies Inventories
Our materials and supplies inventory consists of our share of inventory of well casing and tubing, of which over 90% was purchased new by the Operator at Fetter in late 2008 and early 2009. We carry such inventory at the lower of cost or market value. At March 31, June 30 and September 30, 2009, we recognized a total of $565,991 of impairments for declines in market prices of such casing and tubing. At December 31, 2009, prices had substantially recovered, and the market value of our inventory of casing and tubing exceeded its carrying value by approximately $450,000. However, we do not recognize gains when market value of our inventory exceeds its carrying value.
General and Administrative Expenses
In 2009, general and administrative expenses of $5,270,873 exceeded that in 2008 by $898,671 or 21% due primarily to the following in 2009: (i) approximately $500,000 of costs relating to third-party financial advisory services, (ii) approximately $208,000 in net increases in personnel costs and (iii) approximately $128,000 in increased office rent following expansion of leased office space in mid 2009.
Other Income (Loss)
The table below summarizes the Other Income (Loss) section of our Consolidated Statements of Operations for the year ended December 31, 2009 and the year ended December 31, 2008:
                 
    2009     2008  
Investment income from auction rate preferred shares and cash sweeps
  $ 57,763     $ 511,599  
Recognized 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
    57,763       104,552  
Losses on unregistered PetroHunter common stock sold in 2008
          (369,172 )
 
           
Total other income (loss)
  $ 57,763     $ (264,620 )
 
           
Income Taxes
In September 2009, we recognized a $149,965 tax benefit relating to a partial refund of our federal income taxes paid earlier for 2008. Our 2009 provision for deferred income taxes is zero due to recognition of 100% valuation allowances against our net deferred tax assets of $4,642,559 at December 31, 2008 and $7,121,858 at December 31, 2009. 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 $7,121,858 valuation allowance would be correspondingly reduced and a deferred tax benefit recognized.
Dividends
We had no dividends in 2009. See the comparison below of 2008 dividends compared with 2007 dividends to understand the $627,882 of dividends in 2008.
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.

 

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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 asset retirement obligations
    (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.
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.

 

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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 ASC Topic 350, Intangibles — Goodwill and Others, as further explained in Note 2 of our consolidated financial statements contained in this Annual Report on 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.
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.
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 issued no preferred shares in 2009.

 

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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 2010 to be approximately $55 million. Approximately $41 million is allocated to our expected drilling and production activities; $10 million is allocated to land, and geological and geophysical activities; and $4 million relates to our general and administrative expenses (excluding share-based compensation). We expect to be able to fund these capital expenditures, other commitments and working capital requirements with existing capital, proceeds from the sale of Fetter and Krejci properties in late March 2010 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, 2009, we had cash and cash equivalents of $40.6 million consisting primarily of cash held in Wells Fargo bank accounts, as compared to $23.3 million at December 31, 2008. Working capital was $44.5 million as of December 31, 2009, as compared to $26.7 million at December 31, 2008. We expect to receive approximately $44 million in cash at the sale of our Fetter and Krejci properties. 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 sufficient capital as we may not be able to continue to drill all or some of our projects.
At December 31, 2009, we had $3,150,000 par value ($2,925,000 fair value) in short-term investments in Auction-Rate Preferred Stocks (ARPS) issued by five taxable US closed-end funds. These ARPS pay dividends every 7 or 28 days at variable rates that averaged approximately 0.8% per annum at December 31, 2009. 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.
On August 6, 2009, American filed with the Financial Industry Regulatory Authority (“FINRA”) a statement of claim against Jefferies & Company, Inc. (“Jefferies”), as American’s broker with regards to the ARPS. The statement of claim seeks in arbitration to have Jefferies (i) purchase at par value American’s remaining unredeemed ARPS, (ii) reimburse American for consequential damages (approximating $140,000 to date) and for American’s legal costs in the arbitration and (iii) pay American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions. The arbitration hearing is scheduled to take place in early December 2010.
Net Cash Used By Operating Activities
Cash flows used by operating activities were $3.7 million, $2.4 million and $1.2 million for the years ended December 31, 2009, 2008 and 2007, respectively. The additional $1.3 million in cash used in 2009 compared with 2008 is due primarily to (i) an approximate $1 million decline in revenues in 2009 compared with 2008, (ii) approximately $500,000 spent in 2009 relating to third-party financial advisory services and (iii) a $454,000 decline in investment income for 2009 compared with 2008 as short-term investments were converted to cash to pay for oil and gas property acquisition, exploration and development, offset by (iv) a $186,000 decline in cash paid for income taxes and (v) no interest expense in 2009 versus $107,000 of interest expense in 2008.

 

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The additional $1.2 million in cash outflow in 2008 compared with 2007 is due primarily to (i) $0.7 million in purchases of well casing and tubing inventory and (ii) 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.
Net Cash Used In Investing Activities
In 2009, investing activities used $8.9 million in cash. We received $2.6 million in redemptions of some ARPS at par value, and we received in December 2009 $0.7 million in cash as partial consideration for a third party to earn a 25% share of our working interests in a portion of our Goliath project acreage. We paid $12.1 million in 2009 for acquisition, exploration and development of oil and gas properties. The $12.1 million spent (including $4.1 million spent for costs incurred in 2008) compares with $9.3 million incurred in 2009. Note 3 to our consolidated financial statements contained in this Form 10-K provides further information as to how much was incurred by project and by type of activity (e.g., property acquisition, exploration or development).
In 2008, investing activities provided $23.2 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.
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. 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 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 that extended lease lives.
Net Cash Provided By Financing Activities
Our $30.0 million in cash provided by financing activity occurred in December 2009 with the sale of 9,000, 000 shares of our common stock at $3.50 per share, providing $29.6 million in cash after offering and issuance costs. In December 2009 we also received $0.33 million from limited exercises of employee stock options.
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.

 

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Contractual Obligations as of December 31, 2009
In addition to the $1,032,248 of current liabilities incurred as of December 31, 2009 as reflected on our consolidated balance sheet of that date, we have the following contractual obligations and commitments as of December 31, 2009:
                                 
    Payment due by period  
    Total     2010     2011-2013     After 2013  
Lease of office space
  1,189,331     340,790     848,541      
Asset retirement obligations
      (a)       (a)       (a)       (a)
Long-term Debt
                       
Capital lease obligations
                       
 
                       
Total
  $ 1,189,331     $ 340,790     $ 848,541     $  
 
                       
     
(a)  
The asset retirement obligations liability of $436,487 at December 31, 2009 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. Excluding the properties to be sold in March 2010, our estimated total asset retirement obligations at December 31, 2009, without reduction for equipment salvage value, is approximately $186,890 at current prices. The estimated timing of the $186,890 in payments is $0 in 2010, $80,683 in the three year period 2011 through 2013 and $106,207 after 2016. In many cases, timing will change as factors (such as future changes in oil and gas prices) change the economic lives of our wells.
FASB Codification Discussion
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 (commonly referred to as “GAAP”) have generally been set by the U.S. Financial Accounting Standards Board (commonly referred to as the “FASB”). In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principle, as codified in FASB ASC Topic 105, Generally Accepted Accounting Principles. This standard establishes two levels of U.S. GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (“the Codification” or “ASC”) became the source of authoritative, nongovernmental GAAP, except that financial accounting rules and interpretive releases of the SEC are additional sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became non-authoritative. The new authoritative guidance under ASC Topic 105 became effective for periods ending on or after September 15, 2009, and did not have a material impact on the Company’s consolidated financial statements.
Critical Accounting Policies and Estimates
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. The full cost method is allowed by the ASC but set forth in Rule 4-10 of SEC Regulation S-X, rather than in the ASC. 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.

 

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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 portions of 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. 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.

 

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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).
Recently Issued Accounting Pronouncements
FASB Codification. In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principle, as codified in FASB ASC Topic 105, Generally Accepted Accounting Principles. This standard establishes two levels of U.S. GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (“the Codification” or “ASC”) became the source of authoritative, nongovernmental GAAP, except that financial accounting rules and interpretive releases of the SEC are additional sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became non-authoritative. The new authoritative guidance under ASC Topic 105 became effective for periods ending on or after September 15, 2009, and did not have a material impact on our consolidated financial statements.
Oil and Gas Reserve Information. In December 2008 the SEC published final rules and interpretations updating its oil and gas reporting requirements. In October 2009, the SEC issued Staff Accounting Bulletin No. 113 (SAB No. 113), effective November 4, 2009, revising Staff Accounting Bulletin Series Topic 12 “Oil and Gas Producing Activities” primarily to conform Topic 12 to the aforementioned SEC updates to its oil and gas reporting requirements. Key changes to the SEC’s rules and interpretations include a requirement to use 12-month average pricing rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure (outside of the financial statements) of probable and possible reserves. The full-cost accounting method, which we follow, is changed to no longer allow the option of ceiling test impairments being reduced or eliminated by consideration of oil and gas price increases occurring subsequent to the impairment date. The FASB aligned ASC Topic 932, with the aforementioned SEC requirements by issuing ASC Update 2010-03.
The new SEC and FASB authoritative guidance became effective for our 2009 Annual Report on Form 10-K and has been prospectively adopted by us as of December 31, 2009. The new authoritative guidance did not have a material impact on our consolidated financial statements, except the new requirement to use 12-month average pricing rather than year-end pricing at December 31, 2009, resulted in a $550,000 impairment expense at December 31, 2009, compared with no such impairment expense using year-end pricing.
ASC Update 2010-06. In January 2010 the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures” (“ASC Update 2010-06”). It requires additional disclosures surrounding transfers in and out of Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3. This new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2009. We will apply the new authoritative guidance beginning with our Quarterly Report on Form 10-Q for the three-month period ending March 31, 2010.
ASC Update 2010-06 also requires that purchases, sales, issuances, and settlements for Level 3 measurements be disclosed. This portion of the new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2010. We will apply this new authoritative guidance beginning with our Quarterly Report on Form 10-Q for the three-month period ending March 31, 2011.

 

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We do not expect our adoption of ASC Update 2010-06 to have a material impact on our financial statements.
Fair Value Disclosures of Financial Instruments. New authoritative accounting guidance under FASB ASC Topic 825, Financial Instruments (“ASC Topic 825”) requires us to include disclosures about the fair value of our financial instruments whenever we issues financial information for interim reporting periods and annual reporting periods, whether recognized or not recognized in the consolidated balance sheets. The new ASC guidance became effective for us on April 1, 2009, and did not have a material impact on our consolidated financial statements.
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 and early 2009.
We expect oil and gas price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.
Operating Cost Risk
During 2008 and 2009, we have generally experienced fluctuations in operating costs (including costs of drilling and completing wells) which impact our cash flow from operating activities and profitability. We expect our drilling activity in 2010 to be focused on drilling oil wells with long laterals in the Bakken and/or Three Forks formations in North Dakota. Several other companies seek to drill similar wells in the general area in 2010 whereby drilling and operating costs may rise in response to demand for limited rigs and services in the North Dakota Bakken play.
Fluctuations in drilling costs and production costs, as well as fluctuations in oil and gas prices 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, 2009, we had no interest-bearing debt or credit facilities. Short-term interest rates were less than 1% per annum on our $40.6 million of cash and cash-equivalent investments at December 31, 2009. Short-term dividend rates on our $3,150,000 par value in Auction Rate Preferred Shares approximated 0.8% per annum and are at rates which vary with short-term commercial paper and US LIBOR rates. An increase in short-term interest rates would be favorable to us, increasing our investment income in proportion to our short-term investments and cash-equivalent investments.

 

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Item 8: Financial Statements and Supplementary Data
AMERICAN OIL & GAS INC.
INDEX TO FINANCIAL STATEMENTS

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
American Oil & Gas Inc.
We have audited the accompanying consolidated balance sheets of American Oil & Gas Inc. and subsidiary as of December 31, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
We were not engaged to examine management’s assessment of the effectiveness of American Oil & Gas Inc.’s internal control over financial reporting as of December 31, 2009, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, and, accordingly, we do not express an opinion thereon.
/s/ HEIN & ASSOCIATES LLP
Denver, Colorado
March 15, 2010

 

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AMERICAN OIL & GAS INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2009 AND 2008
                 
    2009     2008  
ASSETS
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 40,632,284     $ 23,269,725  
Short-term investments
    2,925,000       5,450,000  
Accounts receivable
    564,533       1,186,749  
Materials and supplies inventory
    1,269,774       1,236,591  
Prepaid expenses
    149,991       133,360  
Current deferred tax assets (net of valuation allowance, Note 6)
           
 
           
Total current assets
    45,541,582       31,276,425  
 
           
PROPERTY AND EQUIPMENT, AT COST
               
Oil and gas properties, full cost method (including unevaluated costs of $35,611,363 at 12/31/09 and $31,837,965 at 12/31/08)
    44,454,942       40,456,632  
Other property and equipment
    406,273       366,354  
 
           
Total property and equipment
    44,861,215       40,822,986  
Less accumulated depreciation, depletion and amortization
    (5,771,547 )     (4,980,578 )
 
           
Net property and equipment
    39,089,668       35,842,408  
 
           
OTHER LONG-TERM ASSETS
               
Deferred income tax assets (net of valuation allowance, Note 6)
           
Intangible asset (net of accumulated amortization, Note 2)
    60,000       240,000  
Other assets
    80,652       30,385  
 
           
 
  $ 84,771,902     $ 67,389,218  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
CURRENT LIABILITIES
               
Accounts payable and accrued liabilities
  $ 1,032,248     $ 4,286,618  
Income taxes payable
          104,000  
 
           
Total current liabilities
    1,032,248       4,390,618  
 
           
LONG-TERM LIABILITIES
               
Asset retirement obligations
    436,487       430,686  
Deferred income taxes
           
 
           
Total long-term liabilities
    436,487       430,686  
 
           
COMMITMENTS AND CONTINGENCIES (Note 13)
               
STOCKHOLDERS’ EQUITY
               
Preferred stock, $.001 par value, authorized 24,100,000 shares; no outstanding shares at 12/31/09 and 12/31/08
           
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding shares: 57,472,399 at 12/31/09 and 47,875,899 at 12/31/08
    57,472       47,876  
Additional paid-in capital
    122,267,594       91,275,557  
Accumulated deficit
    (39,096,899 )     (28,755,519 )
Accumulated other comprehensive income
    75,000        
 
           
Total equity
    83,303,167       62,567,914  
 
           
 
  $ 84,771,902     $ 67,389,218  
 
           
The accompanying notes are an integral part of the financial statements.

 

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AMERICAN OIL & GAS INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
                         
    2009     2008     2007  
REVENUES
                       
Oil and gas sales
  $ 1,885,136     $ 2,894,589     $ 1,956,508  
Other revenues
                12,000  
 
                 
Total revenues
    1,885,136       2,894,589       1,968,508  
 
                 
OPERATING EXPENSES
                       
Lease operating expenses
    1,086,539       1,278,668       646,000  
General and administrative
    5,270,873       4,372,202       4,307,997  
Depletion, depreciation and amortization
    970,968       1,465,772       1,267,042  
Accretion of asset retirement obligations
    39,873       32,936       23,767  
Impairments of oil and gas properties
    4,500,000       24,310,000        
Impairments of materials and supplies inventory
    565,991              
Impairment of goodwill
          11,670,468        
 
                 
Total operating expenses
    12,434,244       43,130,046       6,244,806  
 
                 
GAIN ON SALE OF OIL & GAS PROPERTIES
          16,500,000        
 
                 
LOSS FROM OPERATIONS
    (10,549,108 )     (23,735,457 )     (4,276,298 )
 
                 
 
                       
OTHER INCOME (LOSS)
                       
Investment income
    57,763       511,599       1,020,712  
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)
    57,763       (264,620 )     47,932  
 
                 
LOSS BEFORE INCOME TAXES
    (10,491,345 )     (24,000,077 )     (4,228,366 )
 
                 
Income tax expense — current
    (149,965 )     244,000        
Income tax expense (benefit) — deferred
          (712,345 )     (1,484,984 )
 
                 
Income tax provision (benefit)
    (149,965 )     (468,345 )     (1,484,984 )
 
                 
NET LOSS
    (10,341,380 )     (23,531,732 )     (2,743,382 )
Less dividends on preferred stock
          (327,882 )     (602,530 )
Less deemed dividends on warrant extensions
          (300,000 )     (450,000 )
 
                 
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
  $ (10,341,380 )   $ (24,159,614 )   $ (3,795,912 )
 
                 
 
                       
NET LOSS PER COMMON SHARE:
                       
Basic
  $ (0.21 )   $ (0.51 )   $ (0.09 )
Diluted
  $ (0.21 )   $ (0.51 )   $ (0.09 )
 
                       
Weighted average common shares outstanding:
                       
Basic
    48,516,065       47,104,025       44,383,861  
Diluted
    48,516,065       47,104,025       44,383,861  
The accompanying notes are an integral part of the financial statements.

 

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AMERICAN OIL & GAS INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
                         
    2009     2008     2007  
CASH FLOWS FROM OPERATING ACTIVITIES
                       
Net loss
  $ (10,341,380 )   $ (23,531,732 )   $ (2,743,382 )
Adjustments to reconcile net loss to net cash provided (used) by operating activities:
                       
Impairments of oil and gas properties
    4,500,000       24,310,000        
Share-based compensation
    1,036,149       904,006       1,091,677  
Depletion, depreciation and amortization
    970,968       1,465,772       1,267,042  
Impairments of materials and supplies inventory
    565,991              
Accretion of asset retirement obligations
    39,873       32,936       23,767  
Gain on sales of oil and gas properties
          (16,500,000 )      
Impairment of goodwill
          11,670,468        
Deferred income taxes
          (712,345 )     (1,484,984 )
Unrealized loss on investment in securities
          300,000       952,100  
Net loss on sales of securities
          369,172       14,518  
Related changes in current assets and current liabilities:
                       
Decrease (increase) in accounts receivable
    259,359       (164,227 )     (230,601 )
Decrease (increase) in material and supplies inventory
    (676,696 )     (739,253 )      
Decrease (increase) in advances and prepaid expenses
    (16,631 )     16,080       252,847  
Increase (decrease) in accounts payable and accrued liabilities
    (65,418 )     164,991       (314,090 )
 
                 
Net cash used by operating activities
    (3,727,785 )     (2,414,132 )     (1,171,106 )
 
                 
 
                       
CASH FLOWS FROM INVESTING ACTIVITIES
                       
Cash proceeds from sales of oil and gas properties
    712,500       31,695,279       777,461  
Cash paid for oil and gas properties
    (12,097,454 )     (20,612,267 )     (15,841,067 )
Cash paid for office equipment and software
    (39,919 )     (27,740 )     (43,129 )
Cash paid for drilling prepayments and other long-term assets
    (50,267 )           (330,203 )
Cash purchases of short-term investments in securities
                (28,750,000 )
Cash proceeds from sale of short-term investments
          683,728       12,360,482  
Cash proceeds from redemption of short-term investments
    2,600,000       11,500,000        
 
                 
Net cash provided (used) by investing activities
    (8,875,140 )     23,239,000       (31,826,456 )
 
                 
 
                       
CASH FLOWS FROM FINANCING ACTIVITIES
                       
Proceeds from sale of common stock
    31,500,000             28,506,602  
Cash paid for stock offering and issuance costs
    (1,864,516 )           (1,956,465 )
Proceeds from employee stock option exercise
    330,000             642,145  
Proceeds from warrant exercise
          56,638       705,025  
Proceeds from short-term borrowings
          10,925,900        
Repayment of short-term borrowings
          (10,925,900 )      
 
                 
Net cash provided by financing activities
    29,965,484       56,638       27,897,307  
 
                 
 
                       
NET INCREASE (DECREASE) IN CASH
    17,362,559       20,881,506       (5,100,255 )
CASH, BEGINNING OF YEAR
    23,269,725       2,388,219       7,488,474  
 
                 
CASH, END OF YEAR
  $ 40,632,284     $ 23,269,725     $ 2,388,219  
 
                 
The accompanying notes are an integral part of the financial statements.

 

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AMERICAN OIL & GAS INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
FOR YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
                                                                 
                                    Additional     Comprehensive Income        
    Preferred     Stock     Common     Stock     Paid-in     Accumulated     Accumulated     Total  
    Shares     Amount     Shares     Amount     Capital     Deficit     Other Income     Equity  
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 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 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  
Sale of stock at $3.50/share for cash
                    9,000,000       9,000       31,491,000                       31,500,000  
Cash paid for stock offering costs
                                    (1,864,516 )                     (1,864,516 )
Exercise of employee stock options
                    165,000       165       329,835                       330,000  
Share-based compensation:
                                                               
Stock option expense
                                    747,516                       747,516  
Accrued stock-based compensation
                                    202,933                       202,933  
Common stock granted and issued
                    431,500       431       83,269                       83,700  
Other
                                    2,000                       2,000  
Comprehensive loss:
                                                               
Net loss
                                            (10,341,380 )                
Increase in unrealized gain on short-term investments
                                                    75,000          
Total comprehensive loss
                                                            (10,266,380 )
 
                                               
December 31, 2009 Balances
        $       57,472,399     $ 57,472     $ 122,267,594     $ (39,096,899 )   $ 75,000     $ 83,303,167  
 
                                               
The accompanying notes are an integral part of the financial statements.

 

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AMERICAN OIL & GAS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
as of December 31, 2009 and 2008 and for the years ended December 31, 2009, 2008 and 2007
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. References to GAAP issued by the FASB in these footnotes are to the FASB Accounting Standards Codification, sometimes referred to as the Codification or ASC. The FASB finalized the Codification effective for periods ending on or after September 15, 2009. Prior FASB standards (like FASB Statement No. 165, Subsequent Events, issued in May 2009) are superseded by the Codification, and new FASB Statements are not being issued. For further discussion of the Codification, see “FASB Codification Discussion” in this filing’s Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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

 

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the assumption required by GAAP that proved reserves and generally proved reserve value for measuring capitalized cost impairment be based (for each proved property) on simple averages of the preceding twelve months’ historical oil and gas prices on the first day of each month.
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.
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 bank accounts 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 other-than-temporary, 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, 2009 and 2008, management had determined that little or no allowance for uncollectible receivables was necessary.
Accounts receivable of $564,533 at December 31, 2009 consisted of $411,909 from sales of oil and gas, $134,635 from joint interest billings to other oil and gas companies who participate with us in acquiring and exploration of oil and gas leases, $33,000 of other receivables, less a $15,011 allowance for uncollectible receivables. 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 of other receivables.
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 well plugging, surface equipment dismantlement and removal, site reclamation and similar activities of our oil and gas properties.

 

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The following table reflects the change in ARO for the years ended December 31, 2009 and 2008:
                 
    2009     2008  
Asset retirement obligation beginning of year
  $ 430,686     $ 323,369  
Liabilities incurred
    58,534       101,638  
Liabilities settled
    (79,432 )     (51,996 )
Accretion
    39,873       32,936  
Revisions in estimated liabilities
    (13,174 )     24,739  
 
           
Asset retirement obligation end of year
  $ 436,487     $ 430,686  
 
           
Current portion of obligation end of year
  $     $  
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, 2009 and 2008, 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 1/12th to evaluated costs and 11/12ths to unevaluated costs, with reclassification to evaluated costs being made evenly over the subsequent eleven calendar quarters.
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 the twelve-month historical averages of 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 certain subsequent events occurring before the filing date of the affected financial statements and indicative that capitalized costs were not impaired at period-end. Effective with filings after December 31, 2009, such subsequent events are limited to 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).

 

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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 property and equipment, 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 found nor recognized any impairment losses on such other property and equipment.
IMPAIRMENT — ASC Subtopic 360-35, Property, Plant and Equipment — Subsequent Measurement, 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. Under ASC Topic 932-360-35, 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 of SEC Regulation S-X Rule 4-10.
BUSINESS COMBINATIONS AND GOODWILL — We account for business combinations in accordance with ASC Topic 805, 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 $11,670,468 of goodwill in our 2005 acquisition of Tower Colombia Corporation.
We account for goodwill in accordance with ASC Topic 350, Intangibles — Goodwill and Other. ASC Topic 350 requires an annual impairment assessment of goodwill. 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 ASC Topic 350 no impairment of goodwill exists. At December 31, 2008, the $11,670,468 of goodwill was fully impaired, and the impairment was recognized.
INTANGIBLE ASSETS — Intangible assets, other than Goodwill, are amortized over their expected useful lives. In the aforementioned 2005 acquisition of Tower Colombia Corporation, we recognized a $900,000 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.
INCOME TAXES — We account for income taxes under the provisions of ASC Topic 740, Income Taxes. Under the asset and liability method of ASC Topic 740, 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 ASC Topic 740 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, 2009 and 2008, 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.

 

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Major Customers: The table below shows for the calendar years 2009, 2008 and 2007 the percentages of our oil and gas revenues for major customers, i.e., those who each account for more than 10% of the year’s oil and gas sales:
                         
Major Customers   2009     2008     2007  
DCP Midstream LLC
    38 %     31 %     36 %
Wyoming Refining Company
    23 %     15 %     13 %
Shell Trading (US) Company
    10 %     17 %     19 %
Nexen Marketing U.S.A., Inc.
                    13 %
 
                 
Total
    71 %     63 %     81 %
 
                 
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, Wells Fargo bank. 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 Share-Based Payment accounting standards (in ASC Topic 718, Compensation — Stock Compensation, and ASC Topic 505, Equity Based Payments to Non-Employees), on a modified prospective basis. The standards require 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.
OFF BALANCE SHEET ARRANGEMENTS — We have no significant off balance sheet arrangements.
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 ASC Topic 280, Segment Reporting. Operating segments, as defined in ASC 280, 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 2007 and 2008 consolidated financial statements have been reclassified to conform to the 2009 financial statement presentation. Such reclassifications have had no effect on net loss.
SUBSEQUENT EVENTS — Those subsequent events known to the Company’s principal executive officer or principal financial officer prior to the first issuance of the financial statements are evaluated for incorporation in the financial statements and notes thereto.

 

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RECENT ACCOUNTING PRONOUNCEMENTS
FASB Codification. In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principle, as codified in FASB ASC Topic 105, Generally Accepted Accounting Principles. This standard establishes two levels of U.S. GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (“the Codification” or “ASC”) became the source of authoritative, nongovernmental GAAP, except that financial accounting rules and interpretive releases of the SEC are additional sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became non-authoritative. The new authoritative guidance under ASC Topic 105 became effective for periods ending on or after September 15, 2009, and did not have a material impact on our consolidated financial statements.
Oil and Gas Reserve Information. In December 2008 the SEC published final rules and interpretations updating its oil and gas reporting requirements. In October 2009, the SEC issued Staff Accounting Bulletin No. 113 (SAB No. 113), effective November 4, 2009, revising Staff Accounting Bulletin Series Topic 12 “Oil and Gas Producing Activities” primarily to conform Topic 12 to the aforementioned SEC updates to its oil and gas reporting requirements. Key changes to the SEC’s rules and interpretations include a requirement to use 12-month average pricing rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure (outside of the financial statements) of probable and possible reserves. The full-cost accounting method, which we follow, is changed to no longer allow the option of ceiling test impairments being reduced or eliminated by consideration of oil and gas price increases occurring subsequent to the impairment date. The FASB aligned ASC Topic 932, with the aforementioned SEC requirements by issuing ASC Update 2010-03.
The new SEC and FASB authoritative guidance became effective for our 2009 Annual Report on Form 10-K and has been prospectively adopted by us as of December 31, 2009. The new authoritative guidance did not have a material impact on our consolidated financial statements, except the new requirement to use 12-month average pricing rather than year-end pricing at December 31, 2009, resulted in a $550,000 impairment expense at December 31, 2009, compared with no such impairment expense using year-end pricing.
ASC Update 2010-06. In January 2010 the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures” (“ASC Update 2010-06”). It requires additional disclosures surrounding transfers in and out of Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3. This new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2009. We will apply the new authoritative guidance beginning with our Quarterly Report on Form 10-Q for the three-month period ending March 31, 2010.
ASC Update 2010-06 also requires that purchases, sales, issuances, and settlements for Level 3 measurements be disclosed. This portion of the new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2010. We will apply this new authoritative guidance beginning with our Quarterly Report on Form 10-Q for the three-month period ending March 31, 2011.
We do not expect our adoption of ASC Update 2010-06 to have a material impact on our financial statements.
Fair Value Disclosures of Financial Instruments. New authoritative accounting guidance under FASB ASC Topic 825, Financial Instruments (“ASC Topic 825”) requires us to include disclosures about the fair value of our financial instruments whenever we issue financial information for interim reporting periods and annual reporting periods, whether recognized or not recognized in the consolidated balance sheets. The new ASC guidance became effective for us on April 1, 2009, and did not have a material impact on our consolidated financial statements.

 

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NOTE 3 — PROPERTY AND EQUIPMENT
Property and equipment at December 31, 2009 and 2008 consisted of the following:
                 
    2009     2008  
Oil and gas properties, full cost method
               
Unevaluated costs, not yet subject to amortization
  $ 35,611,363     $ 31,837,965  
Evaluated costs
    8,843,579       8,618,667  
 
           
 
    44,454,942       40,456,632  
Less accumulated amortization
    (5,510,016 )     (4,796,016 )
 
           
Net carrying value of oil and gas properties
    38,944,926       35,660,616  
Cost of other property and equipment
    406,273       366,354  
Less accumulated depreciation and amortization
    (261,531 )     (184,562 )
 
           
Net property and equipment
  $ 39,089,668     $ 35,842,408  
 
           
In 2009 and 2008, most of our oil and gas properties were in four major projects: Goliath, Fetter, Krejci and Bigfoot. As explained further in Note 12, we signed on February 23, 2010 a letter of intent to sell by March 31, 2010 for approximately $44 million cash all our interests in three Wyoming counties. The properties to be sold include our interests in the Fetter and Krejci projects. Our major project in 2010 will be the Goliath project in North Dakota where we will be drilling wells to the Bakken and Three Forks oil formations.
Unevaluated Oil and Gas Properties
Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until the associated wells or properties are able to be evaluated as to whether the assets have proved reserves or not. Costs are also moved into the amortization base when such costs are believed to be impaired and not recoverable by development or sale of the related asset. Prospect leasing and acquisition normally require one to three years, and the subsequent evaluation normally requires an additional one to three years.
The following table presents the unevaluated capitalized oil and gas properties’ costs and net change for 2009, by major project:
                                                 
    Capitalized Costs     Approximate Acres 12/31/09  
    (in millions)     (Unaudited)  
            Net                     Lease     Our  
Project (State)   12/31/08     Change     12/31/09     Gross     Net*     Net*  
Properties to be sold by March 31, 2010:
                                               
Fetter Project, Powder River Basin (WY)
  $ 14.7     $ 0.3     $ 15.0                          
Krejci Oil Project, Powder River Basin (WY)
    2.4       0.1       2.5                          
Other, Powder River Basin (WY)
    1.2       0.0       1.2                          
 
                                         
Total, unevaluated properties to be sold
    18.3       0.4       18.7                       97,000  
Goliath Project, Williston Basin (ND)
    7.7       2.5       10.2       106,000       79,000       73,000  
Bigfoot Project
    3.3       1.7       5.0       213,000       188,000       131,000  
Other unevaluated costs and acreage
    2.5       (0.8 )     1.7       21,000       20,000       12,000  
 
                                       
Total unevaluated costs and net acres
  $ 31.8       3.8     $ 35.6                       313,000  
 
                                       
     
*  
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.

 

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Of the $35.6 million in costs excluded from the amortization base:
   
Substantially all costs are for property acquisitions;
   
The $18.7 million for properties to be sold in late March 2010 will be reclassified within the full cost pool consistent with gain determination and recognition at the time of sale;
   
We anticipate that substantially all of the $10.2 million in unevaluated costs at Goliath will be moved into the amortization base over 2010 and 2011, as wells are drilled;
   
We anticipate that the $5 million in unevaluated costs at Bigfoot will remain substantially unevaluated in 2010, with future reclassification to evaluated dependent on future drilling and development activities; and
   
We anticipate the $1.7 million in other unevaluated costs will be substantially reclassified to the amortization base over the two-year period ending December 31, 2011.
The Fetter Project’s $0.3 million increase in 2009 is primarily for acquisition, retention or extension of oil and gas leases. The Goliath Project’s $2.5 million increase in 2009 primarily consists of $3 million for acquisition or extension of leases, less $0.7 million received under the Goliath East participation agreement discussed below. The Bigfoot Project’s $1.7 million increase in 2009 consists primarily of $1 million in well costs that remain unevaluated at March 11, 2010 and $0.7 million in lease acquisition and retention costs.
In 2009 and 2008, we capitalized $804,000 and $420,000, respectively, of internal land department costs directly associated with property acquisition, exploration (including lease record maintenance) and development. Capitalized land department costs are initially capitalized 1/12th to evaluated costs and 11/12th to unevaluated costs, with reclassification to evaluated made evenly over the subsequent eleven calendar quarters. In 2009 and in 2008 we also capitalized approximately $100,000 to various unevaluated properties for our internal geologist’s costs directly associated with the acquired properties. In 2007 capitalization of internal costs was less than $100,000.
The following table shows, by year incurred, the unevaluated oil and gas property costs at December 31, 2009 (net of transfers to evaluated costs and net of sales proceeds) excluded from the amortization computation and also the portion of such costs that relate to the properties to be sold in 2010 under the February 23, 2010 Letter of Intent:
                         
    Net Costs     Costs of Properties Being  
Year Incurred   Incurred     Sold     Retained  
Year ended December 31, 2009
  $ 6,222,972     $ 664,934     $ 5,558,038  
Year ended December 31, 2008
    5,547,971       2,036,087       3,511,884  
Year ended December 31, 2007
    3,469,209       1,805,688       1,663,521  
Year ended December 31, 2006
    12,230,777       11,948,320       282,457  
Year ended December 31, 2005
    7,810,852       1,886,209       5,924,643  
Prior to 2005
    329,582       329,582        
 
                 
Total costs as of December 31, 2009
  $ 35,611,363     $ 18,670,820     $ 16,940,543  
 
                 
Sales of Oil & Gas Properties
In December 2009, we entered into a participation agreement (the “Goliath East participation agreement”) with Halliburton Energy Services, Inc. (“Halliburton”) whereby Halliburton would earn 25% of American’s working interest in a portion of the Goliath Project in return for Halliburton (a) paying to American up to $1.1 million in cash and (b) paying 100% of American’s 84.3% share in the cost of drilling, completing and fracing the Tong Trust 1-30H well, with American carried for and retaining 30% of its original 84.3% working interest in the well. In December 2009, American received $712,500 cash from Halliburton under the terms of the Goliath East participation agreement.
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.

 

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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.
Property Acquisition, Exploration and Development Costs
Information relating to the Company’s costs incurred in its oil and gas operations during the years ended December 31, 2009, 2008 and 2007 is summarized as follows:
                         
    2009     2008     2007  
Property acquisition costs, unproved properties
  $ 5,183,876     $ 6,275,102     $ 4,395,467  
Property acquisition costs, proved properties
    400,000              
Exploration costs
    1,856,611       13,563,077       11,364,497  
Development costs
    1,804,395       3,042,469        
Asset retirement costs
    58,534       74,381       73,516  
 
                 
 
  $ 9,303,416     $ 22,955,029     $ 15,833,480  
 
                 
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.
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. During 2009, we recognized $4,500,000 of impairments of oil and gas properties ($2,850,000, net of $1,650,000 increase in deferred tax assets before tax valuation allowances).
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, 2009 and December 31, 2008 to zero as further discussed in Note 6.
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 2009, 2008 and 2007, the annual average amortization rates were $12.50, $25.17, and $25.21, respectively, per boe. After impairment recognition, the amortization rate at December 31, 2009 was $13.42 per boe of proved reserves.
The following table shows by type of asset the Depreciation, Depletion and Amortization (“DD&A”) expense for the years ended December 31, 2009, 2008 and 2007:
                         
    2009     2008     2007  
Amortization of costs for evaluated oil and gas properties
  $ 714,000     $ 1,210,000     $ 1,021,817  
Depreciation of office equipment, furniture and software
    76,968       75,772       65,225  
Amortization of Other Intangible Asset
    180,000       180,000       180,000  
 
                 
Total DD&A expense
  $ 970,968     $ 1,465,772     $ 1,267,042  
 
                 

 

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NOTE 4 — SHORT-TERM INVESTMENTS
Our short-term investments at December 31, 2009 and 2008 were comprised of auction-rate preferred shares (“ARPS”) issued by closed-end mutual funds. ARPS are a form of auction-rate securities (“ARS”) that were bought and sold at par value prior to March 2008 at special auctions held every 7 days or 28 days and paying variable-rate dividends, with the rate re-determined at the auctions. After February 2008, there were no parties willing to buy ARPS at par value at the auctions, i.e., the auction system collapsed. The ARPS are preferred shares with no maturity date and with no right for the holder to ‘put’ the securities to the ARPS issuer (the closed-end mutual fund) for redemption. Since February 2008, many issuers of ARPS have redeemed some or all of their ARPS at par value, and several large investment banks and brokerage firms (generally in settlement with customers or with government agencies) have bought back their customers’ ARPS at par value.
On August 6, 2009, American filed with the Financial Industry Regulatory Authority (“FINRA”) a statement of claim against Jefferies & Company, Inc. (“Jefferies”), as American’s broker with regards to the ARPS. The statement of claim seeks in arbitration to have Jefferies (i) purchase at par value American’s remaining unredeemed ARPS, (ii) reimburse American for consequential damages (approximating $140,000 to date) and for American’s legal costs in the arbitration and (iii) pay American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS dividends American received following the failed auctions. The arbitration hearing is scheduled to take place in early December 2010. We understand that FINRA’s enforcement division is separately investigating Jefferies’ role as a broker of ARPS and as an ARPS Auction Dealer.
We expect to have our ARPS entirely liquidated for cash before December 31, 2010. Absent full liquidation at par value, we expect to sell before December 2010 any remaining ARPS in the secondary market at expected losses (including significant transaction costs) approximating 10% to 20% of the par value of ARPS sold. We may receive an award in arbitration with Jefferies; however, we have no assurance that we will be successful in our claim against Jefferies.
The ARPS we own at December 31, 2009 are classified as short-term investments and are classified under ASC Topic 320 as investments held for sale, rather than marketable securities. Unrealized gains and temporary unrealized losses are recorded in Other Comprehensive Income (Loss). Unrealized losses that are “other-than-temporary” are reflected in the consolidated statement of operations. Unrealized gains resulting from increases in fair value are recorded in Other Comprehensive Income.
The ARPS’ total par value and carrying value (i.e., estimated fair value) from December 31, 2007 through December 31, 2009 are summarized in the following table:
                                                 
    Par Values ($ thousands)     Fair Values ($ thousands)  
    Calamos     Other     All     Calamos     Other     All  
    Funds     Funds     Funds     Funds     Funds     Funds  
Balance at December 31, 2007
    11,275       6,050       17,325       11,275       6,050       17,325  
Less sales prior to 2/16/2008
    (25 )     (50 )     (75 )     (25 )     (50 )     (75 )
Less redemptions by 12/31/08
    (8,925 )     (2,575 )     (11,500 )     (8,925 )     (2,575 )     (11,500 )
Other-than-temporary loss
                                  (300 )     (300 )
 
                                   
Balance at December 31, 2008
    2,325       3,425       5,750       2,325       3,125       5,450  
Less redemptions by 3/31/09
          (200 )     (200 )           (200 )     (200 )
Temporary loss at 3/31/09
                            (250 )           (250 )
 
                                   
Balance at March 31, 2009
    2,325       3,225       5,550       2,075       2,925       5,000  
Less redemptions by 6/30/09
    (1,300 )     (75 )     (1,375 )     (1,300 )     (75 )     (1,375 )
Fair value increases by 6/30/09
                            250       75       325  
 
                                   
Balance at June 30, 2009
    1,025       3,150       4,175       1,025       2,925       3,950  
Less July 2009 redemptions
    (325 )           (325 )     (325 )             (325 )
Less August 2009 redemptions
    (700 )           (700 )     (700 )             (700 )
Change in fair value at 12/31/09
                                           
 
                                   
Balance at December 31, 2009
          3,150       3,150             2,925       2,925  
 
                                   

 

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At December 31, 2009, our remaining ARPS were preferred shares in five closed-end taxable mutual funds: $1,200,000 par value in Evergreen Income Advantage (symbol EAD), $1,075,000 par value in Advent Claymore Convertible Securities (symbol AVK) and $875,000 total par value in the PSY, BPP and PHT funds. The ARPS’ $3,150,000 total par value exceeded their $2,925,000 total carrying value (i.e., estimated fair value) by $225,000. The $225,000 net loss is composed of (i) a $300,000 other-than-temporary loss recognized in the Statement of Operations for the year ended December 31, 2008 and (ii) a $75,000 temporary unrealized gain recorded in Other Comprehensive Income. Fair value, by definition, is before transaction costs in selling the ARPS (See Note 5).
The ARPS dividend rates approximated 0.8% per annum at December 31, 2009. Dividend rates fluctuate weekly or monthly generally at a small premium over 30-day LIBOR or over short-term AA commercial paper.
NOTE 5 — FAIR VALUE MEASUREMENTS
Effective January 1, 2008, we adopted ASC 820 Fair Value Measurements and Disclosures for all financial assets and liabilities measured at fair value on a recurring basis. We chose not to elect the fair value option as prescribed by ASC 820 for financial assets and liabilities that had not been previously carried at fair value. Therefore, material financial assets and liabilities not carried at fair value, such as trade accounts receivable and accounts payable, are still reported at their face values.
ASC 820 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, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
   
Level 3 — Significant inputs to the valuation model which are unobservable.
The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2008 and 2009, and the table shows the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values:
                                 
            Level 1     Level 2     Level 3  
    Total     inputs     inputs     inputs  
As of December 31, 2008
                               
Assets:
                               
Short-term investments available for sale:
                               
Auction Rate Preferred Shares (“ARPS”)
  $ 5,450,000     $     $     $ 5,450,000  
Liabilities
  $     $     $     $  
 
                               
As of December 31, 2009
                               
Assets:
                               
Short-term investments available for sale:
                               
Auction Rate Preferred Shares (“ARPS”)
  $ 2,925,000     $     $     $ 2,925,000  
Liabilities
  $     $     $     $  
The table in Note 4 provides a reconciliation between the $5,450,000 fair value of the ARPS at December 31, 2008 and the $2,925,000 fair value of the ARPS at December 31, 2009. In determining ARPS’ fair values, we were able to use Level 1 inputs at December 31, 2007 and began using Level 3 inputs on September 30, 2008.
Our claim against Jefferies (see Note 4) is not reflected in estimation as to the fair value of our ARPS at December 31, 2009, because fair value is based on what a third party would be willing to pay for the securities excluding any legal rights at December 31, 2009 that American may have against Jefferies.
The risk of loss associated with credit risk is negligible because credit rating agencies continue to classify such ARPS as Triple-A credit risks. Federal law requires the closed-end mutual fund that issued the ARPS to maintain asset values of no less than 200% of the ARPS par value and accrued dividends. A decline in asset value below the 200% ratio requires the fund to quickly restore the ratio such as by selling some assets and using the sale proceeds to pay accrued dividends and buy back a portion of the ARPS at par value. The closed-end mutual funds that issued the ARPS we hold have substantially all of their assets in a variety of corporate bonds and/or stock, which facilitates the selling of assets to redeem sufficient ARPS to maintain the required 200% coverage ratio.

 

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The methodology for Level 3 valuation at December 31, 2009 was similar to that at December 31, 2008, with the key considerations and inputs as to the fair value of our ARPS at December 31, 2009 being as follows:
   
Recognition that the ARPS are relatively illiquid compared to 7-day and 28-day commercial paper and similar debt instruments. ARPS cannot be sold in the secondary market at par value absent an announced plan to redeem the ARPS in the very near future.
   
As of December 31, 2009, there are no announced plans to redeem ARPS we hold.
   
On December 15, 2009, the SEC granted the PHT fund the right to redeem its ARPS using debt if the fund’s trustees should deem redemption to be in the best interest of the fund, its ARPS holders and its common shareholders. The PHT fund has not announced plans for redemption, but the Calamos closed-end taxable funds redeemed all of their ARPS within eight months of receiving a similar SEC grant in early 2009 allowing the use of debt to redeem all ARPS. We own $400,000 par value of PHT ARPS.
   
Recognition that the ARPS we own pay dividends every 7 or 28 days at variable short-term rates that are a small premium above 7 or 30-day LIBOR or commercial paper rates.
   
Assumption that on average the ARPS will be redeemed at 95% to 100% of par value in two to four years because of various factors and expectations, most notably the following:
   
Current short-term interest rates are unusually low whereby (a) LIBOR and commercial paper interest rates a few years from now are likely to be greater than current rates and (b) the ARPS’ rates will be 125% to 150% of the LIBOR and commercial paper rates, which may compel funds to redeem their ARPS with debt, “put-able” ARPS and/or common stock.
   
At December 31, 2009, we own ARPS in five closed-end taxable mutual funds. In two to four years, it seems likely that the vast majority of the ARPS issued by each of the five mutual funds will be owned by four to seven large financial institutions, who will likely have the desire and influence to compel directly (or indirectly, such as through support for changes in federal law and regulations regarding ARPS) that each fund redeem all ARPS at 95% to 100% of par value. Each of the five mutual funds paid seven to nine financial institutions (among a group of 15 institutions) to be “Auction Dealers” (aka “Re-marketing Agents”) in the ARPS auctions. At December 31, 2009, some 40% to 60% of ARPS for each of the five mutual funds were owned collectively by four of those Auction Dealers: (1) Merrill Lynch (now a subsidiary of Bank of America), (2) Citigroup (3) UBS and (4) Morgan Stanley. Their substantial ownership of the ARPS came from their purchases so far of all ARPS at par value from many of their ARPS customers in settlement with FINRA or government agencies. Seven others (including Wells Fargo) of the fifteen Auction Dealers have entered into similar settlements with FINRA, state agencies or the SEC. Of the other four, one (Lehman Brothers) is dissolved and two (Oppenheimer and Jefferies & Co.) are contesting State and FINRA allegations, respectively, of wrongdoings as ARPS brokers. Oppenheimer and Jefferies were Auction Dealers in each of the five mutual funds.
   
Calculations under various cases and assumptions of (a) future interest rates, (b) timing of redemptions and (c) illiquidity of ARPS, whereby the cases indicated a range of ARPS fair values at December 31, 2009 of 90% to 96% of par value, where fair value (by definition) is without regard to transaction costs (such as brokerage fees) in selling the ARPS in a secondary market.
NOTE 6 — INCOME TAXES
We account for income taxes under the provisions of ASC Topic 740, 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.

 

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Income tax expenses and effective income tax rates for the years ended December 31 consist of the following:
                         
    2009     2008     2007  
Current taxes
  $ (149,965 )   $ 244,000     $  
Deferred tax benefit
    (2,369,550 )     (5,464,653 )     (1,484,984 )
Valuation allowance
    2,369,550       4,752,308        
 
                 
Income tax expense (reduction)
  $ (149,965 )   $ (468,345 )   $ (1,484,984 )
 
                 
 
                       
Loss before income taxes
  $ (10,491,345 )   $ (24,000,077 )   $ (4,228,366 )
Effective income tax rate
    1.4 %     2.0 %     35.1 %
The effective income tax rate for the years ended December 31 differs from the U.S. Federal statutory income tax rate as follows:
                         
    2009     2008     2007  
Federal statutory income tax rate
    35.0 %     35.0 %     35.0 %
State income taxes
    2.0 %     1.6 %     1.5 %
Permanent differences:
                       
Goodwill impairment
          (17.8 %)      
Compensation using qualified stock options
    (0.6 %)     (0.5 %)     (3.3 %)
Excess percentage depletion
    (4.6 %)     2.0 %     1.5 %
Other
    (0.7 %)            
Change in valuation allowance
    (22.6 %)     (19.8 %)      
Change in average state tax rate
    (0.4 %)           0.3 %
Other
    (6.7 %)     1.5 %     0.1 %
 
                 
Effective income tax rate
    1.4 %     2.0 %     35.1 %
 
                 
The 4.6% tax rate reduction for excess percentage depletion in 2009 is due to the 2008 tax return as filed differing from plans in early 2009 to elect to capitalize substantially all IDC in order to deduct in 2008 all excess percentage depletion carryforward. The 4.6% tax rate reduction reflects a reversal of the 2008 excess percentage depletion that was assumed last year to be deducted for 2008.
At December 31, 2009, we had for federal income tax reporting $20.1 million in net operating loss carryforwards and $1.4 million in excess percentage depletion carryforward. Under existing federal tax law, a portion of the net operating loss carryforward begins to expire in 2026 and the excess percentage depletion carryforward does not expire.
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 that as of March 12, 2010, we are no longer subject to income tax examinations by tax authorities for years before 2005 for Colorado and before 2006 for federal, Montana, North Dakota and Utah income tax returns. Income taxing authorities have conducted no formal examinations of our past federal and state income tax returns and supporting records. In March and April 2009, the Utah State Tax Commission conducted a limited review of our franchise tax returns for 2005, 2006 and 2007, but the review did not become a formal examination or audit, and the Commission issued no notice of any taxes, penalties or interest due.
On January 1, 2007, we adopted the provisions of ASC Topic 740 regarding uncertainty in income taxes. We found no significant uncertain tax positions as of any date on or before December 31, 2009. Given our substantial net operating loss carryforwards at both the federal and state levels prior to 2010, we do not anticipate any significant interest expense or penalties charged for any examining agents’ tax adjustments of income tax returns prior to 2010 since such adjustments would very likely simply reduce our net operating loss carryforwards.

 

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The components of the deferred tax assets and liabilities as of December 31 are as follows:
                         
    2009     2008     2007  
Current deferred tax assets:
                       
For unrealized loss on short-term investments
  $ 83,287     $ 109,749     $ 347,658  
For unrealized loss on materials & supplies inventory
    209,510              
Less asset valuation allowance
    (292,797 )     (109,749 )      
 
                 
Current deferred tax assets
  $     $     $ 347,658  
 
                 
 
                       
Long-term deferred tax assets (liabilities):
                       
Deferred tax assets:
                       
Federal and state net operating loss carryovers
  $ 7,243,324     $ 171,696     $ 5,731,713  
Oil & gas property costs’ tax basis in excess of basis for financial reporting
    165,754       4,073,868        
Oil and gas property amortization
          51,373       454,771  
Compensation using non-qualified stock options and stock grants
    610,115       364,887       341,452  
Alternative Minimum Tax Credit Carryforward
    94,035              
 
                 
 
    8,113,228       4,661,824       6,527,936  
Less: valuation allowance
    (6,829,062 )     (4,642,559 )      
 
                 
Long-term deferred tax assets
  $ 1,284,166     $ 19,265     $ 6,527,936  
 
                 
Deferred tax liabilities:
                       
Oil and gas property amortization
  $ (1,265,654 )   $     $  
Oil and gas property costs’ carrying value for financial reporting in excess of tax basis
                (7,572,033 )
Other
    (18,512 )     (19,265 )     (15,906 )
 
                 
Total long-term deferred tax liabilities
    (1,284,166 )     (19,265 )     (7,587,939 )
 
                       
Long-term deferred tax assets
    1,284,166       19,265       6,527,936  
 
                 
Net long-term deferred tax assets (liabilities)
  $     $     $ (1,060,003 )
 
                 
At December 31, 2009 and December 31, 2008, we recognized valuation allowances reducing the carrying value of net deferred tax assets to zero. ASC Topic 740 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. We recognized the valuation allowances in consideration of many factors, primarily our recent history of losses and the inherent uncertainties of exploring for oil and gas. As circumstances change in the future, we may reduce deferred tax asset valuation allowances.
The Deferred Tax Assets at December 31, 2008, reflected our plans in early 2009 to defer deduction of substantially all of our intangible drilling costs incurred in 2009 so as to fully utilize our Federal net operating loss carryforward and our percentage depletion carryforward in 2009, when there was a risk that federal tax law could be changed to reduce such carryforwards before we could otherwise use them. At the time of filing our 2008 federal income tax return in September 2009, we opted to deduct substantially all of our intangible drilling costs and not utilize our loss carryforward and percentage depletion carryforward in 2008. Consequently, the deferred tax asset for net operating loss carryforwards remains high.

 

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NOTE 7 — SUPPLEMENTAL INFORMATION TO THE STATEMENTS OF CASH FLOWS
                         
    2009     2008     2007  
Supplemental Schedule of Cash Flow Information
                       
Cash paid for interest expense
  $     $ 107,047     $ 6,162  
Cash paid for income taxes
  $ 130,000     $ 140,000     $  
Cash refunded on income taxes
  $ 175,965     $     $  
 
                       
Supplemental Disclosures of Non-Cash Activities
                       
Share-based compensation expense
  $ 1,036,149     $ 904,006     $ 1,091,677  
Exchange of oil and gas properties
  $ 420,000     $     $  
Materials & supplies inventory used in wells
  $ 77,522     $     $  
Net increase in payables for capital expenditures
  $     $ 2,200,387     $ 134,807  
Conversion of preferred stock into common stock
  $     $ 7,452,000     $ 6,048,000  
Preferred stock dividends paid in common stock
  $     $ 589,530     $ 820,224  
Net drilling prepayments applied to incurred drilling costs
  $     $ 542,876     $  
Oil and gas interests exchanged for PetroHunter common stock
  $     $     $ 270,000  
NOTE 8 — 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. At December 31, 2009 and 2008, we had no preferred stock outstanding. 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.
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. We were obligated to pay an 8% annual dividend on the Series AA 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, 2006 through December 31, 2009.
Warrants
The table below reflects the status of warrants outstanding at December 31, 2009 and 2008 held by others to acquire our common stock:
                         
        Common     Exercise     Expiration
Outstanding as of   Issue Date   Shares     Price     Date
December 31, 2009
  April 16, 2008     50,000     $ 3.50     April 16, 2013
 
                     
 
                       
December 31, 2008
  April 16, 2008     50,000     $ 7.00     April 16, 2013
December 31, 2008
  July 22, 2005     835,626     $ 6.00     September 30, 2009
 
                     
December 31, 2008
        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 warrants for 835,626 shares expired on September 30, 2009. On January 14, 2009, our Board of Directors reduced the exercise price to $3.50 per share for the warrant expiring on April 16, 2013. The $2,000 estimated fair value of the modification in warrant pricing is included in share-based compensation expense for 2009.

 

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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, 2009, 2008, and 2007, options to purchase 2,690 shares, 2,690 shares and 192,690 shares, respectively, were available to be granted pursuant to the 2004 Plan.
At our 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 our Annual Stockholders meeting in July 2009, the stockholders amended the 2006 Plan to increase the number of common stock shares that may be issued from 1,500,000 shares to a total of 3,000,000 shares. At December 31, 2009, 2008 and 2007, options to purchase 1,721,900 shares, 649,400 shares and 981,400 shares, respectively, were available to be granted pursuant to the 2006 Plan.
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 ASC paragraphs 505-50-30-11 and -12, 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 12 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, 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  
Options granted during 2009
    15,000     $ 2.00  
Less options forfeited during 2009
    (15,000 )   $ 2.00  
Less options exercised during 2009
    (165,000 )   $ 2.00  
 
             
Options outstanding — December 31, 2009 (1,498,866 exercisable)
    2,872,000     $ 2.44  
 
             
The weighted-average, grant-date estimated fair value of stock options granted during the years ended December 31, 2009, 2008 and 2007 were $0.40, $0.68 and $1.65, respectively, per underlying common share. We estimated the fair values using both the Black-Scholes stock option pricing model and a Modified Binomial model.

 

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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 $688,350, i.e., the difference between the $946,484 fair value of the new options and the $258,134 fair value of the old options on November 5, 2008.
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, 2009 under the 2004 Plan and 2006 Plan:
                         
Exercise   Remaining        
price   contractual     Number of shares  
per share   life (years)     Outstanding     Exercisable  
$1.25
    4.5       403,000       403,000  
$2.00
    6.4       1,603,000       342,200  
$2.38
    1.0       100,000       100,000  
$3.29
    3.6       100,000       75,000  
$3.34
    5.3       6,000       2,000  
$3.37
    4.3       30,000       30,000  
$3.66
    2.8       500,000       416,666  
$6.03
    3.1       130,000       130,000  
 
                   
 
            2,872,000       1,498,866  
 
                   
Weighted average exercise price per share
          $ 2.44     $ 2.73  
Weighted ave. remaining contractual life
          5.0 years     4.1 years  
Aggregate intrinsic value, December 31, 2009
          $ 5,050,610     $ 2,205,660  
The total estimated unrecognized compensation cost from unvested stock options as of December 31, 2009 was $1,235,987, which is expected to be recognized over a weighted average period of approximately 1.9 years.
The following valuation models and key model assumptions were used for the significant options granted in 2009, 2008 and 2007:
             
    2009   2008   2007
Primary Model (Both Black-Scholes and modified binomial were used each year.)
  Modified Binomial   Modified Binomial   Modified Binomial
Expected option life (in years)
  4   4 to 5   4 to 5
Expected annual volatility over option life
  60%   45%   35%
Risk-free interest rate
  2.1%   2.3% to 2.5%   4.7% to 5.1%
Pre-vesting forfeiture rate
  10%   10% to 12%   0%
Dividend yield
  0%   0%   0%
Intrinsic Value /share that urges exercise
  Not key factor   $2.00   $2.00 to $2.16

 

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The modified binomial model takes into consideration that as a stock price rises significantly above the option exercise price, the resulting significant “intrinsic value” of the option can urge an employee to exercise the option, either (i) to sell some or all of the underlying stock to convert intrinsic value to cash, or (ii) to begin holding some or all of the stock for one year to reduce the income tax rate on the later anticipated gain from sale of the stock.
We 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 2009, 2008 and 2007:
                         
    2009     2008     2007  
Share-based compensation expense:
                       
For stock option grants
  $ 747,516     $ 735,286     $ 914,300  
For stock granted but in escrow or unvested
    202,933       168,720       148,177  
For stock granted with immediate vesting
    83,700             29,200  
For warrant re-pricing
    2,000              
 
                 
Total
  $ 1,036,149     $ 904,006     $ 1,091,677  
 
                 
Total share-based compensation for income tax returns
  $ 353,853     $ 17,720     $ 771,424  
As of December 31, 2009, we had granted 449,500 shares of common stock that were either held in escrow or not vested. They arose from the following stock grants in 2007 and 2009 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, 2009, 12,000 shares were not vested and not issued.
   
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. The shares were valued at $584,000 reflecting the $5.84 per share closing price of the stock at the date of grant.
   
On January 14, 2009, we granted and issued 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. Of the 427,500 shares granted, 90,000 vested at grant and the other 337,500 shares vest upon the earlier of January 14, 2014 or a change in 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 26, 2010, we granted and issued 7,519 shares of restricted common stock to each of our three outside directors, as non-officer director compensation. Each director may not transfer two-thirds of his respective 7,519 Restricted Shares until he is no longer a member of the board.

 

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NOTE 9 — EARNINGS PER SHARE
The following table summarizes the calculations of basic and diluted net income (loss) per common share for the years ended December 31, 2009, 2008 and 2007:
                         
    2009     2008     2007  
Net loss to common stockholders
  $ (10,341,380 )   $ (24,159,614 )   $ (3,795,912 )
Adjustments for dilution
                 
 
                 
Net loss adjusted for effects of dilution
  $ (10,341,380 )   $ (24,159,614 )   $ (3,795,912 )
 
                 
 
                       
Basic Weighted Ave. Common Shares
    48,516,065       47,104,025       44,383,861  
Add dilutive effects of options and warrants
                 
Add dilutive effects of convertible preferred stock
                 
 
                 
Diluted Weighted Ave. Common Shares Outstanding
    48,516,065       47,104,025       44,383,861  
 
                 
 
                       
Net loss per common share — basic
  $ (0.21 )   $ (0.51 )   $ (0.09 )
Net loss per common share — diluted
  $ (0.21 )   $ (0.51 )   $ (0.09 )
NOTE 10 — EMPLOYEE BENEFIT PLANS
We maintain and sponsor health care plans and a contributory 401(k) plan for our employees. Our direct costs related to these plans were $411,491, $370,513 and $264,918 for the years ended December 31, 2009, 2008 and 2007, respectively.
NOTE 11 — RELATED PARTY TRANSACTIONS
We had no related party transactions in 2009, 2008 or in 2007.
NOTE 12 — SUBSEQUENT EVENTS
On February 23, 2010, American and North Finn LLC signed a letter of intent to sell by March 31, 2010 nearly all their developed and undeveloped properties and wells in Converse, Niobrara and Campbell counties, Wyoming for approximately $49 million cash, of which American’s share approximates $44 million. The properties to be sold include all of American’s and North Finn’s interests in the Fetter Project, the Krejci Project and several much smaller Wyoming projects. American is selling (a) approximately 97,000 undeveloped net acres and (b) interests in 20 gross wells (10.4 net wells).
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.

 

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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.
As of December 31, 2009, North Finn had not exercised its option nor made a commitment to exercise under ASC paragraphs 505-50-30-11 and -12, whereby the value of North Finn’s option is not recognized in our financial statements as of December 31, 2009.
As discussed in Note 12 Subsequent Events, American and North Finn intend to sell all of their oil and gas properties in three Wyoming counties. Upon the closing in March 2010 of the proposed sale, all of the remaining North Finn property rights to be exchanged for the 2,900,000 shares will effectively be transferred at the time of closing to American in determining the allocation of sales proceeds between American and North Finn. At such closing North Finn will have met all requirements for earning the 2,900,000 restricted shares. Consequently the value of North Finn’s option will be recognized in our financial statements at the time of closing, increasing equity by the estimated fair value (at the time of closing) of the 2,900,000 restricted shares and increasing the cost of properties being sold.
Office Lease
In 2008 we were in a long-term lease of 6,844 square feet of office space at 1050 17th Street, Suite 2400, Denver, Colorado. As of June 1, 2009, our lease included 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 as of December 31, 2009:
         
    Annual Rental  
Year   Amount  
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  
2010
  $ 121,513     $ 6,560,031     $ 6,681,544  
2011
  $ 74,464     $ 588,553     $ 663,017  
2012
  $ 32,827     $ 284,307     $ 317,134  
2013
  $ 10,565     $ 29,557     $ 40,122  
2014
  $ 10,325     $     $ 10,325  
2015
  $ 10,325     $ 68,222     $ 78,547  
2016
  $ 5,085     $     $ 5,085  
Thereafter
  $ 1,043     $     $ 1,043  
The Company continually evaluates its leasehold interests, therefore certain leases may be abandoned by the Company in the normal course of business.

 

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NOTE 14 — INFORMATION REGARDING PROVED OIL AND GAS RESERVES (UNAUDITED)
As defined by SEC Regulation S-X 4-10 (a), primarily in subsection (22), proved oil and gas reserves are the estimated quantities of crude oil and natural gas (and, in some cases, natural gas liquids) which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (i) from a given date forward, from known reservoirs, and under existing economic and operating conditions, operating methods, and government regulations and (ii) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that contract renewal is reasonably certain. Effective for proved reserve estimates of a given date on or after December 31, 2009, existing economic conditions with regards to a crude oil or natural gas selling price is the average price during the twelve-month period prior to the given date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. For proved reserve of a given date prior to December 31, 2009, the assumed future crude oil or natural gas selling price is the spot price at the given date unless such price was defined by contractual arrangements, excluding escalations based upon future conditions. See SEC Regulation S-X 4-10(a) for the complete SEC definition of proved oil and gas reserves.
As defined by SEC Regulation S-X 4-10(a), primarily in subsection (6), proved developed oil and gas reserves include those proved reserves expected to be recovered through existing wells with existing equipment and operating methods. See SEC Regulation S-X 4-10(a) for the complete SEC definition of proved developed oil and gas reserves.
The determination of oil and gas reserves is highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.
All of our proved oil and gas reserves are located within the continental United States. Ryder Scott Company L.P. (“Ryder Scott”), an independent petroleum engineering firm, determined our estimated proved oil and gas reserves as of December 31, 2009, 2008, 2007 and 2006, summarized in this Note. Ryder Scott determined the projected future cash flows from those proved reserves and the present value, discounted at 10% per annum, of those future cash flows reflected in this Note, except for cash outflows for income taxes. In estimating reserves, Ryder Scott used the SEC definition of proved oil and gas reserves. Projected future cash flows are based on economic and operating conditions as of the applicable December 31st date for 2009, 2008 and 2007, except that, consistent with new SEC rules, for December 31, 2009 future oil and gas prices reflect a simple average of prices at the wellhead on the first day of the twelve months in the calendar year 2009.
Using Ryder Scott’s estimates of proved reserves and future cash flows as of the calendar year-ends and using Company data, we determined for calendar years 2009, 2008 and 2007 (i) the changes in proved reserves, (ii) the future income tax expense amounts in the Standardized Measure and (iii) the changes in the Standardized Measure, disclosed in the tables below.
Estimated net quantities of proved developed and undeveloped reserves of oil and gas for the year ended December 31, 2009, 2008 and 2007 are presented in tables below.
                         
Proved Reserves (Developed and Undeveloped) for the Year Ended December 31, 2009  
    Oil (BBLS)     NGL (BBLS)     Gas (MCF)  
Beginning of year
    75,610       11,139       1,147,074  
Revision to disclose gas reserves pre NGL extraction*
            (11,139 )     66,834  
Other revisions of previous reserve estimates
    1,812               (194,763 )
Extensions and discoveries
    85,455               172,721  
Purchases of minerals in place
    13,651               36,822  
Sales of minerals in place
    (8,992 )             (49,577 )
Production
    (20,026 )             (222,561 )
 
                 
End of year
    147,510             956,550  
 
                 
 
                       
Proved developed reserves at end of year
    64,418             645,308  

 

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*  
At December 31, 2009, NGL (i.e., natural gas liquids) estimated to be recovered from the produced natural gas were not separately estimated by Ryder Scott since Ryder Scott’s estimates of proved natural gas reserves at December 31, 2009 are the gas volumes prior to gas processing for extraction of the natural gas liquids. The table shows a revision to reclassify NGL barrels as a component of gas reserve volumes prior to processing the gas to extract NGL.
The 194,763 mcf downward revision of prior gas reserve estimates is largely attributable to a production performance revision of approximately 150,000 mcf (a 44% downward revision) for our net interest acquired years ago in a Wyoming gas well that had previously produced for many years. Our interest in this well is not among the properties being sold with the Fetter and Krejci projects.
The majority of 2009 additions for extensions and discoveries are attributable to a North Dakota proved undeveloped location where on March 10, 2010, we began drilling the Summerfield 15-15H well.
                         
Proved Reserves (Developed and Undeveloped) for the Year Ended December 31, 2008  
    Oil (BBLS)     NGL (BBLS)     Gas (MCF)  
Beginning of year
    96,399       53,933       1,307,159  
Revisions of previous reserve estimates
    (48,242 )     (43,832 )     (580,707 )
Extensions and discoveries
    46,674       7,221       556,652  
Purchases of minerals in place
                 
Sales of minerals 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 were 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 and discoveries 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.
                         
Proved Reserves (Developed and Undeveloped) for the Year Ended December 31, 2007  
    Oil (BBLS)     NGL (BBLS)     Gas (MCF)  
Beginning of year
    91,850             809,847  
Revisions of previous reserve estimates
    (32,906 )     23,937       28,388  
Extensions and discoveries
    54,722       30,307       608,514  
Purchases of minerals in place
                 
Sales of minerals in place
                 
Production
    (17,267 )     (311 )     (139,590 )
 
                 
End of year
    96,399       53,933       1,307,159  
 
                 
Proved developed reserves at beginning of year
    86,361             713,236  
Proved developed reserves at end of year
    91,106       53,933       1,277,755  
The 2007 net downward revision in oil reserves was 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.

 

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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
Future net cash flows presented in the table which follows are computed using year-end cost rates and year-end oil and gas prices except that for the Standardized Measure at December 31, 2009, oil and gas prices reflect a simple average of the first-day-of-the-month price for the twelve months in 2009. Future corporate overhead expenses and interest expense have not been included.
                         
    As of December 31,  
    2009     2008     2007  
Future cash inflows
  $ 10,967,941     $ 8,102,093     $ 19,840,019  
Future costs:
                       
Production
    (4,559,855 )     (3,156,973 )     (5,792,739 )
Development
    (1,855,599 )     (269,420 )     (319,922 )
Future income tax expense
    (21,448 )     (19,953 )     (101,000 )
 
                 
Future net cash flows
    4,531,039       4,655,747       13,626,358  
10% discount factor
    (2,053,173 )     (1,710,878 )     (5,321,559 )
 
                 
Standardized measure of discounted future net cash flows relating to proved reserves
  $ 2,477,866     $ 2,944,869     $ 8,304,799  
 
                 
The principal sources of changes in the standardized measure of discounted future net cash flows during the years ended December 31, 2009, 2008 and 2007 are as follows:
                         
    2009     2008     2007  
Beginning balance
  $ 2,944,869     $ 8,304,799     $ 4,598,000  
Sales and transfers of oil and gas produced
    (1,098,597 )     (1,615,291 )     (1,310,508 )
Net changes in prices and production costs
    (358,252 )     (2,970,196 )     1,228,973  
Sales of minerals in place
    (263,742 )            
Extensions and discoveries
    644,552       2,055,573       4,549,423  
Purchases of property with proved reserves
    298,143              
Development costs incurred during the year
    104,063       57,000       716,000  
Changes in estimated future development costs
    16,401       130,663        
Revisions in previous quantity estimates
    (60,433 )     (3,754,276 )     (1,917,123 )
Accretion of discount
    252,096       684,515       409,034  
Change in income taxes
    (1,234 )     52,082       31,000  
Change in other
                 
 
                 
Ending balance
  $ 2,477,866     $ 2,944,869     $ 8,304,799  
 
                 
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 ASC Subtopic 932-235, Extractive Industries — Oil and Gas, Notes to Financial Statements. 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.

 

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Standardized Measure Changes in 2009
The $358,252 standardized measure decrease attributable to net changes in prices and production costs is primarily due to (i) the decline in the average gas price from $5.04 per mcf to 3.43 per mcf for the Standardized Measure at December 31, 2008 and 2009, respectively and (ii)a small overall increase in lease operating expense rates. The effect of price changes is a function of price change times the proved reserve volume in the Standardized Measure at December 31, 2008. At December 31, 2008, our proved gas reserves were more than double our proved oil reserves on a barrel-of-oil equivalent basis (of 6 mcf per barrel of oil).
The $644,552 change attributable to extensions and discoveries is primarily attributable to proved undeveloped reserves at a North Dakota drill site, where on March 10, 2010, we began drilling the Summerfield 15-15H well.
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, and $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.
NOTE 15 — SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
                                 
2009   First     Second     Third     Fourth  
Revenues
  $ 305,674     $ 517,478     $ 462,553     $ 599,431  
Loss from operations
  $ (3,910,343 )   $ (1,617,455 )   $ (3,560,170 )   $ (1,461,140 )
Net loss
  $ (3,891,363 )   $ (1,600,118 )   $ (3,400,573 )   $ (1,449,326 )
Earnings per common share:
                               
Basic
  $ (0.08 )   $ (0.03 )   $ (0.07 )   $ (0.03 )
Diluted
  $ (0.08 )   $ (0.03 )   $ (0.07 )   $ (0.03 )
                                 
2008   First     Second     Third     Fourth  
Revenues
  $ 507,804     $ 937,361     $ 1,159,621     $ 289,803  
Loss from operations
  $ (1,498,768 )   $ (951,908 )   $ (19,333,989 )   $ (1,950,792 )
Net 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 )
The sum of the individual quarterly earnings per common share amounts may not agree with year-to-date earnings per common share because each quarterly period’s computation is based on the weighted average number of shares outstanding during that quarterly period.

 

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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, 2009 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, 2009, 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

 

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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, 2009. 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, 2009, our internal control over financial reporting is effective based on those criteria.
Because the Company was a non-accelerated filer at December 31, 2009, the Company was not required to have HEIN & ASSOCIATES, LLP attest to 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, 2009.
Changes in Internal Control over Financial Reporting
During 2009, 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.
There have been no 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.
Item 9B: Other Information
Not applicable.

 

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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 (expected to be filed with the SEC within 120 days after the end of the Company’s fiscal year ended December 31, 2009) 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
Equity Compensation Plan Information
The following table shows the number of securities to be issued upon exercise of outstanding options, warrants and rights as of December 31, 2009.
                         
            Weighted Average     Number of Securities  
    Number of Securities To     Exercise Price of     Remaining Available  
    Be Issued Upon Exercise     Outstanding     for Future Issuance  
    of Outstanding Options,     Options, Warrants     Under Equity  
Plan Category   Warrants and Rights     and Rights     Compensation Plans  
 
                       
Equity compensation plans approved by security holders
    2,922,000     $ 2.46       1,724,590  
Equity compensation plans not approved by security holders
                 
 
                 
Total
    2,922,000     $ 2.46       1,724,590  
 
                 
The table excludes the aforementioned North Finn LLC unexercised option to receive 2,900,000 common shares in exchange for oil and gas properties.
Additional information required by this Item 12 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.

 

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PART IV
Item 15: Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
         
    Page  
Report of Independent Registered Public Accounting Firm
    F-2  
Consolidated Balance Sheets as of December 31, 2009 and 2008
    F-3  
Consolidated Statements of Operations for years ended December 31, 2009, 2008 and 2007
    F-4  
Consolidated Statements of Cash Flows for years ended December 31, 2009, 2008 and 2007
    F-5  
Consolidated Statements of Stockholders’ Equity and Comprehensive Income for years ended December 31, 2009, 2008 and 2007
    F-6  
Notes to Consolidated Financial Statements
  F-7 to F-30  
(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 to 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.)
       
 
  3(v)    
Amended and Restated Bylaws (adopted June 12, 2009) (Incorporated by reference from the Company’s Current Report on Form 8-K, filed on June 18, 2009)
       
 
  10(i)  
2004 Stock Option Plan. (Incorporated by reference from the Company’s Definitive Proxy Statement, filed on June 16, 2004)
       
 
  10(ii)    
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.)

 

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Exhibit No.   Description
       
 
  10(iii)    
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(iv)    
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(v)  
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(vi)  
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(vii)  
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(viii)  
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(ix)    
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(x)  
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(xi)  
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(xii)    
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(xiii)    
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(xiv)  
Amended and Restated 2006 Stock Incentive Plan. (Incorporated by reference to the Company’s Definitive Proxy Statement, as amended, filed on July 26, 2006.)
       
 
  10(xv)  
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(xvi)  
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.)

 

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Exhibit No.   Description
       
 
  10(xvii)    
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(xviii)    
Letter Agreement dated August 22, 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
       
 
  99.1    
Ryder Scott Letter on its estimation of our proved oil and gas reserves at December 31, 2009
     
*  
Management contracts or compensatory plans or arrangements

 

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SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, this 15th day of March, 2010.
         
  American Oil & Gas Inc.
 
 
  /s/ Andrew P. Calerich    
  Andrew P. Calerich    
  President   
     
  /s/ Joseph B. Feiten    
  Joseph B. Feiten   
  Chief Financial Officer
(principal financial officer and
principal accounting officer) 
 
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
         
Signature   Title   Date
 
       
/s/ Patrick D. O’Brien
 
Patrick D. O’Brien
  Chief Executive Officer and Chairman 
(principal executive officer)
  March 15, 2010
 
       
/s/ Andrew P. Calerich
 
Andrew P. Calerich
  President and Director    March 15, 2010
 
       
/s/ Joseph B. Feiten
 
Joseph B. Feiten
  Chief Financial Officer 
(principal financial officer and
principal accounting officer)
  March 15, 2010
 
       
/s/ Nick DeMare
 
Nick DeMare
  Director    March 15, 2010
 
       
/s/ C. Scott Hobbs
 
Scott Hobbs
  Director    March 15, 2010
 
       
/s/ Jon R. Whitney
 
Jon R. Whitney
  Director    March 15, 2010

 

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