American Eagle Energy 10-K 2012 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

____________________

FORM 10-K

(Mark one)

x ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934.

For the fiscal year ended December 31, 2012

OR

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

For the transition period from to

Commission File No: 000-50906

____________________

AMERICAN EAGLE ENERGY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Nevada	20-0237026
(State or Other Jurisdiction	(I.R.S. Employer
of Incorporation or Organization)	Identification No.)

2549 W. Main Street, Suite 202	80120
Littleton, Colorado	(Zip Code)
(Address of Principal Executive Offices)

(303) 798-5235

(Registrant’s Telephone Number, Including Area Code)

____________________

Securities registered under Section 12(b) of the Exchange Act: None

Securities registered under Section 12(g) of the Exchange Act: Common Stock, $0.001 par value

_____________________

Indicate by check mark if the registrant is a well-known seasonal issuer, as defined in Rule 405 of the Securities Act.

Yes¨ Nox

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes¨ Nox

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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.

Yesx No¨

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

¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company.

Large accelerated filer	¨	Accelerated Filer	¨
Non-accelerated filer	¨	Smaller reporting company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes¨ Nox

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, was $32,089,947.

The number of shares outstanding of the registrant’s common stock as of April 10, 2013 was 50,068,346.

AMERICAN EAGLE ENERGY CORPORATION

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business.	3
Item 1A.	Risk Factors.	6
Item 2.	Properties.	12
Item 3.	Legal Proceedings.	13
Item 4.	Mine Safety Disclosure.	14
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities.	14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	15
Item 8.	Financial Statements and Supplementary Data.	32
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.	33
Item 9A.	Controls and Procedures.	33
Item 9B	Other Information.	34
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	35
Item 11.	Executive Compensation.	39
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	42
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	43
Item 14.	Principal Accountant Fees and Services.	44
	PART IV
Item 15.	Exhibits, Financial Statement Schedules.	45
	SIGNATURES	49
	FINANCIAL STATEMENTS AND NOTES

2

PART I

Item 1. Business.

Corporate History

American Eagle Energy Corporation (“we,” “our,” “us” or the “Company”) was incorporated in Nevada on July 25, 2003, to engage in the acquisition, exploration, and development of natural resource properties. On November 7, 2005, we and a then-newly-formed, wholly-owned subsidiary formed for that purpose completed a merger transaction with us as the surviving corporation (the “2005 Merger”). In connection with the 2005 Merger, we changed our name to “Eternal Energy Corp.” from our original name, “Golden Hope Resources Corp.”

On December 20, 2011, we, a newly-formed merger subsidiary (“Merger Sub”), and American Eagle Energy Inc. (“AEE Inc.”) consummated the final steps of a merger transaction (the “2011 Merger”), whereby Merger Sub merged with and into AEE Inc., with AEE Inc. surviving as our wholly-owned subsidiary. Following the initial step of the 2011 Merger, AEE Inc. changed its name from “American Eagle Energy Inc.” to “AMZG, Inc.” In the 2001 Merger, each share of AEE Inc. was converted into 3.641 shares of our common stock, $0.001 par value, per share, which resulted in the issuance of 164,144,426 shares of our common stock. Immediately following the consummation of the 2011 Merger, we declared a one-for-four and one-half reverse split of our common stock. The reverse split reduced the number of shares of our common stock then issued and outstanding to 45,588,948. The retroactive effect of this reverse split has been applied to all share data included in this Annual Report.

In connection with the 2011 Merger, we changed our name from “Eternal Energy Corp.” to “American Eagle Energy Corporation.”

Business Overview

Since the 2005 Merger, we have been engaged in the exploration for petroleum and natural gas in the States of Nevada, Utah, Texas, Colorado, and North Dakota, the North Sea, and southeastern Saskatchewan, Canada, through the acquisition of contractual rights for oil and gas property leases and the participation in the drilling of exploratory wells.

As discussed below, our primary area of focus is, and will be for the foreseeable future, oil deposits located within the Bakken and Three Forks formations in western North Dakota and eastern Montana.

In the fourth quarter of 2010, we began our current drilling activity for our operated wells, targeting the Bakken and Three Forks Formations in Divide County, North Dakota. In November 2010, we elected to participate in our first non-operated well to be drilled within the Spyglass Property area. Since that time, we have elected to participate in 53 non-operated Spyglass wells. For more information about our working interests in the Bakken and Three Forks Formations, see “Properties” below on page 12 for a discussion of the wells in which we have elected to participate that are located in this area.

On January 31, 2011, AEE Inc. entered into a Lease Acquisition Agreement with Americana Exploration LLC and Big Sky Operating LLC to acquire an undivided 66.67% working interest in approximately 47,392 net acres located in Toole County, Montana for cash consideration of $1,235,684.

In May 2011, we entered into a Purchase and Sale Agreement with AEE Inc. and an unrelated third party for the sale by us and AEE Inc. of one-half of our respective 50% working interests in approximately 8,948 net acres located primarily in Divide County, North Dakota (the “Spyglass Property”). The initial closing of the transactions occurred on May 26, 2011 and resulted in the sale of an undivided 50% interest in approximately 8,118 net acres for net cash consideration of 6,913,920, which was divided equally between us and AEE Inc. A second closing related to the transaction occurred on August 5, 2011 and resulted in the sale of an undivided 50% interest in approximately 760 additional net acres for net cash consideration totaling 641,666, which was divided equally between us and AEE Inc. The Purchase and Sale Agreement also provided for the sale by us of an undivided 50% interest in approximately 269 net acres located within the Spyglass Property (as we refer to it under “Properties” below on page 12) in Divide County, North Dakota for net cash consideration totaling $227,079. The closing of this sale occurred on August 5, 2011. Post-closing, we retained a 50% working interest in the Spyglass Property.

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On November 18, 2011, we entered into a Purchase and Sale Agreement with AEE Inc. and a third-party purchaser, pursuant to which we and AEE Inc. agreed to sell to the purchaser an aggregate of 75% of approximately 10,521 aggregate net acres located in Western Divide County, North Dakota, and eastern Sheridan County, Montana (the “West Spyglass Prospect”), a region known for its Bakken and Three Forks zone oil production. The initial closing of the sale occurred on December 14, 2011, with the payment of $10,913,096, to be split equally us and AEE Inc. We retained a 25% working interest in the West Spyglass Prospect acreage and remained the operator on that acreage.

In addition, subject to the expiration of a previously granted ten-day preferential sale right, we agreed to sell to the same third-party purchaser 75% of 1,440 net acres in our Spyglass Property, for cash consideration of $1,889,974, which funds were received in January 2012. Post-closing, we remained the operator on the West Spyglass Prospect.

In January 2012, we commenced drilling of our first operated well located within the Spyglass Property, the Christianson 15-12 well. Throughout the remainder of 2012, we drilled and completed eight additional operated wells within the Spyglass Property. An additional five wells were drilled and awaiting completion as of December 31, 2012.

Effective April 15, 2011, we and AEE Inc., entered into a farmout agreement with Passport Energy Ltd. (“Passport”), whereby Passport agreed to fund 38.5% of the drilling, completing, and equipping costs of up to two future wells located within the Hardy Property in exchange for a 25% working interest in each well. We retained the remaining working interest. In May 2011, we and Passport successfully drilled and completed the Hardy 4-16 well, an offset well located within the Hardy Property. A 29-stage fracture stimulation of the Hardy 4-16 well was completed in July 2011 and was placed on production during September 2011. In December 2011, we and Passport modified our existing farmout agreement to reduce Passport’s interest in the second well to 23.1% of all drilling related costs and 15% of all lease operations expenses and corresponding revenues, and commenced drilling of the Hardy 14-17 well, a second well within the Hardy Project. The Hardy 14-17 well was completed in April 2012.

Competitors

The oil and gas industry is intensely competitive. We compete with numerous individuals and companies, including many major oil and gas companies, which have substantially greater technical, financial, and operational resources and staffs. Accordingly, there is a high degree of competition for desirable oil and gas leases and farmin and farmout agreements, suitable properties for drilling operations, and necessary drilling and completion equipment and services, as well as for access to funds. There are other competitors that have operations in the various areas of Bakken and Three Forks reserves and the presence of these competitors could adversely affect our ability to acquire additional leases and farmin and farmout agreements.

Hydraulic Stimulation

We have drilled and completed twelve operated wells since July 2010. Each of our wells contains a lateral section that has been subjected to hydraulic stimulation in order to improve the productivity of the well. As of the date of this Annual Report, we are currently in the process of drilling and completing five additional wells, each of which will be stimulated using stimulationthese same techniques. We have contracted with industry-standard third-party specialists for both the drilling and completion phases of these wells. To date, there have not been any environmental or safety incidents, citations, or suits related to the hydraulic stimulation operations used as part of the completion of these wells.

As part of the process of drilling exploratory or producing wells, we currently expect that substantially all of the horizontal wells that we may cause to be drilled will be completed using hydraulic stimulation techniques. We will use industry-standard, long-established third-party service providers for such endeavors. When we initiate any new well in the future, we will determine in advance whether it will be hydraulically fractured and, if so, we will include in the planning and budgetary process all costs associated with the fracture treatment. The costs of a well vary based on the depth to which it will be drilled, its horizontal length, and the completion technique to be used, which will include the added expenditure for the fracture treatment, as well as all related environmental and safety considerations.

4

Because we contract with industry-standard, long-established third-party service providers for all drilling, casing, and cementing services, we depend upon their industry expertise, safety processes, and best practices for conducting those operations. Our management, and that of our advisors, has significant, long-term experience with the engineering required to determine where and how a well should be drilled and whether the well should be hydraulically fractured as part of the completion process. Accordingly, we believe that we will be able to determine whether our third-party service providers are utilizing proper drilling and completion techniques. Nevertheless, we will rely on them, in the case of stimulation services, to:

· monitor the rate and pressure of the stimulation treatment in real time for any abrupt change in rate or pressure;

· evaluate the environmental impact of additives to the hydraulic stimulation fluid;

· minimize the use of water during the stimulation process; and

· dispose of any produced water in a manner that avoids any impact on other resources and is in full compliance with all federal, state, and local governmental regulations.

We and our third-party service providers are insured as to various drilling and environmental risks. Our well insurance policy limits are $5,000,000 in each individual instance with a deductible of $100,000. Our environmental liability policy limit is $1,000,000 per individual instance with a deductible of $100,000. Historically, we have not had any indemnification obligations in favor of those entities to whom we sell the oil that is produced from our wells and we do not expect to incur any such obligations in the future. Prior to the closing of the 2011 Merger, AEE Inc. and we, as co-working interest owners, have had reciprocal indemnification obligations to each other.

We rely fully on our third-party service providers to establish and carry out procedures to cope with any negative environmental impact that could occur in the event of a spill or leak in connection with their hydraulic stimulation services. The third-party service providers would be responsible for costs arising out of any surface spillage, mishandling of fluids, or leakage from their equipment, including chemical additives.

The specific chemical composition of the fluids utilized by the third-party service providers in hydraulic stimulation operations are expected to vary by project and by provider; however, we expect that the chemical composition of such fluids will meet industry standards and will be utilized in a manner that conforms to all relevant federal, state, and local rules and regulations.

In order to prevent the underground migration of fracture fluids, we, and we expect our third party service providers to, follow industry-standard practices in respect of casing, cementing, and testing to ensure good physical isolation of the fractured interval from other sections of the well. Our well construction processes and procedures conform to all relevant federal, state, and local rules and regulations. We believe that the large thickness of rock formations between the fractured interval and any potable water sources will minimize the risk of underground migration of fracture fluids. We would generally be responsible for any costs resulting from underground migration of fracture fluids, and we are not fully insured against this risk. The occurrence of a significant event resulting from the underground migration of fracture fluids or surface spillage, mishandling, or leakage of fracture fluids could have a materially adverse effect on our financial condition and results of operations. To date, there have been no such incidents, nor have the members of our management team encountered such an incident in their long-term experience in this industry.

Government Regulations

Our oil and gas operations are subject to various United States and Canadian federal, state / provincial, and local governmentalregulations. Matters subject to regulation include discharge permits for drilling operations, drilling, and abandonment bonds, reports concerning operations, the spacing of wells, and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. The production, handling, storage, transportation, and disposal of oil and gas, by-products thereof, and other substances and materials produced or used in connection with oil and gas operations are also subject to regulation under federal, state, provincial, and local laws and regulations relating primarily to the protection of human health and the environment. To date, expenditures related to complying with these laws, and for remediation of existing environmental contamination, have not been significant in relation to the results of our operations. The requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. For information about hydraulic stimulation regulatory matters, see “Risk Factors – Federal and state legislative and regulatory initiatives relating to hydraulic stimulation could result in increased costs, additional operating restrictions or delays, and inability to book future reserves.”

5

Research and Development

Our business plan is primarily focused on acquiring prospective oil and gas leases and/or operating existing wells located in the United States and Canada. We have expended zero funds on research and development in each of our last two fiscal years. We have developed and are in the process of implementing a future exploration and development plan.

Employees

As of March 31, 2013, our management team consists of Bradley M. Colby, our President, Chief Executive Officer, and Treasurer, Thomas Lantz, our Chief Operating Officer, and Kirk Stingley, our Chief Financial Officer. Including members of senior management, we currently employ 17 full-time operations, financial and administrative employees. We do not expect any material changes in the number of our employees over the next 12-month period. In the past, we have outsourced certain contract employment as needed. It is possible that we may utilize independent contractors to perform certain corporate activities during the next twelve months.

Item 1A. Risk Factors.

The information in this Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that the Company plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” variations of such words, and similar expressions identify forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

These forward-looking statements appear in a number of places and include statements with respect to, among other things:

· estimates of our oil and gas reserves;

· estimates of our future oil and natural gas production, including estimates of any increases or decreases in our production;

· our future financial condition and results of operations;

· our future revenues, cash flows and expenses;

· our access to capital and our anticipated liquidity;

· our future business strategy and other plans and objectives for future operations;

· our outlook on oil and gas prices;

· the amount, nature and timing of capital expenditures, including future development costs, and availability of capital resources to fund capital expenditures;

· our ability to access the capital markets to fund capital and other expenditures;

· the impact of political and regulatory developments;

· our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and

· the impact of federal, state and local political, regulatory and environmental developments in the United States and certain foreign locations where we conduct business operations.

6

These forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control, incident to the exploration for and development, production, and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described herein under “Risk Factors.”

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimates depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

We may not realize the benefits of the 2011 Merger.

There are significant risks and uncertainties associated with our recent merger with AEE Inc. We need to combine and integrate our operations andAEE Inc.’soperations into one company effectively and efficiently. Integration will require substantial management attention and could detract attention from the day-to-day business of the combined company. We could encounter difficulties in the integration process, such as the need to revisit assumptions about reserves, future production, revenues, capital expenditures, and operating costs, including synergies, the loss of key employees or commercial relationships or the need to address unanticipated liabilities. If we cannot continue to integrate our businesses andAEE Inc.’sbusinesses successfully, we may fail to realize the expected benefits of the 2011 Merger.

Re-sales of a substantial number of shares of our common stock in the public market after the 2011 Merger could materially adversely affect the market price of common stock.

In connection with closing the 2011 Merger, we issued toAEE Inc.’sstockholders approximately 36,476,539 shares of our common stock, substantially all of which will have no restrictions on resale. The re-sale of a substantial number of shares of our common stock may result in substantial fluctuations in the price of our common stock. In addition, the re-sale of a substantial number of shares of our common stock within a short period of time could cause our stock price to fall. The sale of those shares could also impair our ability to raise capital through sales of additional shares of our common stock.

There is no assurance that we will operate profitably or will generate positive cash flow in the future.

If we cannot generate positive cash flows in the future, or raise sufficient financing to continue our normal operations, then we may be forced to scale down or even close our operations. In particular, additional capital may be required in the event that drilling and completion costs for further wells increase beyond our expectations, or that we encounter greater costs associated with general and administrative expenses or offering costs. The occurrence of any of the aforementioned events could adversely affect our ability to meet our business plan.

We will depend heavily on outside capital to pay for the continued exploration and development of our properties. Such outside capital may include the sale of additional stock and/or commercial borrowing. Capital may not continue to be available if necessary to meet these continuing exploration and development costs or, if capital is available, it may not be on terms acceptable to us. The issuance of additional equity securities by us would result in a significant dilution in the equity interests of our current stockholders. Obtaining commercial loans, assuming those loans would be available, will increase our liabilities and future cash commitments.

If we are unable to obtain financing in the amounts and on terms deemed acceptable to us, we may be unable to continue our business and as a result may be required to scale back or cease operations for our business, the result of which would be that our stockholders would lose some or all of their investment.

7

A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.

A prolonged decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise capital. Because one of the methods that we have used to finance our operations has been the sale of equity securities, a decline in the price of our common stock could be especially detrimental to our liquidity and our continued operations. Any reduction in our ability to raise equity capital in the future could force us to reallocate funds from other planned uses and, if so, would have a significant negative effect on our business plans and operations, including our ability to develop new projects and continue our current operations. If our stock price declines, we may not be able to raise additional capital or generate funds from operations sufficient to meet our obligations.

If we are not successful in continuing to grow our business, then we may have to scale back or even cease our ongoing business operations.

Our success is significantly dependent on a successful acquisition, drilling, completion, and production program. We may be unable to locate recoverable reserves or operate on a profitable basis. If our business plan is not successful, and we are not able to operate profitably, our investors may lose some or all of their investment.

Trading of our stock may be restricted by the SEC’s “Penny Stock” regulations, which may limit a stockholder’s ability to buy and sell our stock.

The SEC has adopted regulations that generally define “penny stock” to be any equity security that has a market price (as defined) less than $5.00 per share. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers or “accredited investors.” The term “accredited investor” refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with his or her spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC, which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that, prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules may discourage investor interest in, and limit the marketability of, our common stock.

FINRA sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

8

Trading in our common stock on the OTC Bulletin Board and OTC Markets Group, Inc.’s OTCQB tier has been volatile, making it more difficult for our stockholders to sell their shares or liquidate their investments with predictability.

Our common stock is currently quoted on the OTC Bulletin Board and the OTC Markets Group, Inc.’s OTCQX tier. The trading price of our common stock has been subject to wide fluctuations. Trading prices of our common stock may fluctuate in response to a number of factors, many of which have been and will continue to be beyond our control. The stock market has generally experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies with no current business operation. There can be no assurance that trading prices and price earnings ratios previously experienced by our common stock will be matched or maintained. These broad market and industry factors may adversely affect the market price of our common stock, regardless of our operating performance.

In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted. Such litigation, if instituted, could result in substantial costs for us and a diversion of management’s attention and resources.

Our securities are considered highly speculative.

Our securities must be considered highly speculative, generally because of the nature of our business and the early stage of our exploration and development operations. We are engaged in the business of exploring and, if warranted, developing commercial reserves of oil and gas. Any profitability in the future from our business will be dependent upon our ability to locate and develop additional reserves of oil and gas, which itself is subject to numerous risk factors as set forth herein. Since we have not generated any material revenues, we expect that we will need to raise additional monies through the sale of our equity securities or debt in order to continue our business operations.

A portion of our properties are located in undeveloped areas. There can be no assurance that we will establish commercial discoveries on these properties.

Exploration for economic reserves of oil and gas is subject to a number of risk factors. Few properties that are explored are ultimately developed into producing oil and/or gas wells. A number of our properties are in the exploration stage only and are without proven reserves of oil and gas. We may not establish commercial discoveries on any of these properties that do not have any proved developed or undeveloped reserves. For information about our proved reserves, please see Note 15 to our consolidated financial statements as of and for the years ended December 31, 2012 and 2011, included in this Annual Report.

The potential profitability of oil and gas ventures depends upon factors beyond our control.

The potential profitability of oil and gas properties is dependent upon many factors beyond our control. For instance, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. These changes and events will likely materially affect our financial performance.

Adverse weather conditions can also hinder drilling and completion operations. A productive well may become uneconomic in the event water or other deleterious substances are encountered that impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is impregnated with water or other deleterious substances. The marketability of oil and gas that may be acquired or discovered will be affected by numerous factors beyond our control. These factors include the proximity and capacity of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production, and environmental protection. These factors cannot be accurately predicted and the combination of these factors may result in us not receiving an adequate return on invested capital.

Competition in the oil and gas industry is highly competitive and there is no assurance that we will be successful in acquiring the leases.

The oil and gas industry is intensely competitive. We compete with numerous individuals and companies, including many major oil and gas companies that have substantially greater technical, financial, and operational resources and staffs. Accordingly, there is a high degree of competition for desirable oil and gas leases, suitable properties for drilling operations, and necessary drilling and completion equipment and services, as well as for access to funds. We cannot predict if the necessary funds can be raised or that any projected work will be completed. Our budget anticipates our acquisition of additional acreage. This acreage may not become available or if it is available for leasing, we may not be successful in acquiring the leases. There are other competitors that have operations in areas of potential interest to us and the presence of these competitors could adversely affect our ability to acquire additional leases.

9

The marketability of natural resources will be affected by numerous factors beyond our control, which may result in us not receiving an adequate return on invested capital to be profitable or viable.

The marketability of natural resources that may be acquired or discovered by us will be affected by numerous factors beyond our control. These factors include market fluctuations in oil and gas pricing and demand, the proximity and capacity of natural resource markets and processing equipment, land tenure, land use and governmental regulations including regulations concerning the importing and exporting of oil and gas, and environmental protection regulations. The exact effect of these factors cannot be accurately predicted, but the combination of these factors may result in us not receiving an adequate return on invested capital to be profitable or viable.

Oil and gas operations are subject to comprehensive regulation, which may cause substantial delays or require capital outlays in excess of those anticipated, causing an adverse effect on us.

Oil and gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages that we may elect not to insure against due to prohibitive premium costs and other reasons. To date we have not been required to spend any material amount on compliance with environmental regulations. However, we may be required to do so in future and this may affect our ability to expand or maintain our operations.

Exploration and production activities are subject to certain environmental regulations, which may prevent or delay the commencement or continuance of our operations.

In general, our exploration and production activities are subject to certain federal, state, and local laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Compliance with these laws and regulations has not had a material effect on our operations or financial condition to date. Specifically, we are subject to legislation regarding emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in the industry.

We believe that our operations comply, in all material respects, with all applicable environmental regulations. We are not fully insured against all possible environmental risks.

Exploratory drilling involves many risks and we may become liable for pollution or other liabilities, which may have an adverse effect on our financial position.

Drilling operations generally involve a high degree of risk. Hazards such as unusual or unexpected geological formations, power outages, labor disruptions, blow-outs, sour gas leakage, fire, inability to obtain suitable or adequate machinery, equipment or labor, and other risks are involved. We may become subject to liability for pollution or hazards against which we cannot adequately insure or for which we may elect not to insure. Incurring any such liability may have a material adverse effect on our financial position and operations. For information about risks associated specifically with hydraulic stimulation, please see “Business – Hydraulic Stimulation” on page 4 of this Annual Report.

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Any change to government regulation/administrative practices may have a negative impact on our ability to operate and our profitability.

The laws, regulations, policies, or current administrative practices of any government body, organization, or regulatory agency in the United States or any other jurisdiction, may be changed, applied, or interpreted in a manner that will fundamentally alter the ability of our company to carry on our business. The actions, policies, or regulations, or changes thereto, of any government body, regulatory agency, or special interest groups, may have a detrimental effect on us. Any or all of these situations may have a negative impact on our ability to operate and/or our profitability.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Federal Clean Air Act. The EPA has adopted two sets of regulations under the existing Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, in April 2010, the EPA proposed to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of GHG emissions from such facilities would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoptions of any legislation or regulations that require reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirement also could adversely affect demand for the oil and natural gas that we produce.

Federal and state legislative and regulatory initiatives relating to hydraulic stimulation could result in increased costs, additional operating restrictions or delays, and inability to book future reserves.

Hydraulic stimulation is a process used by oil and natural gas exploration and production operators in the completion or re-working of certain oil and natural gas wells, whereby water, sand, and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. We engaged third parties to provide hydraulic stimulation or other well stimulation services to us in connection with the well for which we are the operator and we expect to do so in the future for other wells. Hydraulic stimulation is typically regulated by state oil and natural gas agencies and has not been subject to Federal regulation. However, due to concerns that hydraulic stimulation may adversely affect drinking water supplies, the EPA has commenced a study of the potential adverse effects that hydraulic stimulation may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic stimulation practices. Additionally, legislation has been introduced in Congress to amend the Federal Safe Drinking Water Act to subject hydraulic stimulation processes to regulation under that Act and to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic stimulation process. If enacted, such a provision could require hydraulic stimulation activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping requirements, and meet plugging and abandonment requirements.

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In unrelated oil spill legislation being considered by the U.S. Senate in the aftermath of the April 2010 Macondo well release in the Gulf of Mexico, Senate Majority Leader Harry Reid has added a requirement that natural gas drillers disclose the chemicals that are pumped into the ground as part of the hydraulic stimulation process. Disclosure of chemicals used in the stimulation process could make it easier for third parties opposing hydraulic stimulation to initiate legal proceedings based on allegations that specific chemicals used in the stimulation process could adversely affect groundwater. Certain states and other agencies have adopted or are considering similar disclosure legislation, moratoria, or enforcement initiatives relating to hydraulic stimulation. Adoption of legislation or of any implementing regulations placing restrictions on, or imposing reporting and disclosure obligations regarding, hydraulic stimulation activities could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic stimulation, resulting in reduced amounts of oil and natural gas being produced and booked as reserves in the future, as well as increase our costs of compliance and doing business.

Our Bylaws contain provisions indemnifying our officers and directors against all costs, charges, and expenses incurred by them.

Our Bylaws contain provisions with respect to the indemnification of our officers and directors against all costs, charges, and expenses, including an amount paid to settle an action or satisfy a judgment, (i) actually and reasonably incurred and (ii) in a civil, criminal, or administrative action or proceeding to which such person is made a party by reason of such person being or having been one of our directors or officers.

Investors’ interests in us will be diluted and investors may suffer dilution in their net book value per share if we issue additional shares or raise funds through the sale of equity securities.

In the event that we are required to issue any additional shares or enter into private placements to raise financing through the sale of equity securities, investors’ interests in us will be diluted and investors may suffer dilution in their net book value per share depending on the price at which such securities are sold. If we issue any such additional shares, such issuances also will cause a reduction in the proportionate ownership and voting power of all other stockholders. Further, any such issuance may result in a change in our management and directors.

We have never paid cash dividends and do not intend to do so.

We have never declared or paid cash dividends on our common stock. We currently plan to retain any earnings to finance the growth of our business rather than pay cash dividends. Payments of any cash dividends in the future will depend on our financial condition, results of operations, and capital requirements, as well as other factors deemed relevant by our board of directors.

Our Bylaws do not contain anti-takeover provisions, which could result in a change of our management and directors if there is a take-over of us.

We do not currently have a stockholder rights plan or any anti-takeover provisions in our Bylaws. Without any anti-takeover provisions, there is no deterrent for a take-over of us, which may result in a change in our management and directors.

Item 2. Properties.

We own an undivided 50% working interest in approximately 7,623 net acres located within the Spyglass Property, primarily in Divide County, North Dakota. An unrelated third-party owns the other undivided 50% working interest in such net acres. To date, we have agreed to participate in 53 non-operated wells located within the Spyglass Property areas, at various levels of participation. As of December 31, 2012, 46 of the non-operated wells are producing / shut in and the remaining 7 wells have been, or are in the process of being, drilled or completed. A listing of our Spyglass wells and the status of each well as of December 31, 2012 is discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, below. Our Spyglass Property wells currently produce approximately 1,800 barrels of oil and 1.1 million mmcf of gas per day.

We own a 25% working interest in oil and gas leases covering approximately 4,555 aggregate net acres within in the West Spyglass Prospect, located primarily in Western Divide County, North Dakota, and eastern Sheridan County, Montana. We sold 75% of the working interest to an unrelated third party during 2011. Post-closing, we remain the operator on that acreage.

We own a 100% working interest in oil and gas leases covering approximately 5,914 net acres within the NE Montana Prospect, located in Sheridan and Daniels counties, Montana.

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We own a 33% working interest in oil and gas leases covering approximately 2,757 net acres located in the Glacier Prospect, primarily in Toole County, Montana.

We own a 100% working interest in oil and gas leases covering approximately 697 net acres located within the Sidney North Prospect, primarily in Richland County, Montana.

We own a 100% working interest in oil and gas leases covering approximately 683 net acres located within the Benrude Property, primarily in Roosevelt County, Montana. In 2012, we completed a 3-D seismic analysis of the Benrude Property sometime in 2012. We are currently evaluating the results of the 3-D seismic analysis, in order to determine our development strategy with respect to the Benrude acreage.

We own a 100% working interest in oil and gas leases covering approximately 329 net acres located within the Mustang Prospect, located in Divide Country, North Dakota, outside of the boundaries of our Spyglass Property and West Spyglass Prospect.

We own a 100% working interest in the Hardy Property, containing approximately 4,300 net acres located in southeastern Saskatchewan, Canada. Our working interest in the Hardy Property is subject to certain, well-specific farmout agreements that reduce our working interests in those particular wells. Our Canadian operations currently produce approximately 60 barrels of oil per day.

The following is a summary of our developed acreage as of December 31, 2012:

Property / Prospect	Working Interest			Gross Acres		Net Acres		Number of Leases		Earliest Lease Expiration Date	Latest Lease Expiration Date
Hardy		100	%		960		960		2	April 2014	April 2014
Spyglass		50	%		18,750		4,006		497	Held by Production	Held by Production
Totals					19,710		4,966		499

The following is a summary of our undeveloped acreage as of December 31, 2012:

Property / Prospect	Working Interest			Gross Acres		Net Acres		Number of Leases		Earliest Lease Expiration Date	Latest Lease Expiration Date
Hardy		100	%		3,340		3,340		4	April 2014	April 2014
Spyglass		50	%		14,733		3,883		96	April 2013	August 2017
Benrude		100	%		1,120		683		29	January 2013	July 2015
Glacier		33	%		8,271		2,757		406	May 2013	June 2015
Mustang		100	%		329		329		12	July 2015	August 2015
NE Montana		100	%		10,960		5,914		63	January 2015	December 2016
Sidney North		100	%		834		697		30	July 2014	October 2015
West Spyglass		25	%		42,444		4,555		436	February 2013	August 2017
Totals					82,031		22,158		1,076

Additional information regarding our oil and gas properties can be found in Note 5 and Note 15 to our financial statements as of and for the years ended December 31, 2012 and 2011, which are included in Item 8 of this document (see pages F-17 and F-28, respectively)

We currently lease 5,294 square feet of office space in Littleton, Colorado, which we believe to be sufficient for the operation of our business for the foreseeable future. The current lease agreement expires in December 2014.

We do not own or lease any other properties.

Item 3. Legal Proceedings.

We are not currently a party to any material legal proceedings.

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Item 4. Mine Safety Disclosures.

Not applicable.

PART II

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

Our common stock, par value $0.001, is dually quoted on the OTC Bulletin Board and on the OTC Markets Group, Inc.’s OTCQX tier under the symbol “AMZG.” From November 7, 2005 until January 18, 2012, our symbol was “EERG” except from December 20, 2011 to January 17, 2012 when our symbol was “EERGD” in connection with our 2011 Merger. Active trading in the market of our common stock commenced on February 2, 2006. The following table sets forth the high and low bid prices for our common stock for the periods indicated, as reported by OTC Markets Group, Inc. Such quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not necessarily represent actual transactions. Historical prices have been adjusted to reflect the effect of the 1.0-for-4.5 reverse stock-split that occurred on December 20, 2011.

	Bid
	High		Low
Year ended December 31, 2012:
First Quarter	$	1.40	$	0.56
Second Quarter		0.95		0.64
Third Quarter		0.77		0.60
Fourth Quarter		0.88		0.59
Year ended December 31, 2011:
First Quarter		1.89		0.50
Second Quarter		2.03		1.40
Third Quarter		1.49		0.81
Fourth Quarter		1.75		0.81

As of March 31, 2013, there were 47 holders of record of our common stock.

We have never declared or paid any cash dividends on our common stock. For the foreseeable future, we expect to retain any earnings to finance the operation and expansion of our business.

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

THE FOLLOWING PRESENTATION OF OUR MANAGEMENT'S DISCUSSION AND ANALYSIS SHOULD BE READ IN CONJUNCTION WITH THE FINANCIAL STATEMENTS AND OTHER FINANCIAL INFORMATION INCLUDED ELSEWHERE IN THIS REPORT.

A Note About Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on current management's expectations. These statements may be identified by their use of words like “plans,” “expect,” “aim,” “believe,” “projects,” “anticipate,” “intend,” “estimate,” “will,” “should,” “could,” and other expressions that indicate future events and trends. All statements that address expectations or projections about the future, including statements about our business strategy, expenditures, and financial results are forward-looking statements. We believe that the expectations reflected in such forward-looking statements are accurate. However, we cannot assure you that such expectations will occur.

Actual results could differ materially from those in the forward-looking statements due to a number of uncertainties, including, but not limited to, those discussed in this section. Factors that could cause future results to differ from these expectations include general economic conditions, further changes in our business direction or strategy, competitive factors, oil and gas exploration uncertainties, and an inability to attract, develop, or retain technical, consulting, or managerial agents or independent contractors. As a result, the identification and interpretation of data and other information and their use in developing and selecting assumptions from and among reasonable alternatives requires the exercise of judgment. To the extent that the assumed events do not occur, the outcome may vary substantially from anticipated or projected results, and, accordingly, no opinion is expressed on the achievability of those forward-looking statements. No assurance can be given that any of the assumptions relating to the forward-looking statements specified in the following information are accurate, and we assume no obligation to update any such forward-looking statements. You should not unduly rely on these forward-looking statements, which speak only as of the date of this Annual Report, except as required by law; we are not obligated to release publicly any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this Annual Report or to reflect the occurrence of unanticipated events.

Industry Outlook

The petroleum industry is highly competitive and subject to significant volatility due to numerous market forces. Crude oil and natural gas prices are affected by market fundamentals such as weather, inventory levels, competing fuel prices, overall demand, and the availability of supply.

Worldwide oil prices reached historical highs during the last half of 2008, before tumbling amid worldwide economic crisis. Oil prices stabilized during 2009 and remained stable throughout 2010. Since December 31, 2010, oil prices increased rapidly, topping $100 per barrel in mid-March 2011 and again in March 2012 before settling back into the mid-eighties at the end of the third quarter.

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Oil prices cannot be predicted with any certainty and have significantly affected profitability and returns for upstream producers. Historically, crude oil prices have averaged approximately $86 per barrel over the past five years, per the New York Mercantile Exchange (“NYMEX”). However, during that time, NYMEX oil prices have experienced wide fluctuations in prices, ranging from $37 per barrel to $145 per barrel, with the median price of $86 per barrel. NYMEX oil prices averaged approximately $95 for both of the years ended December 31, 2012 and 2011.

While local supply/demand fundamentals are a decisive factor affecting domestic natural gas prices over the long term, day-to-day prices may be more volatile in the futures markets, such as on the NYMEX and other exchanges, making it difficult to forecast prices with any degree of confidence.

Company Overview

The address of our principal executive office is 2549 W. Main Street, Suite 202, Littleton, Colorado, 80120. Our telephone number is 303-798-5235.

Our common stock is quoted on the OTC Bulletin Board and the OTC Markets Group Inc.’s OTCQX tier under the symbol “AMZG.”

Our Company was incorporated in the State of Nevada under the name “Golden Hope Resources Corp.” on July 25, 2003 and is engaged in the acquisition, exploration, and development of natural resource properties of merit. On November 7, 2005, we filed documents with the Nevada Secretary of State to change our name to “Eternal Energy Corp.” by way of a merger with our wholly-owned subsidiary, Eternal Energy Corp., which was formed solely to facilitate the name change. In December 2011, we again filed documents with the Nevada Secretary of state to change our name to “American Eagle Energy Corporation”, in conjunction with our acquisition of, and merger with, AEE Inc.

Since our inception, we have entered into participation agreements related to oil and gas exploration projects throughout the continental United States, including Colorado, Montana, Nevada, North Dakota, Texas, and Utah, as well as in the province of Saskatchewan, Canada, and areas located in the North Sea.

As of December 31, 2012, we are principally engaged in exploration activities within our Spyglass Property, located in Divide County, North Dakota, where we target the extraction of oil and natural gas reserves from the Bakken and Three-Forks formations. We also hold an interest in a small number of wells located in southeastern Saskatchewan, Canada, though our focus on these wells will continue to diminish as we aggressively pursue the development of our Spyglass Property.

In addition to our existing wells, we own undeveloped acreage interests in the Glacier Prospect, located in Toole County, Montana, the Sidney North Prospect, located in Richland County, Montana and the West Spyglass Prospect, located in an area adjacent to our Spyglass Property in Divide County, North Dakota and Sheridan County, Montana.

Our current operations consist of 17 full-time employees.

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Oil & Gas Wells

As stated above, we are primarily focused on drilling and completing wells located within our Spyglass Property, located in western North Dakota. As of December 31, 2012, we have successfully drilled and completed 9 Spyglass wells, in which we own significant working interests, and for which we serve as the Operator. An additional 5 operated wells have been drilled and are awaiting completion as of December 31, 2012. All 5 of these wells are expected to be completed and put on production during the first quarter of 2013. Our working interest in our Spyglass operated ranges from 17.81% to 46.93%.

In addition, we have elected to participate as a non-operating working interest partner in the drilling of 53 wells within the Spyglass Property and areas within Divide County, North Dakota. As of December 31, 2012, 46 of these wells are producing. The remaining 7 wells are scheduled for completion during the first quarter of 2013. Our working interest ownership in these non-operated wells ranges from 0.03% to 43.82%.

We also operate three wells and participate as a non-operating working interest partner in a fourth well located in southeastern Saskatchewan (the “Hardy Property”). Our working interests in these four wells ranges from 50.00% to 85.00%. Though profitable from a cashflow perspective, the financial results stemming from the operation of our Canadian wells is significantly less favorable than those of our US wells. Accordingly, we will continue to evaluate the performance of our Hardy wells going forward. Should circumstances dictate, we may elect to shut in our Hardy wells and/or seek to sell our interest in such wells in the future.

We evaluate our oil and gas properties for potential impairment on a quarterly basis. At December 31, 2012, we recorded an impairment adjustment in the amount of $10,631,345 related to our Canadian oil and gas properties. There were no impairments evident as of December 31, 2012 relative to our US oil and gas properties.

A summary of our working interest in the Spyglass wells and the status of each well as of December 31, 2012 are as follows:

Well Name	Operator	Working Interest	Actual or Anticipated Spud Date	Current Status
Aarestad 4-34H-160N-97W	Kodiak Oil & Gas Inc.	0.63%	November 1, 2010	Producing
Adams 2-18H-163N-100W	SM Energy Company	18.52%	April 20, 2012	Producing
Anton 3-4-163N-101W(1)	American Eagle Energy Corporation	22.87%	June 15, 2012	Producing
August 4-26H	SM Energy Company	5.96%	August 17, 2012	Producing
Bagley 4-30-163N-100W	SM Energy Company	3.87%	April 4, 2011	Producing

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Baja 1522-04TFH-163N-99W	Samson Resources Company	0.63%	July 9, 2012	Producing
Baja 1522-5H	Samson Resources Company	0.63%	July 7, 2012	Producing
Bakke 3229-2TFH	Samson Resources Company	3.94%	November 8, 2012	Producing
Bakke 3229-3TFH	Samson Resources Company	3.94%	December 14, 2012	Waiting on Completion
Bakke 3229-4TFH	Samson Resources Company	3.94%	December 25, 2012	Waiting on Completion
Bakke 3229-5MBH	Samson Resources Company	3.94%	December 21, 2012	Waiting on Completion
Blazer 2-11-163N-98W	Samson Resources Company	0.94%	February 12, 2011	Producing
Border Farms 3130-1H	Samson Resources Company	17.54%	August 6, 2012	Producing
Border Farms 3130-2TFH	Samson Resources Company	17.54%	August 4, 2012	Producing
Border Farms 3130-6TFH	Samson Resources Company	17.54%	June 7, 2012	Producing
Camino 5-8-163N-98W	Samson Resources Company	1.25%	May 12, 2012	Producing
Christianson 15-12-163N-101W(1)	American Eagle Energy Corporation	17.81%	January 11, 2012	Producing
Christianson Bros. 15-33-164N-101W(1)	American Eagle Energy Corporation	21.39%	November 25, 2012	Waiting on Completion

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Cody 15-11-163N-101W(1)	American Eagle Energy Corporation	18.30%	March 22, 2012	Producing
Coplan 1-3-163N-101W(1)	American Eagle Energy Corporation	22.15%	April 25, 2012	Producing
Denali 13-21-163N-98W	Samson Resources Company	0.03%	December 23, 2010	Producing
Dewitt State 3-16-163-101	American Eagle Energy Corporation	14.06%	December 22, 2012	Waiting on Completion
Dorothy Ann 1-11H	Continental Resources	0.12%	December 10, 2012	Waiting on Completion
Elizabeth 3-4-163N-101W(1)	American Eagle Energy Corporation	22.68%	August 1, 2012	Producing
Gerhardsen 1-10H	Continental Resources	2.37%	January 22, 2011	Producing
Gjovig 0508-5MBH	Samson Resources Company	3.94%	December 24, 2012	Waiting on Completion
Gulbranson 1-1H-163N-100W	SM Energy Company	11.55%	September 13, 2012	Producing
Gulbranson 2-1H-163N-100W	SM Energy Company	11.51%	April 14, 2012	Producing
Haagenson 3-2-163N-101W	American Eagle Energy Corporation	43.82%	September 21, 2012	Producing
Jurasin 32-29-162N-100W	Crescent Point Energy Corp.	0.21%	October 15, 2011	Producing
Karen Bailard 3625-1TFH	Samson Resources Company	1.08%	October 6, 2012	Producing
Karlgaard 27-34-160-98H 1XP	Baytex Energy USA Ltd	0.57%	June 1, 2012	Producing
Lancaster 2-11H-162N-101W	Crescent Point Energy Corp.	6.23%	July 1, 2011	Producing
Legaard 4-25H-163N-101W	SM Energy Company	3.69%	July 19, 2011	Producing

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Leininger 3-10-1H	Mountainview Energy	1.17%	December 12, 2012	Waiting on Completion
Megan 14-12-163N-101W(1)	American Eagle Energy Corporation	17.88%	September 23, 2012	Producing
Mona Johnson 1-3	American Eagle Energy Corporation	46.93%	January 24, 2013	Waiting to Drill
Montclair 0112-2TFH	Samson Resources Company	1.08%	October 10, 2012	Producing
Montclair 1-12-163N-99W	Samson Resources Company	1.60%	November 7, 2011	Producing
Mustang 7-6-163N-98W	Samson Resources Company	0.32%	April 25, 2011	Producing
Muzzy 15-33S-164N-101W(1)	American Eagle Energy Corporation	22.87%	October 23, 2012	Waiting on Completion
Nielsen 1-12H-160N-97W	Continental Resources, Inc.	0.44%	December 21, 2010	Producing
Nomad 0607-1H	Samson Resources Company	17.54%	August 20, 2012	Producing
Nomad 0607-2TFH	Samson Resources Company	17.54%	August 18, 2012	Producing
Nomad 0607-05H	Samson Resources Company	17.54%	June 9, 2012	Producing
Nomad 0607-6TFH	Samson Resources Company	17.54%	June 5, 2012	Producing
Nomad 6-7-163N-99W	Samson Resources Company	28.22%	October 26, 2011	Producing
Olson 15-22-162N-100W	Baytex Energy USA	0.78%	August 11, 2011	Producing

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Reistad 1-1H-162N-102W	Murex Petroleum Corporation	5.50%	February 28, 2011	Producing
Ridgeway 25-36-163N-101W	Crescent Point Energy Corp.	1.88%	August 15, 2011	Producing
Riede 4-14H-163N-100W	SM Energy Company	0.34%	January 30, 2011	Producing
Silas 3-2N-163N-101W(1)	American Eagle Energy Corporation	24.61%	August 31, 2012	Producing
Stanley 8-1E-163N-102W(1)	American Eagle Energy Corporation	17.81%	December 18, 2012	Waiting on Completion
Terri Lynn 3-3-163N-101W	American Eagle Energy Corporation	34.52%	November 22, 2012	Waiting on Completion
Thomte 5-8-163N-99W	Samson Resources Company	6.36%	August 22, 2011	Producing
Thomte 0508-2TFH	Samson Resources Company	3.94%	October 20, 2012	Producing
Thomte 0508-3H	Samson Resources Company	3.94%	November 25, 2012	Producing
Titan 36-25-163N-99W	Samson Resources Company	0.29%	October 8, 2011	Producing
Titan 3625-2TFH	Samson Resources Company	1.08%	October 9, 2012	Producing
Torgeson 1-15H-163N-100W	SM Energy Company	4.38%	March 6, 2011	Producing
Violet 3-3-163N-101W	American Eagle Energy Corporation	20.20%	October 21, 2012	Producing
Wigness 5-8-1H	Mountainview Energy	1.56%	November 14, 2012	Producing
William Bailard 0112-1TFH	Samson Resources Company	1.08%	October 7, 2012	Producing

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Wolter 1-28H-163N-100W	SM Energy Company	1.30%	November 27, 2010	Producing
Wolter 13-9H-163N-100W	SM Energy Company	5.92%	June 26, 2011	Producing
Wolter 15-8H-163N-100W	SM Energy Company	1.54%	November 20, 2011	Producing
Yukon 12-1-163N-98W	Samson Resources Company	1.25%	February 28, 2011	Producing

(1) This well is included in the Carry Agreement to which we are a party as of December 31, 2012. Our working interest in this well is subject to change depending on the length of time it takes for the well to pay out.

Well Summary

The following tables summarize the number of our completed wells and our drilling activity for the years ended December 31, 2012 and 2011:

	December 31, 2012				December 31, 2011
Gross exploratory wells:	U.S.		Canada		U.S.		Canada
Beginning of period		-		-		-		-
Purchased / acquired		-		-		-		-
Drilled		-		-		-		-
Abandoned		-		-		-		-
End of period		-		-		-		-
Gross development wells:
Beginning of period		21.00		2.00		-		1.00
Purchased / acquired		-		-		-		-
Drilled		34.00		2.00		21.00		1.00
Abandoned		-		-		-		-
End of period		55.00		4.00		21.00		2.00

	Year Ended				Year Ended
	December 31, 2012				December 31, 2011
Net exploratory wells:	U.S.		Canada		U.S.		Canada
Beginning of period		-		-		-		-
Purchased / acquired		-		-		-		-
Drilled		-		-		-		-
Abandoned		-		-		-		-
End of period		-		-		-		-

22

	Year Ended				Year Ended
	December 31, 2012				December 31, 2011
Net development wells:	U.S.		Canada		U.S.		Canada
Beginning of period		0.50		1.75		-		1.00
Purchased / acquired		-		-		-		-
Drilled		4.30		1.35		0.50		0.75
Abandoned		-		-		-		-
End of period		4.80		3.10		0.50		1.75

The Company did not drill any dry exploratory or developmental wells during the years ended December 31, 2012 and 2011.

Acquisition of AEE Inc.

On February 23, 2011, we announced our intention to pursue a merger with AEE Inc. On April 8, 2011, we entered into a definitive merger agreement (that was amended on September 28, 2011, to extend the termination date), pursuant to which we formed a wholly-owned subsidiary into which AEE Inc. was merged. On December 20, 2011, we consummated the final steps in the merger transaction and trading of the common stock of the combined company commenced. The relevant documents for the merger were filed with the Secretary of State of Nevada effective November 30, 2011.

The ratio of stockholdings between the companies at the closing of the merger, exclusive of any then-outstanding options, was approximately 80% to the legacy stockholders of AEE Inc. and 20% to our legacy stockholders. Despite the fact that the AEE Inc.’s legacy stockholders held approximately 80% of the Company’s outstanding shares immediately following the merger, other factors present in the structure of the transaction resulted in the Company being determined to be the acquiring entity for financial reporting purposes. Specific factors that led to this conclusion included the fact that the majority of the merged company’s officers and Board of Directors membership consists of legacy Eternal Energy Corp. officers and directors. In addition, there is no single stockholder or organized group of stockholders of the former AEE Inc. that holds the largest minority voting interest in the merged company. Rather, the individual who owns the largest number of shares of the merged company’s voting stock is a legacy Eternal Energy stockholder and was a member of the Eternal Energy Corp.’s senior management and is a member of the merged company’s senior management team.

We completed the registration of the common stock that we issued to the legacy stockholders of AEE Inc. with the Securities and Exchange Commission on November 11, 2011.

Results of Operations for the Year Ended December 31, 2012 vs. 2011

The consolidated results of operations for the year ended December 31, 2012 include the results of operations of both American Eagle Energy Corporation and AEE Inc. and their respective subsidiaries. For financial reporting purposes, the consolidated results of operations for AEE Inc. for the period January 1, 2011 through December 20, 2011, the date of our merger, are excluded from our reportable 2011 results of operations due to accounting rules applicable to business combinations. However, for analysis purposes only, the following discussion includes references, where appropriate, to pro forma amounts, which represent the combined results of operations for the year ended December 31, 2011.

23

Our Spyglass Property represents the majority of our US holdings and is the primary focus of our ongoing and future operations. As discussed previously, we also participate in a small number of wells located within our Hardy Property, in southeastern Saskatchewan, Canada. The following is a summary of our well count as of December 31, 2012:

	US		Canada		Total
Operated wells – producing		9		3		12
Operated wells – waiting to be completed		5		-		5
Non-operated wells – producing		46		1		47
Non-operated wells – waiting to be completed		7		-		7
Totals		67		4		71

Overall, our revenues associated with the sale of oil and gas totaled $10,713,946 for the year ended December 31, 2012, compared to $864,918 for the year ended December 31, 2011, an increase of 1,139%. Our US wells accounted for 82.0% ($8,785,986) of our total sales for 2012. This percentage will continue to climb as we build our inventory of wells within our Spyglass Property going forward.

Due to lower than anticipate production volumes from our Hardy wells, resulting in a significant reduction of our proved Canadian reserves from 2011 to 2012, we were required to write-down the value of the Canadian oil and gas properties at year-end, pursuant to full-cost accounting rules. In doing so, we recognized an impairment expense of $10,631,345 related to our Hardy Property for the year ended December 31, 2012. The impairment expense represents a non-cash charge against our earnings.

Our results from operations for the year ended December 31, 2012 showed a net loss of ($9,292,784), compared to net income of $4,453,901 for the year ended December 31, 2011. Our basic and diluted loss per share for the year ended December 31, 2012 was ($0.20), compared to basic and diluted earnings per share of $0.49 and $0.37, respectively, for the year ended December 31, 2011. The 2011 earnings per share figures have been adjusted to reflect the effects of the 1.0-to-4.5 reverse stock split that occurred in December 2011.

Excluding the impairment expense recognized on the Hardy Property, our operating income for the year ended December 31, 2012 would have been $149,829, compared to an operating loss of ($1,917,117) for the year ended December 31, 2011. Furthermore, our revenues, less oil and gas production costs, was $$7,513,775 for the year ended December 31, 2012, compared to $327,796 for the year ended December 31, 2011. A discussion of the key components of our statements of operations and material fluctuations for the year ended December 31, 2012 and 2011 is provided below.

A comparison of the 2012 and 2011 oil and gas sales and lease operating expenses is as follows:

24

Consolidated:

The following table summarizes our oil and gas revenues and our lease operating expenses for the year ended December 31, 2012 and 2011.

	2012		2011
Oil sales	$	10,705,762	$	864,918
Gas sales		8,184		-
Total revenues	$	10,713,946	$	864,918
Lease operating expenses (“LOE”)	$	2,149,335	$	537,122
Oil sales volumes (barrels)		134,314		11,337
Gas sales volumes (mcf)		2,306		-
Total sales volumes (BOE)		134,698		11,337
Average oil sales price per barrel	$	79.71	$	76.29
Average gas sales price per mcf	$	3.55	$	-
Average LOE per BOE	$	15.96	$	47.38

The decrease in the average LOE per BOE from 2011 to 2012 is primarily due to the increase in the number of US wells, which operate at significantly lower expense levels than our Canadian wells due to significantly lower water levels.

US Operations:

We drilled and completed our first US operated well, the Christianson 15-11, in April 2012. Since that time, we have drilled and completed eight additional US operated wells. The following table summarizes the oil and gas revenues and lease operating expenses for our US operated wells for the years ended December 31, 2012 and 2011.

	2012		2011
US operated wells:
Oil sales	$	3,082,289	$	-
Gas sales		-		-
Total revenues	$	3,082,289	$	-
Lease operating expenses	$	157,708	$	-
Oil sales volumes (barrels)		37,892		-
Gas sales volumes (mcf)		-		-
Total sales volumes (BOE)		37,892		-
Average oil sales price per barrel	$	81.34	$	-
Average gas sales price per mcf	$	-	$	-
Average LOE per BOE	$	4.16	$	-

25

As of December 31, 2012, we own working interests in 53 non-operated producing wells located within the United States. The following table summarizes the oil and gas revenues and lease operating expenses for our US non-operated wells for the years ended December 31, 2012 and 2011.

	2012		2011
US non-operated wells:
Oil sales	$	5,695,513	$	402,436
Gas sales		8,184		-
Total revenues	$	5,703,697	$	402,436
Lease operating expenses	$	265,469	$	23,264
Oil sales volumes (barrels)		70,788		5,535
Gas sales volumes (mcf)		2,306		-
Total sales volumes (BOE)		71,172		5,535
Average oil sales price per barrel	$	80.46	$	72.71
Average gas sales price per mcf	$	3.55	$	-
Average LOE per BOE	$	3.73	$	4.20

We began depleting our US wells in 2012, during which time we recognized aggregate depletion expense totaling $1,547,186 ($14.19 per BOE) related to our US operated and non-operated wells.

Canadian Operations:

In April 2012, we drilled and completed our third Canadian operated well, the Hardy 14-17. As of December 31, 2012, we own working interests in and operate three producing wells within our Hardy Property. The following table summarizes the oil and gas revenues and lease operating expenses for our Canadian operated wells for the years ended December 31, 2012 and 2011.

	2012		2011
Canadian operated wells:
Oil sales	$	1,732,720	$	462,482
Gas sales		-		-
Total revenues	$	1,732,720	$	462,482
Lease operating expenses	$	1,573,587	$	512,234
Oil sales volumes (barrels)		23,208		5,802
Gas sales volumes (mcf)		-		-
Total sales volumes (BOE)		23,208		5,802
Average oil sales price per barrel	$	74.66	$	79.71
Average gas sales price per mcf	$	-	$	-
Average LOE per BOE	$	67.80	$	88.29

26

In 2012, we constructed a flowline to connect the Hardy 7-9 and Hardy 4-16 wells, which reduced our trucking expenses considerably, resulting in a lower average LOE per BOE compared to 2011. However, our Canadian wells continue to incur higher lease operating expenses than our US wells, primarily due to higher water content in the fluids produced by the wells and related trucking and disposal costs.

In July 2012, we elected to participate in our first non-operated well in Canada, the Minton HZ-1C11 well. The Minton HZ-1C11 well was completed and put on production in August, 2012.

	2012		2011
Canadian non-operated wells:
Oil sales	$	195,240	$	-
Gas sales		-		-
Total revenues	$	195,240	$	-
Lease operating expenses	$	152,572	$	-
Oil sales volumes (barrels)		2,425		-
Gas sales volumes (mcf)		-		-
Total sales volumes (BOE)		2,425		-
Average oil sales price per barrel	$	80.51	$	-
Average gas sales price per mcf	$	-	$	-
Average LOE per BOE	$	62.91	$	-

27

We recognized depletion expense totaling $1,253,207 ($48.89 per BOE) and $89,185 ($15.37 per BOE) related to our Canadian wells for the years ended December 31, 2012 and 2011, respectively. The increase is primarily due to the significant decline in our Canadian proved oil and gas reserves from December 31, 2011 to December 31, 2012, coupled with increased production year over year. The decline in our Canadian reserves from 2011 to 2012 is primarily due to lower than anticipated production from certain wells, which resulted in fewer proved, undeveloped reserves being recognized.

Despite generating positive cash flows, our Canadian wells continue to underperform compared to our US wells. Our intention is to aggressively expand our US operations through continued drilling within the Spyglass Property, as well as to conduct exploratory drilling in a number of our undeveloped prospects. Should circumstances dictate, we may elect to shut-in our Hardy wells at some point in the future and/or pursue the sale of such wells. No such determination has been made as of the date of this filing. ,

General and administrative expenses totaled $4,503,759 for the year ended December 31, 2012, compared to $2,148,126 for the year ended December 31, 2011. A discussion of the key components of our general and administrative expenses for the years ended December 31, 2012 and 2011 is as follows:

· Salaries and related payroll expenses totaled $2,607,163 for the year ended December 31, 2012, compared to $663,011 for the same period in 2011. Our staff consisted of 17 full-time employees as of December 31, 2012, compared to 4 full-time employees as of December 31, 2011. Pro-forma payroll expense for the year ended December 31, 2011 would have been $945,960 (6 employees).

· We incurred legal fees totaling $450,975 during the year ended December 31, 2012, compared to $637,708 for the same period in 2011. The majority of our 2011 legal fees were non-recurring and related to the then-proposed merger with AEE Inc., which closed in December 2011. Pro-forma legal fees for the year ended December 31, 2011 would have been $1,022,295.

· We incurred consulting fees totaling $176,447 during the year ended December 31, 2012, compared to $171,417 for the same period in 2011. The 2012 consulting fees included fees associated with the recruitment of new employees totaling $51,250, fees associated with our rebranding totaling $31,782 and fees associated with estimating our proved oil and gas reserves totaling $72,460. Included in the 2011 consulting fees were costs associated with obtaining a fairness opinion related to our then-proposed merger with AEE Inc., totaling $126,051. Pro-forma consulting fees for the year ended December 31, 2011 would have been $187,912.

28

· During the year ended December 31, 2012, we paid geological consulting fees to a related party, Synergy Resources LLC (“Synergy”) totaling $168,000. We incurred no such costs during the same period in 2011. Our consulting arrangement with Synergy is a legacy arrangement from AEE Inc., which was entered into prior to the merger of the two companies. We anticipate utilizing Synergy to provide us with geological consulting services throughout the coming year. Pro-forma consulting fees paid to Synergy for the year ended December 31, 2011 would have been $146,581.

· We incurred accounting fees totaling $311,360 during the year ended December 31, 2012, compared to $169,993 for the same period in 2011. The increase in fees is directly related to the growth and complexity of our accounting operations as a result of drilling and operating additional wells in 2012. Pro-forma accounting fees for the year ended December 31, 2011 would have been $278,919.

· We record the fair value of stock options as of the date of grant, and amortize this value over the vesting term of the options.During the year ended December 31, 2012, we granted 1,760,000 stock options to directors, employees and two independent contractors. As a result, we recognized stock-based compensation expense of $822,485 for the year ended December 31, 2012. We granted 975,000 stock options to members of our management and operational teams, as well as two directors and one independent contractor during 2011 and, in doing so, we recognized stock-based compensation expense of $30,614 for the year ended December 31, 2011.

· We incurred insurance expenses totaling $312,267 during the year ended December 31, 2012, compared to $101,775 for the same period in 2011. The increase is primarily due to obtaining tail coverage for our Directors & Officers insurance for the three-year period prior to the merger with AEE Inc., as well as to obtain well insurance for the wells that we are operating or anticipate drilling in the coming year. Our health insurance premiums also increased as a result of adding significant headcount during 2012. Pro-forma insurance expense for the year ended December 31, 2011 would have been $134,414.

· Beginning in 2012, we began recovering a portion of our general and administrative costs through the assessment of overhead charges on the wells for which we serve as Operator, pursuant to the various operating agreements to which we are a party. Such charges totaled $270,732 for the year ended December 31, 2012. We did not assess any overhead charges during 2011.

· We incurred travel and entertainment related expenses totaling $119,276 during the year ended December 31, 2012, compared to $40,141 for the same period in 2011. We incurred additional travel related costs throughout the year related to the general oversight of our drilling program. Pro-forma travel and entertainment expenses for the year ended December 31, 2011 would have been $71,779.

29

· We incurred computer-related expenses totaling $136,393 for the year ended December 31, 2012, compared to $10,967 for the same period in 2011. The increase is largely due to various computer software licenses that were obtained, as well as access to various oil and gas production and investor relations information services. In addition, we contracted with a third-party provider to manage our network security and to oversee our various IT programs. Pro-forma computer expenses for the year ended December 31, 2011 would have been $63,383.

· We incurred land management fees totaling $203,901 for the year ended December 31, 2012, compared to $72,733 for the same period in 2011. The increase is primarily due to our land management consultant working full-time for us in 2012, versus part-time in 2011. Pro-forma land management fees for the year ended December 31, 2011 would have been $193,158.

· Rent expense associated with our corporate offices totaled $110,364 for the year ended December 31, 2012, compared to $64,193 for the year ended December 31, 2011. In July 2012, we expanded our office space to accommodate the increase in our employee headcount. Pro-forma rent expense for the year ended December 31, 2011 would have been $75,735.

· Though our functional and reporting currency is the US Dollar, the majority of our transactions related to our Hardy Property are transacted in Canadian Dollars. During the year ended December 31, 2012, we recognized a foreign exchange gains totaling $40,131 versus foreign exchange losses of $17,886 for the same period in 2011.

· On a pro-forma basis, aggregate general and administrative expenses would have been $3,376,708 for the year ended December 31, 2011.

We routinely receive dividends from our equity investment in shares of Crescent Point Energy Corp.’s common stock. Dividend income totaled $63,654 for the year ended December 31, 2012, compared to $69,822 for the year ended December 31, 2011.

We recognized an estimated income tax benefit in the amount of $1,240,010 for the year ended December 31, 2012, compared to income tax expense of ($99,291) for the year ended December 31, 2011. Our effective tax rate for the year ended December 31, 2012 was 11.77% compared to (2.18%) for the year ended December 31, 2011. The change in our effective rate is primarily due to the tax effects of the impairment expense that we recognized in 2012 with respect to our Canadian oil & gas properties. Our deferred tax liabilities relate primarily to our merger with AEE Inc., which occurred in December 2011, and intangible drilling costs incurred during the year, which are immediately deductible for tax purposes but are amortized / depleted for financial reporting purposes.

Liquidity and Capital Resources

As of December 31, 2012, our assets totaled $96,914,112, which included, among other items, cash balances totaling $19,057,727, trade receivables totaling $24,750,444 and marketable securities valued at $1,049,859.

30

On December 28, 2012, we entered into a prepaid swap facility (the “Swap Facility”) with Macquarie Bank Limited (“MBL”), pursuant to which MBL agreed to advance up to $18 million. As of December 31, 2012, we had received $16 million under the agreement. The remaining $2 million was received in January 2013. The proceeds of the Swap Facility are recorded as a long-term liability and are earmarked to fund the acquisition and development of oil and gas properties within our Spyglass Property, as well as various corporate activities. Funds received under the Swap Facility will be repaid through a series of monthly payments from the sale of approximately 212,000 barrels of oil over the five-year period from January 2013 to December 2017, with a final balloon payment of $2 million, due in February 2018. The monthly volumes of oil production to be used to calculate the amounts of such tenders represent less than 25% of our current net production. The cost of the Swap Facility is based upon an equivalent variable annual interest rate of LIBOR plus 650 basis points, which was approximately 7.4% as of December 31, 2012.

As of December 31, 2012, we had a working capital deficit of $21,352,954, exclusive of our marketable securities, which, due to our intent to hold them for the foreseeable future, are presented as non-current assets on our December 31, 2012 balance sheet. Included in our working capital deficit is the current portion of the Swap Facility ($5,931,003), and the funds payable to a working interest partner in June 2013 ($5,600,000) in connection with our purchase of additional working interests in certain non-operated wells. In addition, the working capital deficit includes liabilities payable to our Carry Agreement partner ($4,956,817) relating to funds advanced to us for the last of the ten carried wells, the drilling of which had not yet commended as of December 31, 2012.

Our working capital deficit grew during the year ended December 31, 2012 as a result of our accelerating our drilling activities, which, as expected, were in advance of our anticipated corresponding revenues. Our senior management team is currently developing a plan to reduce our working capital deficit in the near future, which includes the evaluation of potential equity and long-term financing opportunities.

Historically, we have raised additional operating capital through private equity funding sources and from the sale of various oil and gas prospects and properties. However, no assurances can be given that we will be able to obtain sufficient operating capital through the sale of common stock and/or borrowing or that the development and implementation of our business plan will generate sufficient future revenues to sustain ongoing operations.

In April 2012, we entered into a Carry Agreement with a third-party working interest partner, pursuant to which (i) that partner agreed to fund 100% of our working interest share of the drilling and completion costs of up to six new oil and gas wells within our Spyglass Property, up to 120% of the anticipated cost of the wells and (ii) we will convey, for a limited duration, a portion of our interest in the pre-payout revenues of each carried well to that partner, as well as a portion of our working interest in the operating costs of the carried wells. If payout has not occurred within two years of the commencement date for such well, then the temporary assignment is to increase to 100% for years three through payout. Once payout has occurred (112% of the costs on a well-by-well basis), our respective revenue and working interests in each carried well will revert to our original interests in each such well. In July 2012, we amended the existing Carry Agreement to include an additional four wells. As of December 31, 2012, seven of the ten carried wells had been drilled, completed and placed on production. None of the seven carried wells had achieved payout as of December 31, 2012. Two additional carried wells were in the process of being drilled and completed as of December 31, 2012. The Company has received aggregated funding under the amended Carry Agreement totaling $32,847,102 as of December 31, 2012.

31

Litigation

As of December 31, 2012, we are not subject to any known, pending or threatened litigation.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Item 8. Financial Statements and Supplementary Data.

Our financial statements required to be included in Item 8 are set forth in the Index to Financial Statements on page F-1 of this Annual Report.

32

American Eagle Energy Corporation

Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

American Eagle Energy Corporation

Index to the Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2012 and 2011	F-2
Consolidated Statements of Operations and Comprehensive Income (Loss) for Each of the Two Years in the Period Ended December 31, 2012	F-3
Consolidated Statements of Stockholders’ Equity for Each of the Two Years in the Period Ended December 31, 2012	F-5
Consolidated Statements of Cash Flows for Each of the Two Years in the Period Ended December 31, 2012	F-6
Notes to the Consolidated Financial Statements	F-7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Stockholders of American Eagle Energy Corporation

We have audited the accompanying consolidated balance sheets of American Eagle Energy Corporation and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for the years then ended. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Eagle Energy Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

Hein & Associates LLP

Denver, Colorado

April 16, 2013

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

F-1

American Eagle Energy Corporation

Consolidated Balance Sheets

As of December 31, 2012 and 2011

	2012			2011
Current assets:
Cash	$	19,057,727		$	12,151,309
Trade receivables		24,750,444			3,105,079
Receivables from related parties		-			314,521
Income tax receivable		190,000			-
Prepaid expenses		133,067			45,690
Total current assets		44,131,238			15,616,599
Equipment and leasehold improvements, net of accumulated depreciation and amortization of $227,067 and $156,744, respectively		201,329			19,823
Oil and gas properties – subject to amortization, net of accumulated depletion of $2,978,403 and $183,238, respectively		43,291,543			15,798,307
Oil and gas properties – not subject to amortization		7,349,994			7,295,215
Marketable securities		1,049,859			1,254,434
Other assets		890,149			56,845
Total assets	$	96,914,112		$	40,041,223
Current liabilities:
Accounts payable	$	54,473,721		$	6,002,204
Amounts due to working interest partners		4,956,817			2,233,267
Accrued income taxes		-			1,460,137
Derivative liability		122,651			-
Current portion of long-term debt		5,931,003			-
Total current liabilities		65,484,192			9,695,608
Asset retirement obligation		441,609			34,628
Noncurrent portion of long-term debt		10,068,997			-
Deferred taxes		3,519,494			4,552,864
Total liabilities		79,514,292			14,283,100
Commitments and contingencies (Note 9)		-			-
Stockholders’ equity:
Common stock, $.001 par value, 194,444,444 shares authorized, 46,068,346 and 45,588,948 shares outstanding		46,068			45,589
Additional paid-in capital		27,094,941			25,948,311
Accumulated other comprehensive income (loss)		(32,091	)		180,447
Accumulated deficit		(9,709,098	)		(416,224	)
Total stockholders’ equity		17,399,820			25,758,123
Total liabilities and stockholders’ equity	$	96,914,112		$	40,041,223

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

F-2

American Eagle Energy Corporation

Consolidated Statements of Income and Comprehensive Income

For Each of the Two Years in the Period Ended December 31, 2012

	2012			2011
Oil and gas revenues	$	10,713,946		$	864,918
Operating expenses:
Oil and gas production costs		3,200,171			537,122
General and administrative expenses		4,503,759			2,148,126
Depreciation, depletion and amortization		2,860,187			96,787
Impairment of oil and gas properties, subject to amortization		10,631,345			-
Total operating expenses		21,195,462			2,782,035
Total operating (loss)		(10,481,516	)		(1,917,117	)
Other income (expense)
Interest income		8,335			5,286
Dividend income		63,654			69,822
Interest expense		(706	)		-
Unrealized loss on derivatives		(122,651	)		-
Gain on the sale of oil and gas property – not subject to amortization, net of costs		-			6,395,201
Total other income (expense)		(51,368	)		6,470,309
Income (loss) before taxes		(10,532,884	)		4,553,192
Income tax benefit (expense)		1,240,010			(99,291	)
Net income (loss)	$	(9,292,874	)	$	4,453,901
Net income (loss) per common share:
Basic	$	(0.20	)	$	0.49
Diluted	$	(0.20	)	$	0.37
Weighted average number of shares outstanding:
Basic		45,792,193			9,143,099
Diluted		45,792,193			12,161,472

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

F-3

American Eagle Energy Corporation

Consolidated Statements of Income and Comprehensive Income

For Each of the Two Years in the Period Ended December 31, 2012

	2012			2011
Net income (loss)	$	(9,292,874	)	$	4,453,901
Other comprehensive (loss) income:
Unrealized losses on securities, net of tax		(109,681	)		(235,016	)
Foreign currency translation adjustments		(102,857	)		-
Comprehensive income (loss)	$	(9,505,412	)	$	4,218,885

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

F-4

American Eagle Energy Corporation

Consolidated Statements of Stockholders’ Equity

For Each of the Two Years in the Period Ended December 31, 2012

							Accumulated
					Additional		Other						Total
	Common Stock				Paid-In		Comprehensive			Accumulated			Stockholders
	Shares		Amount		Capital		Income (Loss)			Deficit			Equity
Balance, January 1, 2011		9,112,405	$	9,112	$	9,231,199	$	415,463		$	(4,870,125	)	$	4,785,649
Shares issued during acquisition		36,476,543		36,477		16,686,498		-			-			16,722,975
Stock based compensation		-		-		30,614		-			-			30,614
Unrealized loss on securities, net of tax		-		-		-		(235,016	)		-			(235,016	)
Net Income		-		-		-		-			4,453,901			4,453,901
Balance, December 31, 2011		45,588,948	$	45,589	$	25,948,311	$	180,447		$	(416,224	)	$	25,758,123
Stock based compensation		-		-		822,485		-			-			822,485
Shares issued in private placement		100,000		100		109,900		-			-			110,000
Shares issued from exercise of stock options		153,830		153		34,471		-			-			34,624
Shares issued in debt financing		225,564		226		179,774		-			-			180,000
Unrealized loss on securities, net of tax		-		-		-		(109,681	)		-			(109,681	)
Foreign exchange translation adjustments		-		-		-		(102,857	)		-			(102,857	)
Net income		-		-		-		-			(9,292,874	)		(9,292,874	)
Balance, December 31, 2012		46,068,342	$	46,068	$	27,094,941	$	(32,091	)	$	(9,709,098	)	$	17,399,820

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

F-5

American Eagle Energy Corporation

Consolidated Statements of Cash Flows

For Each of the Two Years in the Period Ended December 31, 2012

	2012			2011
Cash flows provided by (used for) operating activities:
Net income (loss)	$	(9,292,874	)	$	4,453,901
Adjustments to reconcile net income (loss) to net cash used by operating activities:
Non-cash transactions:
Stock-based compensation		822,485			30,614
Depreciation, depletion and amortization		2,860,187			96,787
Accretion of discount on asset retirement obligation		5,301			1,548
Provision for deferred income taxes		(938,476	)		(385,846	)
Impairment of oil and gas properties		10,631,345			-
Unrealized loss on derivatives		122,651			-
Foreign currency adjustments		(51,556	)		-
Gain on the sale of oil and gas properties,  not subject to amortization		-			(6,395,201	)
Changes in operating assets and liabilities:
(Increase) decrease in prepaid expense		(87,377	)		(8,115	)
Increase in trade receivables		(798,868	)		(568,916	)
Increase in income taxes receivable		(190,000	)		-
(Increase) decrease in receivables from related parties		314,521			(314,521	)
Increase in deposits		(3,304	)		-
Increase in accounts payable		1,954,489			1,047,508
Increase (decrease) in income taxes payable		(1,460,137	)		485,137
Net cash provided by (used for) operating activities		3,888,387			(1,557,104	)
Cash flows provided by (used for) investing activities:
Cash obtained in acquisition		-			5,598,916
Proceeds from the partial sale of oil and gas properties		-			227,079
Proceeds from the partial sale of oil and gas prospects		227,661			9,234,341
Proceeds from the conveyance of working interests		3,789,989			-
Proceeds from the sale of equipment		1,100			700
Additions to oil and gas properties		(18,914,663	)		(5,928,820	)
Additions to equipment and leasehold improvements		(252,929	)		(7,432	)
Increase in amounts due to Carry Agreement partner		2,723,550			2,233,267
Purchase of certificates of deposit		(50,000	)		(50,000	)
Purchase of marketable securities		(51,301	)		-
Net cash provided by (used for) investing activities		(12,526,593	)		11,308,051
Cash flows provided by financing activities:
Proceeds from issuance of stock		110,000			-
Proceeds from exercise of stock options		34,624			-
Proceeds from issuance of long-term debt		16,000,000			-
Commissions paid on issuance of long-term debt		(600,000	)		-
Net cash provided by financing activities		15,544,624			-
Net increase in cash		6,906,418			9,750,947
Cash - beginning of period		12,151,309			2,400,362
Cash - end of period	$	19,057,727		$	12,151,309

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

F-6

American Eagle Energy Corporation

Consolidated Statements of Cash Flows

For Each of the Two Years in the Period Ended December 31, 2012

Supplemental Disclosure of Cash Flow Information

	2012		2011
Cash paid during the period for:
Interest	$	706	$	-
Income taxes		1,255,000		10,438

Supplemental Disclosure of Non-Cash Investing and Financing Activities

	2012		2011
Stock issued in acquisition	$	-	$	16,722,975
Stock issued in connection with debt financing		180,000		-
Property additions included in accounts payable		25,670,531		1,223,505
Recording of asset retirement obligation		406,981		1,913

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

F-7

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

1. Description of Business

American Eagle Energy Corporation (the “Company”) was incorporated in the state of Nevada in March 2003 under the name Golden Hope Resources. In July 2005, the Company changed its name to Eternal Energy Corp. In December 2011, the Company changed its name to American Eagle Energy Corporation, in connection with its acquisition of, and merger with, American Eagle Energy Inc. (“AEE Inc.”). See Note 3.

The Company engages in the acquisition, exploration, development and producing of oil and gas properties. The Company is primarily focused on extracting proved oil reserves. At December 31, 2012, the Company had entered into participation agreements related to oil and gas exploration projects in the Spyglass Property and West Spyglass Prospect, located in Divide County, North Dakota, and Sheridan County, Montana and the Hardy Property, located in southeastern Saskatchewan, Canada. In addition, the Company owns working interests in mineral leases located in Richland, Roosevelt and Toole Counties in Montana.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, AMZG, Inc., EERG Energy ULC (Canadian) and AEE Canada Inc. (Canadian). All material intercompany accounts, transactions and profits have been eliminated.

Certain reclassifications have been made to prior year balances to conform to the current year’s presentation.

In December 2011, the Company announced a 1.0-for-4.5 reverse stock split. As a result, all share and per share information included in these consolidated financial statements has been presented on a post-reverse-split basis.

Revenue Recognition

Revenue from the sale of oil and gas is recognized when the terms of the sale have been finalized and the oil has been delivered to the purchaser. The Company records the sale of its interests in prospects when the terms of the transaction are final and the sales price is determinable.

Concentration of Credit Risk

At December 31, 2012, the Company had $24,718,972 on deposit that exceeded the United States (FDIC) federally insurance limit of $250,000 per bank.

F-8

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

Foreign Currency Adjustments

The functional currency of the Company’s wholly-owned first-tier subsidiaries, EERG Energy ULC (“EERG”) and AEE Canada, Inc. (“AEE Canada”), is the Canadian Dollar. EERG Energy ULC’s and AEE Canada, Inc.’s asset and liability account balances are translated into US Dollars at the exchange rate in effect as of the balance sheet dates. Gains and losses realized upon the settlement of foreign currency transactions are included in the Company’s results of operations. The Company recognized transaction gains (losses) relating to foreign exchange rates totaling ($40,131) and $17,186 for the years ended December 31, 2012 and 2011, respectively. Foreign currency translation adjustments are presented as other comprehensive income.

Components of Other Comprehensive Income

Comprehensive income consists of net income and other gains and losses affecting stockholders’ equity that, under generally accepted accounting principles, are excluded from net income. For the Company, such items consist of unrealized gains (losses) on marketable securities and foreign currency translation adjustments.

Cash and Cash Equivalents

Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.

Receivables

Receivables are stated at the amount the Company expects to collect. In certain instances, the Company has the legal right to offset undistributed revenues from its operated wells against uncollected receivables from its working interest partners. The Company considers the following factors when evaluating the collectability of specific receivable balances: credit-worthiness of the debtor, past transaction history with the debtor, current economic industry trends, and changes in debtor payment terms. If the financial condition of the Company’s debtors were to deteriorate, adversely affecting their ability to make payments, additional allowances would be required.

The Company maintains an estimated allowance for doubtful accounts for estimated losses resulting from the inability of its customers to make required payments. Changes to the allowance for doubtful accounts made as a result of management’s determination regarding the ultimate collectability of such accounts are recognized as a charge to the Company’s earnings. Specific receivable balances that remain outstanding after the Company has used reasonable collection efforts are written off through a charge to the valuation allowance and a credit to the receivable. 

F-9

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

At December 31, 2012 and 2011, the Company has determined that all receivable balances are fully collectible and, accordingly, no allowance for doubtful accounts has been recorded.

Equipment and Leasehold Improvements

Equipment and leasehold improvements are recorded at cost. Expenditures for major additions and improvements are capitalized and depreciated or amortized over the estimated useful lives of the related assets using the straight-line method for financial reporting purposes. The estimated useful lives for significant property and equipment categories are as follows:

Furniture and equipment	3 years
Leasehold improvements	lesser of useful life or lease term

When equipment and improvements are retired or otherwise disposed of, the cost and the related accumulated depreciation are removed from the Company’s accounts and any resulting gain or loss is included in the results of operations for the respective period.

Expenditures for minor replacements, maintenance and repairs are charged to expense as incurred.

Oil and Gas Properties and Prospects

The Company follows the full-cost method of accounting for its investments in oil and gas properties.Under the full-cost method, all costs associated with the acquisition, exploration or development of properties, are capitalized into appropriate cost centers within the full-cost pool. Internal costs that are capitalized are limited to those costs that can be directly identified with acquisition, exploration, and development activities undertaken and do not include any costs related to production, general corporate overhead, or similar activities. Cost centers are established on a country-by-country basis.

Capitalized costs and estimated future development and abandonment costs for each of the Company’s cost centers are amortized on the unit-of-production basis using proved oil and gas reserves. The cost of investments in unproved properties and major development projects are excluded from capitalized costs to be amortized until it is determined that proved reserves can be assigned to the properties. Until such a determination is made, the properties are assessed annually to ascertain whether impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that the well is dry.  

F-10

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

As of the end of each reporting period, the capitalized costs of each cost center are subject to a ceiling test, in which the costs may not exceed the cost center ceiling. The cost center ceiling is equal to (i) the present value of estimated future net revenues computed by applying average monthly prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus (ii) the cost of properties not being amortized; plus (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; less (iv) income tax effects related to differences between the book and tax basis of the properties. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. The Company recognized $10,206,031 and $0 of impairment losses associated with its Canadian cost center for the years ended December 31, 2012 and 2011, respectively.

Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.

Deferred Loan Costs

The Company capitalizes costs that are directly related to securing bank loans and other types of long-term financing and amortizes such costs over the life of the corresponding debt using the effective interest method.

Derivatives

The Company reports its price swap derivative at its fair market value as of each period end. Unrealized gains (losses) for the period associated with the price swap derivative are included in the Company’s results of operations.

Asset Retirement Obligations

The Company records estimated asset retirement obligations related to the future plugging and abandoning of its existing wells in the period in which the wells are completed. The initial recording of an asset retirement obligation results in an increase in the carrying amount of the related long-lived asset and the creation of a liability. The portion of the asset retirement obligation expected to be realized during the next 12-month period is classified as a current liability, while the portion of the asset retirement obligation expected to be realized during subsequent periods is discounted and recorded at its net present value. The discount factors used to determine the net present value of the Company’s asset retirement obligation range from 4.2% to approximately 7.2%, which represents the Company’s estimated incremental borrowing rate as of December 31, 2012.

F-11

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

Changes in the noncurrent portion of the asset retirement obligation due to the passage of time are accreted using the interest method. The amount of change is recognized as an increase in the liability and an accretion expense in the statement of operations. Changes in either the current or noncurrent portion of the Company’s asset retirement obligation resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the related long-lived asset.

Stock-Based Compensation

The Company measures compensation cost for all stock-based awards at fair value on the date of grant and recognizes compensation expense in its statements of operations over the service period that the awards are expected to vest. The Company has elected to recognize compensation cost for all options with graded vesting on a straight-line basis over the vesting period of the entire option. The Company recognized stock-based compensation expense of $822,485 and $30,614 for the years ended December 31, 2012 and 2011, respectively.

Fair Value of Financial Instruments

Fair value is the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

The Company uses Level 2 inputs to determine the fair value of certain warrants to purchase shares of common stock of an entity that is traded on the Canadian National Stock Exchange. The warrants are valued using the Black Scholes Option Pricing Model, which includes a calculation of historical volatility of the stock.

Basic and Diluted Earnings Per Share

Basic earnings per common share is computed by dividing net earnings available to common stockholders by the weighted average number of common shares outstanding during the period. For periods in which the Company recognizes net income, diluted earnings per common share is computed in the same way as basic earnings per common share except that the denominator is increased to include the number of additional common shares that would be outstanding if all potential common shares had been issued that were dilutive. For periods in which the Company recognizes losses, the calculation of diluted earnings per share is the same as the calculation of basic earnings per share. See Note 14 for the calculation of basic and diluted weighted average common shares outstanding for the years ended December 31, 2012 and 2011.

Income Taxes

F-12

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized for the future tax benefits and consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax balances. Deferred income tax assets and liabilities are measured using enacted or substantially enacted tax rates expected to apply to the taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and, thus, are not considered to be available for distribution to the parent company. Net operating loss carry forwards and other deferred tax assets are reviewed annually for recoverability and, if necessary, are recorded net of a valuation allowance. See Note 13 for a summary of the Company’s income tax expense (benefit) for the years ended December 31, 2012 and 2011.

Liquidity

The Company finances its oil and gas exploration and development activities and corporate operations through a combination of internally generated funds, external debt financing and sales of its common stock. As of December 31, 2012, the Company had a working capital deficit of ($21,352,954). The Company is currently developing a plan to reduce its working capital deficit, which may include potential equity sales or long-term borrowings.

Use of Estimates and Assumptions

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent obligations in the financial statements and accompanying notes. The Company’s most significant assumptions are the estimates used in the determination of the deferred income tax asset valuation allowance, the valuation of oil and gas reserves to which the Company owns rights, estimates related to the Company’s asset retirement obligations, valuation of the warrants held by the Company as investments and valuation of assets acquired via merger. The estimation process requires assumptions to be made about future events and conditions, and as such, is inherently subjective and uncertain. Actual results could differ materially from these estimates.

New Accounting Pronouncements

In January 2013, the Financial Accounting Standards Board (“FASB”) issued ASC Update No. 2013-01 (“ASC No. 2013-01”), The objective of ASC No. 2013-01 is to clarify that the scope of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASC No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASC No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The amendments are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The disclosures required by the amendments are required to be applied retrospectively for all comparative periods presented. The Company does not believe the adoptions of this update will have a material impact on the Company’s consolidated financial statements.

F-13

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

3. Acquisition of American Eagle Energy Inc.

On December 20, 2011, the Company finalized its merger transaction with AEE Inc. Prior to the transaction, AEE Inc. operated as a publicly traded company with oil and gas holdings in North Dakota, Texas and southeastern Saskatchewan, Canada and was a working interest partner to the Company with respect to its Hardy Property and certain proved oil and gas properties and unproven oil and gas prospects located in North Dakota. The Company acquired AEE Inc. in order to leverage the two companies’ respective oil and gas holdings.

Pursuant to the terms of the Merger Agreement, the Company issued 36,476,543 shares of its common stock to acquire 100% of the then-outstanding shares of AEE Inc.’s common stock, which resulted in AEE Inc. becoming a wholly owned subsidiary of the Company. Immediately subsequent to the transaction, legacy AEE Inc. stockholders owned approximately 80% of the shares of the Company’s outstanding common stock, exclusive of outstanding options to purchase shares of the Company’s common stock and shares of AEE Inc.’s common stock. The shares of common stock that were issued in connection with the Company’s acquisition of AEE Inc. were registered with the SEC on November 11, 2011.

Despite the fact the AEE Inc.’s legacy stockholders held approximately 80% of the Company’s outstanding shares immediately following the merger, other factors present in the structure of the transaction resulted in the Company being determined to be the acquiring entity for financial reporting purposes. Specific factors that led to this conclusion included the fact that the majority of the merged company’s officers and Board of Directors membership consists of legacy Eternal Energy Corp. officers and directors. In addition, there is no single stockholder or organized group of stockholders of the former AEE Inc. that holds the largest minority voting interest in the merged company. Rather, the individual who owns the largest number of shares of the merged company’s voting stock is a legacy Eternal Energy stockholder and was a member of the Eternal Energy Corp.’s senior management and is a member of the merged company’s senior management team. Immediately after the merger, AEE Inc. changed its name to AMZG, Inc.

The Company’s historical financial statements have been prepared to give effect to the merger and to represent the historical operations of the Company through the merger date and the consolidated results of operations for the period from the merger date forward. The merger was structured to qualify as a “tax-free” transaction pursuant to Internal Revenue Service regulations.

F-14

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The following table summarizes the consideration paid by the Company to acquire AEE Inc. and the net assets acquired:

Consideration given:
36,476,543 shares of the Company’s common stock	$	16,722,975
Identifiable assets acquired and liabilities assumed:
Financial assets acquired	$	6,032,799
Oil and gas properties acquired (amortizable)		12,781,348
Oil and gas properties acquired (non-amortizable)		7,290,500
Financial liabilities assumed		(9,381,672	)
Net assets acquired	$	16,722,975

Because the common stock of both companies is very thinly traded, the Company estimated the fair market value of the shares issued based on an independent valuation.

The financial assets acquired included cash and cash equivalents of $5,598,916, trade and other receivables totaling $351,558, prepaid expenses totaling $7,468, marketable securities of a related party totaling $73,357 and restricted cash totaling $1,500.

The financial liabilities assumed consisted of trade payables and accrued liabilities totaling $3,300,491, amounts due to the Company totaling $251,081 and long-term asset retirement obligations totaling $17,314. The Company recorded a deferred tax liability in the amount of $4,837,786, which represents the future tax effects of the fair market value adjustments applied to the assets of AEE Inc. upon acquisition and current income taxes payable totaling $975,000.

Supplemental Pro Forma Information (Unaudited)

The Company’s consolidated statement of income for the year ended December 31, 2011 includes AEE Inc.’s revenues and net losses for the period December 21, 2011 through December 31, 2011 of $42,308 and ($144,525), respectively.

Had the merger transaction occurred effective January 1, 2011, the Company’s consolidated financial statements for the year ended December 31, 2011 would have been as follows (unaudited):

	Revenue		Net Income
2011 supplemental pro forma information	$	13,165,575	$	8,595,814

F-15

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The following assumptions were used to prepare the supplemental pro forma financial information presented above:

· No adjustments were made to reflect economies of scale or other potential cost savings that may have been achieved had the merger occurred on January 1, 2010.

· No adjustments were made relative to alternative financing strategies that may have been implemented on a combined entity basis.

4. Marketable Securities

Available-for-sale marketable securities at December 31, 2012 and 2011 consist of the following:

			Gains in		Losses in
			Accumulated		Accumulated
	Estimated		Other		Other
	Fair		Comprehensive		Comprehensive
	Value		Income		Income
December 31, 2012
Noncurrent assets:
Common stock	$	1,049,859	$	76,796	$	-
Total available-for-sale marketable securities	$	1,049,859	$	76,796	$	-
December 31, 2011
Noncurrent assets:
Common stock	$	1,254,434	$	281,371	$	-
Total available-for-sale marketable securities	$	1,254,434	$	281,371	$	-

The fair value of substantially all securities is determined by quoted market prices. The estimated fair value of securities for which there are no quoted market prices is based on similar types of securities that are traded in the market. There were no sales of marketable securities for the years ended December 31, 2012 or 2011. Certain warrants to purchase additional shares of common stock of Passport Energy Ltd. were exercised in June 2012. The warrants were valued using the Level 2 hierarchy at December 31, 2011. The shares for which the warrants were exchanged are valued using the Level 1 hierarchy as of December 31, 2012.

F-16

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The fair value of the Company’s financial instruments, measured on a recurring basis at December 31, 2012 and 2011, were as follows:

	Level 1		Level 2		Level 3		Total
December 31, 2012
Marketable securities	$	1,049,859	$	-	$	-	$	1,049,859
December 31, 2011
Marketable securities		1,181,077		73,357		-		1,254,434

5. Purchases and Sales of Royalty and Property Interests

In May 2011, the Company sold half of its 50% working interest in the Spyglass Property to a third party for cash consideration, net of finder’s fees, totaling $3,823,963. As of December 31, 2011, $46,170 of the net proceeds was still receivable. At the time of the sale, the Spyglass Prospect represented the only prospect included in the portion of the Company’s full-cost pool that was not subject to amortization. After reducing the carrying value of the full-cost pool, not subject to amortization to zero, the Company recognized a gain on the sale of $3,072,377. Because proved reserves were later established, subsequent costs associated with the Company interest in the Spyglass Prospect have been assigned to the full-cost pool that is subject to amortization.

Also in May 2011, the Company sold half of its 10% working interest in certain acreage included in the Spyglass Property (previously referred to as the Pebble Beach Property) to the same third-party for cash consideration, net of finder’s fees, totaling $227,079. Because the sale of the Pebble Beach working interest did not represent a significant portion of the full-cost pool that is subject to amortization, the net proceeds received were recorded as a reduction of the amortizable full-cost pool.

In December 2011, the Company sold three-quarters of its 50% working interest in the West Spyglass Prospect to a third party for cash consideration totaling $5,456,548. At the time of the sale, the West Spyglass Prospect represented the only prospect included in the portion of the Company’s full-cost pool that was not subject to amortization. After again reducing the carrying value of the full-cost pool, not subject to amortization, to zero, the Company recognized a gain on the sale of $3,332,737.

Also in December 2011, the Company sold half of its 10% working interest in certain other acreage included in the Spyglass Property (previously referred to as the Pebble Beach Property) to the same third-party for cash consideration totaling $1,889,674. The full amount of the consideration was included in the Company’s receivable balance as of December 31, 2011 and collected in January 2012. Because the sale of the Pebble Beach working interest did not represent a significant portion of the full-cost pool that is subject to amortization, the sales proceeds to be received were recorded as a reduction of the amortizable full-cost pool.

In December 2012, the Company purchased additional working interest in several key, non-operated spacing units within the Spyglass Property from its Carry Agreement partner. The purchase price totaled $8,000,000 in cash, of which $2,400,000 was paid at closing. The remaining $5,600,000, due in June 2013, has been presented as a current liability on the Company’s balance sheet as of December 31,2012.

F-17

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

6. Carry Agreement

On April 16, 2012, the Company entered into a Carry Agreement with a third-party working interest partner, pursuant to which (i) that partner agreed to fund 100% of the Company’s working interest share of the drilling and completion costs of up to six new oil and gas wells within our Spyglass Property, up to 120% of the original AFE amount, and (ii) the Company will convey, for a limited duration, a portion of its revenue interest in the pre-payout revenues of each carried well and a portion of its working interest in the pre-payout operating costs of each carried well, to that partner. In the event that the gross drilling and completion cost of a carried well exceeds 120% of the AFE amount, the Company and the working interest partner will share in the excess costs based on the working interests stipulated in the Carry Agreement.

Pursuant to the terms of the Carry Agreement, the portion of the Company’s net revenue interest in each well to be conveyed to the working interest partner follows a graduated scale, whereby 50% of the Company’s net revenue and working interests is assigned to the working interest partner during the first year of the well’s production or until the carried costs, plus the 12% return, have been achieved, whichever occurs first. In the event that the working interest partner has not recouped all of the carried costs plus the 12% return by the end of the first year of production, the assignment of the Company’s net revenue and working interests in the well will increase from 50% to 75% for the second year of production or until the carried costs, plus the 12% return, have been achieved, whichever occurs first. In the event that the working interest partner has not recouped all of the carried costs, plus the 12% return, by the end of the second year of production, the assignment of the Company’s net revenue and working interests in the well will increase to 100% until the carried costs, plus the 12% return, have been achieved. Once payout has occurred (112% of the costs on a well-by-well basis), the respective working interests in the revenues from each carried well will revert to the original working interests in each such well.

Drilling of the first two carried wells commenced prior to the final closing of the Carry Agreement. As of the date of closing, the Company had incurred drilling costs associated with the first two wells to be covered under the Carry Agreement totaling $3,789,989. Upon execution of the Carry Agreement, these costs were removed from the Company’s books and an offsetting receivable was created. The receivable has since been fully collected. Pursuant to accounting rules, the assignment of a portion of the Company’s working interests in certain existing and future wells under the Carry Agreement has been treated as a conveyance of the working interests. The Company’s share of the revenues and operating costs of the carried wells for the year ended December 31, 2012, as adjusted pursuant to the graduated conveyance schedule per the Carry Agreement, have been included in the Company’s results of operations for the corresponding period. In addition, the Company has disclosed the transfer of the drilling costs to the financing partner as a source of cash from investing activities on its consolidated statement of cash flows for the year ended December 31, 2012.

F-18

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

Effective July 15, 2012, the Company amended the Carry Agreement with the third-party to include an additional four oil and gas wells. As of December 31, 2012, the Company has received $32,847,102 of funding under the Carry Agreement, as amended. Proceeds received pursuant to the terms of the Carry Agreement, subsequent to the closing, are applied against the drilling and completion costs to which they relate. Additions to oil and gas properties that occurred subsequent to the closing of the Carry Agreement are presented net of proceeds received under the Carry Agreement on the consolidated statement of cash flows. Funds received pursuant to the Carry Agreement, prior to the incurrence of related drilling costs, are presented as amounts due to working interest partners on the consolidated balance sheet.

As of December 31, 2012, the gross drilling and completion costs of four of the carried wells had exceeded the 120% of AFE limit. Accordingly, the Company has recorded its working interest share in the excess drilling and completion costs which, as of December 31, 2012, totaled $1,680,215.

7. Swap Facility

On December 28, 2012, the Company entered into a prepaid swap facility with Macquarie Bank Limited (“MBL”), pursuant to which MBL agreed to advance up to $18 million. As of December 31, 2012, the Company had received $16 million under the agreement. The remaining $2 million was received in January 2013.

Funds received under the Swap Facility are accounted for as debt and will be repaid through a series of monthly payments from the sale of approximately 212,000 barrels of oil over the five-year period from January 2013 to December 2017, with a final balloon payment of $2 million, due in February 2018. The monthly volumes of oil production to be used to calculate the amounts of such tenders represent less than 25% of the Company’s current net production. As of December 31, 2012, the interest rate approximated 7.4%.

F-19

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The following table summarizes the scheduled future principal repayments under the Swap Facility:

	Amount
2013	$	5,931,003
2014		3,456,217
2015		2,179,836
2016		2,119,756
2017		2,130,432
2018		2,182,756
Total	$	18,000,000

The payment schedule presented above is based on predetermined volumes and prevailing oil prices as of the date of closing. Fluctuations in oil prices could result in higher or lower aggregate payments over the life of the Swap Facility. Any such changes in aggregate payment amounts will be charged to interest expense when the payments are made.

To effect the Swap Facility, the Company entered into series of agreements for the benefit of MBL, all of which are intended (a) to evidence MBL’s continuing security interest in certain of the Company’s US oil and gas properties, including, without limitation, hydrocarbons produced from such properties and the proceeds of the sale of such hydrocarbons and (b) to secure the Company’s obligations under the Swap Agreement.

The Swap Facility contains customary affirmative and negative covenants for swap facilities of this type, including limitations on the Company with respect to transactions with affiliates, hedging agreements, dividends and distributions, operations in respect of the property that secures its collective obligations under the Swap Facility, liens and encumbrances in respect of the property that secures our collective obligations under the Swap Facility, subsidiaries and divestitures, indebtedness, investments, and changes in business. The Swap Documents provide for customary events of default with corresponding grace periods, including failure to tender any amount when due to MBL under the Swap Agreement, failure to comply with or perform any other agreement or obligation under any of the Swap Documents, misrepresentation, certain cross-defaults, and bankruptcy. In the event of a default by us or our subsidiary, MBL, among other remedies, may terminate its obligations under the Swap Agreement, declare all of our collective obligations thereunder, including all of our future tender obligations, immediately due, and enforce any and all of its rights under the Swap Documents. For certain events of default related to bankruptcy, insolvency, and receivership of ours or of our subsidiary, MBL’s obligations would be automatically terminated and all of our collective outstanding obligations in favor of MBL would become immediately due.

F-20

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The Company has agreed to use the advances only for: (i) development of our Spyglass Property in North Dakota to increase production of hydrocarbons, (ii) acquisition of new oil and gas properties within the Spyglass Property, and (iii) general corporate purposes that are usual and customary in the oil and gas exploration and production business.

As a condition of closing for the Swap Facility, the Company entered into a price swap agreement relative to 59,052 barrels of future oil production, using a fixed price of $88.95 per barrel. Future payments related to these barrels will occur monthly over the term of the Swap Facility. The Company has not designated the price swap agreement as a hedge. Accordingly, management has elected not to apply hedge accounting to this derivative but will, instead, recognize unrealized gains (losses) associated with derivative in its statement of operations in the period for which such unrealized gains (losses) occur.

The price swap agreement has a fair market value of ($122,651) as of December 31, 2012. Accordingly, the Company has presented a short-term derivative liability on its balance sheet as of December 31, 2012 and recognized an unrealized loss associated with the price swap agreement of $122,651 for the year ended December 31, 2012.

The Company paid investment banking fees of $540,000, consulting fees of $50,000, and legal fees of $10,000 in connection with the negotiation and closing of the Swap Facility. In addition, the Company issued 225,564 shares of its common stock, valued at $180,000 as of the date that the Swap Facility was executed, to the investment banking firm that facilitated the transaction. The Company has capitalized these items as deferred financing costs, to be amortized over the life of the Swap Facility.

8. Asset Retirement Obligations

During the years ended December 31, 2012 and 2011, the Company recorded initial, estimated asset retirement obligations totaling $402,928 and $1,913, respectively, in connection with wells that were drilled and completed during the period. The asset retirement obligations represent the discounted future plugging and abandonment costs for operated and non-operated wells located within its Spyglass and Hardy Properties. As of December 31, 2012 and 2011, the consolidated discounted value of the Company’s asset retirement obligations was $441,609 and $34,628, respectively.

The Company recognized accretion expense of $4,053 and $1,548 for the years ended December 31, 2012 and 2011, respectively. The projected plugging dates for wells in which the Company owns a working interest ranges from December 31, 2020 to December 31, 2032.

F-21

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

9. Commitments and Contingencies

Drilling Obligations

The Company has the option to participate in the drilling of future exploratory wells related to its working interest in the Spyglass Property, should any such wells be proposed by the other working interest owners. As of December 31, 2012, the Company has elected to participate in 67 wells located within the Spyglass Property. As such, the Company is currently obligated to fund its non-operating working interest portion of the drilling and future operations costs of these wells. The Company’s working interests in the Spyglass wells range from 0.03% to 43.82%. Additional wells could be proposed in the future, at which time the Company may or may not elect to participate in such additional wells.

The Company intends to drill and operate additional horizontal and/or vertical wells to be located within the Spyglass Property and the West Spyglass Prospect and has contracted for the use of a drilling rig for the foreseeable future. The Company is obligated to pay its proportionate share of the costs related to the use of the drilling rig in connection with the drilling of future wells, some of which are subject to the Carry Agreement.

Employment Contracts

The Company has entered into employment agreements with its President, Chief Operating Officer and Chief Financial Officer which include, among other things, severance clauses should a change of control occur with respect to the Company’s ownership, as defined by the agreements. Should a change of control occur, the Company would be liable for aggregate severance payments totaling $1,173,000.

Lease Obligation

The Company currently leases office space pursuant to the terms of a three-year lease agreement. Future lease payments related to the Company’s office lease as of December 31, 2012 are as follows:

	Amount
2013	$	105,880
2014		111,174
Total	$	217,054

Rent expense for the years ended December 31, 2012 and 2011 totaled $110,364 and $75,735, respectively.

10. Equity Transactions

Shares Issued in Connection with the AEE Inc. Merger

As discussed in Note 3, on December 20, 2011, the Company issued 36,476,543 shares of its common stock to legacy AEE Inc. stockholders in order to acquire 100% of the then-outstanding shares of AEE Inc.

Reverse Stock Split

Immediately subsequent to the acquisition of AEE Inc., the Company declared a 1.0-for-4.5 reverse stock split. All historical share and per share information presented below has been restated and presented on a post-reverse-split basis.

F-22

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

Shares Issued in Connection with Swap Facility

As discussed in Note 7, the Company issued 225,564 shares of its common stock in connection with the Swap Facility with MBL.

Stock Options

In December 2011, the Company granted 975,000 options to purchase shares of the Company’s common stock to certain employees and contractors. The options have a five-year life, are exercisable at a price of $1.18 per share and vest over a two-year period. The stock options were valued using the Black-Scholes Option Pricing Model and had an aggregate fair value of $1,325,414 at the time of grant.

In January 2012, the Company granted 190,000 options to purchase shares of its common stock to certain employees. The options have an exercise price of $1.18 per share. The stock options were valued using the Black-Scholes Option Pricing Model and had an aggregate fair market value of $216,162 at the time of grant.

In February 2012, the Company granted 200,000 options to purchase shares of its common stock to certain employees. The options have an exercise price of $0.92 per share. The stock options were valued using the Black-Scholes Option Pricing Model and had an aggregate fair market value of $175,800 at the time of grant.

As of the date of merger, AEE Inc. had 1,732,990 options to purchase shares of AEE Inc.’s common stock. The options were issued in December 2010 and had a five-year life. In April 2012, these options were exchanged for options to purchase shares of the Company’s common stock at a price of $0.74 per share. The options are scheduled to expire in December 2015.

In August 2012, the Company granted 140,000 options to purchase shares of its common stock to certain non-officer employees and a full-time consultant. The options have an exercise price of $0.72 per share. The stock options were valued using the Black-Scholes Option Pricing Model and had an aggregate fair market value of $69,230 at the time of grant.

In September 2012, the Company granted 100,000 options to purchase shares of its common stock to a non-officer employee. The options have an exercise price of $0.73 per share. The stock options were valued using the Black-Scholes Option Pricing Model and had an aggregate fair market value of $49,260 at the time of grant.

F-23

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

In November 2012, the Company granted 240,000 options to purchase shares of its common stock to non-officer employees. The options have an exercise price of $0.78 per share. The stock options were valued using the Black-Scholes Option Pricing Model and had an aggregate fair market value of $111,144 at the time of grant.

In December 2012, the Company granted 890,000 options to purchase shares of its common stock to employees, directors and a paid consultant. The options have an exercise price of $0.74 per share. The stock options were valued using the Black-Scholes Option Pricing Model and had an aggregate fair market value of $397,118 at the time of grant.

The Company recognized stock-based compensation expense of $822,485 and $30,614 for the years ended December 31, 2012 and 2011, respectively.

The assumptions used in the Black-Scholes Option Pricing Model for the stock options granted were as follows:

	2012			2011
Risk-free interest rate		0.22% to 0.92	%		0.28	%
Expected volatility of common stock		79% to 196	%		101	%
Dividend yield		$0.00			$0.00
Expected life of options		5 years			5 years
Weighted average fair market value of options granted		$0.58			$0.79

A summary of stock option activity for the years ended December 31, 2012 and December 31, 2011 is presented below:

						Weighted
				Weighted		Average
				Average		Remaining
				Exercise		Contract
	Options			Price ($)		Term
Outstanding at January 1, 2011		820,444		$	0.23		3.8 years
Options granted		975,000			1.18		5.0 years
Options exercised		-			-		-
Options expired		-			-		-
Options forfeited		-			-		-
Outstanding at December 31, 2011		1,795,444		$	0.74		4.0 years
AEE Inc. options converted		1,732,990			0.74		3.2 years
Options granted		1,760,000			0.81		4.8 years
Options exercised		(153,834	)		0.23		3.8 years
Options expired		-			-		-
Options forfeited		-			-		-
Outstanding at December 31, 2012		5,134,600		$	0.78		3.6 years
Exercisable at December 31, 2012		2,887,100		$	0.70		2.9 years

F-24

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The options outstanding as of December 31, 2012 and December 31, 2011 have an intrinsic value of $0.12 and $0.56 per share and an aggregate intrinsic value of $616,152 and $1,005,449, respectively.

Shares Reserved for Future Issuance

As of December 31, 2012 and December 31, 2011, the Company had reserved 5,134,600 and 1,795,444 shares, respectively, for future issuance upon exercise of outstanding options.

11. Income Taxes

The Company recognized income tax benefit (expense) of $1,240,010 and ($99,291) for the years ended December 31, 2012 and December 31, 2011, respectively. Income tax expense for the years ended December 31, 2012 and 2011 consisted of the following:

	2012			2011
Current income tax benefit (expense):
Domestic	$	301,533		$	(485,137	)
Foreign		32,268			-
Total current income tax benefit (expense)		333,801			(485,137	)
Deferred income tax benefit (expense):
Domestic		(348,510	)		523,627
Foreign		1,254,719			(137,781	)
Total deferred income tax benefit (expense)		906,209			385,846
Total income tax benefit (expense)	$	1,240,010		$	(99,291	)

Significant components of the Company’s deferred income tax assets and liabilities at December 31, 2012 and 2011 are as follows:

	2012			2011
Deferred tax assets:
Foreign tax credits	$	32,275		$	-
Unrealized hedging loss		44,520			-
Asset retirement obligations		112,608			-
Net operating losses – domestic		4,075,159			-
Net operating losses – foreign		716,967			137,781
Foreign fixed assets		1,448,717			-
Stock options		757,432			464,428
Total deferred tax assets		7,187,678			602,209
Valuation allowance		(2,165,684	)		-
Net deferred income tax assets	$	5,021,994		$	602,209

F-25

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

	2012		2011
Deferred tax liabilities:
Deferred gain	$	-	$	591,100
Investment in foreign subsidiary		181,548		-
Domestic fixed assets		8,353,909		3,061,917
Foreign fixed assets		-		1,401,132
Marketable securities		6,031		100,924
Deferred tax liabilities	$	8,541,488	$	5,155,073
Net deferred tax liabilities	$	3,519,494	$	4,552,864

A reconciliation between the amount of income tax expense for the years ended December 31, 2012 and 2011, determined by applying the appropriate applicable statutory income tax rates, is as follows:

	2012			2011
U.S. Statutory tax benefit (expense)	$	3,581,180		$	(1,620,602	)
State income taxes, net of federal benefit (expense)		242,104			(89,071	)
Foreign taxes paid		-			-
Permanent differences		(8,003	)		(3,054	)
Change in valuation allowance		(2,165,684	)		1,799,976
True-up of prior year amounts		536,758			(324,321	)
Foreign operations		(908,878	)		137,781
Rate change		(39,421	)		-
Other		1,954			-
Net income tax benefit (expense)	$	1,240,010		$	(99,291	)
Effective tax rate		(11.77	)%		2.18	%

12. Earnings Per Share

The following is a reconciliation of the number of shares used in the calculation of basic and diluted earnings per share for the years ended December 31, 2012 and 2011:

	2012			2011
Net income (loss)	$	(9,292,874	)	$	4,453,901
Weighted average number of common shares outstanding		45,792,193			9,143,099
Incremental shares from the assumed exercise of dilutive stock options		-			3,018,373
Diluted common shares outstanding		45,792,193			12,161,472
Earnings (loss) per share - basic	$	(0.20	)	$	0.49
Earnings (loss) per share - diluted	$	(0.20	)	$	0.37

F-26

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

Because the Company recognized a net loss for the year ended December 31, 2012, the calculation of diluted loss per share is the same as the calculation of basic loss per share, as the effect of including any incremental shares from the assumed exercise of dilutive stock options would be anti-dilutive. The number of anti-dilutive shares that have been excluded from the calculation of diluted loss per share for the year ended December 31, 2012 is 468,775.

13. Related Party Transactions

The Company routinely obtains legal services from a firm for whom one of its directors serves as a principal. Fees paid this firm totaled $23,644 and $16,585 for the years ended December 31, 2012 and 2011, respectively.

Historically, the Company has not typically compensated its directors. However, during the year ended December 31, 2011, the Company paid $11,786 to one of its directors for additional services provided in connection with the contemplated acquisition of AEE Inc.

Prior to its acquisition by the Company, AEE Inc. entered into an agreement with Synergy Energy Resources LLC (“Synergy”) for it to provide monthly geological consulting services to AEE Inc. One of the Company’s current directors and one current officer own material ownership interests in Synergy. The Company purchased $140,000 of consulting fees from Synergy during the year ended December 31, 2012 and $7,000 of consulting fees during the period from December 20, 2011, the date of acquisition, through December 31, 2011. In addition, a $20,000 performance bonus was paid to an employee of Synergy related to services rendered in connection with the acquisition of AEE Inc. The consulting agreement between the Company and Synergy can be cancelled at any time by either party.

The Company’s Chairman and Chief Operating Officer each owns overriding royalty interests in certain of the Company’s operated wells. The overriding royalty interests were obtained prior the Company’s acquisition of AEE, Inc. in December 2011 (see Note 3). Revenues paid to these individuals totaled $67,426 and $51,858 for the year ended December 31, 2012. No such overriding revenues were paid during the year ended December 31, 2011 as the operated wells had not yet been drilled as of that time.

F-27

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

14. Subsequent Events

On January 3, 2013, the Company acquired additional working interests in certain of its operated wells from SM Energy Company for $3,899,500 in cash.

On January 4, 2013, the Company sold 4,000,000 shares of its common stock to Power Energy Ltd. at a price of $1.00 per share. Proceeds from the sale totaled $4,000,000.

On February 4, 2013, the Company received the remaining $2,000,000 of funding under the Swap Facility.

15. Supplemental Oil and Gas Information (Unaudited)

During the years ended December 31, 2012 and 2011, the Company incurred the following costs associated with the acquisition, exploration and development of oil and gas properties:

	2012		2011
Acquisition costs	$	16,671,183		2,649,493
Exploration costs		-		-
Development costs		27,914,011		4,502,832
Total costs	$	44,585,194	$	7,152,325

The net capitalized cost of the Company’s oil and gas properties, subject to amortization, as of December 31, 2012 and 2011 is summarized below:

	US			Canadian
	Cost Center			Cost Center			Total
December 31, 2012:
Acquisition costs	$	20,796,371		$	5,254,122		$	26,050,493
Exploration costs		-			-			-
Development costs		22,232,845			10,867,097			33,099,942
Impairments and sales		(2,249,144	)		(10,631,345	)		(12,880,489	)
Gross capitalized costs		40,780,072			5,489,874			46,269,946
Accumulated depletion		(1,547,186	)		(1,431,217	)		(2,978,403	)
Net capitalized costs	$	39,232,886		$	4,058,657		$	43,291,543
December 31, 2011:
Acquisition costs	$	4,336,958		$	5,213,127		$	9,550,085
Exploration costs		-			-			-
Development costs		4,283,103			3,951,764			8,234,867
Impairments and sales		(1,803,407	)		-			(1,803,407	)
Gross capitalized costs		6,816,654			9,164,891			15,981,545
Accumulated depletion		-			(183,238	)		(183,238	)
Net capitalized costs	$	6,816,654		$	8,981,653		$	15,798,307

F-28

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The Company recognized the following revenues and expenses associated with its oil and gas producing activities for the years ended December 31, 2012 and 2011:

	2012			2011
Oil and gas revenues	$	10,713,946		$	864,918
Oil and gas production costs		3,200,171			537,122
Net oil and gas revenues	$	7,513,775		$	327,796
Oil and gas revenues by cost center:
United States	$	8,785,986		$	402,436
Canada		1,927,960			462,482
Total oil revenue	$	10,713,946		$	864,918
Oil and gas production by cost center (BOE):
United States		108,996			5,535
Canada		25,633			5,802
Total oil & gas production		134,629			11,337
Average prices per unit by cost center (BOE):
United States	$	80.60		$	72.71
Canada		75.21			79.71
Oil and gas production costs by cost center:
United States	$	1,474,012		$	23,264
Canada		1,726,159			513,858
Total oil production costs	$	3,200,171		$	537,122
Oil and gas production costs per unit (BOE):
United States	$	13.52		$	4.20
Canada		67.34			88.57
Depletion expense by cost center:
United States	$	1,547,186		$	-
Canada		1,253,207			89,185
Total depletion expense	$	2,800,393		$	89,185
Impairment by cost center:
United States	$	-		$	-
Canada		(10,631,345	)		-
Total impairment	$	(10,631,345	)		-

F-29

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

	2012			2011
Income tax benefit (expense) by cost center:
United States	$	(1,960,028	)	$	(128,918	)
Canada		3,271,170			39,357
Total income tax expense	$	1,311,142		$	(89,561	)
Net operating results from oil and gas activities:
United States	$	3,804,760		$	250,254
Canada		(8,411,581	)		(101,204	)
Total net operating results from oil and gas activities	$	(4,606,821	)	$	149,050

The tables presented below set forth the Company’s net interests in quantities of proved developed and undeveloped reserves of crude oil, condensate and natural gas and changes in such quantities from the prior period. Crude oil reserves estimates include condensate.

The reserve estimation process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of this process, all reserves volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Estimated future cash flows were computed by applying an average of the monthly oil prices for the year to the Company’s share of estimated annual future production from proved oil and gas reserves, net of royalties. Production rate forecasts are derived by a number of methods, including estimates from decline curve analyses, material balance calculations that take into account the volume of substances replacing the volumes produced and associated reservoir pressure changes, or computer simulation of the reservoir performance. Operating costs and capital costs are forecast based on past experience combined with expectations of future cost for the specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary.

The Company has retained an independent petroleum engineering firm to determine its annual estimate of oil and gas reserves as of December 31, 2012 and 2011. The independent petroleum engineering firm estimated the oil and gas reserves associated with the Company’s Hardy, Spyglass and Benrude Properties using generally accepted industry standards, which include the review of technical data, methods and procedures used in estimating reserves volumes, the economic evaluations and reserves classifications.

F-30

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The Company believes that the methodologies used by the independent petroleum engineering firm in preparing the relevant estimates comply with current Securities and Exchange Commission standards for preparing such estimates. The Company has implemented internal controls regarding the development of reasonable oil and gas reserves estimates. These controls include, among other things, a thorough review of the estimated future development costs and estimated production costs associated with the reserves and a comparison of such estimated future costs to actual development and production costs incurred during the current period. In addition, the Company’s operational team compares the average prices used to estimate discounted net future cash flows from proved reserves to actual prices received during the period for reasonableness. The internal control procedures described above were performed by the Company’s operational team, which includes petroleum engineers having in excess of 80 years of oil and gas exploration and production experience, collectively. Based on the performance of these internal controls, the Company’s management believes that the underlying data provided by the Company to the independent petroleum engineering firm for the purpose of preparing its estimates, is reasonable Furthermore, the estimated reserves as of December 31, 2012 and 2011, as described in the final report issued by the independent petroleum engineering firm, were reviewed by members of the Company’s operational management and determined to be reasonable based on the underlying data.

The following tables summarize the Company’s proved oil and gas reserves, annual production and other changes in the Company’s proved oil and gas reserves for the years ended December 31, 2012 and 2011:

	Oil			Gas			Total
	(Barrels)			(Mcf)			(BOE)
For the year ended December 31, 2012:
Proved reserves, beginning of year		1,511,238			416,900			1,580,721
Revisions		(687,083	)		(190,856	)		(718,893	)
Extensions and discoveries		4,428,960			1,774,297			4,724,676
Purchases of reserves in place		478,596			247,780			519,893
Sale of reserves in place		(199,924	)		(106,748	)		(217,715	)
Production		(134,245	)		(2,306	)		(134,629	)
Proved reserves, end of year		5,397,542			2,139,067			5,754,053
Proved reserves by cost center:
United States		5,230,386			2,139,069			5,586,897
Canada		167,156			-			167,156
Total proved reserves		5,397,542			2,139,069			5,754,053
Proved developed reserves		2,387,283			1,074,362			2,566,343
Proved undeveloped reserves		3,010,259			1,064,707			3,187,710
Total proved reserves		5,397,542			2,139,069			5,754,053

F-31

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

	Oil		Gas		Total
	(Barrels)		(Mcf)		(BOE)
Proved developed reserves by cost center:
United States		2,308,551		1,074,362		2,487,611
Canada		78,732		-		78,732
Total proved developed reserves		2,387,283		1,074,362		2,566,343
Proved undeveloped reserves by cost center:
United States		2,921,833		1,064,707		3,099,284
Canada		88,426		-		88,426
Total proved undeveloped reserves		3,010,259		1,064,707		3,187,710

As a result of participating in 15 new wells, the Company converted 351,883 barrels of oil and 195,092 mcf of gas from proved undeveloped reserves to proved developed reserves during the year ended December 31, 2012. The Company incurred $2,897,436 of capitalized expenditures to drill these wells.

	Oil			Gas		Total
	(Barrels)			(Mcf)		(BOE)
For the year ended December 31, 2011:
Proved reserves, beginning of year		198,825			-		198,825
Revisions		50,484			-		50,484
Discoveries		430,920			-		430,920
Purchases of reserves in place		842,346			416,900		911,829
Production		(11,337	)		-		(11,337	)
Proved reserves, end of year		1,511,238			416,900		1,580,721
Proved reserves by cost center:
United States		909,067			416,900		978,550
Canada		602,171			-		602,171
Total proved reserves		1,511,238			416,900		1,580,721
Proved developed reserves		274,188			59,892		284,170
Proved undeveloped reserves		1,237,050			357,008		1,296,551
Total proved reserves		1,511,238			416,900		1,580,721
Proved developed reserves by cost center:
United States		102,937			59,892		112,919
Canada		171,251			-		171,251
Total proved developed reserves		274,188			59,892		284,170

F-32

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

	Oil		Gas		Total
	(Barrels)		(Mcf)		(BOE)
Proved undeveloped reserves by cost center:
United States		806,130		357,008		865,631
Canada		430,920		-		430,920
Total proved undeveloped reserves		1,237,050		357,008		1,296,551

As a result of drilling the Hardy 4-16 well in September 2011, the Company converted 152,348 barrels of oil from proved undeveloped reserves to proved developed reserves. The Company incurred $1,187,598 of capitalized expenditures to drill Hardy 4-16 well.

Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Net Cash Flows

For purposes of the following disclosures, estimates were made of quantities of proved reserves and the periods during which they are expected to be produced. Estimated future cash flows were computed by applying a 12-month average of oil prices, except in those instances where future oil or natural gas sales are covered by physical contract terms providing for higher or lower prices, to the Company’s share of estimated annual future production from proved oil and gas reserves, net of royalties. Future development and production costs were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10 % discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2012 and 2011, respectively.

Standardized Measure of Discounted Future Net Cash Flows

	At December 31,
	2012			2011
Future cash flows	$	448,623,295		$	132,047,257
Future costs:
Production costs		(99,410,979	)		(28,976,839	)
Development costs		(50,693,286	)		(15,273,800	)
Income taxes		(104,826,989	)		(31,309,370	)
Future net cash flows		193,692,041			56,487,248
Ten percent discount factor		(116,784,091	)		(31,265,211	)
Standardized measure of discounted future net cash flows	$	76,907,950		$	25,222,037

F-33

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2012 and 2011 and

For Each of the Two Years in the Period Ended December 31, 2012

The following table summarizes the changes in the Company’s standardized measure of discounted future net cash flows for the years ended December 31, 2012 and 2011:

	At December 31,
	2012			2011
Extensions and discoveries	$	84,275,965		$	10,865,465
Net changes in sales prices and production costs		(2,939,472	)		370,076
Oil and gas sales, net of production costs		(7,513,775	)		(329,420	)
Change in estimated future development costs		12,376,364			(710,348	)
Revision of quantity estimates		(22,267,585	)		999,954
Purchases of mineral interests		12,776,983			17,700,515
Additions of mineral interests due to merger		-			14,176,308
Previously estimated development costs incurred in the current period		2,897,436			1,640,348
Changes in production rates, timing and other		1,947,497			(5,455,760	)
Changes in income taxes		(33,864,445	)		(16,258,320	)
Accretion of discount		3,993,945			287,166
Net increase		51,682,913			23,285,984
Standardized measure of discounted future cash flows:
Beginning of year		25,225,037			1,939,053
End of year	$	76,907,950		$	25,225,037

Assumed prices used to calculate future cash flows

	At December 31,
	2012		2011
Oil price per barrel	$	81.78	$	86.47
Gas price per mcf	$	3.38	$	3.29

F-34

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.

There have been no disagreements in the applicable period.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

Our Principal Executive Officer and Principal Financial Officer has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2012. Based on this evaluation, our Principal Executive Officer and Principal Financial Officer has concluded that our disclosure controls and procedures were effective, at the reasonable assurance level, during the period and as of the end of the period covered by this Annual Report to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosures.

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Our Principal Executive Officer and Principal Financial Officer do not expect that our disclosure controls and procedures will prevent all error and all fraud. 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. Further, the benefits of controls must be considered relative to their costs. Because of 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 us have been detected. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s Report on Internal Control Over Financial Reporting

Our internal controls over financial reporting are designed by, or under the supervision of our Principal Executive Officer and Principal Financial Officer or persons performing similar functions, and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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 necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

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

Our management has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2012, based on the control criteria established in a report entitledInternal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting were not effective as of December 31, 2012 because the Company does not maintain appropriate segregation of duties. This is largely inherent to the size of the Company and the limited number of individuals that it employs. As a result, certain calculations underlying journal entries are not subject to review by someone, other than the preparer, who possesses the necessary knowledge and/or background to perform an effective review of such calculations.

Changes in Internal Control over Financial Reporting

During the fourth quarter of 2012, the Company expanded its system of internal controls over financial reporting to include a more formalized monthly close process and added additional levels of review and approval over account reconciliations and journal entry approvals.

This Annual Report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this Annual Report.

Item 9B. Other Information.

There is no other information required to be disclosed during the fourth quarter of the fiscal year covered by this Annual Report.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Executive Officers and Directors

The following table sets forth information concerning current executive officers and directors as of the date of this Annual Report:

Name	Age	Position(s)
Richard Findley	61	Director (Chairman of the Board)
Bradley M. Colby	56	President, Chief Executive Officer, Treasurer and Director
Kirk A. Stingley	47	Chief Financial Officer
Thomas Lantz	61	Chief Operating Officer
John Anderson	49	Director
Andrew P. Calerich	48	Director
Paul E. Rumler	59	Director and Secretary

Richard (“Dick”) Findley – Mr. Findley was appointed as our Chairman of the Board of Directors immediately following the closing of the 2011 Merger. Prior to the closing of the 2011 Merger and since December 14, 2009, he served as AEE Inc.’s President, Secretary, and Treasurer, and as its sole director. Mr. Findley is a geologist engaged in exploration for oil and gas. His 35-year career began in February 1975 with Tenneco Oil Company, located in Denver, Colorado, and continued with Patrick Petroleum, located in Billings, Montana, in January 1978. Mr. Findley formed Prospector Oil, Inc. in September 1983 to build an independent company working within the Williston Basin and Northern Rockies. He served as Chairman of the Board for Ryland, a company engaged in Bakken exploitation in Saskatchewan and North Dakota, from June 2007 until November 2007 and he served as a board member for RPT Uranium Inc. from July 2008 until June 2009. From October 19, 2010 to March 12, 2012, Mr. Findley served as an Executive Director of Passport, a Canadian resources company traded on the Canadian National Stock Exchange.

Mr. Findley has been credited with the discovery of Elm Coulee Field, which has been ranked as the 23rd largest oil field in terms of liquid proved reserves in the United States and is also the analogy for the Bakken Play in Montana, North Dakota, and Canada. His story has been featured in theWall Street Journal, and theCanadian National Post, as well as other international papers in Italy and the Netherlands. He has also been the subject in oil and gas trade journals, including theAmerican Oil and Gas Reporter,Petroleum Intelligence Weekly, and theAAPG Explorer magazine.

Mr. Findley holds a BS (1973) and an MS (1975) from Texas A&M University. He was awarded a Tenneco Fellowship Grant from 1973 to 1975 and received a best paper award – Third Place, Gulf Coast Association of Geological Societies in 1973. He also received the Michel T. Halbouty Fellowship in 1974. In December 2006, Texas A&M awarded him the Michel Halbouty Medal for distinguished achievement in geosciences and earth resources exploration development and conservation following the discovery of Elm Coulee. Mr. Findley has been a member of the American Association of Petroleum Geologists since 1974 and received its “Outstanding Explorer Award” in 2006 for his discovery of Elm Coulee Field.

Bradley M. Colby – Mr. Colby was appointed as our President, Chief Executive Officer, and Treasurer and as one of our directors on November 4, 2005. From November 2010 until January 1, 2012, he also served as our Chief Financial and Accounting Officer. For the four years prior to joining us, Mr. Colby was a principal at Westport Petroleum, Inc., where he bought and sold producing properties for his own account. Mr. Colby received a BS in Business-Minerals Land Management from the University of Colorado in 1979 and studied petroleum engineering at the Colorado School of Mines.

Kirk A. Stingley – Mr. Stingley was appointed as our Chief Financial Officer on January 1, 2012, having served in that capacity from June 2, 2008, to November 1, 2010. From January 1, 2011 to August 31, 2011, Mr. Stingley provided financial consulting services to us on an independent basis; effective September 1, 2011, he recommenced his status as a full-time employee. During November and December 2010, Mr. Stingley was employed as the Corporate Controller for MicroStar Keg Management LLC. Between January and May 2008, Mr. Stingley was employed by Adam James Consulting, where he provided accounting consulting services. During the preceding four years, from December 2003 to January 2008, he served as the Director of Internal Audit and as Director of Online Operations for The Sports Authority, Inc. Mr. Stingley began his career with Coopers & Lybrand in Houston, Texas and Denver, Colorado, where he provided auditing and consulting services to a number of private and publicly traded companies, whose principle activities involved the exploration, development, and operation of oil and gas properties. Subsequent to leaving public accounting, Mr. Stingley served as the Director of Accounting Services for Jefferson Wells International, a regional financial consulting firm, where he provided accounting and financial related services to various oil and gas related entities. Mr. Stingley holds an active CPA license in Colorado.

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Thomas G. Lantz– Mr. Lantz was appointed as our Chief Operating Office immediately following the closing of the 2011 Merger. Prior to the closing of the 2011 Merger and since June 2010, he had served as AEE Inc.’s Vice President of Operations. During his 30-year professional career and immediately prior to his affiliation with AEE Inc., he served as VP of Operations for a wholly-owned subsidiary of Ryland. From 1998 through 2006, Mr. Lantz was an Asset Manager for Halliburton Energy Services, during which time he led the efforts for several development programs for Halliburton’s clients, including the initial development of the Elm Coulee oil field. In that capacity, he and his team designed the technology for combining fracture stimulation in horizontal well bores, which advancement in technology was the key to unlocking the economic development of the Elm Coulee Field. This technology is being applied worldwide in other unconventional reservoirs in both gas and oil. Mr. Lantz also served as U.S. Operations Manager for Enerplus Resources (USA) Corporation after it acquired a major interest in the Elm Coulee Field from Lyco Oil Corporation. His expertise is reservoir and completion engineering. His recent work has been focused on development of unconventional resource plays in the Rockies, including the Bakken, Three Forks, Wasatch, and Mesaverde Formations. Mr. Lantz received a BS in Chemical Engineering from University of Southern California and engaged in graduate studies at Colorado State University in Mechanical Engineering. From October 5, 2010 to March 17, 2012, he served on the board of directors of Passport.

John Anderson – Mr. Anderson was appointed as one of our directors on November 4, 2005. From December 1994 to the present, he has served as President of Axiom Consulting Partners, a personal consulting and investing company primarily involved in capital raising for private and public companies in North America, Europe, and Asia. Mr. Anderson is the founder and General Partner of Aquastone Capital Partners LLC, a New York-based private gold and special situations fund and serves as the President of Purplefish Capital Ltd., which specializes in financial consulting with small-to mid-cap companies in the resource sector. Mr. Anderson received a BA from University of Western Ontario. He serves as a director or an executive officer of a number of publicly traded natural resources companies with operations around the world:

· Blue Note Mining Inc. (TSX – Venture Exchange), a gold company in Quebec, Canada – director since August 2009.

· Cadan Resources Corp. (TSX – Venture Exchange), a gold and copper producing company operating in the Philippines – director since February 2007, becoming the Chairman of the Board in January 2010 and its Executive Chairman in October 2010.

· Dawson Gold Corporation (TSX – Venture Exchange), a mineral exploration company – director since March 2008.

· Huakan International Mining, Inc. (TSX – Venture Exchange), a gold and exploration company in British Columbia, Canada and Washington State – director since June 2010.

· Northern Freegold Resources Ltd. (TSX – Venture Exchange), a gold exploration and development company in Yukon, Canada – director since January 2010.

· Passport Energy Ltd. (Canadian National Stock Exchange), a Canadian natural resources company – director since September 2009.

· Simba Gold Corp. (TSX – Venture Exchange), a company developing gold projects in Rwanda – director since January 2009 and serves as interim Chief Executive Officer.

· Soho Resources Corp. (TSX – Venture Exchange), a mining company in Mexico – director since November 2010.

· Sona Resource Corp. (TSX – Venture Exchange), a mine development company – director since June 2006.

· Strategic Resources Ltd. (Other OTC), a Nevada company in the business of exploring, acquiring and developing advanced precious metals and base metal properties – President, Chief Executive Officer, Secretary and Treasurer and a director since May 2004.

· Wescorp Energy, Inc. (OTC Bulletin Board), an oil and gas operations solution and engineering company – director between October 2001 and May 2009, Secretary and Treasurer from April 2003 to May 2009 and President and Chief Executive Officer between March 2003 and May 2004.

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Andrew P. Calerich – Mr. Calerich was appointed as one of our directors on February 21, 2012. From July 2003 until its merger into Hess Bakken Investments I Corporation (a wholly-owned subsidiary of Hess Corporation) in December 2010, he held various positions, including president, chief financial officer, and director of American Oil & Gas Inc. Prior to the merger, American Oil & Gas Inc. was a publicly traded independent oil and gas exploration and production company that was engaged in the acquisition of oil and gas mineral leases and the exploration and development of crude oil and natural gas reserves and production, most recently in the Williston Basin of North Dakota and Montana. Since the merger, he has been on sabbatical from full-time employment. During his 20-year professional career, Mr. Calerich has served public companies engaged in upstream oil and gas businesses in a variety of capacities, most recently (January 2011) becoming an independent director for Earthstone Energy, Inc., a Delaware corporation, whose common stock is traded on the NYSE Amex tier. Earthstone is primarily engaged in the exploration, development, and production of oil and natural gas properties, whose operating activities are concentrated in the North Dakota and Montana portions of the Williston basin, the southern portions of Texas, onshore portions of the Gulf Coast, and the Denver-Julesburg basin of Colorado. From August 2006 through September 2007, he served as a Director with Falcon Oil & Gas, Ltd. (TSXV). Mr. Calerich holds an inactive Certified Public Accountant license and earned BS degrees in both Accounting and Business Administration at Regis College, in Denver.

Paul E. Rumler–Mr. Rumler was appointed as one of our directors on July 26, 2007, and he became our corporate Secretary on October 22, 2007. Mr. Rumler also served as the sole member of our Special Committee that reviewed and evaluated the transactions that ultimately became the 2011 Merger. For more than the preceding five years, Mr. Rumler has been the principal shareholder and the managing shareholder at Rumler Tarbox Lyden Law Corporation, PC, in Denver, Colorado. He is a business attorney, whose areas of practice include general corporate and business planning matters and mergers and acquisitions, primarily in the closely held market place. Mr. Rumler is also a shareholder and a member of the board of directors of Stargate International, Inc., a manufacturer located in the Denver, Colorado, metropolitan area.

There are no family relationships among any of our directors, executive officers, or key employees.

Messrs. Anderson, Calerich, and Rumler are independent directors. The determination of independence of directors has been made using the definition of “independent director” contained in Section 803A of the NYSE Amex LLC Company Guide. All directors have participated in the consideration of director nominees. We do not have a policy with regard to attendance at board meetings. Our board of directors held four formal meetings during the year ended December 31, 2012, at which each then-elected director was present. All other proceedings of our board of directors were conducted by resolutions consented to in writing by all of the directors and filed with the minutes of the proceedings of our directors.

We do not have a policy with regard to consideration of nominations of directors. Nominations for directors are accepted from our security holders. There is no minimum qualification for a nominee to be considered by our directors. All of our directors will consider any nomination and will consider such nomination in accordance with his or her fiduciary responsibility to us and our stockholders.

Security holders may send communications to our board of directors by writing to American Eagle Energy Corporation, 2549 West Main Street, Suite 202, Littleton, Colorado 80120, attention: Board of Directors or to any specified director. Any correspondence received at the foregoing address to the attention of one or more directors is promptly forwarded to such director or directors.

Committees

Prior to the consummation of the 2011 Merger, we did not have standing audit, nominating, or compensation committees of our board of directors, or committees performing similar functions; our board of directors performed such functions. Our common stock is not currently listed on any national exchange and we are not required to maintain such committees by any self-regulatory agency. Prior to the 2011 Merger, we did not believe it was necessary for our board of directors to appoint such committees because the volume of matters that historically came before our board of directors for consideration permitted each director to give sufficient time and attention to such matters to be involved in all decision making. Following consummation of the 2011 Merger, our board of directors established three committees: the Audit Committee, the Compensation Committee, and the Nominating and Corporate Governance Committee.

37

Audit Committee

Following consummation of the 2011 Merger and in connection with a potential listing of our common stock on the NYSE Amex, we established an Audit Committee in order to comply with the NYSE MKT rules, on which Messrs. Anderson, Calerich, and Rumler currently serve. Messrs. Anderson, Calerich, and Rumler each qualifies as an “independent director” within the meaning of Section 303A.02 of the NYSE Listed Company Manual and Rule 10A-3 under the Exchange Act. The Audit Committee is responsible for oversight of the integrity of the Company’s financial statements, the selection and retention of our independent registered public accounting firm, review of the scope of their audit function, and review of the audit reports rendered by them. The Audit Committee is not responsible for conducting audits, preparing financial statements, or the accuracy of any financial statements or filings, all of which remain the responsibility of management and our independent registered public accounting firm. Our board of directors has designated Mr. Calerich as the Audit Committee’s named financial expert as defined in Section 407 of the Sarbanes-Oxley Act and the SEC rules under that statute. Mr. Calerich’s biography is available on page 37. The charter of the Audit Committee may be found on our website (www.americaneagleenergy.com).

Compensation Committee

Following consummation of the 2011 Merger and in connection with a potential listing of our common stock on NYSE MKT LLC, we established a Compensation Committee, on which Messrs. Anderson, Findley, and Rumler currently serve. The Compensation Committee is responsible for reviewing and approving our goals and objectives relevant to compensation, evaluating the performance of our senior executive officers (including our Chief Executive Officer) with respect to such goals and objectives, approving the compensation of our senior executive officers (including our Chief Executive Officer), and overseeing our compensation and benefits policies. The charter of the Compensation Committee may be found on our website (www.americaneagleenergy.com).

Nominating and Corporate Governance Committee

Following completion of the 2011 Merger and in connection with a potential listing of our common stock on the NYSE Amex, we established a Nominating and Corporate Governance Committee, on which Messrs. Anderson, Findley, and Rumler currently serve. The Nominating and Corporate Governance Committee is responsible for recommending corporate governance principles and a code of conduct and ethics to our board of directors, overseeing adherence to the corporate governance principles adopted by our board of directors, recommending policies for compensation of directors, recommending criteria and qualifications for new directors, and recommending individuals to be nominated as directors and committee members. This function includes evaluation of new candidates, as well as evaluation of then-current directors.

The Nominating and Corporate Governance Committee will consider nominees recommended by our stockholders. A stockholder’s recommendation must be submitted in writing to: Nominating and Corporate Governance Committee, American Eagle Energy Corporation, 2459 W. Main Street, Suite 202, Littleton, Colorado 80120. The recommendation should include the nominee’s name and biography. The Nominating and Corporate Governance Committee may also require a candidate to furnish additional information regarding his or her eligibility and qualifications. The charter of the Nominating and Corporate Governance Committee may be found on our website (www.americaneagleenergy.com).

Compensation Committee Interlocks and Insider Participation

Historically, our board of directors has performed the functions of a compensation committee. With the exception of Mr. Colby, none of the current members of our board of directors is an employee or officer of ours. None of our officers or employees serves as a member of our Compensation Committee.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Exchange Act requires officers, directors, and persons who own more than 10% of any class of our securities registered under Section 12(g) of the Exchange Act to file reports of ownership and changes in ownership with the SEC. Officers, directors, and greater than 10% stockholders are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file. To our knowledge, based solely on review of the copies of such reports furnished to us, during the fiscal year ended December 31, 2012, or with respect to such fiscal year, all Section 16(a) filing requirements were met.

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Code of Ethics

We adopted a Code of Conduct and Ethics that applies to all of our directors, executive officers, and employees. A copy of our Code of Conduct and Ethics is available on our website (www.americaneagleenergy.com) and is also available free of charge by writing to: Investor Relations, American Eagle Energy Corporation, 2459 W. Main Street, Suite 202, Littleton, Colorado 80120. Our Nominating and Corporate Governance Committee is responsible for the review and oversight of our ethical policies. Our management believes our Code of Conduct and Ethics is reasonably designed to deter wrongdoing and promote honest and ethical conduct; provide full, fair, accurate, timely, and understandable disclosure in public reports; comply with applicable laws; ensure prompt internal reporting of code violations; and provide accountability for adherence to the Code. Our board of directors must approve an amendment, exception, or waiver to the Code of Conduct and Ethics with respect to a director or an executive officer; the Nominating and Corporate Governance Committee must approve the same with respect to any other employee. In addition, a description of any exception, amendment, or waiver to the Code of Conduct and Ethics with respect to the Chief Executive Officer, Chief Financial Officer, our principal accounting officer, controller, or persons performing similar functions will be posted on our website within four business days following the date of such exception, amendment, or waiver.

Item 11. Executive Compensation.

We have not regularly compensated our directors in cash for their service as members of our board of directors. However, during 2011, Mr. Rumler received a payment of $11,786 in connection with his service as the sole member of the special committee of our board of directors that was formed specifically to review and evaluate the transactions that ultimately became the 2011 Merger. We do reimburse our directors for reasonable expenses in connection with attendance at board meetings and, commencing in 2012, have adopted a policy to compensate our directors for their attendance at our board of directors meetings.

The following table presents information concerning compensation paid to our Chief Executive Officer and our other executive officers for the years ended December 31, 2012 and 2011.

Summary Compensation Table

Name & Principal Position	Year	Salary		Bonus		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation		Nonqualified Deferred Compensation Earnings		All Other Compensation		Total
		($)		($)		($)		($) (3)		($)		($)		($)		($)
Bradley M. Colby	2012		204,000		100,000		—		100,395		—		—		—		404,395
President, CEO, and Treasurer	2011		189,000		100,000		—		—		—		—		—		289,000
Kirk Stingley	2012		150,000		30,000		—		22,310		—		—		—		202,310
Chief Financial Officer(1)
Thomas Lantz(2)	2012		204,000		100,000		—		44,620		—		—		—		348,620
Chief Operating Officer	2011		10,323		—		—		—		—		—		—		10,323

(1) Effective January 1, 2012, we re-appointed Kirk Stingley as our Chief Financial Officer. Mr. Stingley previously served in that capacity for us from June 2, 2008, until November 1, 2010.

(2)

Mr. Lantz’s employment commenced on December 20, 2011, immediately following the closing of the 2011 Merger.

(3)

The amounts reported in the “Option Awards” column of the table above reflect the aggregate dollar amounts recognized for option awards for financial statement reporting purposes with respect to our 2011 and 2012 fiscal years. For a discussion of the assumptions and methodologies used to value the awards reported in table above, please see the discussion of option awards contained in Note 10 (Equity Transactions – Stock Options) to our Consolidated Financial Statements, included as part of this Annual Report on Form 10-K.

Narrative Disclosure to Summary Compensation Table

Compensation Philosophy

The Company’s basic objectives for executive compensation are to recruit and keep top quality executive leadership focused on attaining long-term corporate goals and increasing stockholder value.

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Employment Agreements

We have entered into written employment agreements with each of our executive officers, the material terms of which are:

Officer	Annual Compensation	Term	Expiration Date
Bradley M. Colby	$252,000 per year	3 Years	01/1/2015
Thomas G. Lantz	$252,000 per year	3 Years	12/20/2014
Kirk A. Stingley	$165,000 per year	2 Years	01/01/2014

In the event that we terminate Mr. Colby’s or Mr. Lantz’s employment “without cause” or such officer terminates his employment “for good reason,” as each such term is defined in his respective employment agreement, then such individual would be entitled to the following benefits: (i) payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses; (ii) upon the signing and delivering to us a general release of all claims against us, a severance payment equal to one times his then-current annual base salary; and (iii) continuation of group health, vision, and dental benefits in accordance with the relevant benefit plan. If, upon or within 12 months of, a “change of control,” as such term is defined in his respective employment agreement, such individual’s employment is terminated “without cause” or “for good reason,” then such individual would be entitled to the following benefits: (i) payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses; (ii) upon the signing and delivering to us a general release of all claims against us, a severance payment equal to two times his then-current annual base salary; and (iii) continuation of group health, vision, and dental benefits in accordance with the relevant benefit plan. If, within 60 days of a “change of control,” such individual terminates his employment for any reason other than “for good reason,” then such individual would be entitled to the following benefits: (i) payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses; (ii) upon the signing and delivering to us a general release of all claims against us, a severance payment equal to one times his then-current annual base salary; and (iii) continuation of group health, vision, and dental benefits in accordance with the relevant benefit plan. We may also terminate such officer’s employment “for cause,” as such term is defined in his respective employment agreement. In such event, such individual would be entitled to receive payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses.

In the event that we terminate Mr. Stingley’s employment “without cause” or he terminates his employment “for good reason,” as each such term is defined in his employment agreement, then he would be entitled to the following benefits: (i) payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses; (ii) upon the signing and delivering to us a general release of all claims against us, a severance payment of $35,000; and (iii) continuation of group health, vision, and dental benefits in accordance with the relevant benefit plan. If, upon or within 12 months of, a “change of control,” as such term is defined in his respective employment agreement, his employment is terminated “without cause” or “for good reason,” then he would be entitled to the following benefits: (i) payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses; (ii) upon the signing and delivering to us a general release of all claims against us, a severance payment equal to his then-current annual base salary; and (iii) continuation of group health, vision, and dental benefits in accordance with the relevant benefit plan. If, within 60 days of a “change of control,” he terminates his employment for any reason other than “for good reason,” then he would be entitled to the following benefits: (i) payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses; (ii) upon the signing and delivering to us a general release of all claims against us, a severance payment equal to one-half of his then-current annual base salary; and (iii) continuation of group health, vision, and dental benefits in accordance with the relevant benefit plan. We may also terminate his employment “for cause,” as such term is defined in his employment agreement. In such event, he would be entitled to receive payment of all accrued salary through the date of such termination, payment for all accrued, but unused, vacation, and reimbursement of all business expenses.

Stock Option Grants to Management

During 2011, we granted five-year options to purchase 975,000 shares of our common stock with a per-share exercise price of $1.18, 50% of which vested on December 28, 2012 and 50% of which vest on December 28, 2013, in each case subject to the grantee’s continued service as a director, officer, employee, or consultant, as applicable, through such dates. The exercise price at which these options were issued was equal to closing price of our common stock on the date of grant.

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In connection with the 2011 Merger, we granted replacement options to three of our directors or executive officers to purchase 1,732,988 shares of our common stock with a per-share exercise price of $0.74, in exchange for options to purchase shares of AEE Inc. common stock that had been tendered in connection with the 2011 Merger. The replacement options expire on December 30, 2015, the same date on which the original options were set to expire.

Throughout 2012, we granted five-year options to purchase 1,760,000 shares of our common stock with a per-share exercise prices ranging from $0.72 to $1.18, 50% of which vest on the one-year anniversary of the grant date and 50% of which vest on the two-year anniversary of the grant date, in each case subject to the grantee’s continued service as a director, officer, employee, or consultant, as applicable, through such dates. The exercise price at which these options were issued was equal to the average closing price of our common stock for the 5-day period preceding the date of grant.

As of December 31, 2012, the following stock options were outstanding and held by management:

Outstanding Equity Awards at 2012 Fiscal Year-End

Name	Number of Securities Underlying Unexercised Options Exercisable			Number of Securities Underlying Unexercised Options Unexercisable		Option Exercise Price		Option Expiration Date
Bradley M. Colby		225,000	(4)		225,000	$	0.74	12/13/2017
		512,778	(1)		512,778	$	0.225	10/29/2014
		144,416	(1)(2)		144,416	$	0.74	12/30/2015
Kirk A. Stingley		50,000	(4)		50,000	$	0.74	12/13/2017
		150,000	(3)		150,000	$	1.18	12/28/2016
Thomas G. Lantz		225,000	(4)		225,000	$	0.74	12/13/2017
		433,247	(2)		433,247	$	0.74	12/30/2015
Richard L. Findley		50,000	(4)		50,000	$	0.74	12/13/2017
		577,663	(1)(2)		577,663	$	0.74	12/30/2015
John D. Anderson		50,000	(4)		50,000	$	0.74	12/13/2017
		158,834	(1)		158,834	$	0.225	10/29/2014
		50,000	(3)		50,000	$	1.18	12/28/2016
Paul E. Rumler		50,000	(4)		50,000	$	0.74	12/13/2017
		250,000	(3)		250,000	$	1.18	12/28/2016
Andrew P. Calerich		50,000	(4)		50,000	$	0.74	12/13/2017
		200,000	(5)		200,000	$	0.92	2/21/2017

⁽¹⁾ All options vested 100% and were exercisable immediately upon grant.

⁽²⁾ These options were granted by the Company in exchange for options to purchase shares of AEE Inc. common stock that were tendered in connection with the 2011 Merger.

⁽³⁾ Fifty percent of the options granted on December 28, 2011 vested on December 28, 2012, and 50% of such options vest on December 28, 2013, in each event subject to the grantee’s continued service as a director or officer, as applicable, of the Company through such dates.

⁽⁴⁾ Fifty percent of the options granted on December 14, 2012 vest on December 14, 2013, and 50% of such options vest on December 14, 2014, in each event subject to the grantee’s continued service as a director or officer, as applicable, of the Company through such dates.

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⁽⁵⁾ Fifty percent of the options granted on February 21, 2012 vest on February 21, 2013, and 50% of such options vest on February 21, 2014, in each event subject to the grantee’s continued service as a director or officer, as applicable, of the Company through such dates.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth certain information regarding the shares of common stock beneficially owned or deemed to be beneficially owned as of April 10, 2013 by: (i) each person known to beneficially own more than 5% of our common stock, (ii) each of our directors, (iii) our executive officers named above in the summary compensation table, and (iv) all such directors and executive officers as a group.

Except as indicated by the footnotes below, our management believes, based on the information furnished to us, that the persons and entities named in the table below have sole voting and investment power with respect to all shares of our common stock that they beneficially own, subject to applicable community property laws.

In computing the number of shares of our common stock beneficially owned by a person and the percentage ownership of that person, we deemed as outstanding shares of our common stock subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of April 10, 2013. We did not deem such shares outstanding, however, for the purpose of computing the percentage ownership of any other person.

	Shares of Common		Percent of Common
	Stock Beneficially		Stock Beneficially
Name of Beneficial Owner / Management and Address	Owned (1)		Owned (1)
Bradley M. Colby (2)		3,470,258		6.78	%
Kirk A. Stingley (3)		99,687		*
Thomas Lantz (4)		2,793,361		5.53	%
Richard Findley (5)		2,874,510		5.68	%
John Anderson (6)		992,946		1.98	%
Andrew P. Calerich (7)		200,000		*
Paul E. Rumler (8)		313,020		*
All directors and executive officers as a group (7 persons) (9)		10,743,782		20.80	%
Five Percent Beneficial Owner:
Steven Swanson (10)		2,840,321		5.61	%
Power Energy Holdings LLC (11)		4,000,000		7.99	%

* Less than 1%

(1) The applicable percentage ownership is based on 50,068,346 shares of common stock outstanding at April 10, 2013. The number of shares of common stock owned are those “beneficially owned” as determined under the rules of the Securities and Exchange Commission, including any shares of common stock as to which a person has sole or shared voting or investment power and any shares of common stock which the person has the right to acquire within 60 days through the exercise of any option, warrant or right.

(2) Includes 2,373,204 shares owned by Mr. Colby and an aggregate of 439,860 shares owned by five members of his immediate family as to which he disclaims beneficial ownership of an aggregate of 349,888 shares owned of record by his spouse and three of their adult children. Also includes 657,194 shares underlying options that are exercisable within 60 days of April 10, 2013. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, Colorado 80120.

(3) Includes 75,000 shares underlying options that are exercisable within 60 days of April 10, 2013. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, Colorado 80120.

(4) Includes 2,226,524 shares owned by Mr. Lantz and 133,590 shares owned by his adult child as to which he disclaims beneficial ownership. Also includes 433,247 shares underlying options that are exercisable within 60 days of April 10, 2013.

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(5) Includes 2,296,847 shares held by Golden Vista Energy, LLC (“Golden Vista”). Mr. Findley is the sole member of Golden Vista and beneficially owns all of the shares held by Golden Vista. Also includes 577,663 shares underlying options that are exercisable within 60 days of April 10, 2013. The business address for this person is 27 North 27th Street, Suite 21G, Billings, Montana 59101.

(6) Includes 183,834 shares underlying options that are exercisable within 60 days of April 10, 2013. The business address for this person is Suite 916-925 West Georgia Street, Vancouver, British Columbia V6C 3L2.

(7) Includes 100,000 shares underlying options that are exercisable within 60 days of April 10, 2013. The business address for this person is PO Box 1571, Eastlake, Colorado 80614.

(8) Includes 125,000 shares underlying options that are exercisable within 60 days of April 10, 2013. The business address for this person is 1777 South Harrison Street, Suite 1250, Denver, Colorado 80210.

(9) Includes all shares and options referenced in notes 2 through 8.

(10) We obtained this information regarding share ownership from the Schedule 13G/A filed April 18, 2012, by Mr. Swanson. Includes 969,507 shares owned by Mr. Swanson, 969,507 shares owned by his spouse, and 161,822 shares each owned by their two adult children, as to which 1,293,151 shares Mr. Swanson disclaims beneficial ownership. Also includes 577,663 shares underlying options that are exercisable within 60 days of April 10, 2013. The business address for this person is 2375 S. Atlantic Avenue #501, Cocoa Beach, Florida 32931.

(11) The business address for this person is 778 Frontage Rd., Suite 122, Northfield, Illinois 60093.

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

Related Party Transactions

Synergy Resources LLC

In January 2010, AEE Inc. engaged Synergy Resources LLC, a privately-held company (“Synergy”), to provide geological and engineering consulting services. Mr. Findley, who currently serves as a director of the Company, and Mr. Lantz, who currently serves as Chief Operating Officer of the Company, are each a member of Synergy. We purchased $140,000 of consulting fees from Synergy during the year ended December 31, 2012 and $7,000 of consulting fees during the period from December 20, 2011, the date of acquisition, through December 31, 2011. In addition, a $20,000 performance bonus was paid to an employee of Synergy related to services rendered in connection with the acquisition of AEE Inc. In December 2012, we granted 50,000 options to purchase shares of our common stock to this same employee. The options have a five-year life, vest over a period of two years and have an exercise price of $0.74 per option, which is equal to the average closing price of our common stock for the five trading days prior to the date of grant.

Paul E. Rumler

We routinely obtain legal services from a firm for which Mr. Rumler, one of our directors, serves as a principal. Fees paid this firm totaled $23,644 and $16,585 for the years ended December 31, 2012 and 2011, respectively.

Historically, we have not typically compensated its directors. However, during the year ended December 31, 2011, we paid $11,786 to Mr. Rumler for additional services provided in connection with the contemplated acquisition of AEE Inc.

Richard L. Findley

Mr. Findley, our Chairman, owns overriding royalty interests in certain of our operated wells. The overriding royalty interests were obtained prior the Company’s acquisition of AEE, Inc. in December 2011. Revenues paid to Mr. Findley totaled $67,426 for the year ended December 31, 2012.

Thomas G. Lantz

Mr. Lantz, our Chief Operating Officer, owns overriding royalty interests in certain of our operated wells. The overriding royalty interests were obtained prior the Company’s acquisition of AEE, Inc. in December 2011. Revenues paid to Mr. Lantz totaled $51,858 for the year ended December 31, 2012.

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Item 14. Principal Accountant Fees and Services.

Hein & Associates (“Hein”) audited our financial statements for the years ended December 31, 2012 and 2011 and provided preparation services for the 2010 and 2011 US federal and state tax returns.The aggregate fees billed for professional services by Hein for the year ended December 31, 2012 and 2011 were as follows:

	2012		2011
Audit Fees	$	136,061		80,000
Audit Related Fees	$	—		—
Tax Fees	$	51,079		—
All Other Fees	$	—		—
Total	$	187,140		80,000

It is our board of director’s policy and procedure to approve in advance all audit engagement fees and terms and all permitted non-audit services provided by our independent auditors. We believe that all audit engagement fees and terms and permitted non-audit services provided by our independent registered public accounting firm as described in the above table were approved in advance by our board of directors.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

INDEX TO EXHIBITS

Exhibit	Description of Exhibit
2.1	Agreement and Plan of Merger among Eternal Energy Corp., Eternal Sub Corp. and American Eagle Energy Inc., dated April 8, 2011. (Incorporated by reference to Exhibit 2.1 of our Registration Statement on Form S-4 filed May 4, 2011.)
2.1(a)	First Amendment to Agreement and Plan of Merger among Eternal Energy Corp., Eternal Sub Corp. and American Eagle Energy Inc., dated September 28, 2011. (Incorporated by reference to Exhibit 2.1(a) of our Current Report on Form 8-K filed September 28, 2011.)
3(i).1	Articles of Incorporation filed with the Nevada Secretary of State on July 25, 2003. (Incorporated by reference to Exhibit 3.1 of our Form 10-SB filed August 18, 2004.)
3(i).2	Certificate of Change filed with the Nevada Secretary of State effective November 7, 2005. (Incorporated by reference to Exhibit 3(i).2 of our Current Report on Form 8-K filed November 9, 2005.)
3(i).3	Articles of Merger filed with the Nevada Secretary of State effective November 7, 2005. (Incorporated by reference to Exhibit 3(i).3 of our Current Report on Form 8-K filed November 9, 2005.)
3(i).4	Articles of Merger filed with the Nevada Secretary of State effective November 30, 2011. (Incorporated by reference to Exhibit 3(i).4 of our Current Report on Form 8-K filed December 20, 2011.)
3(i).5	Articles of Merger filed with the Nevada Secretary of State effective November 30, 2011. (Incorporated by reference to Exhibit 3(i).5 of our Current Report on Form 8-K filed December 20, 2011.)
3(i).6	Certificate of Change filed with the Nevada Secretary of State effective November 30, 2011. (Incorporated by reference to Exhibit 3(i).6 of our Current Report on Form 8-K filed December 20, 2011.)
3(ii).1	Bylaws, adopted July 18, 2003. (Incorporated by reference to Exhibit 3.2 of our Form 10-SB filed August 18, 2004.)
3(ii).2	Amendment No. 1 to Bylaws, adopted November 4, 2005. (Incorporated by reference to Exhibit 3(ii) of our Current Report on Form 8-K filed November 9, 2005.)
3(ii).3	Amendment No. 2 to Bylaws, adopted February 22, 2011. (Incorporated by reference to Exhibit 3(ii).3 of our Current Report on Form 8-K filed February 23, 2011.)
4.1	American Eagle Energy Corporation 2012 Equity Incentive Plan. (Incorporated by reference to Exhibit 4.1 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.2	Non-qualified Stock Option Agreement, dated as of October 30, 2009, by and between the Registrant and Bradley M. Colby. (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.3	Non-qualified Stock Option Agreement, dated as of October 30, 2009, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.3 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.4	Non-qualified Stock Option Agreement, dated as of October 30, 2009, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.4 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.5	Non-qualified Stock Option Agreement, dated as of December 30, 2010, by and between the Registrant and Bradley M. Colby. (Incorporated by reference to Exhibit 4.5 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.6	Non-qualified Stock Option Agreement, dated as of December 30, 2010, by and between the Registrant and Thomas G. Lantz. (Incorporated by reference to Exhibit 4.6 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.7	Reserved for future use.
4.8	Non-qualified Stock Option Agreement, dated as of December 30, 2010, by and between the Registrant and Richard Findley. (Incorporated by reference to Exhibit 4.8 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.9	Non-qualified Stock Option Agreement, dated as of December 28, 2011, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.9 of our Registration Statement on Form S-8 filed February 28, 2012.)

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4.10	Non-qualified Stock Option Agreement, dated as of December 28, 2011, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.10 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.11	Reserved for future use.
4.12	Non-qualified Stock Option Agreement, dated as of December 28, 2011, by and between the Registrant and Kirk Stingley. (Incorporated by reference to Exhibit 4.12 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.13	Reserved for future use.
4.14	Reserved for future use.
4.15	Reserved for future use.
4.16	Reserved for future use.
4.17	Reserved for future use.
4.18	Reserved for future use.
4.19	Non-qualified Stock Option Agreement, dated as of February 21, 2012, by and between the Registrant and Andrew P. Calerich. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed February 21, 2012.)
4.20	Reserved for future use.
10.1	Agreement and Plan of Merger between Golden Hope Resources Corp. (renamed Eternal Energy Corp.) and Eternal Energy Corp., filed with the Nevada Secretary of State effective November 7, 2005. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 9, 2005.)
10.2	Reserved for future use.
10.3	Purchase and Sale Agreement between Eternal Energy Corp. and American Eagle Energy Inc. dated June 18, 2010. (Incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q filed August 16, 2010.)
10.4	Reserved for future use.
10.5	Reserved for future use.
10.6	Reserved for future use.
10.7	Reserved for future use.
10.8	Reserved for future use.
10.9	Reserved for future use.
10.10	Reserved for future use.
10.11	Amended and Restated Employment Agreement by and between the Registrant and Bradley M. Colby effective July 1, 2011.
10.12	Employment Agreement by and between the Registrant and Thomas G. Lantz, effective November 30, 2011.
10.13	Employment Agreement by and between the Registrant and Kirk Stingley, effective January 1, 2012.
10.14	Consulting Agreement by and between the Registrant and Richard Findley, effective November 30, 2011.
10.15	Reserved for future use.
10.16	Reserved for future use.
10.17	Letter Agreement dated October 15, 2006, by and among Eternal Energy Corp., Fairway Exploration, LLC, Prospector Oil, Inc., and 0770890 B.C. Ltd. (Incorporated by reference to Exhibit 10.17 of our Annual Report on Form 10-KSB filed April 16, 2007).

10.18	Letter Agreement dated October 26, 2006, by and among Eternal Energy Corp., Fairway Exploration, LLC, Prospector Oil, Inc., 0770890 B.C. Ltd., and Rover Resources Inc. (Incorporated by reference to Exhibit 10.18 of our Annual Report on Form 10-KSB filed April 16, 2007.)
10.19	Reserved for future use.
10.20	Reserved for future use.
10.21	Reserved for future use.
10.22	Reserved for future use.
10.23	Reserved for future use.
10.24	Reserved for future use.
10.25	Reserved for future use.

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10.26	Reserved for future use.
10.27	Lease Agreement dated January 1, 2009 by and between Eternal Energy Corp. and Oakley Ventures, LLC. (Incorporated by reference to Exhibit 10.27 of our Annual Report on Form 10-K filed March 23, 2010.)
10.27a	Lease Addendum, dated October 1, 2011 by and between Eternal Energy Corp. and Oakley Ventures, LLC, and Exhibit A thereto. (Incorporated by reference to Exhibit 10.27a of our Annual Report on Form 10-K filed April 16, 2012.)
10.27b*	Lease Addendum, dated July 1, 2012 by and between American Eagle Energy Corporation and Oakley Ventures, LLC.
10.28	Purchase and Sale Agreement by and between Eternal Energy Corp. and Ryland Oil Corporation dated March 26, 2010. (Incorporated by reference to Exhibit 10.28 of our Current Report on Form 8-K filed March 29, 2010.)
10.29	Purchase of Royalty Agreement by and between Eternal Energy Corp. and Ryland Oil Corporation dated March 26, 2010. (Incorporated by reference to Exhibit 10.29 of our Current Report on Form 8-K filed March 29, 2010.)
10.29a	Amending Agreement to the Ryland / Eternal Royalty Purchase Agreement by and between Eternal Energy Corp. and Ryland Oil Corporation dated April 20, 2010. (Incorporated by reference to Exhibit 10.29a of our Current Report on Form 8-K filed March 29, 2010.)
10.30	Reserved for future use.
10.31	Reserved for future use.
10.32	Reserved for future use.
10.33	Reserved for future use.
10.34	Reserved for future use.
10.35	Reserved for future use.
10.36	Letter of Intent between Eternal Energy Corp. and American Eagle Energy Inc. dated February 22, 2011. (Incorporated by reference to Exhibit 10.36 of our Annual Report on Form 10-K filed March 23, 2011.)
10.37	Engagement Letter for Professional Services between Eternal Energy Corp. and C.K. Cooper & Company, dated February 25, 2011. (Incorporated by reference to Exhibit 10.37 of our Annual Report on Form 10-K filed March 23, 2011.)
10.38	Participation and Operating Agreement among Eternal Energy Corp., AEE Canada Inc. and Passport Energy Inc., dated April 15, 2011. (Incorporated by reference to Exhibit 10.38 of our Registration Statement on Form S-4 filed May 4, 2011.)
10.38a	Amendment to the participation and operating agreement amongEergEnergyUlc,Aee Canada Inc. and Passport Energy Inc., dated February 1, 2012. (Incorporated by reference to Exhibit 10.38a of our Annual Report on Form 10-K/A filed April 10, 2012.)
10.39^	Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated May 17, 2011. (Incorporated by reference to Exhibit 10.39 of our Amended Quarterly Report on Form 10-Q/A filed October 11, 2011.)
10.40^	Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated May 17, 2011. (Incorporated by reference to Exhibit 10.40 of our Amended Quarterly Report on Form 10-Q/A filed October 11, 2011.)
10.40a	First Amendment to Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated June 14, 2011. (Incorporated by reference to Exhibit 10.40a of our Quarterly Report on Form 10-Q filed August 18, 2011.)
10.40b	Second Amendment to Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated July 25, 2011. (Incorporated by reference to Exhibit 10.40b of our Quarterly Report on Form 10-Q filed August 18, 2011.)
10.41^	Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated November 15, 2011. (Incorporated by reference to Exhibit 10.38a of our Annual Report on Form 10-K/A filed April 10, 2012.)
10.42^	Carry Agreement by and among American Eagle Energy Corporation, American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated as of April 16, 2012, and Exhibit C thereto. (Incorporated by reference to Exhibit 10.42 of our Quarterly Report on Form 10-Q filed on August 20, 2012.
10.43	First Amendment to Carry Agreement by and among American Eagle Energy Corporation, American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated as of July 15, 2012. (Incorporated by reference to Exhibit 10.43 of our Quarterly Report on Form 10-Q filed on August 20, 2012.)
10.44*	ISDA Master Agreement by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012.

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10.44a*	Schedule to the 2002 ISDA Master Agreement by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012.
10.45*	Commodity Swap Transaction Confirmation by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012.
10.46*	Security Agreement by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012.
10.47*	Mortgage, Security Agreement, Fixture Filing, Financing Statement and Assignment of Production and Revenue by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012.
10.48*	Purchase and Sale Agreement by and between USG Properties Bakken I, LLC and American Eagle Energy Corporation, dated December 20, 2012.
10.49*	Purchase and Sale Agreement Between SM Energy Company and American Eagle Energy Corporation, dated November 20, 2012.
21.1*	List of Subsidiaries.
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 18 U.S.C. Sec. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

____________

* Filed herewith.

^ Portions omitted pursuant to a request for confidential treatment.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

AMERICAN EAGLE ENERGY CORPORATION
By:	/s/ BRADLEY M. COLBY
	Bradley M. Colby
	President, Chief Executive Officer, Treasurer and Director
	Date: April 16, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, 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/BRADLEY M. COLBY	President, Chief Executive Officer, Treasurer and Director (Principal Executive Officer)	April 16, 2013
Bradley M. Colby
/s/KIRK A. STINGLEY	Chief Financial Officer (Principal Accounting Officer)	April 16, 2013
Kirk A. Stingley
/S/THOMAS LANTZ	Chief Operating Officer	April 16, 2013
Thomas Lantz
/s/RICHARD FINDLEY	Director (Chairman)	April 16, 2013
Richard Findley
/s/JOHN ANDERSON	Director	April 16, 2013
John Anderson
/s/ ANDREW P. CALERICH	Director	April 16, 2013
Andrew P. Calerich
/s/PAUL E. RUMLER	Director and Secretary	April 16, 2013
Paul E. Rumler

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