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 EXCHANGE ACT OF 1934.

For the fiscal year ended December 31, 2013

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 ¨ No x

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 ¨ No x

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.

Yes x 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 ¨ No x

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, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, was $67,425,942.

The number of shares outstanding of the registrant’s common stock as of March 28, 2014 was 30,370,537.

AMERICAN EAGLE ENERGY CORPORATION

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business.	3
Item 1A.	Risk Factors.	6
Item 1B.	Unresolved Staff Comments.	18
Item 2.	Properties.	18
Item 3.	Legal Proceedings.	19
Item 4.	Mine Safety Disclosures.	19
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities.	19
Item 6.	Selected Financial Data.	20
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	20
Item 8.	Financial Statements and Supplementary Data.	30
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.	63
Item 9A.	Controls and Procedures.	63
Item 9B	Other Information.	64
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	64
Item 11.	Executive Compensation.	69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	72
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	73
Item 14.	Principal Accounting Fees and Services.	74
	PART IV
Item 15.	Exhibits, Financial Statement Schedules.	74
	SIGNATURES	79

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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.

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

On March 18, 2014, we declared a 1-for-4 reverse split of our common stock. The reverse split reduced the number of shares of our common stock then issued and outstanding to 17,712,151. The retroactive effect of both reverse splits has been applied to all share data included in this Annual Report.

On March 24, 2014, we sold 12,650,000 shares of our common stock in a public offering.

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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.

As of December 31, 2013, we had drilled and completed 28 gross (13.66 net) operated wells located within our Spyglass Area, all of which were producing as of that date, and were in the process of completing two additional Spyglass Area operated wells. The two additional wells were completed in early 2014. In addition, as of December 31, 2013, we had elected to participate in 75 gross (3.65 net) non-operated wells located within our Spyglass Area (primarily in Divide County, North Dakota), all of which were producing as of that date.

As of December 31, 2013, we owned net revenue and working interests in three gross operated wells and one gross non-operated well located in Southeastern Saskatchewan. As of December 31, 2013, two of the operated wells were shut in.  

Business Strategy

Our strategy is to increase stockholder value by developing our current leasehold position in the Spyglass Area and growing estimated proved reserves, production, and cash flow to generate attractive rates of return on capital. Key elements of our business strategy include:

• Develop Proven Formations within our Williston Basin Leasehold Position.  We intend to accelerate development of our delineated acreage position in the Bakken and Three Forks formations in order to maximize the value of our resource potential.

• Employ Leading Edge Drilling and Completion Techniques.  Our executive management team has extensive experience in drilling and completing wells in the Williston Basin, as they were involved in drilling some of the first horizontal wells in the basin over a decade ago. Tom Lantz, our Chief Operating Officer, led the development team at Halliburton that drilled the first Middle Bakken well utilizing both horizontal drilling and hydraulic stimulation in 2001 and has since led the drilling of hundreds of wells in the Williston Basin. Richard Findley, our Chairman, is credited with discovering the Elm Coulee field in the Williston Basin and was also involved with drilling some of the first wells in the basin utilizing horizontal drilling and hydraulic stimulation. By leveraging their years of experience, along with the expertise of our tier-one service providers, we believe that we have the knowledge to drill and complete wells that will provide attractive production rates, ultimate recoveries, and return on invested capital.

• Evaluate and Pursue Strategic Acquisitions in the Williston Basin.  We intend to continuously evaluate acquisition opportunities in the Williston Basin that share similar geographic and geologic characteristics with our existing acreage position. By focusing on our core Spyglass Area of the Williston Basin, we believe we can leverage our existing infrastructure, experience in the area, and industry relationships to maximize returns associated with any future acquisitions.

• Expand Our Resource Potential Through Downspacing and Proving Additional Production Intervals. We believe that the current industry drilling spacing assumptions, which allocate four Bakken and four Three Forks locations per 1,280 acre drilling unit, may be conservative and we continue to monitor tighter spacing trends in the Williston Basin. Additionally, we believe there may be opportunities in the future to produce from other formations underlying our leasehold position, such as the second and third benches of the Three Forks formation, which are currently being successfully produced by other oil and natural gas companies in various parts of the Williston Basin. If we ultimately are successful in proving additional commercially viable formations within our existing leasehold, it could meaningfully add to our resource potential and drilling locations.

• Maintain Adequate Liquidity and a Conservative Leverage Profile to Capitalize on Growth Opportunities. We are focused on maintaining adequate liquidity to support our working capital and capital expenditure needs, as well as to keep our leverage profile at a conservative level relative to our cash flows.

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 farm-in and farm-out 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 farm-in and farm-out agreements.

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Hydraulic Stimulation

As of December 31, 2013, we had drilled and completed 28 gross operated wells located within our Spyglass Area. Each of these 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 9 additional wells, each of which will be stimulated using these 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.

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 $20 million in each individual instance with a deductible of $175,000. 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.

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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 governmental regulations. 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.”

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. 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 28, 2014, our executive 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 22 full-time operations, financial and administrative employees.

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”). You can identify forward-looking statements by the use of forward-looking words, such as “expects,” “projects,” “predicts,” “believes,” “plans,” “anticipates,” “estimates,” “may,” “will,” “possible,” “goal,” “target,” “should,” or “intends” or the negative of those words or similar words. Forward-looking statements involve inherent risks and uncertainties regarding events, conditions, and financial trends that may affect our business, financial condition, liquidity, and results of operations. For a discussion of factors that could cause actual results to differ from those contemplated in the forward-looking statements, please see the discussion under “Risk Factors” contained in this prospectus supplement and the reports we file under the Exchange Act that are incorporated by reference in this prospectus supplement and the accompanying prospectus. Forward-looking statements include, but are not limited to, statements about:

· speculative nature of oil and natural gas exploration, particularly in the Bakken and Three Forks formations on which we are focused;

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· substantial capital requirements and ability to access additional capital;

· ability to meet the drilling schedule;

· uncertainty of drilling results;

· results of acquisitions;

· relationships with partners and service providers;

· ability to acquire additional leasehold interests or other oil and natural gas properties;

· defects in title to our oil and natural gas properties;

· inability to manage growth in our businesses;

· ability to control properties that we do not operate;

· lack of geographic diversification;

· competition in the oil and natural gas industry;

· global financing conditions;

· oil and natural gas realized prices;

· ability to market and distribute oil and natural gas produced;

· seasonal weather conditions;

· government regulation of the oil and natural gas industry, including potential regulations affecting hydraulic stimulation and environmental regulations such as climate change regulations; and

· uninsured or underinsured risks.

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.

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.

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We may be unable to obtain additional capital required to implement our business plan, which could restrict our ability to grow.

Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of capital and cash flow.

Subject to the terms and conditions of the Credit Agreement, we may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our operations in the future.

Any additional capital raised through the sale of equity will dilute the ownership percentage of our stockholders. Raising any such capital could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other securities. In addition, we have granted and will continue to grant equity incentive awards under our equity incentive plans, which may have a further dilutive effect.

Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and natural gas industry in particular), the location of our oil and natural gas properties, and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if oil or natural gas prices decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations, divest our assets at unattractive prices, or obtain financing on unattractive terms.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses, and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition.

If we are not able to generate sufficient funds from our operations and other financing sources, we may not be able to finance our planned development activity, acquisitions, or service our debt.

We have been dependent on debt and equity financing to fund our cash needs that are not funded from operations or the sale of assets, and we will continue to incur additional indebtedness to fund our operations. Low commodity prices, production problems, disappointing drilling results, and other factors beyond our control could reduce our funds from operations and may restrict our ability to obtain additional financing or to pay interest and principal on our debt obligations. Furthermore, we have incurred losses in the past that may affect our ability to obtain financing. Quantifying or predicting the likelihood of any or all of these occurring is difficult in the current domestic and world economy. For these reasons, financing may not be available to us in the future on acceptable terms or at all. In the event additional capital is required but not available on acceptable terms, we would curtail our acquisition, drilling, development, and other activities or could be forced to sell some of our assets on an untimely or unfavorable basis.

Restrictive debt covenants could limit our growth and our ability to finance out operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.

Our Credit Facility (see Page 27) contains a number of significant covenants that, among other things, restrict or limit our ability to:

• pay dividends or distributions on our capital stock;

• make certain loans and investments;

• enter into certain transactions with affiliates;

8

• create or assume certain liens on our assets;

• merge or to enter into other business combination transactions;

• enter into transactions that would result in a change of control of us; or

• engage in certain other corporate activities.

Also, our Credit Agreement requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our Credit Agreement impose on us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our Credit Agreement. A default, if not cured or waived, could result in all indebtedness outstanding under our Credit Agreement becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

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.

We may have difficulty integrating and managing the growth associated with our acquisitions.

Our acquisitions may place a significant strain on our financial, technical, operational and administrative resources. We may not be able to integrate the operations of the acquired assets without increases in costs, losses in revenues or other difficulties. In addition, we may not be able to realize the operating efficiencies, synergies, costs savings or other benefits expected from such acquisitions. Any unexpected costs or delays incurred in connection with such integration could have an adverse effect on our business, results of operations or financial condition. We may need to hire new employees to help manage our operations, and we may need to add resources as we scale up our business. However, we may experience difficulties in finding additional qualified personnel and we may need to supplement our staff with contract and consultant personnel until we are able to hire new employees. Our ability to continue to grow after acquisitions will depend upon a number of factors, including our ability to identify and acquire new exploratory prospects and other acquisition targets, our ability to develop then existing prospects, our ability to successfully adopt an operated approach, our ability to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts, hydrocarbon prices and access to capital. We may not be successful in achieving or managing growth, and any such failure could have a material adverse effect on us.

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 17 to our consolidated financial statements as of and for the years ended December 31, 2013 and 2012, which is included in Item 8 of this document (see page 58).

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Successful exploitation of the Williston Basis is subject to risks related to horizontal drilling and completion techniques.

Operations in the Williston Basin involve utilizing the latest drilling and completion techniques, including horizontal drilling and completion techniques, to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling horizontally through the formation, running casing the entire length of the well bore, and being able to run tools and other equipment consistently through the horizontal well bore. Completion risks include, but are not limited to, being able to hydraulically stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations, and successfully cleaning out the well bore after completion of the final hydraulic stimulation stage. Ultimately, the success of these latest drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period.

Our drilling and completion of a long lateral well in the Bakken and Three Forks formations in our Spyglass Area generally costs us between $6.0 million and $6.5 million, which is significantly more expensive than a typical onshore conventional well. Accordingly, unsuccessful exploration or development activity affecting even a small number of wells could have a significant impact on our results of operations.

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.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth, and the value of our business.

Oil and natural gas are commodities, the prices of which are determined based on world demand, supply, and other factors, all of which are beyond our control. These factors include:

• the domestic and foreign supply of oil and natural gas;

• the current level of prices and expectations about future prices of oil and natural gas;

• the level of global oil and natural gas exploration and production;

• the cost of exploring for, developing, producing, and, delivering oil and natural gas;

• the price of foreign oil and natural gas imports;

• political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia;

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• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• speculative trading in oil and natural gas derivative contracts;

• the level of consumer product demand;

• weather conditions and other natural disasters;

• risks associated with operating drilling rigs;

• technological advances affecting energy consumption;

• domestic and foreign governmental regulations and taxes;

• the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

• the proximity and capacity of oil and natural gas pipelines and other transportation facilities;

• the price and availability of alternative fuels; and

• overall domestic and global economic conditions.

World prices for oil and natural gas have fluctuated widely in recent years, and we expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves, and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and natural gas industry. Prices may not remain at current levels. Decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations, and quantities of reserves recoverable on an economic basis. A significant decrease in oil and natural gas prices could also adversely impact our ability to raise additional capital to pursue future drilling activities.

Our hedging activities could result in financial losses or could reduce our net income or increase our net loss, which may adversely affect our business.

In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we may enter into oil and natural gas price hedging arrangements with respect to a portion of expected production that we fund. Such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

• production is less than expected;

• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or

• the counterparties to our hedging agreements fail to perform under the contracts.

Lower oil and natural gas prices, decreases in value of undeveloped acreage, lease expirations, and material changes to our plans of development may cause us to record ceiling test write-downs.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling,” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If, at the end of any fiscal period, we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. We recognized a ceiling test write-down for the years ended December 31, 2013 and 2012 of approximately $1.7 million and $10.6 million, respectively, and we may recognize write-downs in the future if commodity prices decline or if we experience substantial downward adjustments to our estimated proved reserves.

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Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.

Certain of our reports that we file with the SEC pursuant to the Exchange Act contain estimates of our proved oil and natural gas reserves. The estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices, and other factors, many of which are beyond our control.

At December 31, 2013 on an actual basis, approximately 65% of our estimated reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of these oil and natural gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled, and actual results may not be as estimated.

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.

Shortages of equipment, services, and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in new regions, causing periodic shortages. These problems can be particularly severe in certain regions such as the Williston Basin. During periods of high oil and natural gas prices, the demand for drilling rigs and equipment has increased along with increased activity levels, which may result in shortages of equipment. In addition, there has been a shortage of hydraulic stimulation capacity in many of the areas in which we operate. This shortage in hydraulic stimulation capacity could occur in the future. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel. These types of shortages and subsequent price increases could affect our profit margin, cash flow, and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

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All of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area.

As of December 31, 2013, approximately 99.5% of our proved reserves and approximately 98% of our production were located in the Williston Basin in northeastern Montana and northwestern North Dakota. As a result, we may be exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, or interruption of transportation of oil or natural gas produced from the wells in this area. Due to the geographically concentrated nature of our portfolio of properties, a number of our properties could experience many of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more geographically diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

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.

Our business depends on oil and natural gas gathering and transportation facilities, most of which are owned by third parties.

The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of gathering and pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. Insufficient transportation in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.” We generally do not purchase firm transportation on third party pipeline facilities, and, therefore, the transportation of our production can be interrupted by other customers that have firm arrangements.

The disruption of third-party facilities due to maintenance, weather, or other interruptions of service could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored. A total shut-in of our production could materially affect us due to a resulting lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.

Insufficient transportation in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.

The Williston Basin crude oil business environment has historically been characterized by periods when oil production has surpassed local transportation, resulting in substantial discounts in the price received for crude oil versus prices quoted for West Texas Intermediate (the “WTI”) crude oil. Although additional Williston Basin transportation takeaway capacity was added in the last few years, production also increased due to the elevated drilling activity. The increased production coupled with delays in rail car arrivals and commissioning of rail loading facilities caused price differentials at times to be at the high-end of the historical average range of approximately 10% to 15% of the WTI crude oil index price in the first half of 2012 and second half of 2013. After these periods, differentials improved due to expanding rail infrastructure and pipeline expansions coming online. On barrels that are transported over pipelines to either Clearbrook, Minnesota, or Guernsey, Wyoming, our realized price for crude oil is generally the quoted price for Bakken crude oil less transportation costs from the point where the crude oil is sold.

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We may have difficulty distributing our oil and natural gas production, which could harm our financial condition.

In order to sell the oil and natural gas that we are able to produce from the Williston Basin, we may have to continue our current, or potentially make new, arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the Williston Basin area in which we operate. These factors may affect our ability to explore and develop our properties and to store and transport our oil and natural gas production, which may increase our expenses.

Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations, or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing, and operating any well is often uncertain, and new wells may not be productive.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and natural gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.

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.

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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 5 of this Annual Report.

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.

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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.

We engage third parties to provide hydraulic stimulation or other well stimulation services to us in connection with the wells for which we are the operator and we expect to do so in the future for other wells. Hydraulic stimulation typically involves the injection under pressure of water, sand, and additives into rock formations in order to stimulate hydrocarbon production. Hydraulic stimulation using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act (the “SDWA”), but opponents of hydraulic stimulation have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic stimulation to regulation under the SDWA. Eliminating this exemption could establish an additional level of regulation and permitting at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic stimulation and increase our cost of compliance and doing business. In addition, the EPA’s Office of Research and Development is conducting a scientific study to investigate the possible relationships between hydraulic stimulation and drinking water. The results of that study, which are expected to be available in draft during 2014 for peer review and public comment, could advance the development of additional regulations.

Even in the absence of new legislation, the EPA recently asserted the authority to regulate hydraulic stimulation involving the use of diesel additives under the SDWA’s Underground Injection Control Program (the “UIC Program”), which regulates the underground injection of substances. On May 4, 2012, the EPA published draft UIC Program guidance for oil and natural gas hydraulic stimulation activities using diesel fuel. The guidance document is designed for use by employees of the EPA that draft the UIC permits and describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic stimulation process. The EPA is encouraging state programs to review and consider use of the above mentioned draft guidance. To the extent that EPA’s new regulatory guidance is extended to our operations by permitting authorities, additional and significant compliance costs may arise that could materially affect our operations, cash flows, and financial position.

Hydraulic stimulation operations require the use of water and the disposal or recycling of water that has been used in operations. The federal Clean Water Act (the “CWA”) restricts the discharge of produced waters and other pollutants into waters of the United States and requires permits before any pollutants may be so discharged. On October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic stimulation and certain other natural gas operations. The CWA and comparable state laws and regulations provide for penalties for unauthorized discharges of pollutants including produced water, oil, and other hazardous substances. Compliance with and future revisions to requirements and permits governing the use, discharge, and recycling of water used for hydraulic stimulation may increase our costs and cause delays, interruptions, or terminations of our operations that cannot be predicted.

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On May 16, 2013, the DOI released a revised proposed rule that, if adopted as drafted, would require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic stimulation process; (ii) confirm their wells meet certain construction standards; and (iii) establish site plans to manage flowback water. The revised proposed rule was subject to a 90-day public comment period, which ended on August 23, 2013. The Department of Energy (the “DOE”) is also considering whether to implement actions to lessen the environmental impact associated with hydraulic stimulation operations. Initiatives by the EPA and other federal and state regulators to expand their regulation of hydraulic stimulation, together with the possible adoption of new federal or state laws or regulations that significantly restrict hydraulic stimulation, could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform hydraulic stimulation, increase our costs of compliance and doing business, and delay or prevent the development of unconventional hydrocarbon resources from shale and other formations that are not commercial without the use of hydraulic stimulation. In addition, there have been proposals by non-governmental organizations to restrict certain buyers from purchasing oil and natural gas produced from wells that have utilized hydraulic stimulation in their completion process, which could negatively impact our ability to sell our production from wells that utilized these stimulation processes.

Apart from federal regulatory initiatives, states have been considering or implementing new requirements for hydraulic stimulation, including restricting its use in environmentally sensitive areas. Similarly, some localities have significantly limited or prohibited drilling activities, or are considering doing so. Although it is not possible at this time to predict the final requirements of any additional federal or state legislation or regulation regarding hydraulic stimulation, any new federal, state, or local restrictions on hydraulic stimulation that may be imposed in areas where we conduct business, such as the Bakken and Three Forks areas, could significantly increase our operating, capital, and compliance costs, as well as delay or halt our ability to develop oil and natural gas reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate, and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), enacted in 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position-limits rule was vacated by the U.S. District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

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 our 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.

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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 natural gas. Any profitability in the future from our business will be dependent upon our ability to locate and develop additional reserves of oil and natural gas, which itself is subject to numerous risk factors, including those 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.

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 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.

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 1B. Unresolved Staff Comments

The disclosures are not applicable to us.

Item 2. Properties.

As of December 31, 2013, we owned an approximate undivided 58% working interest in approximately 29,560 net acres located within the Spyglass Area, primarily in Divide County, North Dakota. As of December 31, 2013, we had drilled and completed 28 gross (13.66 net) operated wells and elected to participate in 75 gross (3.65 net) non-operated wells located within the Spyglass Area, all of which are producing as of that date. Our Spyglass Area wells currently produce approximately 1,850 barrels of oil equivalent (“BOE”) per day (“BOEPD”).

In addition to our focus area in Divide County, North Dakota, we have a total of approximately 12,000 net acres mostly located in Sheridan, Daniels, and Richland Counties, Montana, and southeastern Saskatchewan, Canada. We currently do not plan to devote capital to any of these areas over the next 12 months. 

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 The following is a summary of our developed acreage as of December 31, 2013:

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		51	%		18,175		9,191		532	Held by Production	Held by Production
Totals					19,135		10,151		534

The following is a summary of our undeveloped acreage as of December 31, 2013:

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		62	%		32,911		20,369		591	January 2014	August 2018
Benrude		100	%		623		623		27	February 2014	July 2015
Mustang		100	%		58		58		11	July 2015	August 2015
NE Montana		100	%		5,902		5,902		63	January 2015	December 2016
Sidney North		100	%		633		633		27	July 2014	October 2015
Pebble Beach		17	%		1,751		301		57	June 2017	June 2017
Totals					45,218		31,226		780

Additional information regarding our oil and gas properties can be found in Note 2 and Note 17 to our financial statements as of and for the years ended December 31, 2013 and 2012, which are included in Item 8 of this document (see pages 41 and 58, respectively).

We currently lease 8,755 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 June 30, 2016.

We do not own or lease any other properties.

Item 3. Legal Proceedings.

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

Item 4. Mine Safety Disclosures.

The disclosures are not applicable to us.

PART II

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

Since November 20, 2013, our common stock has been listed on the NYSE MKT under the symbol “AMZG.” Prior to listing on NYSE MKT, our common stock was quoted on the OTC Bulletin Board and the OTC Markets Group, Inc.’s OTCQX tier under the symbol “AMZG.”

The following table sets forth the high and low sale prices for our common stock for the periods indicated, as reported by NYSE MKT on and after November 20, 2013, and the high and low bid prices for our common stock, as reported by OTC Markets Group, Inc. before such date, in each case both on an actual basis and after giving effect to the 1-for-4 reverse stock split of our common stock that we plan to effect concurrently with the pricing of this offering. The prices for our common stock through and including November 19, 2013, 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 one-for four reverse stock-split that occurred on March 18, 2014.

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	High		Low
Year ended December 31, 2013:
First Quarter	$	8.60	$	3.28
Second Quarter		8.80		6.64
Third Quarter		9.96		6.52
Fourth Quarter (through November 19, 2013)		11.40		7.56
Fourth Quarter (from and after November 20, 2013)		10.72		8.04
Year ended December 31, 2012:
First Quarter		5.60		2.24
Second Quarter		3.80		2.56
Third Quarter		3.08		2.40
Fourth Quarter		3.52		2.36

As of March 28, 2014, there were 35 holders of record of our common stock.

We have never declared or paid any cash dividends on our common stock. We currently plan to retain any earnings to finance the growth of our business rather than to 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.

Item 6. Selected Financial Data

The disclosures are not applicable to us.

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 the reader 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. The reader 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.

Oil prices cannot be predicted with any certainty and have significantly affected profitability and returns for upstream producers. Historically, West Texas Intermediate (“WTI”) crude oil prices have averaged approximately $85.68 per barrel over the past five years, per the U.S. Energy Information Administration. However, during that time, WTI oil prices have experienced wide fluctuations in prices, ranging from $34.03 per barrel to $113.39 per barrel, with the median price of $88.32 per barrel. The daily WTI oil prices averaged approximately $97.97 and $94.15 for the years ended December 31, 2013 and 2012, respectively.

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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 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 current operations consist of 22 full-time employees.

As of November 20, 2013, our common stock has been listed on the NYSE MKT LLC. under the symbol “AMZG.” Prior to that, it was 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, American Eagle Energy Inc.

We are principally engaged in exploration activities in the northwest portion of Divide County, North Dakota, where we target the extraction of oil and natural gas reserves from the Middle Bakken and Three Forks formations. We are aggressively pursuing the development of our Spyglass Area, to which virtually all of our capital is being deployed. Our Spyglass Area represents 97% of our 2013 annual revenue and 99% of our estimated proved reserves as of December 31, 2013. We also hold an interest in a small number of wells located in southeastern Saskatchewan, Canada, to which we are not presently deploying capital.

In addition to our existing wells, we own undeveloped acreage interests located in Sheridan, Daniels and Richland Counties, Montana. We currently do not plan to devote capital to any of these areas over the next twelve months.

Oil & Gas Wells

We are primarily focused on drilling and completing wells located within our Spyglass Area, located in northwestern Divide County, North Dakota. As of December 31, 2013, 28 gross (13.66 net) of our operated Spyglass wells were producing, in which we own working interests ranging from approximately 8% to 66%, with an average working interest of approximately 49%. At December 31, 2013, there were 22 gross (11.58 net) operated wells producing from the Three Forks formation and 6 gross (2.07 net) operated wells producing from the Middle Bakken formation. During the year ended December 31, 2013, we added 19 gross operated wells (11.56 net) to production in our Spyglass Project area.

In addition, we have elected to participate as a non-operating working interest partner in the drilling of 75 gross (3.65 net) wells within the Spyglass Area, all of which were producing as of December 31, 2013. Our working interest ownership in these non-operated wells ranges from less than 1% to approximately 28%, with an average working interest of approximately 5%.

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The following table summarizes our Spyglass Area well activity for the year ended December 31, 2013:

			Non-		Total
	Operated		Operated		Spyglass
Gross Wells
Wells producing at beginning of period		9		46		55
Wells added to production during the period		19		29		48
Wells producing at end of period		28		75		103
Net Wells
Wells producing at beginning of period		2.10		2.69		4.79
Wells added to production during the period		11.56		0.96		12.52
Wells producing at end of period		13.66		3.65		17.31

We also operate three gross (2.50 net) wells and participate as a non-operating working interest partner in a fourth well (50% net working interest) located in southeastern Saskatchewan (the “Hardy Property”). Our working interests in these four gross (3.00 net) wells ranges from 50% to 100%, with an average of approximately 78%. The financial results stemming from the operation of our Canadian wells are significantly less favorable than those of our US wells. Accordingly, we will continue to evaluate the performance of our Hardy wells. Should circumstances dictate, we may elect to shut in our Hardy wells and/or seek to sell our interest in the wells.

Our capital expenditures related to well development totaled approximately $60.6 million for the year ended December 31, 2013. The cost of drilling and completing successful wells is dependent on a number of factors including, among other things, the vertical depth of the well, the lateral length of the well, the geological zone targeted for development, the methods used to complete the wells and the weather conditions at the time the wells are drilled. In general, our costs of drilling and completing wells that we operate decreased significantly during 2013 as a result of more efficient drilling operations, which has decreased the average number of days it takes for us to reach total depth on our wells, as well as the utilization of newer completion strategies and equipment.

During the year ended December 31, 2013, we spent approximately $62.9 million to acquire additional working and net revenue interests in existing producing wells as well as to expand our overall acreage position in areas containing proved oil and gas reserves.

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Oil and Gas Reserves

As a result of our successful drilling efforts, the expansion of our acreage positions and our acquisition of additional working and net revenue interests during the year, the estimated pre-tax present value of our proved oil and gas reserves, discounted at an annual rate of 10% (“PV10”) increased from approximately $118.5 million at January 1, 2013 to approximately $308.1 million as of December 31, 2013, a 160% increase.

During the year ended December 31, 2013, the volume of our estimated proved, developed oil and gas reserves increased from approximately 2.6 million BOE as of January 1, 2013 to approximately 4.7 million BOE as of December 31, 2013, an 81% increase. This increase is primarily the result of our successful drilling efforts, which enabled us to bring 19 new gross (11.56 net) operated wells onto production during the year. In addition, the estimated PV10 value of our proved, developed oil and gas reserves increased from approximately $66.9 million at December 31, 2012 to approximately $151.7 million as of December 31, 2013, a 127% increase. In addition to bringing new wells onto production, the value of our proved developed reserves was further enhanced by the increase in average oil and gas prices used to estimate such reserves, from $81.78 per barrel and $3.38 per mcf in 2012 to $90.63 per barrel and $5.15 per mcf during 2013.

The drilling and completion of new, operated wells during the year also contributed to the increase in our estimated proved, undeveloped oil and gas reserves from 3.2 million BOE as of January 1, 2013 to approximately 8.8 million BOE as of December 31, 2013, a 175% increase. The estimated PV10 value of our estimated proved, undeveloped reserves increased from approximately $51.6 million to approximately $156.4 million during the year, an increase of 203%.

Operating Results

The following table summarizes our consolidated revenue, production data, and operating expenses for the years ended December 31, 2013 and 2012:

	2013		2012
Revenues:
Oil revenues	$	42,850,592	$	10,705,762
Gas revenues		145,066		8,184
Liquids revenues		143,299		-
Total revenues	$	43,138,957	$	10,713,946
Sales volumes:
Oil (barrels)		492,706		134,314
Gas (mcf)		27,556		2,306
Liquids (barrels)		5,507		-
Total barrels of oil equivalent (“BOE”)		502,806		134,698
Average daily sales volumes (“BOEPD”)		1,378		369

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	2013		2012
Average sales prices:
Oil sales (per barrel)	$	86.97	$	79.71
Effect of settled derivatives (per barrel)		1.63		-
Oil sales, net of settled derivatives (per barrel)		88.60		79.71
Gas sales (per mcf)		5.26		3.55
Liquids sales (per barrel)		26.02		-
Oil equivalent sales per BOE	$	87.39	$	79.54
Adjusted Operating expenses (Non-GAAP):
Lease operating expenses (“LOE”)	$	6,719,219	$	2,152,170
Production taxes		4,889,887		1,048,001
Total oil and gas operating expenses		11,609,106		3,200,171
General and administrative expenses, excluding stock-based compensation		6,157,678		3,681,274
Stock-based compensation (non-cash)		1,203,118		822,485
Depletion, depreciation and amortization (non-cash)		10,073,464		2,860,187
Impairment of oil and gas properties (non-cash)		1,731,535		10,631,345
Total operating expenses	$	30,774,901	$	21,195,462
Costs and expenses per BOE:
LOE	$	13.36	$	15.98
Production taxes		9.73		7.78
Total oil and gas operating expenses		23.09		23.76
General and administrative expenses, excluding stock-based compensation		12.25		27.33
Stock-based compensation (non-cash)		2.39		6.11
Depletion, depreciation and amortization (non-cash)		20.03		21.23
Impairment of oil and gas properties (non-cash)		3.44		78.93
Total operating expenses	$	61.20	$	157.36
Adjusted net income (Non-GAAP)
Net income (loss)	$	1,594,434	$	(9,292,874	)
Add: Impairment of oil and gas properties		1,731,535		10,631,345
Add: Loss on early extinguishment of debt		3,713,972		-
Add: Unrealized losses on derivatives		814,609		122,651
Adjusted net income	$	7,854,550	$	1,461,122

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	2013			2012
Adjusted net income per share (Non-GAAP):
Basic	$	0.56		$	0.13
Diluted	$	0.54		$	0.13
Weighted average number of shares outstanding:
Basic		13,931,688			11,448,048
Diluted		14,598,836			11,565,242
Adjusted EBITDA (Non-GAAP):
Net income (loss)	$	1,594,434		$	(9,292,874	)
Less: Interest income		(13,292	)		(8,335	)
Less: Dividend income		(67,442	)		(63,654	)
Add: Interest expense		5,356,041			706
Add: Income tax expense (benefit)		1,768,716			(1,240,010	)
Add: Depletion, depreciation and amortization (non-cash)		10,073,464			2,860,187
Add: Stock-based compensation (non-cash)		1,203,118			822,485
Add: Loss on extinguishment of debt (non-cash)		3,713,972			-
Add: Impairment of oil and gas properties (non-cash)		1,731,535			10,631,345
Add: Unrealized losses on derivatives		814,609			122,651
Adjusted EBITDA	$	26,175,155		$	3,832,501
Adjusted EBITDA per share (Non-GAAP):
Basic	$	1.88		$	0.33
Diluted	$	1.79		$	0.33
Adjusted cash flow from operations (Non-GAAP):
Adjusted EBITDA	$	26,175,155		$	3,832,501
Less: Interest expense		(5,356,041	)		(706	)
Add: Amortization of deferred financing costs		601,855			-
Adjusted cash flow from operations	$	21,420,969		$	3,831,795

Results of Operations for the year ended December 31, 2013 vs. December 31, 2012

The following discussion is based on our consolidated results of operations, which includes our US oil and gas activities as well as well as those of our Canadian subsidiaries. As indicated above, our US operations is responsible for the vast majority of our revenues, oil and gas operating costs and general and administrative expenses, and is the primary focus of our go-forward operations.

Revenues from sales of oil and gas totaled approximately $43.1 million for the year ended December 31, 2013, compared to approximately $10.7 million for the year ended December 31, 2012, an increase of 303%. This increase was driven primarily by a 273% increase in production by volume and a 9% increase in year-to-date crude oil prices received. Oil sales represented 99% and 100% of total sales during the years ended December 31, 2013 and 2012, respectively. Production primarily increased due to the addition of 19 gross (11.56 net) productive operated wells and 29 gross (0.96 net) productive non-operated wells in the Williston Basin from December 31, 2012 to December 31, 2013. During the year ended December 31, 2013, we realized an $86.97 average price per barrel of oil ($88.60 including settled derivatives) compared to a $79.71 average price per barrel of oil during the year ended December 31, 2012. Our US wells accounted for 97% ($41.8 million) of our consolidated sales for the year ended December 31, 2013, compared to 82% of our consolidated sales for the year ended December 31, 2012.

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Lease operating expenses were approximately $6.7 million for the year ended December 31, 2013 compared to approximately $2.2 million for the year ended December 31, 2012. On a per-unit basis, LOE was $13.36 per BOE for the year ended December 31, 2013 compared to $15.98 per BOE for the year ended December 31, 2012. The decrease in the average LOE per BOE from 2012 to 2013 is primarily due to improved location wear, elevated production from wells that came onto production during the year, which drives the LOE per BOE downward, as well as more efficient overall production. We added 19 gross (11.56 net) productive operated wells and 29 gross (0.96 net) productive non-operated wells in the Williston Basin during the year ended December 31, 2013.

Production taxes were approximately $4.9 million for the year ended December 31, 2013, compared to approximately $1.0 million for the year ended December 31, 2012. Production taxes as a percentage of total revenues were 11.3% for the year ended December 31, 2013, compared to 9.8% for the year ended December 31, 2012. The Company’s Canadian oil and gas sales are not subject to production taxes. The increase in production tax expense as a percentage of total revenues correlates to the increase in US oil and gas revenues as a percentage of total, consolidated oil and gas revenues from 2012 to 2013.

General and administrative expenses, excluding stock based compensation, totaled approximately $6.2 million for the year ended December 31, 2013, compared to approximately $3.7 million for the year ended December 31, 2012. The increase is largely attributable to additional payroll and employee benefit expenses, as the number of our employees grew from 16 as of December 31, 2012 to 22 as of December 31, 2013. We also incurred higher legal and accounting fees during the period, as our Company contemplated various equity and financing transactions and successfully transitioned its common stock from the OTC Markets Group, Inc.’s OTC-QX tier to being listed on the NYSE MKT in November 2013.

Depletion, depreciation and amortization expense was approximately $10.1 million ($20.03 per BOE) for the year ended December 31, 2013, and approximately $2.9 million ($21.23 per BOE) for the year ended December 31, 2012. Our depletion expense is based on the capitalized costs related to oil and gas properties for which proved reserves have been assigned, plus the estimated future development costs necessary to convert undeveloped proved reserves to proved producing reserves. Our capitalized costs related to amortizable oil and gas properties increased from $46.3 million at December 31, 2012 to $167.7 million at December 31, 2013. This increase in depletion expense was due primarily to the addition of 19 gross (11.56 net) productive operated wells and 29 gross (0.96 net) productive non-operated wells in the Williston Basin during the year ended December 31, 2013, as well as the identification of 265 new future drill sites, for which proved, undeveloped reserves have been assigned.

Due to lower than anticipated production volumes from our Hardy Property wells and declining oil prices during the period, we were required to write-down the value of our Canadian oil and gas properties at year-end December 31, 2012, and again at March 31, 2013, pursuant to full-cost accounting rules. In doing so, we recognized an impairment expense of approximately $1.7 million related to our Hardy Property for the year ended December 31, 2013, compared to $10.6 million for the year ended December 31, 2012. The impairment expense represents a non-cash charge against our earnings.

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In August 2013, we entered into $200 million credit facility (“Credit Facility”) with Morgan Stanley Capital Group, Inc. (“MSCG”), at which time we borrowed $68 million. We used a portion of these funds to fully repay the then-outstanding balance of our prepaid swap facility (“Swap Facility” with Macquarie Bank Ltd. (“MBL”). In doing so, we recognized a loss on the early extinguishment of debt totaling approximately $3.7 million, which included the non-cash write-off of approximately $0.6 million of deferred financing costs related to the MBL Swap Facility.

We recognized aggregate interest expense totaling approximately $5.4 million for the year ended December 31, 2013, of which approximately $0.9 million related to our Swap Facility and approximately $4.4 million related to our Credit Facility. Included in the aggregate interest expense figure is non-cash amortization of deferred financing costs totaling approximately $0.6 million. We did not recognize any debt-related interest expense during the corresponding period in 2012 as we closed on the Swap Facility on December 28, 2012. The specific terms of the Swap Facility and the Credit Facility are discussed in the “Liquidity and Capital Resources” section, below.

In connection with our Credit Facility, we are required to enter into price swap agreements covering up to 85% of the anticipated production from our estimated proved developed reserves over the remaining life of the Credit Facility. We recognized realized gains from derivatives totaling approximately $0.8 million and unrealized losses from derivatives totaling approximately $0.8 million for the year ended December 31, 2013. Additional losses or offsetting gains could be recognized in the future, depending on projected future oil prices.

We recognized estimated income tax expense of approximately $1.8 million for the year ended December 31, 2013, compared to an income tax benefit of approximately $1.2 million for the year ended December 31, 2012.

Our basic and diluted income per share was $0.11 for the year ended December 31, 2013, compared to basic and diluted losses per share of ($0.81) for the year ended December 31, 2012.

Our adjusted net income for the year ended December 31, 2013 and 2012 was approximately $7.9 million and $1.5 million, respectively. Adjusted net income is derived by adding back unusual or infrequent items, such as the impairment of our Canadian properties and the early extinguishment of debt, as well as the effect of unrealized derivative gains (losses) to our net income. Adjusted net income is a non-GAAP financial measure.

Our adjusted EBITDA for the years ended December 31, 2013 and 2012 was approximately $26.2 million and $3.8 million, respectively. Adjusted EBITDA is derived by removing non-operating expenses, such as interest income (expense), income tax benefit (expense) and dividend income, from the calculation of net income, along with unusual or infrequent items, such as the impairment of oil and gas properties and the early extinguishment of debt. The calculation of Adjusted EBITDA also takes into consideration the effect of certain non-cash items, such as depletion, depreciation and amortization, stock-based compensation and any unrealized gains (losses) from derivatives. Adjusted EBITDA is a non-GAAP financial measure.

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Liquidity and Capital Resources

As of December 31, 2013, our assets totaled approximately $216.2 million, which included, among other items, cash balances of approximately $31.9 million, trade receivables totaling approximately $17.9 million and marketable securities valued at approximately $1.0 million. Our working capital as of December 31, 2013 was approximately $4.9 million.

On December 28, 2012, we entered into our Swap Facility with MBL, pursuant to which MBL agreed to advance up to $18.0 million, of which $16.0 million was received at closing. The remaining $2.0 million was received in January 2013. Funds received under the Swap Facility were accounted for as debt and were scheduled to 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 $2.0 million, due in February 2018.

On August 9, 2013, we sold 1,250,000 million shares of our common stock (5,000,000 shares on a pre-reverse-split basis) at a price of $8.00 per share ($2.00 per share on a pre-reverse-split basis) in transaction utilizing our June 2013 shelf registration. The net proceeds from the sale of equity totaled approximately $9.9 million and were used to reduce our working capital deficit.

On August 12, 2013, we entered into a second carry agreement (the “Second Carry Agreement”) with one of our working interest partners (our “Carry Agreement Partner”), pursuant to which our Carry Agreement Partner agreed to fund 100% of our working interest share of the drilling and completion costs of up to five new oil and gas wells to be located within the Spyglass Area, up to 120% of the original authorized-for-expenditure (“AFE”) amount. In the event that the gross drilling and completion cost of a carried well exceeds 120% of the AFE amount, we and our Carry Agreement Partner will share in the excess costs based on the working interests stipulated in the Second Carry Agreement. 

Pursuant to the terms of the Second Carry Agreement, 50% of the our net revenue interest in each well will be conveyed to our Carry Agreement Partner for a period of two years or until such a time when our Carry Agreement Partner has recouped 112% of the carried drilling and completion costs of the well, whichever occurs sooner.  In the event that our Carry Agreement Partner has not recouped 112% of the carried drilling and completion costs by the end of the second year of production, we have agreed to make cash payments to our Carry Agreement Partner in the amount of the shortfall.  Once our Carry Agreement Partner has recouped 112% of the carried drilling and completion costs of a well, the conveyed working interest and net revenue interest will revert to us. 

Also on August 12, 2013, we entered into a Farm-Out Agreement with the Carry Agreement Partner, pursuant to which that Carry Agreement 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 to be located within the original Spyglass and West Spyglass sections of the Spyglass Area. Pursuant to the terms of the Farm-Out Agreement, we will convey, for a period of time, 100% of our net revenue interest in the pre-payout revenues of each farm-out well and 100% of our working interest in the pre-payout operating costs of each farm-out well, to our Carry Agreement Partner, until such a time when our Carry Agreement Partner has recouped 112% of the drilling and completion costs associated with each well.  Once our Carry Agreement Partner has recouped 112% of the drilling and completion costs of a well, our Carry Agreement Partner will convey 30% of our original working and net revenue interests in each farm-out well back to us.

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On August 19, 2013, we entered into a $200.0 million Credit Facility with MSCG, which is comprised of an initial $68.0 million term loan (the “Initial Term Loan”), an available term loan of up to $40.0 million to be used to fund a potential future acquisition (the “Spyglass Tranche A Loan”), and an uncommitted term loan of up to $92.0 million (the “Tranche B Loan”). The Credit Facility is collateralized by, among other things, our oil and gas properties and future oil and gas sales derived from such properties. A portion of the funds received from the Initial Term Loan were used to repay in full the then-outstanding balance under the Swap Facility. We recognized a loss on the early extinguishment of the Swap Facility in the amount of approximately $3.7 million. The remaining proceeds from the Initial Term Loan were or will be used (i) to reduce our outstanding payables, (ii) to further develop our Spyglass Area in North Dakota, (iii) to acquire new oil and gas properties within the Spyglass Area and (iv) to fund general corporate purposes.

On October 7, 2013, we closed the $40.0 million Spyglass Tranche A Loan, which brought our outstanding balance under the Credit Facility to $108.0 million.

In October 2013, we sold an aggregate of 3,941,449 shares (15,765,794 shares on a pre-reverse-split basis) of our common stock at a price of $6.80 per share ($1.70 per share on a pre-reverse-split basis) in transaction utilizing our June 2013 shelf registration. Proceeds received from the sale of equity, net of closing costs, issuance costs and broker fees, totaled approximately $25.0 million.

On March 24, 2014, we sold an aggregate of 12,650,000 shares (50.6 million shares on a pre-reverse-split basis) of our common stock at a price of $6.60 per share ($1.65 per share on a pre-reverse-split basis) in transaction utilizing our shelf registration. Proceeds received from the sale of equity, net of issuance costs and broker fees, totaling approximately $78.0 million. A portion of the net proceeds from the public offering will be used to close the second half of our previously announced working interest acquisition. The remaining funds will be used to fund a portion of our 2014 drilling program and to provide working capital support.

The aggregate proceeds received by us from the aforementioned sales of equity and borrowings were used to acquire additional working interests in our Spyglass Area, and will be used (i) to execute our 2014 drilling program, (ii) to fund further development of wells within our Spyglass Area, and (iii) to provide working capital for operations.

On March 11, 2014, we exercised the purchase option in favor of us (the “Purchase Option”) under the PSO Agreement (as defined below). For $47 million ($45.8 million after adjusting for positive purchase price adjustments) in cash paid by us to our Carry Agreement Partner at the March 27, 2014 closing (the Second Closing”). We acquired additional working interests and net revenue interests from our Carry Agreement Partner in our existing acreage and wells in the Spyglass Area (the “Second Acquisition”).

The Second Acquisition increased our net operated acreage by 8,244 net acres and added approximately 450 BOEPD as of the June 1, 2013 effective date of the Second Acquisition. It also increased our Spyglass Area operated average working interest from approximately 44% to 55% in our total Spyglass Area and from approximately 51% to 60% in our proved area of Spyglass.

The Second Acquisition was consummated pursuant to the Purchase, Sale and Option Agreement dated August 12, 2013 (the “Initial PSO Agreement”) with our Carry Agreement Partner, which we amended on September 30, 2013 (the “First Amendment”), amended again on October 2, 2013 (the “Second Amendment”), and subsequently amended a third time on March 27, 2014 in connection with the Second Closing (the “Third Amendment,” and, collectively with the Initial PSO Agreement, the First Amendment, and the Second Amendment, the “PSO Agreement”). In October 2013, we closed the first portion of the acquisition under the PSO Agreement, pursuant to which, for $47 million ($45 million at close after adjusting for positive purchase price adjustments), we purchased approximately 9,700 net acres in our Spyglass Area with production of approximately 750 BOEPD as of the June 1, 2013 effective date (the “First Acquisition”).

In connection with the Second Closing and pursuant to the Third Amendment, our Carry Agreement Partner and we entered into a new Joint Operating Agreement that fully amends and replaces the previously existing joint operating agreements between us for the primary purposes of (i) reducing the area of mutual interest (the “AMI”) to limit it to the producing spacing units and (ii) extending the AMI for two years. Also effective upon the Second Closing, our obligations under the Second Carry Agreement have been completely satisfied.

For more detail regarding the materials terms of the PSO Agreement, the First Acquisition, the Purchase Option, the interests that are subject to the Purchase Option (including financial information with respect to such interests), and the Second Carry Agreement and the Farm-Out Agreement that we entered into with our JV Partner in connection with the PSO Agreement, see (i) our Current Report on Form 8-K/A filed with the Securities and Exchange Commission on December 16, 2013 and (ii) our Current Report on Form 8-K filed with the Securities and Exchange Commission on March 10, 2014.

On March 27, 2014, for approximately $7.5 million paid by us to our Carry Agreement Partner on such date, we purchased from it approximately 5,000 net acres located in the original West Spyglass area. The acquisition included all of its leasehold, mutual interests, lease and title records, contractual and beneficial rights, together with any and all similar rights and interests appurtenant thereto, with an effective date as of March 1, 2014.

In connection with this acquisition, our Carry Agreement Partner and we agreed to amend the terms of the Farm-Out Agreement, (i) to change the location of the sixth well covered thereunder, (ii) to provide that we shall farmout 50% of our working interest to it on identical terms as stated in the Farm-Out Agreement, and (iii) to provide that we shall pay our remaining 50% working interest in the drilling of the sixth farm-out well. We also agreed to reimburse our Carry Agreement Partner for certain costs incurred by it pertaining to the Shelly 3-2N-163-102 well.

It is possible that we will seek additional financing, or raise capital through the sale of additional shares of our common stock in the future, in order to fund future drilling activities, to develop our existing acreage further, or to acquire acreage or interests in other oil and gas properties.

Litigation

As of December 31, 2013, we were not subject to any known, pending or threatened litigation.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

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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 31 of this Annual Report.

American Eagle Energy Corporation

Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

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American Eagle Energy Corporation

Index to the Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Report of Independent Registered Public Accounting Firm	32
Consolidated Balance Sheets as of December 31, 2013 and 2012	33
Consolidated Statements of Operations and Comprehensive Income (Loss) for Each of the Two Years in the Period Ended December 31, 2013	34
Consolidated Statements of Stockholders’ Equity for Each of the Two Years in the Period Ended December 31, 2013	36
Consolidated Statements of Cash Flows for Each of the Two Years in the Period Ended December 31, 2013	37
Notes to the Consolidated Financial Statements	38

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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, 2013 and 2012, and the related consolidated statements of operations and other 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 audit 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, 2013 and 2012, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

/s/ Hein & Associates LLP

Denver, Colorado

March 28, 2014

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

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American Eagle Energy Corporation

Consolidated Balance Sheets

As of December 31, 2013 and 2012

	2013			2012
Current assets:
Cash	$	31,850,161		$	19,057,727
Trade receivables		17,919,518			24,750,444
Income tax receivable		-			190,000
Prepaid expenses		68,194			133,067
Total current assets		49,837,873			44,131,238
Equipment and leasehold improvements, net of accumulated depreciation and amortization of $322,437 and $227,067, respectively		173,516			201,329
Oil and gas properties (full cost method) – subject to amortization, net of accumulated depletion of $12,849,063 and $2,978,403, respectively		155,145,039			43,291,543
Oil and gas properties (full cost method) – not subject to amortization		2,487,158			7,349,994
Marketable securities		1,049,944			1,049,859
Other assets		7,503,612			890,149
Total assets	$	216,197,142		$	96,914,112
Current liabilities:
Accounts payable	$	41,842,068		$	54,473,721
Amounts due to working interest partners		-			4,956,817
Derivative liability		64,737			122,651
Current portion of long-term debt		3,000,000			5,931,003
Total current liabilities		44,906,805			65,484,192
Asset retirement obligation		1,059,689			441,609
Noncurrent portion of long-term debt		105,000,000			10,068,997
Noncurrent derivative liability		749,872			-
Deferred taxes		5,385,954			3,519,494
Total liabilities		157,102,320			79,514,292
Commitments and contingencies (Note 11)
Stockholders’ equity:
Common stock, $.001 par value, 48,611,111 shares authorized, 17,712,151 and 11,517,087 shares outstanding		17,712			11,517
Additional paid-in capital		67,197,521			27,129,492
Accumulated other comprehensive income (loss)		(5,747	)		(32,091	)
Accumulated deficit		(8,114,664	)		(9,709,098	)
Total stockholders’ equity		59,094,822			17,399,820
Total liabilities and stockholders’ equity	$	216,197,142		$	96,914,112

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

33

American Eagle Energy Corporation

Consolidated Statements of Operations and Comprehensive Income (Loss)

For Each of the Two Years in the Period Ended December 31, 2013

	2013			2012
Oil and gas revenues	$	43,138,957		$	10,713,946
Operating expenses:
Oil and gas production costs		11,609,106			3,200,171
General and administrative expenses		7,360,796			4,503,759
Depreciation, depletion and amortization		10,073,464			2,860,187
Impairment of oil and gas properties, subject to amortization		1,731,535			10,631,345
Total operating expenses		30,774,901			21,195,462
Total operating income (loss)		12,364,056			(10,481,516	)
Other income (expense)
Interest income		13,292			8,335
Dividend income		67,442			63,654
Interest expense		(5,356,041	)		(706	)
Loss on early extinguishment of debt		(3,713,972	)		-
Realized gain on derivatives		802,982			-
Unrealized loss on derivatives		(814,609	)		(122,651	)
Total other income (expense)		(9,000,906	)		(51,368	)
Income (loss) before taxes		3,363,150			(10,532,884	)
Income tax expense (benefit)		1,768,716			(1,240,010	)
Net income (loss)	$	1,594,434		$	(9,292,874	)
Net income (loss) per common share:
Basic	$	0.11		$	(0.81	)
Diluted	$	0.11		$	(0.81	)
Weighted average number of shares outstanding:
Basic		13,961,688			11,448,048
Diluted		14,598,836			11,448,048

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

34

American Eagle Energy Corporation

Consolidated Statements of Operations and Comprehensive Income (Loss)

For Each of the Two Years in the Period Ended December 31, 2013

	2013			2012
Net income (loss)	$	1,594,434		$	(9,292,874	)
Other comprehensive (loss) income:
Unrealized gains (losses) on securities, net of tax		(1,270	)		(109,681	)
Foreign currency translation adjustments, net of tax		27,614			(102,857	)
Comprehensive income (loss)	$	1,620,778		$	(9,505,412	)

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

35

American Eagle Energy Corporation

Consolidated Statements of Stockholders’ Equity

For Each of the Two Years in the Period Ended December 31, 2013

								Accumulated
					Additional			Other						Total
	Common Stock				Paid-In			Comprehensive			Accumulated			Stockholders
	Shares		Amount		Capital			Income (Loss)			Deficit			Equity
Balance, December 31, 2011		11,397,238	$	11,397	$	25,982,503		$	180,447		$	(416,224	)	$	25,758,123
Stock based compensation		-		-		822,485			-			-			822,485
Shares issued in private placement		25,000		25		109,975			-			-			110,000
Shares issued from exercise of stock options		38,458		39		34,585			-			-			34,624
Shares issued in debt financing		56,391		56		179,944			-			-			180,000
Unrealized loss on securities, net of tax		-		-		-			(109,681	)		-			(109,681	)
Foreign exchange translation adjustments		-		-		-			(102,857	)		-			(102,857	)
Net loss		-		-		-			-			(9,292,874	)		(9,292,874	)
Balance, December 31, 2012		11,517,087	$	11,517	$	27,129,492		$	(32,091	)	$	(9,709,098	)	$	17,399,820
Stock based compensation		-		-		1,203,118			-			-			1,203,118
Shares issued in private placements		2,250,000		2,250		13,875,117			-			-			13,877,367
Shares issued in public offerings		3,941,449		3,941		24,989,798			-			-			24,993,739
Shares issued upon exercise of options		3,607		4		(4	)		-			-			-
Unrealized loss on securities, net of tax		-		-		-			(1,270	)		-			(1,270	)
Foreign exchange translation adjustments		-		-		-			27,614			-			27,614
Rounding effect of 1-for-4 reverse split		8		-		-			-			-			-
Net income		-		-		-			-			1,594,434			1,594,434
Balance, December 31, 2013		17,712,151	$	17,712	$	67,197,521		$	(5,747	)	$	(8,114,664	)	$	59,094,822

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

36

American Eagle Energy Corporation

Consolidated Statements of Cash Flows

For Each of the Two Years in the Period Ended December 31, 2013

	2013			2012
Cash flows provided by (used for) operating activities:
Net income (loss)	$	1,594,434		$	(9,292,874	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Stock-based compensation		1,203,118			822,485
Depreciation, depletion and amortization		10,073,464			2,860,187
Amortization of deferred loan costs		601,855			-
Accretion of discount on asset retirement obligation		49,357			5,301
Provision for deferred income taxes		1,794,437			(938,476	)
Impairment of oil and gas properties		1,731,535			10,631,345
Unrealized loss on derivatives		691,958			122,651
Foreign currency adjustments		(12,062	)		(51,556	)
Loss on early extinguishment of debt		3,713,972
Changes in operating assets and liabilities:
Prepaid expense		63,797			(87,377	)
Trade receivables		4,468,346			(798,868	)
Income taxes receivable		190,000			(190,000	)
Receivables from related parties		-			314,521
Deposits		-			(3,304	)
Accounts payable		4,247,092			1,954,489
Income taxes payable		-			(1,460,137	)
Net cash provided by (used for) operating activities		30,411,303			3,888,387
Cash flows provided by (used for) investing activities:
Proceeds from the partial sale of oil and gas prospects		-			227,661
Proceeds from the conveyance of working interests		-			3,789,989
Proceeds from the sale of equipment		-			1,100
Additions to oil and gas properties		(136,267,327	)		(18,914,663	)
Additions to equipment and leasehold improvements		(67,557	)		(252,929	)
Increase (decrease) in amounts due to Carry Agreement partner		(4,956,817	)		2,723,550
Purchase of certificates of deposit		-			(50,000	)
Purchase of marketable securities		-			(51,301	)
Net cash provided by (used for) investing activities		(141,291,701	)		(12,526,593	)
Cash flows provided by financing activities:
Net proceeds from issuance of stock		38,871,106			110,000
Proceeds from exercise of stock options		-			34,624
Net proceeds from issuance of long-term debt		105,935,346			16,000,000
Repayment of debt		(21,131,197	)		(600,000	)
Net cash provided by financing activities		123,675,255			15,544,624
Effect of exchange rate changes on cash		(2,423	)		-
Net increase in cash		12,792,434			6,906,418
Cash - beginning of period		19,057,727			12,151,309
Cash - end of period	$	31,850,161		$	19,057,727

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

37

American Eagle Energy Corporation

Consolidated Statements of Cash Flows

For Each of the Two Years in the Period Ended December 31, 2013

Supplemental Disclosure of Cash Flow Information

	2013			2012
Cash paid during the period for:
Interest	$	3,746,186		$	706
Income taxes		(177,640	)		1,255,000

Supplemental Disclosure of Non-Cash Investing and Financing Activities

	2013		2012
Stock issued in connection with debt financing	$	-	$	180,000
Property additions included in accounts payable		19,424,634		25,670,531
Property additions through the establishment of asset retirement obligations		515,840		406,981

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

38

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

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.

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, 2013, the Company had entered into participation agreements related to oil and gas exploration projects in the Spyglass Area, 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 first-tier subsidiaries, AMZG, Inc., EERG Energy ULC (“EERG” - Canadian) and AEE Canada Inc. (“AEE Canada” - 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. These reclassifications had no effect on net income (loss) for the year ended December 31, 2012.

Revenue Recognition

Revenue from the sale of produced 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 accrues estimated oil and gas sales for production periods that have not yet been settled in cash.

Concentration of Credit Risk

At any point throughout the year, the Company may have amounts that exceed the United States (FDIC) federally insurance limit of $250,000 per bank.

39

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Foreign Currency Adjustments

The functional currency of EERG and AEE Canada is the Canadian Dollar. EERG’s and AEE Canada’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. 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 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. 

40

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

At December 31, 2013 and 2012, 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.  

41

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

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 impairment losses totaling approximately $1.7 million and approximately $10.6 million associated with its Canadian cost center for the years ended December 31, 2013 and 2012, respectively.

Proceeds received from the disposal of oil and gas properties 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 derivatives at its fair market value as of the end of each reporting period. 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 10.5%, which represented the Company’s estimated incremental borrowing rate as of the dates that the corresponding wells were put on production.

42

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

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 approximately $1.2 million and $0.8 million for the years ended December 31, 2013 and 2012, 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 volatility of the Company’s 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, 2013 and 2012.

43

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Income Taxes

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. 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, 2013 and 2012.

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, 2013, the Company had working capital of approximately $4.9 million.

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 and the valuation of oil and gas reserves to which the Company owns rights. 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.

44

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

3. Marketable Securities and Fair Value Measurements

Available-for-sale marketable securities at December 31, 2013 and 2012 consist of the following:

			Gains in		Losses in
			Accumulated		Accumulated
	Estimated		Other		Other
	Fair		Comprehensive		Comprehensive
	Value		Income		Income
December 31, 2013
Noncurrent assets:
Common stock	$	1,049,944	$	76,881	$	-
December 31, 2012
Noncurrent assets:
Common stock	$	1,049,859	$	76,796	$	-

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, 2013 or 2012.

The fair value of the Company’s financial instruments, measured on a recurring basis at December 31, 2013 and 2012, were as follows:

December 31, 2013	Level 1		Level 2			Level 3		Total
Marketable securities	$	1,049,944	$	-		$	-	$	1,049,944
Current derivative asset		-		210,779			-		210,779
Current derivative liability		-		(275,516	)		-		(275,516	)
Noncurrent derivative liability		-		(749,872	)		-		(749,872	)
December 31, 2012
Marketable securities		1,049,859		-			-		1,049,859
Current derivative liability		-		(122,651	)		-		(122,651	)

4. Purchases of Royalty and Property Interests

In December 2012, the Company purchased additional net revenue and working interests in several key, non-operated spacing units within the Spyglass Area from its Carry Agreement partner. The purchase price totaled $8 million in cash, of which $2.4 million was paid at closing. The remaining $5.6 million was paid in September, 2013.

45

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

In January 2013, the Company purchased additional net revenue and working interests in several key, non-operated spacing units within the Spyglass Area from SM Energy Company. The purchase price totaled approximately $3.9 million in cash, which was paid at closing.

In October 2013, the Company purchased additional net revenue and working interests in proved producing and proved undeveloped properties located within the Spyglass Area from a certain working interest partner. The transaction closed on October 2, 2013 with an effective date of June 1, 2013. The gross purchase price for the acquired interests totaled $47 million. The net purchase prices, after taking into consideration revenues and operating expenses associated with the acquired interests from the period June 1, 2013 through the closing date, totaled $41.4 million. To finance the acquisition, the Company sold shares of its common stock, through two public offerings (See Note 12), and borrowed an additional $40 million under its existing credit facility with Morgan Stanley Capital Group, Inc. (See Note 8).

Supplemental Pro Forma Information (Unaudited)

The Company’s consolidated statement of income for the year ended December 31, 2013 includes revenues and oil and gas operating expenses related to the net revenue and working interests acquired in October 2013 for the period October 2, 2013 through December 31, 2013 of approximately $4.2 million and $1.0 million, respectively.

Had the purchase of these additional net revenue and working interests occurred on January 1, 2012, the Company’s consolidated financial statements for the years ended December 31, 2013 and 2012 would have been as follows:

	2013		2012
Pro forma revenues	$	57,823,375	$	15,988,431
Pro forma net income (loss)	$	4,134,461	$	(10,872,966	)

5. Carry Agreements

On April 16, 2012, the Company entered into a carry agreement (the “First Carry Agreement”) with a third-party working interest partner (“Carry Agreement 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 Area, 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 the Carry Agreement 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 Carry Agreement Partner will share in the excess costs based on the working interests stipulated in the First Carry Agreement.

Pursuant to the terms of the First Carry Agreement, the portion of the Company’s net revenue interest in each well to be conveyed to the Carry Agreement Partner follows a graduated scale, whereby 50% of the Company’s net revenue and working interests is assigned to the Carry Agreement 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 Carry Agreement 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 Carry Agreement 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.

46

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Drilling of the first two carried wells commenced prior to the final closing of the First 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 First Carry Agreement totaling approximately $3.8 million. Upon execution of the First 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 First 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 years ended December 31, 2013 and 2012, as adjusted pursuant to the graduated conveyance schedule per the First 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 years ended December 31, 2013 and 2012.

Effective July 15, 2012, the Company amended the First Carry Agreement with the Carry Agreement Partner to include an additional four oil and gas wells. As of December 31, 2013, the Company has received approximately $28.5 million of funding under the First Carry Agreement, as amended. Proceeds received pursuant to the terms of the First 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 First Carry Agreement are presented net of proceeds received under the First Carry Agreement on the consolidated statement of cash flows. Funds received pursuant to the First 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, 2013, all ten of the wells drilled pursuant to the First Carry Agreement were producing. As of December 31, 2013, the gross drilling and completion costs of five 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, 2013, totaled approximately $2.5 million. None of the ten wells covered by the First Carry Agreement has achieved payout as of December 31, 2013.

In August 2013, the Company entered into a second carry agreement (the “Second Carry Agreement”) with the Carry Agreement Partner, pursuant to which (i) that Carry Agreement Partner agreed to fund 100% of the Company’s working interest share of the drilling and completion costs of up to five new oil and gas wells to be located within the Spyglass Area, up to 120% of the original AFE amount, and (ii) the Company will convey, for a limited duration, 50% of its revenue interest in the pre-payout revenues of each carried well and 50% of its working interest in the pre-payout operating costs of each carried well, to the Carry Agreement 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 Carry Agreement Partner will share in the excess costs based on the working interests stipulated in the Carry Agreement. 

47

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Pursuant to the terms of the Second Carry Agreement, 50% of the Company’s net revenue interest in each well will be conveyed to the Carry Agreement Partner for a period of two years or until such a time when the working interest partner has recouped 112% of the carried drilling and completion costs of the well, whichever occurs sooner.  In the event that the Carry Agreement Partner has not recouped 112% of the carried drilling and completion costs by the end of the second year of production, the Company has agreed to make cash payments to the Carry Agreement Partner in the amount of the shortfall.  Once the Carry Agreement Partner has recouped 112% of the carried drilling and completion costs of a well, the conveyed working interest and net revenue interest will revert to the Company. 

As of December 31, 2013, two of the five wells drilled pursuant to the Second Carry Agreement were producing. The remaining three wells were either in the process of being completed or awaiting drilling. To date, the Company has received approximately $4.1 million of funding under the Second Carry Agreement. As of December 31, 2013, the cost of drilling and completing each of these five wells has not exceeded the 120% of AFE cost threshold. Accordingly, the Company has not recorded any drilling and completion costs associated with these five wells as of December 31, 2013. None of the five wells covered by the Second Carry Agreement has achieved payout as of December 31, 2013.

6. Farm-Out Agreement

In August 2013, the Company entered into a Farm-Out Agreement (the “Farm-Out Agreement”) with the same Carry Agreement Partner, pursuant to which (i) that Carry Agreement 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 to be located within the original Spyglass and West Spyglass sections of the Spyglass Area and (ii) the Company will convey, for a period of time, 100% of its net revenue interest in the pre-payout revenues of each farm-out well and 100% of its working interest in the pre-payout operating costs of each farm-out well, to the Carry Agreement Partner, until such a time when the Carry Agreement Partner has recouped 112% of the drilling and completion costs associated with each well.  Once the Carry Agreement Partner has recouped 112% of the drilling and completion costs of a well, the Carry Agreement Partner will convey 30% of the Company’s original working and net revenue interests in each farm-out well back to the Company.

As of December 31, 2013, two of the six wells drilled pursuant to the Farm-Out Agreement were producing. The remaining four wells were either in the process of being completed or awaiting drilling. To date, the Company has received approximately $5.1 million of funding under the Farm-Out Agreement. None of the six wells covered by the Farm-Out Agreement has achieved payout as of December 31, 2013.

48

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

7. Swap Facility

On December 28, 2012, the Company entered into a prepaid Swap Facility with MBL, pursuant to which MBL agreed to advance up to $18 million, of which $16 million was received at closing. The remaining $2 million was received in January 2013.

Funds received under the Swap Facility are accounted for as debt and were scheduled to 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 Company incurred investment banking fees and closing costs totaling $780,000 in connection with the negotiation and closing of the MBL Swap Facility. The Company capitalized these items as deferred financing costs, to be amortized over the life of the Swap Facility. The Company recognized approximately $151,000 of amortization expense related to the deferred financing costs for the year ended December 31, 2013. The amortization of deferred loan costs is included as an additional component of interest expense for the respective periods.

On August 19, 2013, the Company repaid in full the outstanding balance under the Swap Facility using proceeds received from a new Credit Facility (see Note 8). The total payoff amount was approximately $18.0 million, which included 100% of the then outstanding principal balance, the settlement of all outstanding swap agreements, and certain prepayment penalties. The Company recognized a loss on the early extinguishment of debt of approximately $3.7 million, which includes prepayment penalties, the termination of related price swap agreements and the write-off of deferred financing costs associated with the Swap Facility.

The annual interest rate associated with the Swap Facility approximated 7.4%. The Company recognized interest expense related to the Swap Facility totaling approximately $903,000 and $183,000 for the years ended December 31, 2013 and 2012, respectively.

8. Credit Facility

In August 2013, the Company entered into a $200 million Credit Facility with MSCG, which is comprised of an initial $68 million term loan (the “Initial Term Loan”), a $40 million term loan to be used to fund certain working interest purchases (the “Spyglass Tranche A Loan”) and an uncommitted term loan of up to $92 million (the “Tranche B Loan”). The Credit Facility is collateralized by, among other things, the Company’s oil and gas properties and future oil and gas sales derived from such properties.

Proceeds from borrowings under the Initial Term Loan totaling $68 million were used: (i) to reduce the Company’s payables, (ii) to develop its Spyglass Area in North Dakota to increase production of hydrocarbons, (iii) to acquire new oil and gas properties within the Spyglass Area and (iv) to fund general corporate purposes that are usual and customary in the oil and gas exploration and production business.

49

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Proceeds from borrowings under the Spyglass Tranche A Loan totaling $40 million were used to purchase additional net revenue and working interests in the Spyglass Area (See Note 4).

The Credit facility has a five-year term and carries a variable interest rate ranging from approximately 5.5% to 10.5%. The variable interest rate is based primarily on the ratio of the Company’s proved developed reserves to its debt for a given period. As of December 31, 2013, the applicable variable interest rate on the Credit Facility was 10.5%. Interest expense related to the Initial Term Loan and Spyglass Tranche A Loan totaled approximately $3.8 million for the year ended December 31, 2013.

The Company incurred investment banking fees and closing costs totaling approximately $7.8 million in connection with the negotiation and closing of the Initial Term Loan and Spyglass Tranche A Loan. The Company has capitalized these items as deferred financing costs, and will amortize these costs over the life of the Credit Facility using the effective interest method. The amortization of deferred financing costs is included as a component of the Company’s interest expense for the period. The Company amortized approximately $451,000 of deferred financing costs related to the Credit Facility during the year ended December 31, 2013.

Scheduled principal repayments under the Credit Facility begin in August 2014. The amount of each monthly principal payment is dependent on the ratio of the present value of the Company’s proved developed reserves, discounted at a rate of 9%, to the amount of borrowing outstanding under the Credit Facility as of certain predetermined dates. The minimum monthly amortization applicable to the Initial Term Loan and the Spyglass Tranche A Loan is $600,000. Accordingly, the Company has classified $3.0 million of the debt outstanding under the Credit Facility as a current liability.

The Credit Facility contains customary affirmative and negative covenants for borrowings 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 Credit Facility, liens and encumbrances in respect of the property that secures our collective obligations under the Credit Facility, subsidiaries and divestitures, indebtedness, investments, and changes in business. As of December 31, 2013, the Company was in compliance with these covenants.

50

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Future minimum principal payments under the Credit Facility are as follows:

	Amount
2014	$	3,000,000
2015		7,200,000
2016		7,200,000
2017		7,200,000
2018		83,400,000
Total	$	108,000,000

9. Price Swap Agreements

As a condition of closing for the Swap Facility (see Note 7), the Company entered into various commodity derivative contracts to mitigate the effects of potential downward pricing on the Company’s oil and gas revenues. The contracts included floating vs. fixed price swaps for the Company’s produced oil. The Company did not designate the price swap agreements as hedges. Accordingly, management elected not to apply hedge accounting to these derivatives but, instead, recognized unrealized gains (losses) associated with the derivative in its statement of operations in the period for which such unrealized gains (losses) occur. These price swaps were closed at the time that the Swap Facility was repaid in full. The Company recognized realized losses on the price swap agreements associated with the Swap Facility of approximately $37,000 for the year ended December 31, 2013.

As a condition of closing for the Credit Facility (see Note 8), the Company entered into a commodity price swap agreement covering 85% of its projected five-year future production on its proved, developed, producing properties. 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 the derivative in its statement of operations in the period for which such unrealized gains (losses) will occur. The Company recognized realized gains on the price swap agreements associated with the Credit Facility totaling approximately $766,000 for the year ended December 31, 2013.

The Company’s outstanding price swap agreements had the following net fair market values as of December 31, 2013 and 2012:

	2013			2012
Current derivative asset	$	210,779		$	-
Current derivative liability		(275,516	)		(122,651	)
Non-current derivative liability		(749,872	)		-
Net derivative liability	$	(814,609	)	$	(122,651	)

51

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

10. Asset Retirement Obligations

During the years ended December 31, 2013 and 2012, the Company recorded initial, estimated asset retirement obligations totaling approximately $569,000 and $403,000, 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 Area and Hardy Property. As of December 31, 2013 and 2012, the consolidated discounted value of the Company’s asset retirement obligations was approximately $1.1 million and $442,000, respectively. The projected plugging dates for wells in which the Company owns a working interest ranges from December 31, 2015 to December 31, 2032.

11. Commitments and Contingencies

Drilling Obligations

The Company has the option to participate in the drilling of future non-operated, development wells related to its working interest in the Spyglass Area, should any such wells be proposed by the other working interest owners. As of December 31, 2013, the Company has elected to participate in 76 wells located within the Spyglass Area. 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 0.04% to 28.34%. 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 Area 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 Second Carry Agreement (see Note 5).

Employment Contracts

The Company has entered into employment agreements with its President, its Chief Operating Officer, its Chief Financial Officer and three other members of management, which stipulate, among other things, severance payments in the event that employment is terminated without cause or as a result of a change in control, as defined by the employment agreements. As of December 31, 2013, the amount of severance payments that the Company would be obligated to make under the terms of the employment agreements would total approximately $1.1 million.

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, 2013 are as follows:

52

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

	Amount
2014	$	177,798
2015		183,855
2016		96,305
Total	$	457,958

Rent expense for the years ended December 31, 2013 and 2012 totaled approximately $146,000 and $110,000, respectively.

12. Equity Transactions

Shares Issued in Connection with Swap Facility

As discussed in Note 7, the Company issued 56,391 shares of its common stock in connection with the Swap Facility with MBL.

Private Placements

In January 2013, the Company sold 1,000,000 shares of its common stock in a private placement at a price of $4.00 per share. Proceeds from the sale totaled $4.0 million.

Public Offerings

In August 2013, the Company sold 1,250,000 shares of its common stock in a public offering at a price of $8.00 per share. Proceeds from the sale totaled $9.9 million, net investment banking fees.

In October 2013, the Company sold 3,941,449 shares of its common stock at a price of $6.80 per share in two public offerings. The sale of stock was completed pursuant to the Company’s August 2, 2013 shelf registration. Proceeds from the sale, net of expenses and broker fees, totaled approximately $25.0 million.

Stock Options

During the years ended December 31, 2013 and 2012, the Company granted 440,000 and 648,125 stock options to members of its Board of Directors, employees and certain key third-party consultants. Each of the stock options granted have a five-year life and vest 50% on the one-year anniversary of the grant date, with the remaining 50% vesting on the second-year anniversary of the grant date.

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

	2013	2012
Risk-free interest rate	0.23% to 0.35%	0.22% to 0.92%
Expected volatility of common stock	62% to 84%	79% to 196%
Dividend yield	$0.00	$0.00
Expected life of options	5 years	5 years

53

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

A summary of stock option activity for the years ended December 31, 2013 and December 31, 2012 is presented below:

						Weighted
				Weighted		Average
				Average		Remaining
				Exercise		Contract
	Options			Price ($)		Term
Outstanding at December 31, 2011		448,861		$	0.90		3.8 years
AEE Inc. options converted		433,248			2.96		3.2 years
Options granted		440,000			3.24		4.8 years
Options exercised		(38,459	)		0.90		3.8 years
Options expired		-			-		-
Options forfeited		-			-		-
Outstanding at December 31, 2012		1,283,650		$	3.12		3.6 years
Options granted		648,125			8.48		4.8 years
Options exercised		(5,000	)		3.12		4.0 years
Options expired		-			-		-
Options forfeited		-			-		-
Outstanding at December 31, 2013		1,926,775		$	4.92		3.4 years
Exercisable at December 31, 2013		1,068,650		$	3.12		2.4 years

The options outstanding as of December 31, 2013 and December 31, 2012 have an intrinsic value of $4.12 and $0.48 per share and an aggregate intrinsic value of approximately $7.9 million and $616,000, respectively.

Shares Reserved for Future Issuance

As of December 31, 2013 and December 31, 2012, the Company had reserved 1,926,775 and 1,283,650 shares, respectively, for future issuance upon exercise of outstanding options.

The Company recognized stock-based compensation expense of approximately $1.2 million and $800,000 for the years ended December 31, 2013 and 2012, respectively.

13. Income Taxes

The Company recognized income tax expense (benefit) of approximately $1.8 million and ($1.2 million) for the years ended December 31, 2013 and December 31, 2012, respectively. Income tax expense (benefit) for the years ended December 31, 2013 and 2012 consisted of the following:

54

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

	2013			2012
Current income tax expense (benefit):
Domestic	$	(17,346	)	$	(301,533	)
Foreign		(77,174	)		(32,268	)
Total current income tax benefit		(94,520	)		(333,801	)
Deferred income tax expense (benefit):
Domestic		1,863,236			348,510
Foreign		-			(1,254,719	)
Total deferred income tax expense (benefit)		1,863,236			(906,209	)
Total income tax expense (benefit)	$	1,768,716		$	(1,240,010	)

Significant components of the Company’s deferred income tax assets and liabilities at December 31, 2013 and 2012 are as follows:

	2013			2012
Deferred tax assets:
Foreign tax credits	$	52,261		$	32,275
Unrealized hedging loss		301,327			44,520
Asset retirement obligations		308,475			112,608
Net operating losses – domestic		5,688,168			4,075,159
Net operating losses – foreign		864,374			716,967
Foreign fixed assets		1,936,859			1,448,717
Stock options		1,213,480			757,432
Marketable securities		47,633			-
Other		160,209			-
Total deferred tax assets		10,572,786			7,187,678
Valuation allowance		(2,858,328	)		(2,165,684	)
Net deferred income tax assets	$	7,714,458		$	5,021,994
Deferred tax liabilities:
Deferred gain	$	-			-
Investment in foreign subsidiary		321,673			181,548
Domestic fixed assets		12,778,739			8,353,909
Marketable securities		-			6,031
Deferred tax liabilities	$	13,100,412		$	8,541,488
Net deferred tax liabilities	$	5,385,954		$	3,519,494

A reconciliation between the amount of income tax expense for the years ended December 31, 2013 and 2012, determined by applying the appropriate applicable statutory income tax rates, is as follows:

55

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

	2013			2012
U.S. Statutory tax expense (benefit)	$	1,143,472		$	(3,581,180	)
State income taxes, net of federal expense (benefit)		95,728			(242,104	)
Foreign taxes paid		12,360			-
Permanent differences		10,843			8,003
Change in valuation allowance		640,894			2,165,684
True-up of prior year amounts		243,794			(536,758	)
Foreign operations		(235,630	)		908,878
Rate change		(142,745	)		39,421
Other		-			(1,954	)
Total income tax expense (benefit)	$	1,768,716		$	(1,240,010	)
Effective tax rate		52.59	%		(11.77	)%

14. 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, 2013 and 2012:

	2013		2012
Net income (loss)	$	1,594,434	$	(9,292,874	)
Weighted average number of common shares outstanding		13,961,688		11,448,048
Incremental shares from the assumed exercise of dilutive stock options		637,148		-
Diluted common shares outstanding		14,598,836		11,448,048
Earnings (loss) per share - basic	$	0.11	$	(0.81	)
Earnings (loss) per share - diluted	$	0.11	$	(0.81	)

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.

56

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

15. Related Party Transactions

The Company is under contract through February 2015 to sell 100% of its oil, gas and liquids production to Power Energy Partners LP (“Power Energy”). In January 2014, Power Energy purchased 1,000,000 shares of our common stock at price of $4.00 per share via a private placement. In August 2013, Power Energy purchased an additional 1,250,000 shares of our common stock at a price of $8.00 per share via a public offering.

The Company routinely obtains legal services from a firm for whom one of its directors serves as a principal. Fees paid this firm approximated $37,000 and $24,000 for the years ended December 31, 2013 and 2012, respectively.

The Company receives monthly geological consulting services from Synergy Energy Resources LLC (“Synergy”). One of the Company’s current directors and one current officer own material ownership interests in Synergy. The Company incurred $168,000 of consulting expenses from Synergy during each of the years ended December 31, 2013 and 2012.

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. Revenues paid to these individuals totaled approximately $608,000 and $540,000 for the year ended December 31, 2013, and approximately $67,000 and $52,000 for the year ended December 31, 2012, respectively.

16. Subsequent Events

Reverse Stock Split

On March 18, 2014, the Company completed a 1-for-4 reverse split of the Company’s common stock. Pursuant to accounting guidelines, all historical share and per-share data contained in these financial statements has been restated to reflect the reverse stock split as if it had occurred on January 1, 2012.

Public Offering

On March 24, 2014, the Company closed on a public stock offering, pursuant to which the Company sold 12,650,000 shares of its common stock. The sale of stock was completed pursuant to the Company’s December 2013 shelf registration. Proceeds from the sale, net of expenses, broker fees and commissions totaled approximately $78.0 million.

Working Interest Acquisition

On March 27, 2014, the Company closed on its option to purchase additional net revenue and working interests in proved producing and proved undeveloped properties located within the Spyglass Area from a certain working interest partner. The gross purchase price for the acquired interests of $47 million is subject to adjustments for revenues, operating expenses and capital expenditures associated with the acquired interests from the period June 1, 2013 through the closing date. The acquisition of the working interests was funded with proceeds received from the March 2014 public offering, as discussed above.

Also on March 27, 2014, the Company purchased approximately 5,000 net unproved acres located within the Spyglass Area from the same working interest partner, for cash consideration of approximately $7.5 million.

57

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

17. Supplemental Oil and Gas Information (Unaudited)

During the years ended December 31, 2013 and 2012, the Company incurred the following costs associated with the acquisition, exploration and development of oil and gas properties:

	2013		2012
Acquisition costs	$	62,859,262		16,671,183
Exploration costs		32,053,227		-
Development costs		28,543,201		27,914,011
Total costs	$	123,455,690	$	44,585,194

The net capitalized cost of the Company’s oil and gas properties, subject to amortization, as of December 31, 2013 and 2012 is summarized below:

	2013			2012
Acquisition costs	$	88,909,755		$	26,050,493
Exploration costs		-			-
Development costs		93,696,371			33,099,942
Impairments and sales		(14,612,024	)		(12,880,489	)
Gross capitalized costs		167,994,102			46,269,946
Accumulated depletion		(12,849,063	)		(2,978,403	)
Net capitalized costs	$	155,145,039		$	43,291,543

The Company owns mineral interests in both operated and non-operated producing wells, as well as in undeveloped acreage, for which proved oil and gas reserves have been assigned, the vast majority of which are located in the United States. The Company also owns mineral interests in a small number of operated and non-operated properties located in Canada. Pursuant to full-cost accounting rules, the Company maintains separate cost centers for its US and Canadian oil and gas properties and related costs. The proved reserves associated with the Company’s US cost center represents 99.5% of the Company’s total proved reserves, both on a volume and discounted, future cash flow (PV10) basis as of December 31, 2013. Furthermore, revenues generated from the Company’s US oil and gas properties accounted for 97.1% of the Company’s total revenue for the year ended December 31, 2013. Because the result of operations and proved reserves associated with the Company’s Canadian oil and gas operations is properties is not material to the Company’s overall results of operations and reserves, the Company has elected to present the following supplemental oil and gas information on a consolidated basis, rather than by cost center.

The Company recognized the following revenues and expenses associated with its oil and gas producing activities for the years ended December 31, 2013 and 2012:

58

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

	2013		2012
Oil and gas revenues	$	43,138,957	$	10,713,946
Oil and gas production costs		11,609,106		3,200,171
Net oil and gas revenues	$	31,529,851	$	7,513,775
Oil production (barrels)		492,706		134,314
Gas production (mcf)		27,556		2,306
Liquids production (barrels)		5,507		-
Barrels of Oil Equivalent (BOE)		502,806		134,698
Depletion expense	$	9,978,094	$	2,800,393
Impairment expense		1,731,535		10,361,345
Average sales price per BOE	$	85.80	$	79.58
Oil and gas production costs per BOE		23.09		23.77
Depletion expense per BOE		19.84		20.81
Impairment expense per BOE		3.44		76.96

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 firms to determine its annual estimate of oil and gas reserves as of December 31, 2013 and 2012. The independent petroleum engineering firms estimated the oil and gas reserves associated with the Company’s US and Canadian oil and gas 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.

59

American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

The Company believes that the methodologies used by the independent petroleum engineering firms 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, 2013 and 2012, 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, 2013 and 2012:

	Oil			Gas			Total
	(Barrels)			(Mcf)			(BOE)
For the year ended December 31, 2013:
Proved reserves, beginning of year		5,397,542			2,139,067			5,754,053
Revisions		(1,614,155	)		308,004			(1,562,821	)
Extensions and discoveries		7,411,947			5,333,628			8,300,885
Purchases of reserves in place		1,411,387			898,849			1,561,195
Production		(498,213	)		(27,556	)		(502,806	)
Proved reserves, end of year		12,108,508			8,651,992			13,550,506
Proved developed reserves		4,206,422			3,046,787			4,714,219
Proved undeveloped reserves		7,902,086			5,605,205			8,836,287
Total proved reserves		12,108,508			8,651,992			13,550,506

As a result of participating in 19 new wells, the Company converted 956,515 barrels of oil and 340,926 mcf of gas from proved undeveloped reserves to proved developed reserves during the year ended December 31, 2013. The Company incurred $19,826,083 of capitalized expenditures to drill these wells.

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American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

	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 developed reserves		2,387,283			1,074,362			2,566,343
Proved undeveloped reserves		3,010,259			1,064,705			3,187,710
Total proved reserves		5,397,542			2,139,067			5,754,053

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.

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, 2013 and 2012, respectively.

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American Eagle Energy Corporation

Notes to the Consolidated Financial Statements

As of December 31, 2013 and 2012 and

For Each of the Two Years in the Period Ended December 31, 2013

Standardized Measure of Discounted Future Net Cash Flows

	At December 31,
	2013			2012
Future cash flows	$	1,141,907,375		$	448,623,295
Future costs:
Production costs		(307,092,719	)		(99,410,979	)
Development costs		(177,750,094	)		(50,693,286	)
Income taxes		(184,362,116	)		(104,826,989	)
Future net cash flows		472,702,446			193,692,041
Ten percent discount factor		(250,648,070	)		(116,784,091	)
Standardized measure of discounted future net cash flows	$	222,054,376		$	76,907,950

The following table summarizes the changes in the Company’s standardized measure of discounted future net cash flows for the years ended December 31, 2013 and 2012:

	At December 31,
	2013			2012
Extensions and discoveries	$	167,599,587		$	84,275,965
Net changes in sales prices and production costs		1,000,967			(2,939,472	)
Oil and gas sales, net of production costs		(31,529,851	)		(7,513,775	)
Change in estimated future development costs		(5,658,987	)		12,376,364
Revision of quantity estimates		(34,499,036	)		(22,267,585	)
Purchases of mineral interests		35,496,098			12,776,983
Previously estimated development costs incurred in the current period		14,256,379			2,897,436
Changes in production rates, timing and other		21,691,900			1,947,497
Changes in income taxes		(35,913,703	)		(33,864,445	)
Accretion of discount		12,703,072			3,993,945
Net increase		145,146,426			51,682,913
Standardized measure of discounted future cash flows:
Beginning of year		76,907,950			25,225,037
End of year	$	222,054,376		$	76,907,950

Assumed prices used to calculate future cash flows

	At December 31,
	2013		2012
Oil price per barrel	$	90.63	$	81.78
Gas price per mcf	$	5.15	$	3.38

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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, 2013. 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.

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.

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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, 2013, based on the control criteria established in a report entitled Internal 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 effective as of December 31, 2013

Changes in Internal Control over Financial Reporting

During the fourth quarter of 2013, we hired a Manager of Financial Reporting, which added another level of review of certain complex accounting calculations and transactions 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.

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	62	Director (Chairman of the Board)
Bradley M. Colby	57	President, Chief Executive Officer, Treasurer and Director
Kirk A. Stingley	47	Chief Financial Officer
Thomas Lantz	61	Chief Operating Officer
John Anderson	50	Director
Andrew P. Calerich	49	Director
Paul E. Rumler James N. Whyte	60 55	Director and Secretary Director

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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 the Wall Street Journal, and the Canadian 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 the American Oil and Gas Reporter, Petroleum Intelligence Weekly, and the AAPG 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 Purplefish Capital Ltd., a personal consulting and investing company primarily involved in capital raising for private and public companies in North America, Europe, and Asia. Mr. Anderson was the founder and General Partner of Aquastone Capital Partners LLC, a New York-based private gold and special situations fund, which successfully operated from 2006-2009. He serves as a director a few 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 serving as its Executive Chairman in from October 2010 through May 2013, after all permits were granted and construction was completed.

· 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 from June 2010 through April 2013.

· Northern Freegold Resources Ltd. (TSX – Venture Exchange), a gold exploration and development company in Yukon, Canada – director since January 2010. Appointed Chairman in 2012.

· 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.

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 and the southern portions of Texas. Mr. Calerich holds an inactive Certified Public Accountant license and earned BS degrees in both Accounting and Business Administration at Regis College, in Denver.

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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.

James N. Whyte – Mr. Whyte has served as Executive Vice President of Human Resources and Risk Management of Intrepid Potash, Inc., a public company whose common stock is listed on the NYSE, since December 2007.  Prior to that time, Mr. Whyte served as the Vice President of Human Resources and Risk Management for Intrepid Mining LLC, a wholly-owned subsidiary of Intrepid Potash, Inc., since May 2004.  Prior to joining Intrepid Potash, Inc., spent 17 years in the property and casualty insurance industry, including roles with Marsh and McLennan, Incorporated, American Re-Insurance and a private insurance brokerage firm that he founded.  Mr. Whyte brings an extensive knowledge base related to human resources and risk management activities to our Board.

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

Messrs. Anderson, Calerich, Rumler and Whyte 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 11 formal meetings during the year ended December 31, 2013, 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

Following consummation of our merger with American Eagle Energy, Inc. in December 2011, our board of directors established three committees: the Audit Committee, the Compensation Committee, and the Nominating and Corporate Governance Committee.

Audit Committee

Our Audit Committee is comprised of Messrs. Anderson, Calerich, and Whyte, each of whom 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 Chairman and 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 66. The charter of the Audit Committee may be found on our website (www.americaneagleenergy.com).

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Compensation Committee

Our Compensation Committee is comprised of Messrs. Anderson, Calerich and Rumler. 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. Our board of directors has designated Mr. Rumler as the Compensation Committee’s Chairman. The charter of the Compensation Committee may be found on our website (www.americaneagleenergy.com). As noted in his biography, above, Mr. Rumler has been our corporate secretary and one of our directors since 2007. He became a member of the Compensation Committee upon its formation in 2011. For NYSE MKT purposes, Mr. Rumler’s service as our corporate secretary may preclude a determination that his status is as an “independent director.” As part of our listing application process with the NYSE MKT, we utilized certain exemptions that permitted Mr. Rumler to serve on such Committee until November 20, 2015 (two years from the date of our listing). That exemption requires us to disclose that our board determined that our best interests and those of our stockholders require Mr. Rumler’s membership on the Compensation Committee. In that context, we believe that his perspective and historical knowledge of our operations and the enhancement of our economic value brought about through the efforts of management, as we continue to mature as an enterprise, warrant his membership on this Committee during such two-year period.

Nominating and Corporate Governance Committee

Our Nominating and Corporate Governance Committee is comprised of Messrs. Anderson, Calerich and Rumler. 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. Our board of directors has designated Mr. Rumler as the Nominating and Corporate Governance Committee’s Chairman. As noted in his biography, above, Mr. Rumler has been our corporate secretary and one of our directors since 2007. He became a member of the Nominating and Corporate Governance Committee upon its formation in 2011. For NYSE MKT purposes, Mr. Rumler’s service as our corporate secretary may preclude a determination that his status is as an “independent director.” As part of our listing application process with the NYSE MKT, we utilized certain exemptions that permitted Mr. Rumler to serve on such Committee until November 20, 2015 (two years from the date of our listing). That exemption requires us to disclose that our best interests and those of our stockholders require Mr. Rumler’s membership on the Nominating and Corporate Governance Committee. In that context, we believe that his perspective and historical knowledge of our operations and our changing and developing needs in respect of the types of persons whom we believe would be assets on our board of directors warrant his membership on this Committee during such two-year period.

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, although Mr. Rumler serves as our Corporate Secretary. 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, 2013, 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.

In 2012, we adopted a policy to compensate our independent directors for their attendance at our board of directors meetings. We also do reimburse our directors for reasonable expenses in connection with attendance at board meetings and, commencing

The following table presents information concerning compensation paid to our Chief Executive Officer and our other executive officers for the years ended December 31, 2013 and 2012.

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
			($)		($)		($)		($)(1)		($)		($)		($)		($)
Bradley M. Colby		2013		252,000		400,000		—		325,650		—		—		—		977,650
President, CEO, and Treasurer		2012		204,000		100,000		—		100,395		—		—		—		404,395
Kirk Stingley Chief Financial Officer		2013 2012		165,000 150,000		40,000 30,000		— —		97,695 22,310		— —		— —		— —		302,695 202,310
Thomas Lantz		2013		252,000		100,000		—		244,238		—		—		—		596,238
Chief Operating Officer		2012		204,000		100,000		—		44,620		—		—		—		348,620

(1) 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 2013 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 12 (Equity Transactions – Stock Options) to our Consolidated Financial Statements, which is included in Item 8 of this document (see page 53).

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.

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	$350,000 per year	5 Years	04/30/2016
Thomas G. Lantz	$300,000 per year	3 Years	04/30/2016
Kirk A. Stingley	$185,000 per year	2 Years	04/30/2015

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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 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. 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 equal to one-half 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, 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 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 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

Throughout 2012, we granted five-year options to purchase 440,000 shares of our common stock to members of our management team, directors, employees and/or key consultants. The per-share exercise prices ranged from $2.88 to $4.72. Fifty percent (50%) of the stock options vest on the one-year anniversary of the grant date, with the other 50% vesting 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.

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Throughout 2013, we granted five-year options to purchase 648,125 shares of our common stock to members of our management team, directors, employees and/or key consultants. The per-share exercise prices ranged from $2.76 to $9.56. Fifty percent (50%) of the stock options vest on the one-year anniversary of the grant date, with the other 50% vesting 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, 2013, the following stock options were outstanding and held by management:

Outstanding Equity Awards at 2013 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		75,000	(7)		75,000	$	8.68	12/12/2018
		56,250	(4)		56,250	$	2.96	12/13/2017
		128,195	(1)		128,195	$	0.90	10/29/2014
		36,104	(1)(2)		36,104	$	2.96	12/30/2015
Kirk A. Stingley		22,500	(7)		22,500	$	8.68	12/12/2018
		12,500	(4)		12,500	$	2.96	12/13/2017
		37,500	(3)		37,500	$	4.72	12/28/2016
Thomas G. Lantz		56,250	(7)		56,250	$	8.68	12/12/2018
		56,250	(4)		56,250	$	2.96	12/13/2017
		108,312	(2)		108,312	$	2.96	12/30/2015
Richard L. Findley		12,500	(7)		12,500	$	8.68	12/12/2013
		12,500	(4)		12,500	$	2.96	12/13/2017
		144,416	(1)(2)		144,416	$	2.96	12/30/2015
John D. Anderson		37,500	(7)		37,500	$	8.68	12/12/2018
		12,500	(4)		12,500	$	2.96	12/13/2017
		39,709	(1)		39,709	$	0.90	10/29/2014
		12,500	(3)		12,500	$	4.72	12/28/2016
Paul E. Rumler		37,500	(7)		37.500	$	8.68	12/12/2018
		12,500	(4)		12,500	$	2.96	12/13/2017
		62,500	(3)		62,500	$	4.72	12/28/2016
Andrew P. Calerich		37,500	(7)		37,500	$	8.68	12/12/2018
		12,500	(4)		12,500	$	2.96	12/13/2017
		50,000	(5)		50,000	$	3.68	2/21/2017
James N. Whyte		12,500	(7)		12,500	$	8.68	12/12/2018
		50,000	(6)		50,000	$	3.68	11/12//2018

⁽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 vested on December 28, 2013.

⁽⁴⁾ Fifty percent of the options granted on December 14, 2012 vested 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 vested on February 21, 2013, and 50% of such options vested on February 21, 2014.

⁽⁶⁾ Fifty percent of the options granted on November 13, 2013 vested on November 13, 2014, and 50% of such options vest on November 13, 2015, in each event subject to the grantee’s continued service as a director or officer, as applicable, of the Company through such dates.

⁽⁷⁾ Fifty percent of the options granted on December 13, 2013 vest on December 13, 2014, and 50% of such options vest on December 13, 2015, 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 March 28, 2014 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 March 28, 2014. 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)		983,162		2.93	%
Kirk A. Stingley (3)		49,922		*
Thomas Lantz (4)		677,443		2.22	%
Richard Findley (5)		724,878		2.37	%
John Anderson (6)		259,486		*
Andrew P. Calerich (7)		81,250		*
Paul E. Rumler (8)		114,708		*
James N. Whyte		-		*
All directors and executive officers as a group (8 persons) (9)		2,890,849		9.03	%
Five Percent Beneficial Owner:
Power Energy Partners LLC (10)		2,250,000		7.41	%

* Less than 1%

(1) The applicable percentage ownership is based on 30,370,537 shares of common stock outstanding at March 28, 2014. 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.

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(2) Includes 703,266 shares owned by Mr. Colby and an aggregate of 109,965 shares owned by five members of his immediate family as to which he disclaims beneficial ownership of an aggregate of 87,472 shares owned of record by his spouse and three of their adult children. Also includes 192,424 shares underlying options that are exercisable within 60 days of March 28, 2014. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, Colorado 80120.

(3) Includes 6,172 shares owned by Mr. Stingley and 43,750 shares underlying options that are exercisable within 60 days of March 28, 2014. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, Colorado 80120.

(4) Includes 540,814 shares owned by Mr. Lantz and 15,824 shares owned by his adult child as to which he disclaims beneficial ownership. Also includes 120,812 shares underlying options that are exercisable within 60 days of March 28, 2014.

(5) Includes 574,212 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 150,666 shares underlying options that are exercisable within 60 days of March 28, 2014. The business address for this person is 27 North 27th Street, Suite 21G, Billings, Montana 59101.

(6) Includes 202,278 shares owned by Mr. Anderson and 57,208 shares underlying options that are exercisable within 60 days of March 28, 2014. The business address for this person is 52 Powell Street, Suite 200, Vancouver, British Columbia V6A 1E7.

(7) Includes 25,000 shares owned by Mr. Calerich and 56,250 shares underlying options that are exercisable within 60 days of March 28, 2014. The business address for this person is PO Box 1571, Eastlake, Colorado 80614.

(8) Includes 45,958 shares owned by Mr. Rumler and 68,750 shares underlying options that are exercisable within 60 days of March 28, 2014. 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) George Archos is the managing member and has voting and dispositive power over these shares. Mr. Archos disclaims beneficial ownership except to the extent of his pecuniary interests therein. The business address for this holder is 484 W. Wood Street, Palatine, Illinois 60067.

Lock-Up Agreements

We and our executive officers and directors have agreed that, for a period of 90 days from March 19, 2014, we and they will not, without the prior written consent of Johnson Rice & Company LLC (“Johnson Rice”) (which consent may be withheld at its sole discretion), directly or indirectly, sell, offer, contract, or grant any option to sell, pledge, transfer, or establish an open “put equivalent position” within the meaning of the Exchange Act or otherwise dispose of or transfer, or announce the offering of, or file any registration statement under the Securities Act of 1933, as amended, in respect of, any shares of our common stock, options, or warrants to acquire shares of our common stock or securities exchangeable or exercisable for or convertible into shares of our common stock. In addition, our executive officers and directors may not enter into a swap or other derivatives transaction that transfers to another, in whole or in part, the economic benefits or risk of ownership in our common stock, or otherwise dispose of any shares of our common stock, options or warrants or securities exchangeable or exercisable for or convertible into shares of our common stock currently or later owned either of record or beneficially, or publicly announce an intention to do any of the foregoing.

The restrictions above do not apply to (i) our issuance of shares of common stock or options to purchase shares of common stock, or shares of common stock upon exercise of options, pursuant to any stock option, stock bonus or other stock plan or arrangement described in this prospectus supplement or any amendment to or replacement of such plan, (ii) our issuance of shares of common stock or securities convertible into or exercisable for shares of common stock as consideration in a merger or other acquisition (provided that any recipient of such securities agrees to be bound by the foregoing restrictions for the remainder of the lock-up period) and (iii) our filing of one or more registration statements either (x) on Form S-8 or amendments thereto relating to the issuance of shares of common stock or the issuance and exercise of options to purchase shares of common stock granted under our employee benefit plans existing on March 19, 2014 or any amendment to or replacement of such plan or (y) to which Johnson Rice has consented, or in connection with our entry into a definitive agreement relating to an acquisition. Our executive officers and directors may transfer shares of our common stock or such other convertible, exercisable or exchangeable securities without the prior written consent of Johnson Rice if: (a) Johnson Rice receives a signed lock-up agreement for the balance of the 90-day restricted period from each donee, trustee, distributee, or transferee, as the case may be; (b) any such transfer does not involve a disposition for value; (c) such sales, individually or in the aggregate, of less than 1% of our then outstanding common stock after giving effect to the offering; (d) the transferor does not otherwise voluntarily effect any public filing or report regarding such transfers; and (e) such transfer is (i) a bona fide gift or gifts; (ii) to any trust for the direct or indirect benefit of the transferor or the immediate family of the transferor; or (iii) to the transferor’s affiliates or to any investment fund or other entity controlled or managed by the transferor.

If (A) during the last 17 days of the 90-day period, we issue an earnings release or material news or a material event relating to us occurs or (B) prior to the expiration of the 90-day period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day period, then in each case the 90-day period will be extended until the expiration of the 18-day period beginning on the date of the issuance of the earnings release or the occurrence of the material news or material event, as applicable, except that such extension will not apply under certain circumstances if we certify to Johnson Rice that our common stock is an “actively traded security” as defined in Regulation M and that we meet certain other requirements.

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

Related Party Transactions

Power Energy Partners Ltd.

The Company is under contract through February 2015 to sell 100% of its oil, gas and liquids production to Power Energy Partners, Ltd. In January 2014, Power Energy purchased 1,000,000 shares of our common stock at price of $4.00 per share via a private placement. In August 2013, Power Energy purchased an additional 1,250,000 shares of our common stock at a price of $8.00 per share via a public offering.

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 $168,000 of consulting fees from Synergy during each of the years ended December 31, 2013 and 2012.

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 $36,528 and $23,644 for the years ended December 31, 2013 and 2012, respectively.

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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 $608,455 and $67,426 for the years ended December 31, 2013 and 2012, respectively.

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 $540,009 and $51,858 for the years ended December 31, 2013 and 2012, respectively.

Item 14. Principal Accountant Fees and Services.

Hein & Associates (“Hein”) audited our financial statements for the years ended December 31, 2013 and 2012 and provided preparation services for the 2012 and 2011 US federal and state tax returns. The aggregate fees billed for professional services by Hein for the year ended December 31, 2013 and 2012 were as follows:

	2013		2012
Audit Fees	$	317,137		216,755
Audit Related Fees	$	40,000		—
Tax Fees	$	34,100		68,071
All Other Fees	$	—		—
Total	$	391,237		284,826

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.

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.)755
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.)

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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(i).7	Certificate of Change filed with the Nevada Secretary of State effective March 18, 2014. (Incorporated by reference to Exhibit 3(i).7 of our Current Report on Form 8-K filed on March 21, 2014.)
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*	American Eagle Energy Corporation 2013 Equity Incentive Plan.
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.)
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*	Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Bradley M. Colby.
4.14*	Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Thomas G. Lantz.
4.15*	Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Kirk A. Stingley.
4.16*	Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Richard Findley.
4.17*	Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Paul E. Rumler.
4.18*	Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and John Anderson.

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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	Non-qualified Stock Option Agreement, dated as of November 14, 2013, by and between the Registrant and James N. Whyte. (Incorporated by reference to Exhibit 4.20 of our Current Report on Form 8-K filed November 14, 2013.)
4.21*	Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Andrew P. Calerich.
4.22*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Bradley M. Colby.
4.23*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Thomas G. Lantz.
4.24*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Kirk A. Stingley.
4.25*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Richard Findley.
4.26*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Paul E. Rumler.
4.27*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and John Anderson.
4.28*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Andrew P. Calerich.
4.29*	Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and James N. Whyte.
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	Restricted Common Stock Purchase Agreement by and between American Eagle Energy Corporation and Power Energy Holdings, LLC, dated January 4, 2013. (Incorporated by reference to Exhibit 10.4 of our Quarterly Report on Form 10-Q filed May 14, 2013.)
10.5	Common Stock Purchase Agreement by and between American Eagle Energy Corporation and Power Energy Holdings, LLC, dated August 9, 2013. (Incorporated by reference to Exhibit 10.5 of our Quarterly Report on Form 10-Q filed August 19, 2013.)
10.6	Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated August 12, 2013. (Incorporated by reference to Exhibit 10.6 of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6a	First Amendment to Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated September 30, 2013. (Incorporated by reference to Exhibit 10.6a of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6b	Second Amendment to Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated October 2, 2013. (Incorporated by reference to Exhibit 10.6b of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6c	Notice of Exercise pursuant to the Purchase and Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated October 2, 2013. (Incorporated by reference to Exhibit 10.6c of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6d*	Third Amendment to the Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated March 27, 2014.
10.7	Underwriting Agreement by and between American Eagle Energy Corporation and Johnson Rice & Company LLC, dated March 18, 2014. (Incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K, filed March 19, 2014.)
10.8	Purchase Agreement by and between American Eagle Energy Corporation and Northland Securities, Inc. dated October 2, 2013 (Incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K filed on October 2, 2013.)

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10.9	Purchase Agreement by and between American Eagle Energy Corporation and Northland Securities, Inc. dated October 9, 2013 (Incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K filed on October 10, 2013.)
10.10	Reserved for future use.
10.11*	Amended and Restated Employment Agreement by and between the Registrant and Bradley M. Colby effective May 1 2013.
10.12*	Employment Agreement by and between the Registrant and Thomas G. Lantz, effective May 1, 2013.
10.13*	Employment Agreement by and between the Registrant and Kirk Stingley, effective May 1, 2013.
10.14	Consulting Agreement by and between the Registrant and Richard Findley, effective November 30, 2011. (Incorporated by reference to Exhibit 10.41 of our Annual Report on Form 10-K filed April 16, 2012.)
10.15	Reserved for future use.
10.16	Reserved for future use.
10.17	Carry Agreement by and among American Eagle Energy Corporation, AMZG, Inc. and USG Properties Bakken I, LLC, dated August 12, 2013. (Incorporated by reference to Exhibit 10.20 of our Quarterly Report on Form 10-Q filed August 19, 2013.)
10.18	Farm-Out Agreement by and among American Eagle Energy Corporation, AMZG, Inc. and USG Properties Bakken I, LLC, dated August 12, 2013. (Incorporated by reference to Exhibit 10.21 of our Quarterly Report on Form 10-Q, filed August 19, 2013.)
10.19*	Letter Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated March 21, 2014.
10.19a*	Amendment and Addendum to Letter Agreement among American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated March 27, 2014.
10.20	Credit Agreement, dated as of August 19, 2013, among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc., as administrative agent for such lenders. (Incorporated by reference to Exhibit 10.20 of our Form 8-K filed August 23, 2013.)
10.20a	First Amendment to the Credit Agreement among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc., dated October 2, 2013.
10.20b	Second Amendment to the Credit Agreement among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc., dated October 2, 2013.
10.21	Promissory Note by American Eagle Energy Corporation, dated as of August 19, 2013, payable to the order of Morgan Stanley Capital Group Inc. in the principal amount of $200,000,000. (Incorporated by reference to Exhibit 10.21 of our Form 8-K filed August 23, 2013.)
10.22	Pledge and Security Agreement, dated as of August 19, 2013, among American Eagle Energy Corporation, AMZG, Inc., AEE Canada, Inc., EERG Energy ULC, and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.22 of our Form 8-K filed August 23, 2013.)
10.23	Mortgage-Collateral Real Estate Mortgage, Deed of Trust, Indenture, Security Agreement, Fixture Filing, As-Extracted Collateral Filing, Financing Statement and Assignment of Production, dated as of August 19, 2013, by American Eagle Energy Corporation, AMZG, Inc., and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.23 of our Form 8-K filed August 23, 2013.)
10.24	Guaranty Agreement, dated as of August 19, 2013, among AMZG, Inc., AEE Canada Inc., EERG Energy ULC, and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.24 of our Form 8-K filed August 23, 2013.)
10.25	Form of Warrant of American Eagle Energy Corporation. (Incorporated by reference to Exhibit 10.25 of our Form 8-K filed August 23, 2013.)
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. (Incorporated by reference to Exhibit 10.27b of our Quarterly Report on Form 10-Q filed on August 20, 2012.)

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10.27c	Lease Addendum, dated November 1, 2013 by and between American Eagle Energy Corporation and Oakley Ventures, LLC.
10.28	Reserved for future use.
10.29	Reserved for future use.
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 among Eerg Energy Ulc, 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. (Incorporated by reference to Exhibit 10.44 of our Annual Report on Form 10-K filed on April 16, 2013.)
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. (Incorporated by reference to Exhibit 10.44a of our Annual Report on Form 10-K filed on April 16, 2013.)
10.45	Commodity Swap Transaction Confirmation by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012. (Incorporated by reference to Exhibit 10.45 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.46	Security Agreement by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012. (Incorporated by reference to Exhibit 10.46 of our Annual Report on Form 10-K filed on April 16, 2013.)

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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. (Incorporated by reference to Exhibit 10.47 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.48	Purchase and Sale Agreement by and between USG Properties Bakken I, LLC and American Eagle Energy Corporation, dated December 20, 2012. (Incorporated by reference to Exhibit 10.48 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.49	Purchase and Sale Agreement Between SM Energy Company and American Eagle Energy Corporation, dated November 20, 2012. (Incorporated by reference to Exhibit 10.49 of our Annual Report on Form 10-K filed on April 16, 2013.)
21.1*	List of Subsidiaries. (Incorporated by reference to Exhibit 21.1 of our Annual Report on Form 10-K filed April 16, 2013.)
23.1	Consent of Ryder Scott Company LP. (Incorporated by reference to Exhibit 23.1 of our Current Report on Form 8-K filed March 10, 2014.)
23.2*	Consent of Hein & Associates LLP, dated March 28, 2014.
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.
99.1	Report of Ryder Scott Company dated February 17, 2014. (Incorporated by reference to Exhibit 99.1 to our Current Report on Form 8-K filed on March 10, 2014.)

* Filed herewith.

^ Portions omitted pursuant to a request for confidential treatment. 

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: March 28, 2014

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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)	March 28, 2014
Bradley M. Colby
/s/KIRK A. STINGLEY	Chief Financial Officer (Principal Accounting Officer)	March 28, 2014
Kirk A. Stingley
/S/THOMAS LANTZ	Chief Operating Officer	March 28, 2014
Thomas Lantz
/s/RICHARD FINDLEY	Director (Chairman)	March 28, 2014
Richard Findley
/s/JOHN ANDERSON	Director	March 28, 2014
John Anderson
/s/ ANDREW P. CALERICH	Director	March 28, 2014
Andrew P. Calerich
/s/ PAUL E. RUMLER	Director and Secretary	March 28, 2014
Paul E. Rumler
/s/ JAMES N. WHYTE	Director	March 28, 2014
James N. Whyte

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