Attached files
| file | filename |
|---|---|
| EX-21.1 - EXHIBIT 21.1 - AMERICAN EAGLE ENERGY Corp | v403074_ex21-1.htm |
| EX-23.2 - EXHIBIT 23.2 - AMERICAN EAGLE ENERGY Corp | v403074_ex23-2.htm |
| EX-31.1 - EXHIBIT 31.1 - AMERICAN EAGLE ENERGY Corp | v403074_ex31-1.htm |
| EX-23.1 - EXHIBIT 23.1 - AMERICAN EAGLE ENERGY Corp | v403074_ex23-1.htm |
| EX-32.1 - EXHIBIT 32.1 - AMERICAN EAGLE ENERGY Corp | v403074_ex32-1.htm |
| EX-31.2 - EXHIBIT 31.2 - AMERICAN EAGLE ENERGY Corp | v403074_ex31-2.htm |
| EX-32.2 - EXHIBIT 32.2 - AMERICAN EAGLE ENERGY Corp | v403074_ex32-2.htm |
| EX-99.1 - EXHIBIT 99.1 - AMERICAN EAGLE ENERGY Corp | v403074_ex99-1.htm |
| EXCEL - IDEA: XBRL DOCUMENT - AMERICAN EAGLE ENERGY Corp | Financial_Report.xls |
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, 2014
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 | x | |
| Non-accelerated filer | ¨ | Smaller reporting company | ¨ |
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, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, was $182,316,228.
The number of shares outstanding of the registrant’s common stock as of March 25, 2014 was 30,448,714.
AMERICAN EAGLE ENERGY CORPORATION
TABLE OF CONTENTS
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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 one-for-four 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 this reverse split 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.
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.
100% of our revenues are derived from the sale of crude oil and natural gas products. The sale of crude oil accounted for approximately 99% of our total revenues for each of the three years ended December 31, 2014, 2013 and 2012. We have contracted to sell 100% of our crude oil to Power Energy Partners, LP (“Power Energy”) through 2015, at average monthly prices for West Texas Intermediate crude oil, less a predetermined differential factor. Sales of our crude oil occur once the oil has left the wellhead. As such, there is no backlog of sales for our crude oil as of December 31, 2014.
In July 2014, we sold all of our interests in our Canadian oil and gas properties. 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, 2014, we had drilled and completed 54 gross (32.2 net) operated wells located within the Spyglass Property, all of which were producing as of that date, and were in the process of completing two additional Spyglass Property operated wells. We anticipate that the two additional wells will be completed sometime in 2015. In addition, as of December 31, 2014, we had elected to participate in 81 gross (4.2 net) non-operated wells located within the Spyglass Property, all of which were producing as of that date.
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 continue to develop our delineated acreage position in the Bakken and Three Forks formations, at a reasonable pace and as our cash flows will allow, 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. |
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Concentration of Customer Risk
In February 2013, we entered into an agreement to sell 100% of our crude oil to Power Energy. This agreement expires on December 31, 2015. For each of the years ended December 31, 2014, 2013, and 2012, sales of crude oil to Power Energy accounted for approximately 99% of our total revenues. The loss of Power Energy as a customer could have a material adverse effect on our financial condition, insomuch as it would require us to negotiate sales terms with a new purchaser on terms that could be less favorable than those of our current contract with Power Energy.
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. If we are unable to secure desirable oil and gas leases and farm-in and farm-out agreements, suitable properties for drilling operations, necessary drilling and completion equipment and services, and adequate capital, we may face shortages, delays, or increased costs from time to time. Competitors with greater resources than us may have a greater ability to continue drilling activities during periods of low natural gas and crude oil prices.
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.
We also face competition from alternate fuel sources.
Hydraulic Stimulation
To date, we have drilled and completed 54 gross operated wells located within our Spyglass Property. Each of these wells contains a lateral section that has been subjected to hydraulic stimulation in order to improve the productivity of the well. 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 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 stimulated and, if so, we will include in the planning and budgetary process all costs associated with the stimulation. 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 stimulation, 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 stimulated 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. |
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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.
In order to prevent the underground migration of hydraulic stimulation 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 stimulated 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 stimulated interval and any potable water sources will minimize the risk of underground migration of hydraulic stimulation fluids. We would generally be responsible for any costs resulting from underground migration of hydraulic stimulation fluids, and we are not fully insured against this risk. The occurrence of a significant event resulting from the underground migration of hydraulic stimulation fluids or surface spillage, mishandling, or leakage of hydraulic stimulation 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.
Seasonality
We operate in North Dakota where we are subject to extreme winters that can cause normal drilling operations to cease resulting in decreased production. The extreme winters can also lead to heavy thawing periods where we may experience road closures that may also cause normal drilling operations to temporarily cease.
Government Regulations
Our oil and gas operations have been, or continue to be, 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.”
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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
Our executive management team consists of Bradley M. Colby, our President, Chief Executive Officer, and Treasurer, Thomas Lantz, our Chief Operating Officer, Kirk Stingley, our Chief Financial Officer, and Laura Peterson, our Corporate Secretary. Including members of senior management, we currently employ 21 full-time operations, financial and administrative employees.
The information in this Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that the Company plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” variations of such words, and similar expressions identify forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
These forward-looking statements appear in a number of places and include statements with respect to, among other things:
| · | estimates of our oil and gas reserves; |
| · | estimates of our future oil and natural gas production, including estimates of any increases or decreases in our production; |
| · | our future financial condition and results of operations; |
| · | our future revenues, cash flows and expenses; |
| · | our access to capital and our anticipated liquidity; |
| · | our future business strategy and other plans and objectives for future operations; |
| · | our outlook on oil and gas prices; |
| · | the amount, nature and timing of capital expenditures, including future development costs, and availability of capital resources to fund capital expenditures; |
| · | our ability to access the capital markets to fund capital and other expenditures; |
| · | the impact of political and regulatory developments; |
| · | our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and |
| · | the impact of federal, state and local political, regulatory and environmental developments in the United States and certain foreign locations where we conduct business operations. |
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.”
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The prevailing oil price environment may require that we sell certain assets, restructure our debt, raise additional debt or equity, or seek protection.
Should the prevailing oil prices as of December 31, 2014 remain in effect for an extended period of time, it is likely that we would need to pursue some form of asset sale, debt restructuring, or capital raising effort in order to fund its operations and to service its existing debt during the next twelve months. Our management is actively developing plans to improve its working capital position and/or to reduce its future debt service costs, through the aforementioned means, in order to remain a going concern for the foreseeable future. If we are unable to restructure our Bonds, obtain additional debt or equity financing or achieve adequate proceeds from the sale of assets, we may file a voluntary petition for reorganization relief under Chapter 11 of the Bankruptcy Code in order to provide us with additional time to identify an appropriate solution to our financial situation and to implement a plan of reorganization aimed at improving our capital structure.
We recognized impairment losses of approximately $81.9 million associated with our US cost center for the year ended December 31, 2014, and, depending on future oil and gas prices, may recognize further impairment losses in the future.
We recognized impairment losses totaling approximately $81.9 million associated with our US cost center for the year ended December 31, 2014. Continued prolonged declines in oil and gas prices may result in additional impairment of our oil and gas properties, causing the operation of certain oil and gas wells to become uneconomic and adversely impact our liquidity.
Our common stock is listed on the NYSE MKT but may be subject to a delisting procedure.
Our common stock is listed on the NYSE MKT (the “Exchange”). Although we have not received any communications from the Exchange regarding its initiation of any potential delisting process, based upon the recent price of our common stock, it is possible that we might receive a notification that we have had fallen below the Exchange’s continued listing standard relating to minimum share price – a minimum average closing price of $1.00 per share over 30 consecutive trading days. The price of our common stock has remained below such threshold for more than such period.
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.
A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.
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.
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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 Bonds (see Exhibit 10.28) contains a number of significant covenants that, among other things, restrict or limit our ability to:
| · | Pay dividends or distributions on our capital stock; |
| · | Enter into certain transactions with affiliates; |
| · | 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 (see Exhibit 10.31) 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.
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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. See discussion regarding undeveloped properties in Item 2, Properties (see page 18). For information about our proved reserves, please see Note 17 to our consolidated financial statements as of and for the years ended December 31, 2014 and 2013, which is included in Item 8 of this document (see page F-28).
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.
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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. |
| · | 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 natural disasters; |
| · | risks associated with operating drilling rigs; |
| · | technological advances affecting energy consumption; |
| · | domestic and foreign governmental regulations and taxes; |
| · | continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; |
| · | 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. Since August 2014, crude oil prices have declined in excess of 50% and have remained at this level throughout 2015 to date. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and natural gas industry. The decrease in the prices of oil and natural gas have had a material adverse effect on our financial condition, the future results of our operations, and quantities of reserves recoverable on an economic basis. This significant decrease in oil and natural gas prices will 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 have from time to time entered into oil and natural gas price hedging arrangements with respect to a portion of our expected production. In December, we monetized our then-outstanding hedges and have not entered into any further oil and natural gas hedging arrangements. Hedging arrangements 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:
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| · | 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 |
| · | 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 ceiling test write-downs for the years ended December 31, 2014, 2013 and 2012 of approximately $81.9 million, $1.5 million, $10.6 million, respectively, and we may recognize write-downs in the future if commodity prices remain at their depressed levels or decline further, or if we experience substantial downward adjustments to our estimated proved reserves.
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.
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.
At December 31, 2014 on barrel of oil equivalent basis, approximately 42% 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.
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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 long-term growth strategy 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.
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, 2014, 100% of our proved reserves and 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.
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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 higher than the quoted price for Bakken crude oil, less transportation costs from the point where the crude oil is sold, due to favorable terms contained in our existing contract for the sale of our crude oil. The existing contract expires at the end of 2015, after which there can be no guarantee that we will continue to realize higher than normal industry prices.
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.
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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.
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 15 of this Annual Report.
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Any change to government regulation/administrative practices may have a negative impact on our ability to operate and our profitability.
The laws, regulations, policies, or current administrative practices of any government body, organization, or regulatory agency in the United States or any other jurisdiction, may be changed, applied, or interpreted in a manner that will fundamentally alter the ability of our company to carry on our business. The actions, policies, or regulations, or changes thereto, of any government body, regulatory agency, or special interest groups, may have a detrimental effect on us. Any or all of these situations may have a negative impact on our ability to operate and/or our profitability.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Federal Clean Air Act. The EPA has adopted two sets of regulations under the existing Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, in April 2010, the EPA proposed to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. These EPA regulatory actions have been challenged by various industry groups, initially in the D.C. Circuit, which in 2012 ruled in favor of the EPA in all respects. However, in June 2014, the United States Supreme Court reversed the D.C. Circuit and struck down the EPA’s greenhouse gas permitting rules to the extent they impose a requirement to obtain a permit based solely on emissions of greenhouse gases. However, large sources of air pollutants other than greenhouse gases would still be required to implement the best available capture technology for greenhouse gases. The EPA has also adopted reporting rules for greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries as well as certain onshore oil and natural gas extraction and production facilities.
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.
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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.
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.
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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.
Our stock price has declined significantly since August 2014. 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 the trading price of our common stock remains at its current level, we may not be able to raise additional capital or generate funds from operations sufficient to meet our obligations.
Our securities are considered highly speculative.
Our securities must be considered highly speculative, generally because of the nature of our business. 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.
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.
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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.
Acreage:
As of December 31, 2014, we owned an undivided 56% working interest in approximately 77,721 gross acres (43,637 net acres) located within the Spyglass Property, primarily in Divide County, North Dakota. The acreage is held under 1,189 leases, which unless held by production, are scheduled to expire between February 2015 and August 2018.
In addition to our focus area in Divide County, North Dakota, we have a total of approximately 6,851 net acres mostly located in Sheridan, Daniels, and Richland Counties, Montana. We currently do not plan to devote capital to any of these areas in the foreseeable future and, accordingly, have fully impaired our investment in these undeveloped locations.
The following is a summary of our developed and undeveloped acreage as of December 31, 2014:
| Property / Prospect | Working Interest | Gross Acres | Net Acres | Number of Leases | Earliest Lease Expiration Date | Latest Lease Expiration Date | ||||||||||||||
| Developed: | ||||||||||||||||||||
| Spyglass | 52 | % | 24,562 | 19,138 | 591 | N/A | N/A | |||||||||||||
| Total developed | 24,562 | 19,138 | 591 | |||||||||||||||||
| Undeveloped: | ||||||||||||||||||||
| Spyglass | 60 | % | 40,794 | 24,499 | 504 | February 2015 | August 2018 | |||||||||||||
| Benrude | 40 | % | 800 | 323 | 4 | February 2015 | July 2015 | |||||||||||||
| Mustang | 30 | % | 238 | 66 | 12 | July 2015 | August 2015 | |||||||||||||
| NE Montana | 57 | % | 10,406 | 5,902 | 63 | January 2015 | December 2016 | |||||||||||||
| Sidney North | 43 | % | 641 | 277 | 12 | January 2015 | October 2015 | |||||||||||||
| Pebble Beach | 50 | % | 280 | 140 | 3 | June 2017 | June 2017 | |||||||||||||
| Total undeveloped | 53,159 | 31,207 | 598 | |||||||||||||||||
Productive Wells:
As of December 31, 2014, we had drilled and completed 54 gross (32.2 net) productive operated wells located within the Spyglass Property. Of the productive wells, 39 gross (25.0 net) operated wells were producing from the Three Forks formation and 15 gross (7.2 net) operated wells were producing from the Middle Bakken formation. Our working interest in our productive operating wells ranges from approximately 5% to 100%, with an average working interest of approximately 60% per well.
In addition, we own net revenue and working interests in 81 gross (4.2 net) productive non-operated wells located within the Spyglass Property. Our working interest ownership in these non-operated wells ranges from less than 1% to approximately 28%, with an average working interest of approximately 6%.
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Our Spyglass Property wells produced and average of approximately 2,300 barrels of oil equivalent (“BOE”) per day (“BOEPD”) for the month of December, 2014.
Prior to the sale of our Canadian oil and gas properties in July 2014, we operated three productive wells located in southeastern Saskatchewan, Canada. Our working interest in these three wells ranged from 50% to 85%. Our average working interest in the three wells was 78%. In addition, we had elected to participate in one productive non-operated well, in which we owned 50% net revenue and working interests. Our Canadian oil and gas properties were not material to the capitalized costs of, the revenues generated by, or the proved reserves associated with our consolidated oil and gas properties as of and for the years ended December 31, 2014, 2013 and 2012.
Drilling and Completion Activity:
The following table summarizes our drilling and completion activity related to our Spyglass Property for the years ended December 31, 2014, 2013 and 2012.
| 2014 | 2013 | 2012 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Operated Wells: | ||||||||||||||||||||||||
| Producing at beginning of period | 28 | 13.7 | 9 | 2.1 | - | - | ||||||||||||||||||
| Added to production during the period | 26 | 14.8 | 19 | 11.6 | 9 | 2.1 | ||||||||||||||||||
| Added through working interest acquisition | - | 3.7 | - | - | - | - | ||||||||||||||||||
| Producing at end of period | 54 | 32.2 | 28 | 13.7 | 9 | 2.1 | ||||||||||||||||||
| Non-Operated Wells: | ||||||||||||||||||||||||
| Producing at beginning of period | 75 | 3.6 | 46 | 2.7 | 21 | 0.5 | ||||||||||||||||||
| Added to production during the period | 6 | 0.6 | 29 | 0.9 | 25 | 2.2 | ||||||||||||||||||
| Producing at end of period | 81 | 4.2 | 75 | 3.6 | 46 | 2.7 | ||||||||||||||||||
In addition to the wells drilled and completed during the year ended December 31, 2014 (included in the table presented above), as of March 16, 2014, we were in the process of completing two gross (1.9 net) additional Spyglass Property operated wells. Each of the two wells has been drilled to its total depth, and each is awaiting fracture stimulation and completion. We anticipate that the two additional wells will be completed sometime in 2015.
Oil and Gas Production
The following table summarizes the revenues, sales volumes, approximate realized prices from the sale of oil, gas and natural gas liquids (NGL’s”) from properties in which we owned net revenue and working interests (in thousands, except for volumes and BOE figures):
| 2014 | 2013 | 2012 | ||||||||||
| Sales volumes: | ||||||||||||
| Oil (barrels) | 749,681 | 492,706 | 134,314 | |||||||||
| Gas (mcf) | 41,791 | 27,557 | 2,306 | |||||||||
| NGL (barrels) | 13,838 | 5,507 | - | |||||||||
| Total sales volumes (BOE) | 770,484 | 502,806 | 134,698 | |||||||||
| Revenues: | ||||||||||||
| Oil sales | $ | 59,795 | $ | 42,821 | $ | 10,706 | ||||||
| Gas sales | 271 | 145 | 9 | |||||||||
| NGL sales | 483 | 143 | - | |||||||||
| Total revenues | $ | 60,549 | $ | 43,139 | $ | 10,714 | ||||||
| Average sales prices: | ||||||||||||
| Oil sales (per barrel) | $ | 79.76 | $ | 86.97 | $ | 79.71 | ||||||
| Effect of derivatives settled in the normal course of business | 2.84 | 1.63 | - | |||||||||
| Oil sales, net of settled derivatives | 82.60 | 88.60 | 79.71 | |||||||||
| Gas sales (per mcf) | 6.47 | 5.26 | 3.55 | |||||||||
| NGL sales | 34.97 | 26.02 | - | |||||||||
| Average sales price per BOE | $ | 81.35 | $ | 87.39 | $ | 79.54 | ||||||
| Lease operating expenses | $ | 15,211 | $ | 6,719 | $ | 2,152 | ||||||
| Lease operating expenses per BOE | $ | 19.74 | $ | 13.36 | $ | 7.78 | ||||||
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Oil and Gas Reserves
The information presented below summarizes all of our estimated proved oil and gas reserves as of December 31, 2014, 2013 and 2012. Our estimated reserves as of December 31, 2014 and 2013 were audited by Ryder Scott Company, L.P. (“Ryder Scott”). Our estimated reserves as of December 31, 2012 were audited by MHA Petroleum Consultants, LLC. The prices used in the calculation of proved reserve estimates reflect the 12 month average of the first-day-of-the-month prices in accordance with Securities and Exchange Commission (“SEC”) rules, and were $82.86 per barrel for oil, $5.08 per mcf for natural gas for the year ended December 31, 2014.
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.
We retained independent petroleum engineering firms to audit our annual estimate of oil and gas reserves as of December 31, 2014, 2013 and 2012. The independent petroleum engineering firms estimated the oil and gas reserves associated with our US and Canadian oil and gas properties, prior to the sale of our Canadian 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. We believe 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.
Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. PV-10 shown in the following table is not intended to represent the current market value of our estimated proved reserves. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – 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.
Internal Controls Over Oil and Gas Reserves Estimates
We have 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, our 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 our 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, we believe that the underlying data provided by us to the independent petroleum engineering firm for the purpose of preparing its estimates, is reasonable. Furthermore, the estimated reserves as of December 31, 2014, 2013 and 2012, as described in the final report issued by the independent petroleum engineering firms, were reviewed by members of our operational management and determined to be reasonable based on the underlying data.
| 20 |
The following table summarizes estimated proved reserves and estimated future cash flows, discounted at a rate of 10% per annum (“PV10”), as of December 31, 2014, 2013 and 2012, (in thousands) and related pricing assumptions:
| As of December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Proved developed: | ||||||||||||
| Oil (Mbarrels) | 5,495 | 4,207 | 2,388 | |||||||||
| Gas (Mmcf) | 4,820 | 3,047 | 1,074 | |||||||||
| Total proved developed reserves (BOE) | 6,298 | 4,717 | 2,566 | |||||||||
| Proved undeveloped: | ||||||||||||
| Oil (Mbarrels) | 4,092 | 7,902 | 3,010 | |||||||||
| Gas (Mmcf) | 3,000 | 5,605 | 1,065 | |||||||||
| Total proved undeveloped reserves (BOE) | 4,592 | 8,836 | 3,188 | |||||||||
| Total proved: | ||||||||||||
| Oil (Mbarrels) | 9,587 | 12,109 | 5,398 | |||||||||
| Gas (Mmcf) | 7,820 | 8,652 | 2,139 | |||||||||
| Total proved reserves (BOE) | 10,890 | 13,550 | 5,754 | |||||||||
| Proved developed reserves percentage | 58 | % | 35 | % | 45 | % | ||||||
| Proved undeveloped reserves percentage | 42 | % | 65 | % | 55 | % | ||||||
| Estimated PV10: | ||||||||||||
| Proved developed reserves | $ | 178,500 | $ | 151,716 | $ | 66,873 | ||||||
| Proved undeveloped reserves | 49,464 | 156,374 | 51,658 | |||||||||
| Total proved reserves | $ | 227,964 | $ | 308,090 | $ | 118,531 | ||||||
| Pricing assumptions: | ||||||||||||
| Oil (per barrel) | $ | 82.36 | $ | 90.63 | $ | 81.78 | ||||||
| Gas (per mcf) | $ | 5.08 | $ | 5.15 | $ | 3.38 | ||||||
The following table summarizes the changes in our estimated proved reserves volumes for the year ended December 31, 2014 (in thousands):
| Oil | Gas | Total | ||||||||||
| (Barrels) | (Mcf) | (BOE) | ||||||||||
| Proved reserves, beginning of year | 12,109 | 8,652 | 13,550 | |||||||||
| Revisions | (3,726 | ) | (2,377 | ) | (4,122 | ) | ||||||
| Extensions and discoveries | 1,064 | 640 | 1,171 | |||||||||
| Purchases of reserves in place | 1,051 | 948 | 1,209 | |||||||||
| Sale of reserves in place | (148 | ) | (1 | ) | (148 | ) | ||||||
| Production | (763 | ) | (42 | ) | (770 | ) | ||||||
| Proved reserves, end of year | 9,587 | 7,820 | 10,890 | |||||||||
As a result of participating in 32 gross new wells, we converted approximately 657,000 barrels of oil and approximately 41,000 mcf of gas from proved undeveloped reserves to proved developed reserves during the year ended December 31, 2014. We incurred approximately $56.4 million of capitalized expenditures to drill these wells.
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The decrease in our proved undeveloped reserves from December 31, 2013 to December 31, 2014 is primarily due to uncertainty regarding whether or not we will have sufficient capital to support our current development plan. Historically, we have occasionally utilized carry agreements and farm-out agreements to accelerate the drilling of additional operated wells. The amount of proved undeveloped reserves that we are claiming as of December 31, 2014 has been determined based on the assumption that the we will continue to utilize such arrangements in the future in order to continue our planned drilling activities. We have reduced our net revenue and working interests in the future wells that comprise our proved undeveloped reserves by 50% in consideration of the anticipated terms of such arrangements.
Standardized Measure 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, 2014, 2013 and 2012, respectively.
Standardized Measure of Discounted Future Net Cash Flows (in thousands):
| 2014 | 2013 | 2012 | ||||||||||
| Future cash flows | $ | 829,316 | $ | 1,141,907 | $ | 448,623 | ||||||
| Future costs: | ||||||||||||
| Production costs | (273,430 | ) | (307,093 | ) | (99,411 | ) | ||||||
| Development costs | (109,102 | ) | (177,750 | ) | (50,693 | ) | ||||||
| Income taxes | (47,464 | ) | (184,362 | ) | (104,827 | ) | ||||||
| Future net cash flows | 399,320 | 472,702 | 193,692 | |||||||||
| Ten percent discount factor | (195,573 | ) | (250,648 | ) | (116,784 | ) | ||||||
| Standardized measure of discounted future net cash flows | $ | 203,747 | $ | 222,054 | $ | 76,908 | ||||||
The following table summarizes the changes in the Company’s standardized measure of discounted future net cash flows for the years ended December 31, 2014, 2013 and 2012 (in thousands):
| 22 |
| 2014 | 2013 | 2012 | ||||||||||
| Extensions and discoveries | $ | 35,491 | $ | 167,600 | $ | 84,276 | ||||||
| Net changes in sales prices and production costs | (54,609 | ) | 1,001 | (2,939 | ) | |||||||
| Oil and gas sales, net of production costs | (38,480 | ) | (31,530 | ) | (7,514 | ) | ||||||
| Change in estimated future development costs | 95,259 | (5,659 | ) | 12,376 | ||||||||
| Revision of quantity estimates | (136,988 | ) | (34,499 | ) | (22,267 | ) | ||||||
| Purchases of mineral interests | 42,855 | 35,496 | 12,777 | |||||||||
| Sales of mineral interests | (5,368 | ) | - | - | ||||||||
| Previously estimated development costs incurred in the current period | (58,895 | ) | 14,256 | 2,897 | ||||||||
| Changes in production rates, timing & other | 14,366 | 21,692 | 1,947 | |||||||||
| Changes in income taxes | 57,037 | (35,914 | ) | (33,864 | ) | |||||||
| Accretion of discount | 31,025 | 12,703 | 3,994 | |||||||||
| Net increase | (18,307 | ) | 145,146 | 51,683 | ||||||||
| Standardized measure of discounted future cash flows – beginning of the year | 222,054 | 76,908 | 25,225 | |||||||||
| Standardized measure of discounted future cash flows – end of the year | $ | 203,747 | $ | 222,054 | $ | 76,908 | ||||||
Assumed prices used to calculate future cash flows
| 2014 | 2013 | 2012 | ||||||||||
| Oil price per barrel | $ | 82.36 | $ | 90.63 | $ | 81.78 | ||||||
| Gas price per mcf | $ | 5.08 | $ | 5.15 | $ | 3.38 | ||||||
Additional information regarding our oil and gas properties can be found in Note 2 and Note 20 to our financial statements as of December 31, 2014 and 2013 and for each of the years in the three-year period ended December 31, 2014, which are included in Item 8 of this document (see pages F-10 and F-27, 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.
We are not currently a party to any material legal proceedings.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Common Stock Price Ranges, Common Stock Dividends, and Stockholder Information.
On November 20, 2103, our common stock, par value $0.001, became listed on the New York Stock Exchange MKT (“NYSE MKT”) under the symbol “AMZG”. Prior to that time, our stock was quoted on the OTC Markets Group, Inc.’s OTCQX tier under the symbol “AMZG.” From November 7, 2005 until January 18, 2012, our symbol was “EERG” except from December 20, 2011 to January 17, 2012 when our symbol was “EERGD” in connection with our 2011 Merger. Active trading in the market of our common stock commenced on February 2, 2006.
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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.. 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 17, 2014.
| Bid | ||||||||
| High | Low | |||||||
| Year ended December 31, 2014: | ||||||||
| First Quarter | $ | 2.10 | $ | 1.71 | ||||
| First Quarter (from and after 1 for 4 reverse stock split) | 7.30 | 6.61 | ||||||
| Second Quarter | 7.47 | 5.65 | ||||||
| Third Quarter | 6.43 | 3.88 | ||||||
| Fourth Quarter | 3.79 | 0.61 | ||||||
| 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 | 11.40 | 7.56 | ||||||
| Fourth Quarter (from and after November 20, 2013) | 10.72 | 8.04 | ||||||
As of March 10, 2015, the closing price for our common stock was $0.16. As of March 10, 2015, there were 29 holders of record of our common stock.
We have never declared or paid any cash dividends on our common stock. For the foreseeable future, we expect to retain any earnings to finance the operation and expansion of our business.
Common Stock Performance Graph
The stock performance graph and table below compares our cumulative total stockholder return on our common stock during the five fiscal years ended December 31, 2014, with the cumulative total stockholder return of NYSE MKT Composite Index and the cumulative total stockholder return of select peers, which include the following companies: Barnwell Industries, Inc., BPZ Resources, Dune Energy Inc., Emerald Oil, Fieldpoint Petroleum Corporation, FX Energy, Inc., Miller Energy Resources, Postrock Energy Corporation, Saratoga Resources, Inc., Synergy Resources, US Energy, and Warren Resources, Inc.
The comparison assumes $100 was invested on December 31, 2009 in our common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the graph below are based on historical data and are not intended to forecast the possible future performance of our common stock.
| 24 |
| 2009 | 2010 | 2011 | 2012 | 2013 | 2014 | |||||||||||||||||||
| American Eagle Energy Corporation | $ | 100 | $ | 71.94 | $ | 188.94 | $ | 110.66 | $ | 283.58 | $ | 21.96 | ||||||||||||
| NYSE MKT Composite Index | $ | 100 | $ | 121.01 | $ | 124.84 | $ | 127.70 | $ | 131.07 | $ | 132.58 | ||||||||||||
| Peer Group | $ | 100 | $ | 150.78 | $ | 295.75 | $ | 280.37 | $ | 255.54 | $ | 290.73 | ||||||||||||
Item 6. Selected Financial Data
The following table sets forth selected supplemental financial and operating data as of or for the years ended December 31 (in thousands, except for per unit values). The financial data for each of the five years presented was derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunctions with our consolidated financial statements included in this report.
| 25 |
| 2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||||||||
| Results of Operations Data: | ||||||||||||||||||||
| Oil and gas sales | $ | 60,549 | $ | 43,139 | $ | 10,714 | $ | 865 | $ | 208 | ||||||||||
| Operating expenses | 22,069 | 11,609 | 3,200 | 2,782 | 1,652 | |||||||||||||||
| Net income (loss) | (92,216 | ) | 1,594 | (9,292 | ) | 4,454 | 2,884 | |||||||||||||
| Net income (loss) per share: | ||||||||||||||||||||
| Basic | $ | (3.35 | ) | $ | 0.11 | $ | (0.81 | ) | $ | 1.95 | $ | 1.22 | ||||||||
| Diluted | $ | (3.35 | ) | $ | 0.11 | $ | (0.81 | ) | $ | 1.47 | $ | 1.18 | ||||||||
| Weighted average shares outstanding: | ||||||||||||||||||||
| Basic | 27,513 | 13,962 | 11,448 | 2,286 | 2,359 | |||||||||||||||
| Diluted | 27,513 | 14,599 | 11,448 | 3,040 | 2,434 | |||||||||||||||
| Balance Sheet Data: | ||||||||||||||||||||
| Working capital | $ | (13,558 | ) | $ | 4,932 | $ | (21,353 | ) | $ | 5,921 | $ | 2,528 | ||||||||
| Total assets | 270,934 | 216,408 | 96,914 | 40,041 | 5,230 | |||||||||||||||
| Total debt | 173,467 | 108,000 | 16,000 | - | - | |||||||||||||||
| Total liabilities | 223,960 | 157,313 | 79,514 | 14,283 | 444 | |||||||||||||||
| Total shareholders’ equity | 46,974 | 59,095 | 17,400 | 25,758 | 4,786 | |||||||||||||||
| Statement of Cash Flow Data: | ||||||||||||||||||||
| Provided by (used for) operating activities | $ | 26,614 | $ | 30,411 | $ | 3,888 | $ | 676 | $ | (2,186 | ) | |||||||||
| Provided by (used for) investing activities | (162,867 | ) | (141,292 | ) | (12,527 | ) | 9,075 | 3,407 | ||||||||||||
| Provided by (used for) financing activities | 130,161 | 123,675 | 15,545 | - | (329 | ) | ||||||||||||||
| Effect of foreign currency exchange rate changes | 130 | (2 | ) | - | - | - | ||||||||||||||
| Net increase (decrease) in cash | $ | (5,962 | ) | $ | 12,792 | $ | 6,906 | $ | 9,751 | $ | 892 | |||||||||
| Proved Oil and Gas Reserves: | ||||||||||||||||||||
| Oil (MMBbl) | 9,587 | 12,109 | 5,398 | 1,511 | 199 | |||||||||||||||
| Gas (Mmcf) | 7,820 | 8,652 | 2,139 | 417 | - | |||||||||||||||
| MMBOE | 10,890 | 13,550 | 5,754 | 1,581 | 199 | |||||||||||||||
| Production Volumes: | ||||||||||||||||||||
| Oil (MMBbl) | 749 | 493 | 134 | 11 | 3 | |||||||||||||||
| Gas (Mmcf) | 42 | 28 | 2 | - | - | |||||||||||||||
| Natural Gas Liquids (MMBbl) | 14 | 5 | - | - | - | |||||||||||||||
| MMBOE | 770 | 503 | 135 | 11 | 3 | |||||||||||||||
| 26 |
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, such as further changes in our business direction or strategy, competitive factors and an inability to attract, develop, or retain technical, consulting, or managerial agents or independent contractors, as well as economic conditions specific to the oil and gas industry, such as the availability of drilling rigs and crews, uncertainty with respect to future oil and gas prices and potential government regulation over drilling and completion techniques. 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 $91.93 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 $53.45 per barrel to $113.39 per barrel, with the median price of $93.47 per barrel. The daily WTI oil prices averaged approximately $93.17, $97.97 and $94.15 for the years ended December 31, 2014, 2013 and 2012, respectively. The average price of oil fell to $73.21 for the fourth quarter of 2014, primarily as a result of oversupply and global economic pressures from middle-eastern oil producing countries. WTI prices hit their five-year low during the final week of December 2014, closing at $53.45 per barrel, and have continued to decline during the first quarter of 2015.
| 27 |
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. In addition, prolonged declines in oil and gas prices may ultimately result in the additional impairment of our oil and gas properties, cause the operation of certain oil and gas wells to become uneconomic and adversely impact our liquidity.
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.
During the past five years, we have engaged in exploration and production activities in both the northern United States as well as southeastern Saskatchewan, Canada. In July 2014, we sold all of our net revenue and working interests in our Canadian oil and gas properties. As of December 31, 2014, we are engaged in exploration and production activities in the northwest portion of Divide County, North Dakota, where we target the extraction of oil and natural gas reserves from the Three Forks and Middle Bakken formations. We have aggressively pursued the development of our Spyglass Area, to which virtually all of our capital has been or is being deployed. Our Spyglass Area generated 99% of our revenue for the year ended December 31, 2014 and represents 100% of our estimated remaining proved reserves as of December 31, 2014.
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, 2014, we had drilled and completed 54 gross (32.2 net) operated wells in our Spyglass Property, all of which were producing, and were in the process of completing two additional wells. An additional 2 gross (1.9 net) wells have been drilled and are awaiting completion.
We own working interests in our operated wells ranging from approximately 5% to 100%, with an average working interest of approximately 60%. Of the producing wells, 39 gross (25.0 net) operated wells were producing from the Three Forks formation and 15 gross (7.2 net) operated wells were producing from the Middle Bakken formation. During the year ended December 31, 2014, we added 26 gross (14.8 net) operated wells to production in our Spyglass Area. In addition, we added 3.7 net operated wells to production as a result of acquiring additional working interests in our existing operated wells.
| 28 |
We have elected to participate as a non-operating working interest partner in the drilling of 81 gross (4.2 net) wells within the Spyglass Area, all of which were producing as of December 31, 2014. Our working interest ownership in these non-operated wells ranges from less than 1% to approximately 28%, with an average working interest of approximately 6%.
The following table summarizes our Spyglass Area well activity for the year ended December 31, 2014:
| Non- | Total | |||||||||||
| Operated | Operated | Spyglass | ||||||||||
| Gross Wells | ||||||||||||
| Wells producing at beginning of period | 28 | 75 | 103 | |||||||||
| Wells added to production during the period | 26 | 6 | 32 | |||||||||
| Wells producing at end of period | 54 | 81 | 135 | |||||||||
| Net Wells | ||||||||||||
| Wells producing at beginning of period | 13.7 | 3.6 | 17.3 | |||||||||
| Wells added to production during the period | 14.8 | 0.0 | 14.8 | |||||||||
| Wells added as a result of purchasing additional | ||||||||||||
| Working interests | 3.7 | 0.6 | 4.3 | |||||||||
| Wells producing at end of period | 32.2 | 4.2 | 36.4 | |||||||||
Our capital expenditures related to exploration and well development totaled approximately $114.4 million for the year ended December 31, 2014. 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 and completed. In general, our costs of drilling wells that we operate decreased during 2014 as a result of more efficient drilling operations, which decreased the average number of days it takes for us to reach total depth on our wells.
During the year ended December 31, 2014, we spent approximately $57.9 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. Of this amount, approximately $54.8 million was spent to acquire additional working and net revenue interests from one of our working interest partners. The acquisition of the additional working and net revenue interests was funded from proceeds received from a public offering of our common stock in March 2014.
Oil and Gas Reserves
During the year ended December 31, 2014, the volume of our estimated proved, developed oil and gas reserves increased from approximately 4.7 million barrels of oil equivalent (“BOE”) as of January 1, 2014 to approximately 6.3 million BOE as of December 31, 2014, a 34% increase (60% increase after considering 2014 production). This increase is primarily the result of our successful drilling efforts, which enabled us to bring 26 new gross (14.8 net) operated wells onto production during the year. In addition, the estimated pre-tax present value of our proved, developed oil and gas reserves, discounted at an annual rate of 10% (“PV10”), increased from approximately $151.7 million at December 31, 2013 to approximately $178.5 million as of December 31, 2014, an 18% increase. The impact of bringing new wells onto production on the PV10 of our total proved developed reserves was mitigated by the decrease in average oil and gas prices used to estimate such reserves, from $90.63 per barrel and $5.15 per mcf in 2013 to $82.36 per barrel and $5.08 per mcf during 2014.
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The sharp decline in oil prices experienced during the fourth quarter of 2014 significantly impacted both the reserve volume and PV10 value of our proved, undeveloped properties, as lower prices negatively affect the economic viability of drilling future wells. The PV10 value of our proved undeveloped reserves fell from approximately $156.4 million as of December 31, 2013 to approximately $49.5 million at December 31, 2014. The decrease in the our proved undeveloped reserves from December 31, 2013 to December 31, 2014 is primarily due to uncertainty regarding whether or not we will have sufficient capital to support our current development plan. Historically, we have utilized carry agreements and farm-out agreements to accelerate the drilling of operated wells. The PV10 value of our proved undeveloped reserves as of December 31, 2014 has been determined based on the assumption that we will continue to utilize such arrangements in the future in order to continue our planned drilling activities. Accordingly, we have reduced our net revenue and working interests in the future wells that comprise our proved undeveloped reserves by 50% in consideration the anticipated terms of such arrangements.
Overall, our total proved reserves decreased from approximately 13.6 million BOE to approximately 10.9 million BOE during 2014. The PV10 value of our proved oil and gas reserves decreased from approximately $308.1 million at December 31, 2013 to approximately $228.0 million at December 31, 2014, primarily as a result of the aforementioned decline in oil prices during the fourth quarter of 2014.
PV10 is a standard, non-GAAP measure that is used within the oil and gas industry to value an entity’s proved oil and gas reserves, based on estimated future cash flows.
Operating Results
For the purpose of furthering the reader’s understanding of the results of our operations, we have elected to present certain non-GAAP financial measures that are commonly used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to analyze the results of our operations for the years ended December 31, 2014, 2013 and 2012. Specific non-GAAP financial measures presented include Adjusted Net Earnings, Adjusted Net Earnings per Share, Adjusted EBITDA and Adjusted Cash Flow from Operations. A description of each non-GAAP financial measure presented is provided below.
We define Adjusted Net Earnings as net income excluding any loss from the impairment of oil and gas properties and changes in the fair value of our outstanding commodity derivatives. We believe that this financial measure is meaningful because it excludes the effects of non-cash items that are primarily based on predicted future commodity prices, over which management has no control.
Adjusted Net Earnings per Share is calculated by dividing Adjusted Net Earnings by the weighted average shares of our common stock that were outstanding for the period. GAAP requires the use of basic weighted average shares outstanding for the period to calculate both basic and diluted net loss per share for periods in which an entity recognizes a net loss, as the use of the diluted weighted average shares outstanding for the period would have an anti-dilutive effect. In the event that, for a given period, we recognize a net loss (GAAP basis), but Adjusted Net Earnings (non-GAAP basis), we also present Adjusted Net Earnings Per Share (non-GAAP basis) on both a basic and diluted basis using the appropriate weighted average shares outstanding figure as the denominator.
We define Adjusted EBITDA as net income before depletion, depreciation and amortization, impairment of oil and natural gas properties, asset retirement obligation accretion expense, gain (loss) on derivative activities, net cash receipts (payments) on settled derivative instruments, premiums (paid) received on options that settled during the period, interest expense, and income tax expense.
Management believes Adjusted EBITDA is useful because it allows management to evaluate our operating performance more effectively and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the methods by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity.
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Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which is a component of Adjusted EBITDA. The Adjusted EBITDA presented below may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in the our various agreements, including the agreements governing the Senior Credit Facility. We have included a reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, below.
We believe that Adjusted Cash Flow from Operations is a meaningful financial measure because it excludes the majority of non-cash charges from EBITDA, yet includes the portion of interest expense that paid in cash, thus providing a measurement of our ability to service our debt.
The following table summarizes our consolidated revenue, production data, and operating expenses for the years ended December 31, 2014, 2013 and 2012:
| 2014 | 2013 | 2012 | ||||||||||
| Sales (in thousands): | ||||||||||||
| Oil sales | $ | 59,795 | $ | 42,851 | $ | 10,706 | ||||||
| Gas sales | 271 | 145 | 8 | |||||||||
| Liquids sales | 483 | 143 | - | |||||||||
| Total sales | $ | 60,549 | $ | 43,139 | $ | 10,714 | ||||||
| Volumes: | ||||||||||||
| Oil sales (barrels) | 749,681 | 492,706 | 134,314 | |||||||||
| Gas sales (mcf) | 41,791 | 27,556 | 2,306 | |||||||||
| Liquids sales (barrels) | 13,838 | 5,507 | - | |||||||||
| Total barrels of oil equivalent (“BOE”) | 770,484 | 502,806 | 134,698 | |||||||||
| Average daily sales volumes (BOE) | 2,111 | 1,378 | 369 | |||||||||
| Average sales price: | ||||||||||||
| Oil sales (per barrel) | $ | 79.76 | $ | 86.97 | $ | 79.71 | ||||||
| Effect of derivatives settled in the normal course of business (per barrel) | 2.02 | 1.63 | - | |||||||||
| Oil sales, net of settled derivatives (per barrel) | 81.78 | 88.60 | 79.71 | |||||||||
| Gas sales (per mcf) | 6.47 | 5.26 | 3.55 | |||||||||
| Liquids sales (per barrel) | 34.97 | 26.02 | - | |||||||||
| Oil equivalent sales per BOE | $ | 80.55 | $ | 87.39 | $ | 79.54 | ||||||
| Operating expenses (in thousands): | ||||||||||||
| Lease operating expenses (“LOE”) | $ | 15,211 | $ | 6,719 | $ | 2,152 | ||||||
| Production taxes | 6,858 | 4,890 | 1,048 | |||||||||
| Total oil and gas production expenses | 22,069 | 11,609 | 3,200 | |||||||||
| General and administrative expenses, excluding stock-based compensation | 6,041 | 6,158 | 3,682 | |||||||||
| Stock-based compensation (non-cash) | 1,791 | 1,203 | 822 | |||||||||
| Depletion, depreciation and amortization (non-cash) | 24,604 | 10,073 | 2,860 | |||||||||
| Impairment of oil and gas properties (non-cash) | 81,908 | 1,732 | 10,631 | |||||||||
| Total operating expenses | $ | 136,413 | $ | 30,775 | $ | 21,195 | ||||||
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| 2014 | 2013 | 2012 | ||||||||||
| Operating expenses per BOE: | ||||||||||||
| LOE | $ | 19.74 | $ | 13.36 | $ | 15.98 | ||||||
| Production taxes | 8.90 | 9.73 | 7.78 | |||||||||
| Total oil and gas production expenses | 28.64 | 23.09 | 23.76 | |||||||||
| General and administrative expenses, excluding stock-based compensation | 7.84 | 12.25 | 27.33 | |||||||||
| Stock-based compensation (non-cash) | 2.33 | 2.39 | 6.11 | |||||||||
| Depletion, depreciation and amortization (non-cash) | 31.93 | 20.03 | 21.23 | |||||||||
| Impairment of oil and gas properties (non-cash) | 106.31 | 3.44 | 78.93 | |||||||||
| Total operating expenses per BOE | $ | 177.05 | $ | 61.20 | $ | 157.36 | ||||||
| Adjusted earnings (Non-GAAP; in thousands): | ||||||||||||
| Net income (loss) | $ | (92,216 | ) | $ | 1,594 | $ | (9,292 | ) | ||||
| Add: Impairment of oil and gas properties | 81,908 | 1,732 | 10,631 | |||||||||
| Add: Loss on sale of oil and gas properties | 12 | - | - | |||||||||
| Less: One-time realized gains on settlement of derivatives | (5,095 | ) | - | - | ||||||||
| Add: Loss on early extinguishment of debt | 11,894 | 3,714 | - | |||||||||
| Add: Change in fair value of marketable securities | 491 | - | - | |||||||||
| Add: Change in fair values of derivatives | - | 815 | 122 | |||||||||
| Adjusted earnings | $ | (3,006 | ) | $ | 7,855 | $ | 1,461 | |||||
| Adjusted earnings per share (Non-GAAP): | ||||||||||||
| Basic | $ | (0.11 | ) | $ | 0.56 | $ | 0.13 | |||||
| Diluted | $ | (0.11 | ) | $ | 0.54 | $ | 0.13 | |||||
| Weighted average number of shares outstanding (in thousands): | ||||||||||||
| Basic | 27,513 | 13,932 | 11,448 | |||||||||
| Diluted | 27,835 | 14,599 | 11,565 | |||||||||
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| 2014 | 2013 | 2012 | ||||||||||
| Adjusted EBITDA (Non-GAAP; in thousands): | ||||||||||||
| Net income (loss) | $ | (92,216 | ) | $ | 1,594 | $ | (9,292 | ) | ||||
| Less: Interest and dividend income | (57 | ) | (81 | ) | (72 | ) | ||||||
| Add: Interest expense | 15,900 | 5,356 | 1 | |||||||||
| Add: Income tax expense (benefit) | (5,280 | ) | 1,769 | (1,240 | ) | |||||||
| Add: Depletion, depreciation and amortization (non-cash) | 24,604 | 10,073 | 2,860 | |||||||||
| Add: Stock-based compensation (non-cash) | 1,791 | 1,203 | 822 | |||||||||
| Add: Accretion of asset retirement obligations (non-cash) | 84 | 49 | 65 | |||||||||
| Add: Impairment of oil and gas properties (non-cash) | 81,908 | 1,731 | 10,631 | |||||||||
| Add: Loss on sale of oil and gas properties | 12 | - | - | |||||||||
| Add: Loss on early extinguishment of debt | 11,894 | 3,714 | - | |||||||||
| Less: One-time realized gains on settlement of derivatives | (5,095 | ) | - | - | ||||||||
| Add: Change in fair value of marketable securities | 491 | - | - | |||||||||
| Change in fair value of derivatives | - | 815 | 123 | |||||||||
| Adjusted EBITDA | $ | 34,036 | $ | 26,223 | $ | 3,898 | ||||||
| Adjusted EBITDA per share (Non-GAAP): | ||||||||||||
| Basic | $ | 1.24 | $ | 1.88 | $ | 0.34 | ||||||
| Diluted | $ | 1.22 | $ | 1.79 | $ | 0.34 | ||||||
| Adjusted cash flow from operations (Non-GAAP): | ||||||||||||
| Adjusted EBITDA | $ | 34,036 | $ | 26,223 | $ | 3,898 | ||||||
| Less: Interest expense | (15,900 | ) | (5,356 | ) | (1 | ) | ||||||
| Add: Amortization of deferred financing costs (non-cash) | 1,670 | 602 | - | |||||||||
| Add: Amortization of bond discount (non-cash) | 113 | - | - | |||||||||
| Adjusted cash flow from operations | $ | 19,919 | $ | 21,469 | $ | 3,897 | ||||||
Results of Operations for the year ended December 31, 2014 vs. December 31, 2013
In July 2014, we sold all of our Canadian net revenue and working interests, resulting in a loss on the sale of oil and gas properties of approximately $12,000. Oil and gas sales from our Canadian properties accounted for less than 1% of our consolidated oil and gas sales for the year ended December 31, 2014, and less than 3% of our consolidated oil and gas sales for the year ended December 31, 2013.
Revenues from the sale of oil, natural gas and liquids totaled approximately $60.5 million for the year ended December 31, 2014, compared to approximately $43.1 million for the year ended December 31, 2013, an increase of 40%. This increase was driven primarily by a 53% increase in production by volume, which was partially offset by a 8% decline in oil prices, after considering the effects of settled derivatives. Our wells continue to be primarily oil-producing wells, with 99% of total revenues for the year ended December 31, 2014 and 2013 resulting from oil sales. Our average daily production for the year ended December 31, 2014, calculated on a barrel of oil equivalent basis, was 2,111 BOEPD, compared to 1,378 BOEPD for 2013. Production volumes increased primarily due to the addition of 26 gross (14.8 net) operated wells and 6 gross (0.6 net) non-operated wells to production within the Williston Basin during the year. For the year ended December 31, 2014, our average realized price per barrel of oil was $79.76 ($82.60 after considering the effects derivatives that were settled in the normal course of business) compared to an average realized price of $86.97 ($88.60, after considering the effects of settled derivatives) per barrel for the year ended December 31, 2013.
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Lease operating expenses totaled approximately $15.2 million for the year ended December 31, 2014 compared to approximately $6.7 million for the year ended December 31, 2013. On a per-unit basis, LOE increased from $13.36 per BOE for the year ended December 31, 2013 to $19.74 per BOE for the year ended December 31, 2014. The increase in LOE per BOE from 2013 to 2014 is primarily due to planned workover expenses related to some of our older wells, as well as higher water transportation and disposition costs.
Production taxes totaled approximately $6.9 million for the year ended December 31, 2014, compared to approximately $4.9 million for the year ended December 31, 2013. Production taxes, as a percentage of total revenues were approximately 11.3% for both of the years ended December 31, 2014 and 2013. The statutory production tax rate for our North Dakota operated wells is 11.5%.
General and administrative expenses, excluding stock based compensation, totaled approximately $6.0 million for the year ended December 31, 2014, compared to approximately $6.2 million for the year ended December 31, 2013. Included in general and administrative expenses is stock-based compensation totaling approximately $1.8 million and $1.2 million for the year ended December 31, 2014 and 2013, respectively. Stock-based compensation is a non-cash charge to earnings.
Depletion, depreciation and amortization expense totaled approximately $24.6 million ($31.93 per BOE) for the year ended December 31, 2014, compared to approximately $10.1 million ($20.03 per BOE) for the year ended December 31, 2013. 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 proved undeveloped reserves to proved producing reserves. Our gross capitalized costs related to amortizable oil and gas properties, prior to any year-end impairment adjustments, increased from approximately $168.0 million at December 31, 2013 to approximately $341.7 million at December 31, 2014. The increase in depletion expense was due primarily to the addition of 26 gross (14.8 net) operated wells to production during 2014, as well as the incurrence of approximately $57.9 million of costs to acquire additional acreage and net revenue / working interests in existing properties.
Because we do not intend to develop our oil and gas properties, not subject to amortization, during the foreseeable future, and because no viable economic market exists for monetizing these properties as of December 31, 2014, we reclassified all of the capital costs associated with these undeveloped properties to our full cost pool. Under full cost accounting rules, we were required to write-down the value of our oil and gas properties, subject to amortization, as of December 31, 2014 by approximately $81.9 million. The impairment was largely due to falling oil prices, which negatively affected the PV10 value of the underlying oil and gas reserves. The impairment expenses represent non-cash charges against our earnings. Because SEC rules require proved oil and gas reserves to be valued using an unweighted arithmetic average of oil and gas prices for the preceding twelve-month period, and because forecasted oil prices for 2015 are projected to be lower than what was experienced during 2014, it is likely that we will recognized additional impairments during 2015 that will be material to our financial results.
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Due to lower than anticipate production volumes from our Hardy Property wells, we recognized impairment expense of approximately $1.7 million during the year ended at December 31, 2013 in connection with our Canadian oil and gas properties. The impairment expense represents a non-cash charge against our earnings. As noted above, we sold all of our net revenue and working interests in our Canadian oil and gas properties in July 2014.
In August 2013, we entered into the $200 million MSCG Credit Facility, at which time we borrowed $68 million. We used a portion of these funds to repay in full the then-outstanding balance of our prepaid Swap Facility (the “MBL Swap Facility”) with Macquarie Bank Limited (“MBL”). In doing so, we recognized a loss on the early extinguishment of the MBL debt of approximately $3.7 million, which consisted of a prepayment penalty and the write-off of unamortized deferred financing costs. In October 2013, we borrowed an additional $40 million under the MSGC Credit Facility to acquire certain working and net revenue interests in the Spyglass Property from one of our working interest partners.
In August 2014, we issued a series of 11% secured bonds (the “Bonds”) through a Rule 144A / Regulation S private offering. The Bonds mature on September 1, 2019 and have an aggregate gross value of $175 million. The Bonds were issued at a discount (99.059%), resulting in an original issuance discount of approximately $1.6 million. Net proceeds received from the issuance of the Bonds were approximately $167.3 million, net of the bond discount, investment banking fees and closing costs. We also incurred legal and bond rating fees totaling approximately $1.0 million in connection with the issuance of the Bonds. A portion of the net proceeds received from the issuance of the Bonds was used to repay in full the then-outstanding balance of the MSCG Credit Facility. In repaying the amounts due under the MSCG Credit Facility prior to its scheduled maturity, we recognized a loss on the early extinguishment of debt totaling approximately $11.9 million, which included amendment and prepayment penalties totaling approximately $5.5 million and the non-cash write-off of approximately $6.4 million of unamortized deferred financing costs.
We recognized interest expense totaling approximately $15.9 million for the year ended December 31, 2014 related to the MSCG Credit Facility, prior to repayment, and the Bonds. Interest expense for the year ended December 31, 2013 related to the MBL Swap Facility and the MSCG Credit Facility totaled approximately $5.4 million. Included in the aggregate interest expense figures for the year ended December 31, 2014 and 2013 is the amortization of the original issuance bond discount and deferred financing costs, both of which are non-cash items. The specific terms of the Bonds are discussed in the “Liquidity and Capital Resources” section, below.
In connection with MSCG Credit Facility, we were required to enter into price swap agreements with MSGC covering up to 85% of the anticipated production from our estimated proved developed reserves over the remaining life of the MSCG Credit Facility. The purpose of price swap agreements was to limit our potential exposure to falling oil prices. Sustained oil prices above the pre-determined terms of our price-swap agreements resulted in realized and unrealized losses, while sustained oil prices below the pre-determined terms of our price swap agreements resulted in realized and unrealized gains. The price swap agreements are considered derivatives under generally accepted accounting principles. We recognized losses on the normal settlement of these monthly swap agreements totaling approximately $751,000 for the year ended December 31, 2014. In addition, we were required to settle all of the remaining price swaps with MSGC prior to their scheduled maturity, which resulted in a one-time loss on the settlement of price swaps of approximately $6.4 million. We recognized gains on the normal settlement of prices swaps totaling approximately $803,000 and unrealized losses totaling approximately $815,000 resulting from the change in fair value of unsettled price swaps for the year ended December 31, 2013.
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In September 2014, we entered into new swap agreements covering approximately 55% of our expected oil production through December 2015. As a result of falling oil prices, we realized gains on the normal settlement of the new monthly swap agreements totaling approximately $2.6 million for the year ended December 31, 2014. In order to strengthen our working capital position, we elected to settle all of the remaining new price swap agreements at the end of December, which resulted in a one-time gain of approximately $11.5 million. As of December 31, 2014, we no longer have any price swap agreements in place.
We recognized an estimated income tax benefit of approximately $5.3 million for the year ended December 31, 2014, compared to an income tax expense of approximately $1.8 million for the year ended December 31, 2013. Our estimated tax expense (benefit) rates for the periods were (5.4%) and 52.6%, respectively.
Our basic and diluted loss per share was ($3.35) for the year ended December 31, 2014, compared to earnings per share of $0.11 for the year ended December 31, 2013. Because we recognized a net loss for the current period, diluted income per share for the year ended December 31, 2014 is calculated using the basic weighted average number of weighted shares outstanding for the period, as the effect of including potentially dilutive items would be anti-dilutive.
Our adjusted loss for the year ended December 31, 2014 was approximately $3.0 million, compared to an adjusted earnings of approximately $7.9 million for the year ended December 31, 2013. Adjusted earnings is derived by adding back unrealized changes in fair value of commodity derivatives (non-cash) to net income or adjusting for other non-recurring gains or losses during the period. Adjusted earnings is a non-GAAP financial measure.
Our adjusted EBITDA for the years ended December 31, 2014 and 2013 was approximately $34.0 million and $26.2 million, respectively. Adjusted EBITDA represents net earnings before interest income, dividend income, interest expense, income taxes, depletion, depreciation, and amortization, non-cash expenses related to stock-based compensation, impairment of oil and gas properties, loss on early extinguishment of debt, accretion of asset retirement obligations and changes in fair value of commodity derivatives (non-cash), and adjusted for other non-recurring gains or losses during the period. Adjusted EBITDA is a non-GAAP financial measure.
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 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. 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 anticipate production volumes from our Hardy Property wells and declining oil prices, 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.
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 $629,000 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 $903,000 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 $668,000. 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.
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In connection with our Credit Facility, we were 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 $803,000 and unrealized losses from derivatives totaling approximately $815,000 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 earnings 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 earnings 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.
Liquidity and Capital Resources
As of December 31, 2014, our assets totaled approximately $270.9 million, which included, among other items, cash balances of approximately $25.9 million, trade receivables totaling approximately $9.5 million and marketable securities valued at approximately $756,000.
As of December 31, 2014, we had a working capital deficit of approximately $13.6 million. The sharp decline in oil prices that occurred during the latter part of 2014 materially reduced the revenues that were generated from the sale of our oil and gas production volumes during that period which, in turn, negatively affected our year-end working capital balance. The potential for future oil prices to remain at their current price levels for an extended period of time raises substantial doubt regarding our ability to continue as a going concern. Should the prevailing oil prices as of December 31, 2014 remain in effect for an extended period of time, it is likely that we would need to pursue some form of asset sale, debt restructuring or capital raising effort in order to fund its operations and to service its existing debt during the next twelve months. Our management is actively developing plans to improve its working capital position and/or to reduce its future debt service costs, through the aforementioned means, in order to remain a going concern for the foreseeable future. If we are unable to restructure our Bonds, obtain additional debt or equity financing or achieve adequate proceeds from the sale of assets, we may file a voluntary petition for reorganization relief under Chapter 11 of the Bankruptcy Code in order to provide us with additional time to identify an appropriate solution to our financial situation and to implement a plan of reorganization aimed at improving our capital structure.
Despite falling oil prices, we generated approximately $26.6 million of positive cash flow from our operations for the year ended December 31, 2014, which included a loss on the early extinguishment of our then-outstanding Credit Facility with Morgan Stanley Capital Group.
| 38 |
During the year ended December 31, 2014, we spent approximately $164.2 million to drill and complete new oil and gas wells and to acquire both new acreage as well as additional working interests in our existing acreage position. The cost of drilling these new wells and of expanding our net acreage position were largely funded through the public sale of our common stock (March 2014), which generated net proceeds of approximately $78.3 million, and through the sale of high-yield bonds (the “Bonds”) (August 2014), which generated net proceeds of approximately $173.4 million, of which approximately $113.5 million was also used to repay previous indebtedness.
The Bonds, which mature on September 1, 2019, carry an annual interest rate of 11% and are secured by second lien positions in substantially all of our assets. Interest related to the Bonds is payable in arrears on March 1st and September 1st of each year until the bonds mature. The Bond Indenture contains customary affirmative and negative covenants for financial instruments of this nature, including limitations with respect to our ability to pay dividends, distributions and to secure additional future borrowings. The Bond Indenture also provides for a “carve out” of an additional $60 million of first-lien debt and an additional $20 million of unsecured debt.
Also in August 2014, we entered into a Senior Credit Facility (the “Senior Credit Facility”) with SunTrust Robinson Humphrey, Inc. (“SunTrust”), which provides for the initial availability of up to $35 million of borrowing capacity. In the event that we achieve certain milestones or maintain certain financial ratios, the borrowing capacity of the Senior Credit Facility may be increased to $60 million in the future. Amounts borrowed under the Senior Credit Facility are secured by a first-lien position on virtually all of our assets. Given falling oil prices throughout the fourth quarter of 2014, SunTrust elected to perform a borrowing capacity redetermination as of December 31, 2014, at which time the borrowing capacity was temporarily reduced to zero. As of December 31, 2014, we had not borrowed any funds under the Senior Credit Facility. With the SunTrust’s approval, the Senior Credit Facility may be assigned to other potential lenders for the purpose of borrowing additional funds in the future.
The Senior Credit Facility contains customary affirmative and negative covenants for borrowings of this type, including limitations on us with respect to transactions with affiliates, hedging agreements, dividends and distributions, operations in respect of the property that secures its collective obligations under the Senior Credit Facility, indebtedness, investments, and changes in business. The Senior Credit Facility also contains a number of financial covenants, including the maintaining of a current ratio of no less than 1.0 and a total debt to EBITDAX ratio of no more than 4.0. We were not in compliance with these covenants for the three-month period ended December 31, 2014 and have obtained a waiver of the covenants for this period. The non-compliance does not trigger any cross-default provisions associated with the Bonds.
We elected to defer the payment of approximately $9.8 million of interest due on our Bonds that was due on March 2, 2015. The terms of the Bond Indenture provide for a 30-day grace period, during which the interest payment can be made without the payment constituting an event of default. We intend to utilize the 30-day grace period to evaluate strategies for improving our liquidity. The 30-day grace period expires on March 31, 2015. As of the date of these financial statements, we have not yet determined whether the interest payment will be made. Accordingly, pursuant to generally accepted accounting principles, we have classified the Bonds as a current liability as of December 31, 2014. Absent any event of default, the subsequent payment of the interest due on the Bonds within the prescribed grace period, would allow us to classify the Bonds as a non-current liability in any revised or future financial statements.
It is possible that we may seek to borrow additional funds through the assignment of our Senior Credit Facility or to raise capital through the sale of additional shares of our common stock at any time 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, 2014, we were not subject to any material known, pending or threatened litigation.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
| 39 |
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our financial results from oil and gas operations may vary with fluctuations in oil and natural gas prices. Oil and natural gas are commodities, the market prices of which are determined based on world demand, supply, and other factors, all of which are beyond our control.
In order to manage our exposure to oil and natural gas price risk, we have from time to time entered into oil and natural gas price hedging arrangements with respect to a portion of our expected production. The purpose of entering into such agreements is to mitigate the potential negative effect of falling oil prices on our future results of operations and future cash flows. The commodity price swap agreements generally provide for monthly cash settlements between the parties to the agreements. On occasion, should economic conditions suggest that it is beneficial to do so, we may elect to settle our commodity price swap agreements in their entirety, which could have a material impact on our short term results of operations and overall liquidity. As of December 31, 2014, we are not a party to any commodity price swap agreements. However, we may elect to enter into such agreements again in the future.
| 40 |
Interest Rate Risk
Funds borrowed under our Senior Credit Facility are subject to a variable interest rate that is based on LIBOR. As such, significant changes in the LIBOR rate could have a material impact on the results of our operations and/or our ability to service any debt outstanding under the Senior Credit Facility. The variable interest rate associated with funds borrowed under the Senior Credit Facility is capped at a rate of 7% annually. As of December 31, 2014, there are no borrowings outstanding under the Senior Credit Facility.
Foreign Currency Exchange Risk
We are not exposed to foreign currency exchange risks as of December 31, 2014.
Inflation
Inflation affects the cost of supply, labor, products, services required for operations, maintenance, and capital improvements. While this impact of inflation has remained low in recent years, oil and natural gas prices are subject to rapid fluctuations. To compensate for fluctuations in oil and natural gas prices, we adjust selling prices to the extent allowed by the market.
Item 8. Financial Statements and Supplementary Data.
Our financial statements required to be included in Item 8 are set forth in the Index to Financial Statements on page F-1 of this Annual Report. Select supplementary financial data is included in Note 21 to the financial statements found on F-31 page.
| 41 |
American Eagle Energy Corporation
Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
American Eagle Energy Corporation
Index to the Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
American Eagle Energy Corporation
We have audited the accompanying consolidated balance sheets of American Eagle Energy Corporation and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Eagle Energy Corporation and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), American Eagle Energy Corporation’s and subsidiaries’ internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013, and our report dated March 30, 2015 expressed an unqualified opinion on the effectiveness of American Eagle Energy Corporation’s internal control over financial reporting.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 19 to the financial statements, the Company has a working capital deficit, and cash from operations may not be sufficient to fund operating activities and debt service obligations. Also, as described in Note 18, the Company did not make an interest payment that was due March 2, 2015. If the Company does not make the interest payment within the 30-day grace period, the bondholders may pursue various remedies. As a result, the Company may be forced to restructure its debts, reorganize or seek protection under bankruptcy laws. These facts raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters also are described in Note 19. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ Hein & Associates LLP
Denver, Colorado
March 30, 2015
| F-1 |
American Eagle Energy Corporation
Consolidated Balance Sheets
As of December 31, 2014 and 2013
(In Thousands, Except for per Share Data)
| 2014 | 2013 | |||||||
| Current assets: | ||||||||
| Cash | $ | 25,888 | $ | 31,850 | ||||
| Trade receivables | 9,466 | 17,920 | ||||||
| Income tax receivable | 25 | - | ||||||
| Prepaid expenses | 128 | 68 | ||||||
| Derivative asset | - | 211 | ||||||
| Total current assets | 35,507 | 50,049 | ||||||
| Equipment and leasehold improvements, net of accumulated depreciation and amortization of $490 and $322, respectively | 210 | 174 | ||||||
| Oil and gas properties, full-cost method – subject to amortization, net of accumulated depletion of $35,332 and $12,849, respectively | 226,918 | 155,145 | ||||||
| Oil and gas properties, full-cost method – not subject to amortization | - | 2,487 | ||||||
| Marketable securities | 756 | 1,050 | ||||||
| Other assets | 7,543 | 7,503 | ||||||
| Total assets | $ | 270,934 | $ | 216,408 | ||||
| Current liabilities: | ||||||||
| Accounts payable and accrued liabilities | $ | 49,065 | $ | 41,841 | ||||
| Derivative liability | - | 276 | ||||||
| Bonds payable, net of discount of $1,532 and $0, respectively | 173,467 | - | ||||||
| Current portion of notes payable | - | 3,000 | ||||||
| Total current liabilities | 222,532 | 45,117 | ||||||
| Asset retirement obligation | 1,428 | 1,060 | ||||||
| Noncurrent portion of notes payable | - | 105,000 | ||||||
| Noncurrent derivative liability | - | 750 | ||||||
| Deferred taxes | - | 5,386 | ||||||
| Total liabilities | 223,960 | 157,313 | ||||||
| Commitments and contingencies (Note 13) | ||||||||
| Stockholders’ equity: | ||||||||
| Common stock, $.001 par value, 48,611 shares authorized, 30,449 and 17,712 shares outstanding | 30 | 18 | ||||||
| Additional paid-in capital | 147,275 | 67,198 | ||||||
| Accumulated other comprehensive income (loss) | - | (6 | ) | |||||
| Accumulated deficit | (100,331 | ) | (8,115 | ) | ||||
| Total stockholders’ equity | 46,974 | 59,095 | ||||||
| Total liabilities and stockholders’ equity | $ | 270,934 | $ | 216,408 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| F-2 |
American Eagle Energy Corporation
Consolidated Statements of Operations
For Each of the Three Years in the Period Ended December 31, 2014
(In Thousands, Except for Per Share Data)
| 2014 | 2013 | 2012 | ||||||||||
| Oil and gas sales | $ | 60,549 | $ | 43,139 | $ | 10,714 | ||||||
| Operating expenses: | ||||||||||||
| Oil and gas production costs | 22,069 | 11,609 | 3,200 | |||||||||
| General and administrative | 7,832 | 7,361 | 4,504 | |||||||||
| Depletion, depreciation and amortization | 24,604 | 10,073 | 2,860 | |||||||||
| Impairment of oil and gas properties, subject to amortization | 81,908 | 1,732 | 10,631 | |||||||||
| Total operating expenses | 136,413 | 30,775 | 21,195 | |||||||||
| Total operating income (loss) | (75,864 | ) | 12,364 | (10,481 | ) | |||||||
| Other income (expense): | ||||||||||||
| Interest and dividend income | 57 | 81 | 72 | |||||||||
| Interest expense | (15,900 | ) | (5,356 | ) | (1 | ) | ||||||
| Loss on early extinguishment of debt | (11,894 | ) | (3,714 | ) | - | |||||||
| Loss on sale of oil & gas properties | (12 | ) | - | - | ||||||||
| Change in fair value of marketable securities | (491 | ) | - | - | ||||||||
| Gains on settlement of derivatives | 6,608 | 803 | - | |||||||||
| Change in fair value of derivatives | - | (815 | ) | (122 | ) | |||||||
| Total other income (expense) | (21,632 | ) | (9,001 | ) | (51 | ) | ||||||
| Income (loss) before taxes | (97,496 | ) | 3,363 | (10,532 | ) | |||||||
| Income tax expense (benefit) | (5,280 | ) | 1,769 | (1,240 | ) | |||||||
| Net income (loss) | $ | (92,216 | ) | $ | 1,594 | $ | (9,292 | ) | ||||
| Net income (loss) per common share: | ||||||||||||
| Basic | $ | (3.35 | ) | $ | 0.11 | $ | (0.81 | ) | ||||
| Diluted | $ | (3.35 | ) | $ | 0.11 | $ | (0.81 | ) | ||||
| Weighted average number of shares outstanding: | ||||||||||||
| Basic | 27,513 | 13,962 | 11,448 | |||||||||
| Diluted | 27,513 | 14,599 | 11,448 | |||||||||
The accompanying notes are an integral part of the consolidated financial statements.
| F-3 |
American Eagle Energy Corporation
Consolidated Statements of Comprehensive Income (Loss)
For Each of the Three Years in the Period Ended December 31, 2014
(In Thousands, Except for Per Share Data)
| 2014 | 2013 | 2012 | ||||||||||
| Net income (loss) | $ | (92,216 | ) | $ | 1,594 | $ | (9,292 | ) | ||||
| Other comprehensive income (loss), net of tax: | ||||||||||||
| Unrealized losses on securities | (491 | ) | (1 | ) | (110 | ) | ||||||
| Foreign current translation adjustments | 497 | 28 | (103 | ) | ||||||||
| Comprehensive income (loss) | $ | (92,210 | ) | $ | 1,621 | $ | (9,505 | ) | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| F-4 |
American Eagle Energy Corporation
Consolidated Statements of Stockholders’ Equity
For Each of the Three Years in the Period Ended December 31, 2014
(In Thousands)
| Accumulated | ||||||||||||||||||||||||
| Additional | Other | Total | ||||||||||||||||||||||
| Common Stock | Paid-In | Comprehensive | Accumulated | Stockholders | ||||||||||||||||||||
| Shares | Amount | Capital | Income (Loss) | Deficit | Equity | |||||||||||||||||||
| Balance, January 1, 2012 | 11,398 | $ | 12 | $ | 25,983 | $ | 180 | $ | (417 | ) | $ | 25,758 | ||||||||||||
| Stock based compensation | - | - | 822 | - | - | 822 | ||||||||||||||||||
| Shares issued in private placement | 25 | - | 110 | - | - | 110 | ||||||||||||||||||
| Shares issued from exercise of stock options | 38 | - | 35 | - | - | 35 | ||||||||||||||||||
| Shares issued in debt financing | 56 | - | 180 | - | - | 180 | ||||||||||||||||||
| Unrealized loss on securities, net of tax | - | - | - | (110 | ) | - | (110 | ) | ||||||||||||||||
| Foreign exchange translation adjustments | - | - | - | (103 | ) | - | (103 | ) | ||||||||||||||||
| Net loss | - | - | - | - | (9,292 | ) | (9,292 | ) | ||||||||||||||||
| Balance, December 31, 2012 | 11,517 | $ | 12 | $ | 27,130 | $ | (33 | ) | $ | (9,709 | ) | $ | 17,400 | |||||||||||
| Stock based compensation | - | - | 1,203 | - | - | 1,203 | ||||||||||||||||||
| Shares issued in private placements | 2,250 | 2 | 13,875 | - | - | 13,877 | ||||||||||||||||||
| Shares issued in public offerings | 3,941 | 4 | 24,990 | - | - | 24,994 | ||||||||||||||||||
| Shares issued upon exercise of options | 4 | - | - | - | - | - | ||||||||||||||||||
| Unrealized loss on securities, net of tax | - | - | - | (1 | ) | - | (1 | ) | ||||||||||||||||
| Foreign exchange translation adjustments | - | - | - | 28 | - | 28 | ||||||||||||||||||
| Net income | - | - | - | - | 1,594 | 1,594 | ||||||||||||||||||
| Balance, December 31, 2013 | 17,712 | $ | 18 | $ | 67,198 | $ | (6 | ) | $ | (8,115 | ) | $ | 59,095 | |||||||||||
| Stock based compensation | - | - | 1,791 | - | - | 1,791 | ||||||||||||||||||
| Round up shares issued in reverse-split | 75 | - | - | - | - | - | ||||||||||||||||||
| Shares issued in public offerings | 12,650 | 12 | 78,286 | - | - | 78,298 | ||||||||||||||||||
| Shares issued upon exercise of options | 12 | - | - | - | - | - | ||||||||||||||||||
| Unrealized loss on securities, net of tax | - | - | - | (491 | ) | - | (491 | ) | ||||||||||||||||
| Foreign exchange translation adjustments | - | - | - | 497 | - | 497 | ||||||||||||||||||
| Net income | - | - | - | (92,216 | ) | (92,216 | ) | |||||||||||||||||
| Balance, December 31, 2014 | 30,449 | $ | 30 | $ | 147,275 | $ | - | $ | (100,331 | ) | $ | 46,974 | ||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
| F-5 |
American Eagle Energy Corporation
Consolidated Statements of Cash Flows
For Each of the Three Years in the Period Ended December 31, 2014
(In Thousands)
| 2014 | 2013 | 2012 | ||||||||||
| Cash flows provided by operating activities: | ||||||||||||
| Net income (loss) | $ | (92,216 | ) | $ | 1,594 | $ | (9,292 | ) | ||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities | ||||||||||||
| Non-cash transactions: | ||||||||||||
| Stock-based compensation | 1,791 | 1,203 | 822 | |||||||||
| Depletion, depreciation and amortization | 24,604 | 10,073 | 2,860 | |||||||||
| Impairment of oil and gas properties | 81,908 | 1,732 | 10,631 | |||||||||
| Accretion of discount on asset retirement obligations | 83 | 49 | 5 | |||||||||
| Amortization of deferred financing costs | 1,556 | 602 | - | |||||||||
| Amortization of debt discount | 113 | - | ||||||||||
| Provision for deferred income tax expense (benefit) | (5,386 | ) | 1,794 | (938 | ) | |||||||
| Loss on early extinguishment of debt | 11,894 | 3,714 | - | |||||||||
| Loss on sale of oil and gas properties | (12 | ) | - | - | ||||||||
| Change in fair value of marketable securities | 491 | - | - | |||||||||
| Change in fair value of derivatives | (815 | ) | 692 | 122 | ||||||||
| Foreign currency transaction gains (losses) | 11 | (11 | ) | (53 | ) | |||||||
| Changes in operating assets and liabilities: | ||||||||||||
| Prepaid expenses | (60 | ) | 64 | (87 | ) | |||||||
| Trade receivables | (5,857 | ) | 4,468 | (799 | ) | |||||||
| Income taxes receivable | (25 | ) | 190 | (190 | ) | |||||||
| Receivables from related parties | - | - | 315 | |||||||||
| Deposits | - | - | (3 | ) | ||||||||
| Accounts payable and accrued liabilities | 8,534 | 4,247 | 1,955 | |||||||||
| Income taxes payable | - | - | (1,460 | ) | ||||||||
| Net cash provided by operating activities | 26,614 | 30,411 | 3,888 | |||||||||
| Cash flows used for investing activities: | ||||||||||||
| Proceeds from conveyance of working interests | - | - | 3,790 | |||||||||
| Additions to oil and gas properties | (164,265 | ) | (136,267 | ) | (18,915 | ) | ||||||
| Proceeds from sale of oil and gas properties | 1,824 | - | 228 | |||||||||
| Additions to equipment and leasehold improvements | (204 | ) | (68 | ) | (252 | ) | ||||||
| Purchases of marketable securities | (222 | ) | - | (51 | ) | |||||||
| Purchases of certificates of deposit | - | - | (50 | ) | ||||||||
| Increase (decrease) in amounts due to Carry Agreement Partner | - | (4,957 | ) | 2,723 | ||||||||
| Net cash used for investing activities | (162,867 | ) | (141,292 | ) | (12,527 | ) | ||||||
The accompanying notes are an integral part of the consolidated financial statements.
| F-6 |
American Eagle Energy Corporation
Consolidated Statements of Cash Flows
For Each of the Three Years in the Period Ended December 31, 2014
(In Thousands)
| 2014 | 2013 | 2012 | ||||||||||
| Cash flows provided by financing activities: | ||||||||||||
| Proceeds from issuance of stock | 78,298 | 38,871 | 110 | |||||||||
| Proceeds from exercise of stock options | - | - | 35 | |||||||||
| Proceeds from issuance of notes | - | 105,935 | 16,000 | |||||||||
| Repayment of notes | (113,465 | ) | (21,131 | ) | (600 | ) | ||||||
| Proceeds from issuance of bonds | 173,353 | - | - | |||||||||
| Payment of other deferred financing costs | (8,025 | ) | - | - | ||||||||
| Net cash provided by investing activities | 130,161 | 123,675 | 15,545 | |||||||||
| Effect of exchange rate changes on cash | 130 | (2 | ) | - | ||||||||
| Net change in cash | (5,962 | ) | 12,792 | 6,906 | ||||||||
| Cash – beginning of period | 31,850 | 19,058 | 12,152 | |||||||||
| Cash – end of period | $ | 25,888 | $ | 31,850 | $ | 19,058 | ||||||
Supplemental Disclosure of Cash Flow Information
| Cash paid (received) during the period for: | ||||||||||||
| Interest | 7,598 | 3,746 | 1 | |||||||||
| Taxes | - | (178 | ) | 1,255 |
Supplemental Disclosure of Non-Cash Investing and Financing Activities
| Stock issued in connection with debt financing | - | - | 180 | |||||||||
| Property additions included in accounts payable | 24,798 | 19,425 | 25,671 | |||||||||
| Property additions through the establishment of asset retirement obligations | 516 | 516 | 407 | |||||||||
| Direct financing of prepayment and other penalties | 5,465 | - | - |
The accompanying notes are an integral part of the consolidated financial statements.
| F-7 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 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 and development of oil and gas properties, and is primarily focused on extracting proved oil reserves from those properties. As of September 30, 2014, the Company had entered into participation agreements related to oil and gas exploration and development projects in the Spyglass Area, located in Divide County, North Dakota, and Sheridan County, Montana. In addition, the Company owns working interests in mineral leases located in Richland, Roosevelt and Toole Counties in Montana.
| 2. | Summary of Significant Accounting Policies |
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, AMZG, Inc., EERG Energy ULC (“EERG” - Canadian) and AEE Canada Inc. (“AEE Canada” - Canadian). All material intercompany accounts, transactions and profits have been eliminated.
As discussed in Note 4, the Company sold 100% of its net revenue and working interests in its Canadian oil and gas properties in July 2014. The Company legally dissolved its Canadian subsidiaries (EERG and AEE Canada) in October 2014, at which time, all remaining assets held by the Canadian entities were transferred back to the parent company. The accompanying Consolidated Statements of Operations and Comprehensive Income (Loss) and Consolidated Statements of Cash Flows for the year ended December 31, 2014 include the operating results and activities of EERG and AEE Canada through the date of dissolution.
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 years ended December 31, 2013 and 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 or gas 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 on deposit that exceed the United States Federal Deposit Insurance Company insurance limit of $250,000 per bank.
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.
| F-8 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
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.
At December 31, 2014 and 2013, 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.
| F-9 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
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 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 are excluded from capitalized costs to be amortized until it is determined whether or not 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 uneconomic holes are included in the amortization base immediately upon determination that the well is uneconomic.
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.
During the year ended December 31, 2014, the Company determined that it was unlikely that it would pursue the development of its oil and gas properties that are not subject to amortization in the foreseeable future. As a result, the Company reclassified all of the capitalized costs associated with these properties into the full cost pool.
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 the unweighted arithmetic average of prices posted on the first day of each of the preceding twelve months (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 $81.9 million associated with its US cost center for the year ended December 31, 2014, and 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.
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.
| F-10 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
Derivatives
Historically, the Company has entered into a number of oil price swap agreements, which represent derivative financial instruments. The Company reports its derivatives at their fair market value as of the end of each reporting period. Changes in the fair value of derivatives are included in the Company’s results of operations in the period in which they occur. The Company has no open derivative positions as of December 31, 2014.
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 11.0%, which represented the Company’s estimated incremental borrowing rate as of the dates that the corresponding wells were put on production.
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 $1.8 million, $1.2 million and $822,000 for the years ended December 31, 2014, 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.
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 16 for the calculation of basic and diluted weighted average common shares outstanding for the years ended December 31, 2014, 2013 and 2012.
| F-11 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
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 15 for a summary of the Company’s income tax expense (benefit) for the years ended December 31, 2014, 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, 2014, the Company had working capital deficit of approximately $13.6 million. See Note 19 for further discussion regarding the liquidity of the Company.
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 April 2014, the Financial Accounting Standards Board (“FASB”) issued Update 2014-08 - Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The objective of the amendments in this update is to change the criteria for reporting discontinued operations and enhance convergence of the FASB's and the International Accounting Standards Board's reporting requirements for discontinued operations. The amendments in this update change the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity, or a business or nonprofit activity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments in this update require an entity to present, for each comparative period, the assets and liabilities of a disposal group that includes a discontinued operation separately in the asset and liability sections, respectively, of the statement of financial position. The amendments in this update also require additional disclosures about discontinued operations. Public business entities must apply the amendments in this update prospectively to both of the following: (1) All disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years; (2) All businesses or nonprofit activities that, on acquisition, are classified as held for sale that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The Company does not believe the adoption of this update will have a material impact on the Company’s consolidated financial statements.
| F-12 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
In May 2014, the FASB issued Update 2014-09 - Revenue from Contracts with Customers (Topic 606). The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for accounting principles generally accepted in the United States and International Financial Reporting Standards. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity should disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. The Company does not believe the adoption of this update will have a material impact on the Company’s consolidated financial statements.
In June 2014, the FASB issued ASC Update No. 2014-12 - Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period (“ASC No. 2014-12”). The objective of the amendments in this update is to resolve the diverse accounting treatment of share-based payment awards. The amendments in this update apply to all reporting entities that grant their employees share-based payments in which the terms of the award provide that a performance target that affects vesting could be achieved after the requisite service period. The amendments require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in either (i) the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered or (ii) if the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period will reflect the number of awards that are expected to vest and will be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in this update are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in this update either (a) prospectively to all awards granted or modified after the effective date or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company does not believe the adoption of this update will have a material impact on the Company’s consolidated financial statements.
| F-13 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 3. | Marketable Securities and Fair Value Measurements |
Available-for-sale marketable securities at December 31, 2014 and 2013 consist of the following (in thousands):
| Gains in | Losses in | |||||||||||
| Accumulated | Accumulated | |||||||||||
| Estimated | Other | Other | ||||||||||
| Fair | Comprehensive | Comprehensive | ||||||||||
| Value | Income | Income | ||||||||||
| December 31, 2014 | ||||||||||||
| Noncurrent assets: | ||||||||||||
| Marketable securities | $ | 756 | $ | - | $ | - | ||||||
| December 31, 2013 | ||||||||||||
| Noncurrent assets: | ||||||||||||
| Marketable securities | $ | 1,050 | $ | 100 | $ | (75 | ) | |||||
The fair value of substantially all securities is determined by quoted market prices. There were no sales of marketable securities for the years ended December 31, 2014 or 2013.
The fair value of the Company’s financial instruments, measured on a recurring basis at December 31, 2014 and 2013, were as follows (in thousands):
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| December 31, 2014 | ||||||||||||||||
| Marketable securities | $ | 756 | $ | - | $ | - | $ | 756 | ||||||||
| December 31, 2013 | ||||||||||||||||
| Marketable securities | 1,050 | - | - | 1,050 | ||||||||||||
| Current derivative asset | - | 211 | - | 211 | ||||||||||||
| Current derivative liability | - | (276 | ) | - | (276 | ) | ||||||||||
| Noncurrent derivative liability | - | (750 | ) | - | (750 | ) | ||||||||||
| 4. | Purchases and Sales of Royalty and Property Interests |
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 $47.0 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 approximately $41.4 million. To finance the acquisition, the Company sold shares of its common stock, through two public offerings (See Note 14), and borrowed an additional $40 million under its then-existing Credit Facility (the “MSCG Credit Facility”) with Morgan Stanley Capital Group, Inc. (“MSCG”) (See Note 8). The agreement contained the option to purchase additional net revenue and working interests in the same producing and proved undeveloped properties at a later date.
| F-14 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
In March 2014, the Company exercised its option to purchase the additional net revenue and working interests in proved producing and proved undeveloped properties located within the Spyglass Area from the same working interest partner. The transaction closed on March 26, 2014 with an effective date of June 1, 2013. The gross purchase price for the acquired interests totaled approximately $47.1 million. The acquisition of the additional net revenue and working interests was funded with proceeds received from a March 2014 public offering, as discussed in Note 14.
Supplemental Pro Forma Information (Unaudited)
The Company’s consolidated statements of income for the years ended December 31, 2014 and 2013 include revenues and oil and gas operating expenses related to the net revenue and working interests acquired for the periods subsequent to the effective date of each transaction.
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, 2014, 2013 and 2012 would have been as follows (in thousands):
| 2014 | 2013 | ||||||||
| Pro forma revenues | $ | 63,723 | $ | 67,360 | |||||
| Pro forma net income (loss) | $ | (91,728 | ) | $ | 5,708 | ||||
| Pro forma income (loss) per share – basic | $ | (3.02 | ) | $ | 0.21 | ||||
| Pro forma income (loss) per share – diluted | $ | (3.02 | ) | $ | 0.21 | ||||
Also in March 2014, the Company acquired certain undeveloped acreage from the same working interest partner at a price of approximately $7.5 million.
In July 2014, the Company sold 100% of its net revenue and working interests in its Canadian oil and gas properties (the “Hardy Property) to its then working interest partner. Prior to the sale, the Hardy Property represented 100% of the Canadian cost center for the Company’s full-cost pool. Cash proceeds received from the sale approximated $1.8 million, which resulted in a loss on the sale of approximately $12,000.
| 5. | Carry Agreements |
On April 16, 2012, the Company entered into a Carry Agreement with a third-party working interest partner (the “Carry Agreement Partner”), pursuant to which (i) the 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 within our Spyglass Area, up to 120% of the original AFE amount, and (ii) the Company agreed to 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 would share in the excess costs based on the working interests stipulated in the Carry Agreement.
| F-15 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
Pursuant to the terms of the Carry Agreement, the portion of the Company’s net revenue interest in each well to be conveyed to the Carry Agreement Partner followed a graduated scale, whereby 50% of the Company’s net revenue and working interests are 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 had 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 would increase from 50% to 75% for the second year of production or until the carried costs, plus the 12% return, had been achieved, whichever occurs first. In the event that the Carry Agreement Partner had 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 would increase to 100% until the carried costs, plus the 12% return, had 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 would revert to the original working interests in each such well.
Effective July 15, 2012, the Company amended the Carry Agreement with the third-party to include an additional four oil and gas wells.
As discussed in Note 4, the Company acquired net revenue and working interests associated with certain properties, in March 2014, including 100% of the net revenue and working interests that had been conveyed to the Carry Agreement Partner, which effectively terminated the Carry Agreement.
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 agreed to 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.
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, 2014, all five of the wells to be drilled pursuant to the Second Carry Agreement have been completed. To date, the Company has received approximately $17.7 million of funding under the Second Carry Agreement. This amount is net of cumulative revenues and oil and gas operating costs associated with the carried wells, which were conveyed to the Carry Agreement Partner pursuant to the terms of the Second Carry Agreement. As noted above, the Carry Agreement Partner is entitled to receive a 12% return on the amount of capitalized drilling and completion costs that it has funded on the Company’s behalf.
As of December 31, 2014, the cost of drilling and completing one of the five wells exceeded the 120% of AFE cost threshold. Accordingly, the Company has recorded its portion of excess drilling and completion costs associated with this well, totaling approximately $1.0 million as of December 31, 2014. None of the five wells covered by the Second Carry Agreement has achieved payout as of December 31, 2014.
| F-16 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 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 Property 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, 2014, all six of the wells drilled pursuant to the Farm-Out Agreement have been completed. None of the six wells covered by the Farm-Out Agreement has achieved payout as of December 31, 2014.
| 7. | Swap Facility |
On December 28, 2012, the Company entered into a prepaid Swap Facility with Macquarie Bank Limited (“MBL”), pursuant to which MBL agreed to advance up to $18 million, of which $16 million was received at closing. The remaining $2 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 million, due in February 2018.
On August 19, 2013, the Company repaid in full the outstanding balance under the Swap Facility using proceeds received from its Credit Facility with MSCG (see Note 8). The total payoff amount was approximately $18 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 during 2013 on the early extinguishment of debt of approximately $3.7 million, which included 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.
The Company incurred investment banking fees and closing costs totaling approximately $780,000 in connection with the negotiation and closing of the MBL Swap Facility. The Company capitalized these items as deferred financing costs, and began amortizing the deferred financing costs over the life of the Swap Facility. The Company recognized approximately $151,000 and $0 of amortization expense related to the deferred financing costs for the years ended December 31, 2013 and 2012, respectively. The amortization of deferred loan costs is included as an additional component of interest expense for the respective periods.
| F-17 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 8. | Credit Facility |
In August 2013, the Company entered into the $200 million MSCG Credit Facility, which was comprised of a $68 million initial 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 MSCG Credit Facility was collateralized by, among other things, the Company’s oil and gas properties and future oil and gas sales derived from such properties.
Net proceeds from borrowings under the Initial Term Loan totaling approximately $67.3 million were used: (i) to repay amounts outstanding under the Swap Facility, thus fully extinguishing the Swap Facility, (ii) to reduce the Company’s payables, (iii) to develop its Spyglass Area in North Dakota to increase production of hydrocarbons, (iv) to acquire new oil and gas properties within the Spyglass Area and (v) to fund general corporate purposes that are usual and customary in the oil and gas exploration and production business.
Proceeds from borrowings under the Spyglass Tranche A Loan totaling approximately $40 million were used to purchase additional net revenue and working interests in the Spyglass Area (See Note 4).
In July 2014, the Company borrowed approximately $2.2 million in connection with the amendment of certain financial covenants contained in the original MSCG Credit Facility agreement.
In August 2014, the Company repaid all amounts then-outstanding under the MSCG Credit Agreement with funds received from the issuance of certain bonds (see Note 9) and, in doing so, recognized a loss on the early extinguishment of debt totaling approximately $11.9 million. The loss on the early extinguishment of debt included, the covenant amendment fee of approximately $2.2 million, a prepayment penalty of approximately $3.3 million and the write-off of unamortized deferred financing costs of approximately $6.4 million.
The MSCG Credit Facility contained 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 MSCG Credit Facility, liens and encumbrances in respect of the property that secures the Company’s collective obligations under the MSCG Credit Facility, subsidiaries and divestitures, indebtedness, investments, and changes in business. The MSCG Credit Agreement also contained a number of financial covenants, including the maintaining of an adjusted minimum working capital ratio of 1.0.
The MSCG Credit Facility had a five-year term and carried a variable interest rate ranging from approximately 5.5% to 10.5%. The variable interest rate was based primarily on the ratio of the Company’s proved developed reserves to its debt for a given period. Interest expense related to the Initial Term Loan and Spyglass Tranche A Loan totaled approximately $7.6 million and $3.8 million for the years ended December 31, 2014 and 2013, respectively.
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 capitalized these items as deferred financing costs, and began amortizing these costs over the life of the MSCG 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 $1.0 million and $451,000 of deferred financing costs related to the MSCG Credit Facility during the years ended December 31, 2014 and 2013, respectively.
| F-18 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 9. | Bonds Payable |
In August 2014, the Company issued a series of 11% secured bonds (the “Bonds”) through a Rule 144A / Regulation S private offering. The Bonds mature on September 1, 2019 and have an aggregate gross value of $175 million. The Bonds were issued at a discount (99.059%), resulting in a discount of approximately $1.6 million. Net proceeds received from the issuance of the Bonds approximated $167.3 million, net of the bond discount, investment banking fees and closing costs. A portion of the net proceeds received from the issuance of the Bonds was used to repay in full the then-outstanding balance of the MSCG Credit Facility (see Note 8). The Company is amortizing the bond discount over the life of the bonds using the effective interest method. Amortization of the Bond discount totaled approximately $114,000 for the year ended December 31, 2014.
The Bonds bear interest at a rate of 11.0% annually. Interest on the Bonds is payable in arrears each March 1st and September 1st. Interest expense related to the Bonds totaled approximately $6.6 million for the year ended December 31, 2014.
The Company incurred investment banking fees and closing costs totaling approximately $7.2 million in connection with the issuance of the Bonds. The Company has capitalized these items as deferred financing costs, and is amortizing these costs over the life of the Bonds 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 deferred financing costs related to the Bonds of approximately $500,000 for the year ended December 31, 2014.
The Bond Indenture contains customary affirmative and negative covenants for financial instruments of this nature, including limitations on the Company with respect to dividends, distributions and additional future borrowings. The Company is in compliance with all covenants required by the Bond Indenture as of December 31, 2014. The Bonds are secured by a second priority lien on virtually all of the Company’s assets.
The Bonds traded on the open market at a significant discount during the fourth quarter of 2014. On December 29, 2014, the date of the last recorded public trade of the bonds during 2014, Bonds with an aggregate par value of $1.0 million were traded at a discounted price of $0.4325 on the dollar, which suggests that the aggregate fair market value of the Bonds outstanding as of December 31, 2014 was approximately $75.7 million. The actual trade price represents a Hierarchy Level 1 input for the purpose of estimating fair market value.
As discussed in Note 18. the Company elected to defer the payment of interest due on the bonds on March 2, 2015. The terms of the Bond Indenture provide for a 30-day grace period, during which the interest payment can be paid without triggering an event of default. The 30-day grace period expires on March 31, 2015. As of the date of these financial statements, the Company has not yet determined whether the interest payment will be made. Accordingly, pursuant to generally accepted accounting principles, the Company has classified the Bonds as a current liability as of December 31, 2014. Absent any event of default, the subsequent payment of the interest due on the Bonds within the prescribed grace period, would allow the Company to classify the Bonds as a non-current liability in any revised or future financial statements.
| 10. | Senior Secured Revolving Credit Facility |
Also in August 2014, the Company entered into a Senior Secured Credit Facility (the “Senior Credit Facility”) with SunTrust Robinson Humphrey, Inc. (“SunTrust), which provided for the initial availability of up to $35 million of borrowing capacity. Borrowing capacity is periodically evaluated and adjusted based on, among other things, the discounted value of the Company’s oil and gas reserves (see Note 20). Given falling oil prices throughout the fourth quarter of 2014, SunTrust elected to perform a borrowing capacity redetermination as of December 31, 2014, at which time the borrowing capacity was temporarily reduced to zero. In the event that market conditions improve and/or the Company achieves certain milestones or maintains certain financial ratios, the borrowing capacity of the Senior Credit Facility may be increased to a maximum $60 million at some point in the future. At no time has the Company borrowed funds under the Senior Credit Facility to date.
When outstanding, amounts drawn under the Senior Credit Facility are subject to variable annual interest rates ranging from LIBOR plus 1.75% to LIBOR plus 3.75%, depending on the nature of the borrowing and the balance outstanding under the Senior Credit Facility at the time the funds are drawn. The terms of the Senior Credit Facility also call for the payment of unused commitment fees relative to amounts that are available, but not drawn, under the Senior Credit Facility. Unused commitment fees associated with the unused portion of the borrowing capacity are included as a component of the Company’s interest expense for the period. The Company recognized approximately $46,000 of unused commitment fees related to the Senior Credit Facility for the year ended December 31, 2014. The Company will not incur additional unused commitment fees during any future period for which the borrowing capacity is zero.
| F-19 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
The Company incurred investment banking fees and closing costs totaling approximately $779,000 in connection with the establishment of the Senior Credit Facility. The Company has capitalized these items as deferred financing costs, and is amortizing these costs over the life of the Senior Credit Facility using a method that approximates 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 $52,000 of deferred financing costs related to the Bonds during the year ended December 31, 2014.
The Senior 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 Senior Credit Facility, indebtedness, investments, and changes in business. The Senior Credit Facility also contains a number of financial covenants, including the maintaining of a current ratio of no less than 1.0 and a ratio of total debt to EBITDAX of no more than 4.0. The Company was not in compliance with these covenants for the period ended December 31, 2014, but has obtained a waiver from SunTrust for the period in question. Pursuant to the terms of the Intercreditor Agreement between the Company, SunTrust and the Bond holders, non-compliance with the covenants does not trigger any cross-default provisions associated with the Bonds.
| 11. | Price Swap Derivatives |
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 the changes in the fair value of the price swap agreements in its statement of operations in the period for which such unrealized changes occurred. These price swaps were closed in August 2013, concurrent with the full repayment of the Swap Facility. The Company recognized realized gains associated with the price swap agreements totaling approximately $116,000 for the year ended December 31, 2013.
As a condition of the MSCG Credit Facility (see Note 8), the Company was required to enter into commodity price swap agreements covering up to 85% of its projected five-year future production on its proved, developed, producing properties. 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 the changes in the fair value of the price swap agreements in its statement of operations in the period in which such unrealized changes in fair value occur. The Company recognized estimated unrealized losses on the price swaps associated with the MSCG Credit Facility of approximately $815,000 and $0 for the years ended December 31, 2013 and 2012, respectively. The price swap agreements were fully settled in August 2014 in conjunction with the full-repayment of the then-outstanding balance of the MSCG Credit Facility (see Note 8). The Company recognized realized losses on the settlement of the price swaps associated with the MSCG Credit Facility totaling approximately $7.5 million for the years ended December 31, 2014.
| F-20 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
In September 2014, the Company entered into new commodity price swap agreements. The new price swap agreements were settled in December 2014. The Company recognized realized gains on the new price swaps of approximately $14.1 million for the year ended December 31, 2014. The Company has no open derivative positions as of December 31, 2014.
| 12. | Asset Retirement Obligations |
During the years ended December 31, 2014 and 2013, the Company recorded initial, estimated asset retirement obligations totaling approximately $516,000 and $569,000, 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 and Hardy Properties. As of December 31, 2014 and 2013, the consolidated discounted value of the Company’s asset retirement obligations was approximately $1.4 million and $1.1 million, respectively. The projected plugging dates for wells in which the Company owns a working interest ranges from December 31, 2015 to December 31, 2032.
| 13. | 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 Property, should any such wells be proposed by the other working interest owners. As of December 31, 2014, the Company has elected to participate in nine future wells located within the Spyglass Property, with the Company's non-operated working interest in the Spyglass wells ranging from 0.2% to 23.0%. The Company's estimated portion of the aggregate drilling and completion costs of these wells is approximately $3.8 million. In January 2015, the Company sold its net revenue and working interests in six of the nine non-operated wells to SM Energy (Note 18), which reduced its drilling obligation by approximately $1.8 million. Of the remaining $2.0 million of drilling obligation, approximately $1.1 million has been incurred as of December 31, 2014. Additional wells could be proposed in the future, at which time the Company may or may not elect to participate in such additional wells.
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, 2014, the amount of severance payments that the Company would be obligated to make under the terms of the employment agreements would total approximately $2.2 million.
Lease Obligation
The Company currently leases office space pursuant to the terms of a three-year lease agreement. Future minimum lease payments related to the Company’s office lease as of December 31, 2014 are as follows (in thousands):
| Amount | ||||
| 2015 | $ | 184 | ||
| 2016 | 96 | |||
| Total | $ | 280 | ||
Rent expense for the years ended December 31, 2014, 2013 and 2012 totaled approximately $259,000, $146,000 and $110,000, respectively.
| F-21 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 14. | Equity Transactions |
Reverse Split
In March 2014, the Company completed a 1-for-4 reverse split of its common stock. Pursuant to accounting guidelines, all historical share and per-share data contained in these financial statements have been restated to reflect the reverse split for all periods presented.
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.
In August 2013, the Company sold 1,250,000 shares of its common stock in a private offering at a price of $8.00 per share. Proceeds from the sale totaled $9.9 million, net investment banking fees.
Public Offerings
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.
In March 2014, the Company sold 12,650,000 shares of its common stock in a public offering at a price of $6.60 per share. The sale of the 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 $78.3 million.
Stock Options
During the years ended December 31, 2014, and 2013, the Company granted to members of its Board of Directors, employees and certain key third-party consultants 87,500 and 648,125 stock options with a weighted average fair market value per option granted of $1.63 and $4.41, respectively. The aggregate fair market value of the options granted during the years ended December 31, 2014 and 2013 was approximately $142,000 and $2.9 million, respectively. 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:
| 2014 | 2013 | ||
| Risk-free interest rate | 0.43% to 0.56% | 0.22% to 0.35% | |
| Expected volatility of common stock | 59% to 76% | 62% to 84% | |
| Dividend yield | $0.00 | $0.00 | |
| Expected life of options | 5 years | 5 years |
| F-22 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
A summary of stock option activity for the years ended December 31, 2014 and December 31, 2013 is presented below:
| Weighted | ||||||||||
| Weighted | Average | |||||||||
| Average | Remaining | |||||||||
| Exercise | Contract | |||||||||
| Options | Price ($) | Term | ||||||||
| Outstanding at December 31, 2012 | 1,283,650 | $ | 3.12 | 3.6 years | ||||||
| Options granted | 648,125 | 8.48 | ||||||||
| Options exercised | (5,000 | ) | 3.12 | |||||||
| Options expired | - | - | ||||||||
| Options forfeited | - | - | ||||||||
| Outstanding at December 31, 2013 | 1,926,775 | $ | 4.92 | 3.4 years | ||||||
| Options granted | 87,500 | 3.19 | ||||||||
| Options exercised | (23,125 | ) | 2.92 | |||||||
| Options expired | - | - | ||||||||
| Options forfeited | - | - | ||||||||
| Outstanding at December 31, 2014 | 1,991,150 | $ | 4.81 | 2.5 years | ||||||
| Exercisable at December 31, 2014 | 1,584,588 | $ | 4.18 | 2.1 years | ||||||
The following is a schedule of outstanding stock options as of December 31, 2014 by exercise price:
| Options | Options | Exercise | ||||||||||
| Grant Date | Outstanding | Exercisable | Price | |||||||||
| December 12, 2014 | 50,000 | - | $ | 0.73 | ||||||||
| October 30, 2009 | 166,652 | 166,652 | 0.90 | |||||||||
| October 1, 2012 | 10,000 | 10,000 | 2.76 | |||||||||
| August 1, 2012 | 30,000 | 30,000 | 2.88 | |||||||||
| September 1, 2012 | 12,500 | 12,500 | 2.92 | |||||||||
| December 14, 2012 | 216,875 | 216,875 | 2.96 | |||||||||
| December 30, 2010 | 433,248 | 433,248 | 2.97 | |||||||||
| November 1, 2012 | 55,000 | 55,000 | 3.12 | |||||||||
| February 21, 2012 | 50,000 | 50,000 | 3.68 | |||||||||
| December 14, 2011 | 291,250 | 291,250 | 4.72 | |||||||||
| February 1, 2013 | 31,250 | 15,625 | 5.84 | |||||||||
| June 23, 2014 | 25,000 | - | 6.18 | |||||||||
| October 1, 2013 | 50,000 | 25,000 | 6.72 | |||||||||
| June 15, 2013 | 37,500 | 18,750 | 6.84 | |||||||||
| May 5, 2014 | 12,500 | - | 7.05 | |||||||||
| October 28, 2013 | 12,500 | 6,250 | 8.60 | |||||||||
| December 13, 2013 | 441,875 | 220,938 | 8.68 | |||||||||
| September 23, 2013 | 7,500 | 3,750 | 9.16 | |||||||||
| October 1, 2013 | 7,500 | 3,750 | 9.28 | |||||||||
| November 14, 2013 | 50,000 | 25,000 | 9.56 | |||||||||
| Totals | 1,991,150 | 1,584,588 | ||||||||||
| F-23 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
The options outstanding as of December 31, 2014 and December 31, 2013 have an intrinsic value of $0 and $4.12 per share and an aggregate intrinsic value of approximately $0 and $7.9 million, respectively.
Shares Reserved for Future Issuance
As of December 31, 2014 and December 31, 2013, the Company had reserved 1,991,150 and 1,926,275 shares, respectively, for future issuance upon exercise of outstanding options.
The Company recognized stock-based compensation expense associated with its outstanding stock options of approximately $1.8 million, $1.2 million and $822,000 for the years ended December 31, 2014, 2013 and 2012, respectively.
| 15. | Income Taxes |
The Company recognized income tax benefit of approximately $5.3 million and $1.2 million for the years ended December 31, 2014 and 2012, respectively, and income tax expense of approximately $1.8 million for the year ended December 31, 2013. Income tax expense (benefit) for the years ended December 31, 2014, 2013 and 2012 consisted of the following (in thousands):
| 2014 | 2013 | 2012 | ||||||||||
| Current income tax expense (benefit): | ||||||||||||
| Domestic | $ | 16 | $ | (17 | ) | $ | (302 | ) | ||||
| Foreign | - | (77 | ) | (32 | ) | |||||||
| Total current income tax expense (benefit) | 16 | (94 | ) | (334 | ) | |||||||
| Deferred income tax expense (benefit): | ||||||||||||
| Domestic | $ | (40,424 | ) | $ | 1,863 | $ | 349 | |||||
| Foreign | 2,891 | (636) | (3,421 | ) | ||||||||
| Change in valuation allowance | 32,237 | 636 | 2,166 | |||||||||
| Total deferred income tax expense (benefit) | (5,296 | ) | 1,863 | (906 | ) | |||||||
| Total income tax expense (benefit) | $ | (5,280 | ) | $ | 1,769 | $ | (1,240 | ) | ||||
Significant components of the Company’s deferred income tax assets and liabilities at December 31, 2014 and 2013 are as follows (in thousands):
| 2014 | 2013 | |||||||
| Deferred tax assets: | ||||||||
| Foreign tax credits | $ | 52 | $ | 52 | ||||
| Unrealized hedging loss | 488 | 301 | ||||||
| Asset retirement obligations | 534 | 308 | ||||||
| Net operating losses – domestic | 18,900 | 5,688 | ||||||
| Net operating losses – foreign | - | 864 | ||||||
| Domestic fixed assets | 14,848 | - | ||||||
| Foreign fixed assets | - | 1,937 | ||||||
| Stock options | 1,881 | 1,214 | ||||||
| Marketable securities | - | 48 | ||||||
| Other | 17 | 160 | ||||||
| Total deferred tax assets | 36,720 | 10,572 | ||||||
| Valuation allowance | (35,038 | ) | (2,858 | ) | ||||
| Net deferred income tax assets | $ | 1,682 | $ | 7,714 | ||||
| F-24 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 2014 | 2013 | |||||||
| Deferred tax liabilities: | ||||||||
| Investment in foreign subsidiary | $ | - | 321 | |||||
| Domestic fixed assets | - | 12,779 | ||||||
| Asset retirement obligations | 491 | - | ||||||
| Other | 1,191 | - | ||||||
| Deferred tax liabilities | $ | 1,682 | $ | 13,100 | ||||
| Net deferred tax liabilities | $ | - | $ | 5,386 | ||||
A reconciliation between the amount of income tax expense for the years ended December 31, 2014, 2013 and 2012, determined by applying the appropriate applicable statutory income tax rates, is as follows (in thousands):
| 2014 | 2013 | 2012 | ||||||||||
| US Statutory tax expense (benefit) | $ | (33,149 | ) | $ | 1,144 | $ | (3,581 | ) | ||||
| State income taxes, net of federal expense (benefit) | (2,508 | ) | 96 | (242 | ) | |||||||
| Foreign taxes paid | 6 | 12 | - | |||||||||
| Permanent differences | 8 | 11 | 8 | |||||||||
| Change in valuation allowance | 32,228 | 641 | 2,166 | |||||||||
| True-up of prior year amounts | 657 | 244 | (537 | ) | ||||||||
| Foreign operations | (2,437 | ) | (236 | ) | 909 | |||||||
| Rate change | (92 | ) | (143 | ) | 39 | |||||||
| Other | 7 | - | (2 | ) | ||||||||
| Net income tax expense (benefit) | $ | (5,280 | ) | $ | 1,769 | $ | (1,240 | ) | ||||
| Effective tax rate | 5.4 | % | 52.6 | % | 11.8 | % | ||||||
As discussed in Note 4, the Company divested all of its foreign operations through the sale of its interests in the oil and gas properties held by its Canadian subsidiaries in July 2014 and subsequent dissolution of the two subsidiaries on October 31, 2014. For tax purposes, the Company recognized losses that include certain bad debt and worthless security deductions because it did not receive repayment for its investments in the Canadian subsidiaries.
Based upon the Company’s history of operating losses, the Company’s management has determined that it is more likely than not that the U.S. federal and state deferred tax assets as of December 31, 2014 will not be realized. Consequently, the Company has established a valuation allowance for its net U.S. federal and state deferred tax assets during the year ended December 31, 2014.
As of December 31, 2014, the Company has U.S. federal and aggregate state net operating loss carryforwards of approximately $49.9 million and $36.0 million, which expire at various dates through 2034. IRC Section 382 of the Internal Revenue Code of 1986, as amended, provides an annual limitation on the utilization of net operating losses should the Company undergo an ownership change, as defined in IRC Section 382. The utilization of the estimated net operating losses may be limited due to changes in ownership. The possible limitations have not been determined as of December 31, 2014 since there would be no financial statement impact based on a full valuation allowance against the estimated net operating losses.
| F-25 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 16. | 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, 2014, 2013 and 2012 (in thousands, except per share data):
| 2014 | 2013 | 2012 | ||||||||||
| Net income (loss) | $ | (92,216 | ) | $ | 1,594 | $ | (9,292 | ) | ||||
| Weighted average number of common shares outstanding | 27,513 | 13,962 | 11,448 | |||||||||
| Incremental shares from the assumed exercise of dilutive stock options | - | 637 | - | |||||||||
| Diluted common shares outstanding | 27,513 | 14,599 | 11,448 | |||||||||
| Earnings (loss) per share – basic | $ | (3.35 | ) | $ | 0.11 | $ | (0.81 | ) | ||||
| Earnings (loss) per share – diluted | $ | (3.35 | ) | $ | 0.11 | $ | (0.81 | ) | ||||
Because the Company recognized a net loss for the years ended December 31, 2014 and 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 years ended December 31, 2014 and 2012 is approximately 322,000 and 469,000 shares, respectively.
| 17. | Related Party Transactions |
The Company routinely obtains legal services from a firm for whom one of its directors serves as a principal. Fees paid this firm approximated $56,000, $37,000 and $24,000 for the years ended December 31, 2014, 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 $84,000, $168,000 and $168,000 of consulting expenses from Synergy during each of the years ended December 31, 2014, 2013 and 2012, respectively. The Company terminated its agreement with Synergy effective June 30, 2014.
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. Royalties paid to the Company’s Chairman totaled approximately $472,000, $608,000 and $67,000 for the years ended December 31, 2014, 2013 and 2012, respectively. Royalties paid to the Company’s Chief Operating Officer totaled approximately $382,000, $540,000 and $52,000 for the years ended December 31, 2014, 2013 and 2012, respectively.
| 18. | Subsequent Events |
In January 2015, the Company sold its net revenue and working interests in certain non-operated wells to SM Energy. Cash proceeds received from the sale totaled approximately $9.5 million.
| F-26 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
The Company elected to defer the payment of approximately $9.8 million of interest due on its Bonds on March 2, 2015. The terms of the Bond Indenture provide for a 30-day cure period, during which the interest payment can be made without the late payment constituting an event of default. The Company intends to utilize the 30-day grace period to evaluate strategies for improving its liquidity.
| 19. | Going Concern |
As of December 31, 2014, the Company has a working capital deficit of approximately $13.6 million. The sharp decline in oil prices that occurred during the latter part of 2014 materially reduced the revenues that were generated from the sale of the Company’s oil and gas production volumes during that period which, in turn, negatively affected the Company’s year-end working capital balance. The potential for future oil prices to remain at their current price levels for an extended period of time raises substantial doubt regarding the Company’s ability to continue as a going concern. For purposes of this discussion, the term “substantial doubt” refers to concerns that a company may not be able to meet its obligations when they come due.
Should the prevailing oil prices as of December 31, 2014 remain in effect for an extended period of time, it is likely that the Company would need to pursue some form of asset sale, debt restructuring or capital raising effort in order to fund its operations and to service its existing debt during the next twelve months. The Company’s management is actively developing plans to improve its working capital position and/or to reduce its future debt service costs, through the aforementioned means, in order to remain a going concern for the foreseeable future. If the Company is unable to restructure its Bonds, obtain additional debt or equity financing or achieve adequate proceeds from the sale of assets, the Company may file a voluntary petition for reorganization relief under Chapter 11 of the Bankruptcy Code in order to provide additional time to identify an appropriate solution to its financial situation and to implement a plan of reorganization aimed at improving its capital structure.
| 20. | Supplemental Oil and Gas Information (Unaudited) |
During the years ended December 31, 2014, 2013 and 2012, the Company incurred the following costs associated with the acquisition, exploration and development of oil and gas properties (in thousands):
| 2014 | 2013 | 2012 | ||||||||||
| Acquisition costs | $ | 57,946 | $ | 62,860 | $ | 16,671 | ||||||
| Exploration costs | 53,651 | 32,053 | - | |||||||||
| Development costs | 60,711 | 28,543 | 27,914 | |||||||||
| Total costs | $ | 172,308 | $ | 123,456 | $ | 44,585 | ||||||
The net capitalized cost of the Company’s oil and gas properties, subject to amortization, as of December 31, 2014 and 2013 is summarized below (in thousands):
| 2014 | 2013 | |||||||
| Acquisition costs | $ | 147,477 | $ | 88,910 | ||||
| Exploration costs | - | - | ||||||
| Development costs | 196,774 | 93,696 | ||||||
| Impairments and sales | (82,001 | ) | (14,612 | ) | ||||
| Gross capitalized costs | 262,250 | 167,994 | ||||||
| Accumulated depletion | (35,332 | ) | (12,849 | ) | ||||
| Net capitalized costs | $ | 226,918 | $ | 155,145 | ||||
| F-27 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
The Company has owned 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 in both the United States and Canada. The Company sold its interests in its Canadian oil and gas properties in July 2014 (See Note 4). Pursuant to full-cost accounting rules, the Company maintained separate cost centers for it’s US and Canadian oil and gas properties and related costs. The proved reserves associated with the Company’s US cost center represents 100% and 99.5% of the Company’s total proved reserves, both on a volume and discounted, future cash flow (PV10) basis as of December 31, 2014 and 2013, respectively. Furthermore, revenues generated from the Company’s US oil and gas properties accounted for 99.4%, 97.1% and 82.0% of the Company’s total revenue for the years ended December 31, 2014, 2013 and 2012, respectively. Because the result of operations and proved reserves associated with the Company’s Canadian oil and gas operations 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 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.
| Oil | Gas | Total | ||||||||||
| (Barrels) | (Mcf) | (BOE) | ||||||||||
| For the year ended December 31, 2014: | ||||||||||||
| Proved reserves, beginning of year | 12,109 | 8,652 | 13,550 | |||||||||
| Revisions | (3,726 | ) | (2,377 | ) | (4,122 | ) | ||||||
| Extensions and discoveries | 1,064 | 640 | 1,171 | |||||||||
| Purchases of reserves in place | 1,051 | 948 | 1,209 | |||||||||
| Sale of reserves in place | (148 | ) | (1 | ) | (148 | ) | ||||||
| Production | (763 | ) | (42 | ) | (770 | ) | ||||||
| Proved reserves, end of year | 9,587 | 7,820 | 10,890 | |||||||||
| Proved developed reserves | 5,495 | 4,820 | 6,298 | |||||||||
| Proved undeveloped reserves | 4,092 | 3,000 | 4,592 | |||||||||
| Total proved reserves | 9,587 | 7,820 | 10,890 | |||||||||
| F-28 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
As a result of participating in 32 gross new wells, the Company converted approximately 1,713,000 barrels of oil and approximately 1,187,000 mcf of gas from proved undeveloped reserves to proved developed reserves during the year ended December 31, 2014. The Company incurred approximately $56.5 million of capitalized expenditures to drill these wells.
The decrease in the Company’s proved undeveloped reserves from December 31, 2013 to December 31, 2014 is primarily due to uncertainty regarding whether or not the Company will have sufficient capital to support its current development plan. The Company has historically utilized carry agreements (see Note 5) and farm-out agreements (see Note 6) to accelerate the drilling of its operated wells. The amount of proved undeveloped reserves that the Company is claiming as of December 31, 2014 have been determined based on the assumption that the Company will continue to utilize such arrangements in the future in order to continue its planned drilling activities. The Company’s has reduced its net revenue and working interests in the future wells that comprise its proved undeveloped reserves by 50% in consideration of the anticipated terms of such arrangements.
| Oil | Gas | Total | ||||||||||
| (Barrels) | (Mcf) | (BOE) | ||||||||||
| For the year ended December 31, 2013: | ||||||||||||
| Proved reserves, beginning of year | 5,398 | 2,139 | 5,754 | |||||||||
| Revisions | (1,614 | ) | 308 | (1,563 | ) | |||||||
| Extensions and discoveries | 7,412 | 5,334 | 8,301 | |||||||||
| Purchases of reserves in place | 1,411 | 899 | 1,561 | |||||||||
| Production | (498 | ) | (28 | ) | (503 | ) | ||||||
| Proved reserves, end of year | 12,109 | 8,652 | 13,550 | |||||||||
| Proved developed reserves | 4,207 | 3,047 | 4,714 | |||||||||
| Proved undeveloped reserves | 7,902 | 5,605 | 8,836 | |||||||||
| Total proved reserves | 12,109 | 8,652 | 13,550 | |||||||||
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 approximately $19.8 million of capitalized expenditures to drill these wells.
| Oil | Gas | Total | ||||||||||
| (Barrels) | (Mcf) | (BOE) | ||||||||||
| For the year ended December 31, 2012: | ||||||||||||
| Proved reserves, beginning of year | 1,511 | 417 | 1,581 | |||||||||
| Revisions | (687 | ) | (191 | ) | (719 | ) | ||||||
| Extensions and discoveries | 4,429 | 1,774 | 4,725 | |||||||||
| Purchases of reserves in place | 479 | 248 | 520 | |||||||||
| Sales of reserves in place | (200 | ) | (107 | ) | (218 | ) | ||||||
| Production | (134 | ) | (2 | ) | (135 | ) | ||||||
| Proved reserves, end of year | 5,398 | 2,139 | 5,754 | |||||||||
| Proved developed reserves | 2,388 | 1,074 | 2,566 | |||||||||
| Proved undeveloped reserves | 3,010 | 1,065 | 3,188 | |||||||||
| Total proved reserves | 5,398 | 2,139 | 5,754 | |||||||||
| F-29 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
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 approximately $2.9 million 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, 2014, 2013 and 2012, respectively.
Standardized Measure of Discounted Future Net Cash Flows (in thousands):
| 2014 | 2013 | 2012 | ||||||||||
| Future cash flows | $ | 829,316 | $ | 1,141,907 | $ | 448,623 | ||||||
| Future costs: | ||||||||||||
| Production costs | (273,430 | ) | (307,093 | ) | (99,411 | ) | ||||||
| Development costs | (109,102 | ) | (177,750 | ) | (50,693 | ) | ||||||
| Income taxes | (47,464 | ) | (184,362 | ) | (104,827 | ) | ||||||
| Future net cash flows | 399,320 | 472,702 | 193,692 | |||||||||
| Ten percent discount factor | (195,573 | ) | (250,648 | ) | (116,784 | ) | ||||||
| Standardized measure of discounted future net cash flows | $ | 203,747 | $ | 222,054 | $ | 76,908 | ||||||
The following table summarizes the changes in the Company’s standardized measure of discounted future net cash flows for the years ended December 31, 2014, 2013 and 2012 (in thousands):
| F-30 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| 2014 | 2013 | 2012 | ||||||||||
| Extensions and discoveries | $ | 35,491 | $ | 167,600 | $ | 84,276 | ||||||
| Net changes in sales prices and production costs | (54,609 | ) | 1,001 | (2,939 | ) | |||||||
| Oil and gas sales, net of production costs | (38,480 | ) | (31,530 | ) | (7,514 | ) | ||||||
| Change in estimated future development costs | 95,259 | (5,659 | ) | 12,376 | ||||||||
| Revision of quantity estimates | (136,988 | ) | (34,499 | ) | (22,267 | ) | ||||||
| Purchases of mineral interests | 42,855 | 35,496 | 12,777 | |||||||||
| Sales of mineral interests | (5,368 | ) | - | - | ||||||||
| Previously estimated development costs incurred in the current period | (58,895 | ) | 14,256 | 2,897 | ||||||||
| Changes in production rates, timing & other | 14,366 | 21,692 | 1,947 | |||||||||
| Changes in income taxes | 57,037 | (35,914 | ) | (33,864 | ) | |||||||
| Accretion of discount | 31,025 | 12,703 | 3,994 | |||||||||
| Net increase | (18,307 | ) | 145,146 | 51,683 | ||||||||
| Standardized measure of discounted future cash flows – beginning of the year | 222,054 | 76,908 | 25,225 | |||||||||
| Standardized measure of discounted future cash flows – end of the year | $ | 203,747 | $ | 222,054 | $ | 76,908 | ||||||
Assumed prices used to calculate future cash flows
| 2014 | 2013 | 2012 | ||||||||||
| Oil price per barrel | $ | 82.36 | $ | 90.63 | $ | 81.78 | ||||||
| Gas price per mcf | $ | 5.08 | $ | 5.15 | $ | 3.38 | ||||||
| 21. | Quarterly Financial Information (Unaudited) |
The Company’s quarterly financial information for the years ended December 31, 2014, 2013 and 2012 is as follows (in thousands, except for per-share data):
| For the Year Ended December 31, 2014 | ||||||||||||||||
| First | Second | Third | Fourth | |||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
| Oil and gas revenues | $ | 12,545 | $ | 16,463 | $ | 17,091 | $ | 14,450 | ||||||||
| Operating expenses | 9,306 | 12,570 | 13,885 | 100,652 | ||||||||||||
| Other income (expense) | (4,905 | ) | (9,896 | ) | (14,513 | ) | 7,682 | |||||||||
| Net income (loss) | (1,028 | ) | (3,900 | ) | (8,738 | ) | (78,550 | ) | ||||||||
| Basic earnings (loss) per share | (0.06 | ) | (0.13 | ) | (0.29 | ) | (2.58 | ) | ||||||||
| Diluted earnings (loss) per share | (0.06 | ) | (0.13 | ) | (0.29 | ) | (2.58 | ) | ||||||||
| Cash provided by operating activities | 7,384 | 1,850 | 11,353 | 6,027 | ||||||||||||
| Cash used for investing activities | (67,441 | ) | (29,731 | ) | (36,661 | ) | (29,034 | ) | ||||||||
| Cash provided by (used for) financing activities | 78,299 | - | 51,909 | (47 | ) | |||||||||||
| F-31 |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2014 and 2013 and
For Each of the Three Years in the Period Ended December 31, 2014
| For the Year Ended December 31, 2013 | ||||||||||||||||
| First | Second | Third | Fourth | |||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
| Oil and gas revenues | $ | 7,629 | $ | 10,370 | $ | 11,639 | $ | 13,501 | ||||||||
| Operating expenses | 5,756 | 6,330 | 7,391 | 11,298 | ||||||||||||
| Other income (expense) | (425 | ) | (210 | ) | (5,830 | ) | (2,536 | ) | ||||||||
| Net income (loss) | 355 | 2,637 | (936 | ) | (462 | ) | ||||||||||
| Basic earnings (loss) per share | 0.03 | 0.21 | (0.07 | ) | (0.03 | ) | ||||||||||
| Diluted earnings (loss) per share | 0.03 | 0.20 | (0.07 | ) | (0.03 | ) | ||||||||||
| Cash provided by operating activities | 10,484 | 3,377 | 11,390 | 5,160 | ||||||||||||
| Cash used for investing activities | (16,378 | ) | (2,903 | ) | (66,123 | ) | (55,888 | ) | ||||||||
| Cash provided by (used for) financing activities | 5,029 | (1,640 | ) | 56,706 | 63,580 | |||||||||||
| For the Year Ended December 31, 2012 | ||||||||||||||||
| First | Second | Third | Fourth | |||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
| Oil and gas revenues | $ | 1,226 | $ | 1,691 | $ | 2,875 | $ | 4,922 | ||||||||
| Operating expenses | 1,882 | 1,832 | 2,388 | 15,093 | ||||||||||||
| Other income (expense) | 21 | 12 | 19 | (103 | ) | |||||||||||
| Net income (loss) | (358 | ) | (147 | ) | 892 | (9,679 | ) | |||||||||
| Basic earnings (loss) per share | (0.01 | ) | (0.00 | ) | 0.02 | (0.21 | ) | |||||||||
| Diluted earnings (loss) per share | (0.01 | ) | (0.00 | ) | 0.02 | (0.21 | ) | |||||||||
| Cash provided by (used for) operating activities | 3,443 | 5,040 | 5,855 | (10,450 | ) | |||||||||||
| Cash provided by (used for) investing activities | (8,657 | ) | (2,038 | ) | 3,486 | (5,318 | ) | |||||||||
| Cash provided by financing activities | 145 | - | - | 15,400 | ||||||||||||
| F-32 |
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, 2014. Based on this evaluation, our Principal Executive Officer and Principal Financial Officer have 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, 2014, based on the control criteria established in a report entitled Internal Control — Integrated Framework—2013, issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, our management has concluded that our internal control over financial reporting was effective as of December 31, 2014 and no material weaknesses were discovered. Furthermore, our internal controls over financial reporting have been audited in conjunction with the audit of the financial statements included herein (See Item 8 of this document).
The effectiveness of internal control over financial reporting as of December 31, 2014 has been audited by Hein & Associates LLP, the independent registered public accounting firm that audited our financial statements included in this Annual Report.
Changes in Internal Control over Financial Reporting
During the fourth quarter of 2014, we did not implement any material changes to our internal controls over financial reporting.
Attestation Report of Hein & Associates LLP
Our independent public accounting firm, Hein & Associates LLP, has issued an attestation report on our internal control over financial reporting. This report immediately follows.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
American Eagle Energy Corporation
We have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), American Eagle Energy Corporation’s and subsidiaries’ internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 (the COSO criteria), and express an unqualified opinion on the effectiveness of American Eagle Energy Corporation’s internal control over financial reporting.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, American Eagle Energy Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.
/s/ Hein & Associates LLP
Denver, Colorado
March 30, 2015
| 44 |
There is no other information required to be disclosed during the fourth quarter of the fiscal year covered by this Annual Report.
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 | 63 | Director (Chairman of the Board) | ||
| Bradley M. Colby | 58 | President, Chief Executive Officer, Treasurer and Director | ||
| Thomas Lantz | 62 | Chief Operating Officer | ||
| Kirk A. Stingley | 48 | Chief Financial Officer | ||
| Laura E. Peterson | 30 | Secretary | ||
| John Anderson | 51 | Director | ||
| Paul E. Rumler | 61 | Director | ||
| James N. Whyte | 56 | Director | ||
| Bruce Poignant | 51 | Director |
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. We believe Mr. Findley’s qualifications to serve on our Board include his expertise in the energy field and his service as a director and an executive for several businesses.
| 45 |
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. We believe Mr. Colby’s qualifications to serve on our Board include his extensive understanding of the Company’s business and his education and experience in the energy industry.
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 hydraulic 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.
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.
Laura E. Peterson – Effective October 31, 2014, the Board of Directors named Laura Peterson, 30, as the Corporate Secretary, replacing Paul Rumler, who had held that position since October 22, 2007. Ms. Peterson has been AMZG’s in-house Corporate Attorney since May 5, 2014. Prior to joining us, Ms. Peterson was working as a contract attorney for the State of Colorado in its Office of the Alternate Defense Counsel. Ms. Peterson received a BA in Theology from Seattle Pacific University in 2007 and her JD from Seattle University School of Law in 2012. Ms. Peterson is a member of the Colorado Bar Association and the Denver Bar Association. Ms. Peterson is the daughter of Brad Colby, our President, CEO and Treasurer and one of our directors.
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:
| · | 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. |
| 46 |
| · | 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. |
Paul E. Rumler – Mr. Rumler was appointed as one of our directors on July 26, 2007, and was our corporate Secretary between October 22, 2007 and October 31, 2014.. 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. Rumler’s qualifications to serve on our Board include his experience with corporate legal matters and his years of leadership with the Company.
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. We believe Mr. Whyte’s qualifications to serve on our Board include his experience in senior management positions and his extensive knowledge base related to human resources and risk management activities.
Bruce Poignant – Mr. Poignant has served in a variety of positions at the New York Stock Exchange (the “NYSE”), most recently, through August 2014, as Managing Director of the NYSE’s Capital Markets Group. Prior to the NYSE’s 2008 acquisition of the American Stock Exchange (the “Amex”), Mr. Poignant served, among other positions, as a Vice President of the Amex. Since leaving the NYSE, he has been a senior consultant to Donohoe Advisory Associates LLC, principally focused on assisting reporting issuers with the listing processes for a primary stock exchange. During more than 20 years at the NYSE and Amex, Mr. Poignant worked with listed and prospectively listed companies with regulatory and compliance issues, including their ongoing disclosure compliance and corporate governance issues, as well as assisting numerous companies, both public and private, with their IPO readiness and navigation through the exchange’s original listing process. Working closely with the regulatory arms of the NYSE and, before that, the Amex, Mr. Poignant would counsel companies on compliance with listing standards and the applicability of standards, processes, and timelines. Prior to his tenure with the NYSE and Amex, Mr. Poignant spent three years at Dean Witter Reynolds in its operations and retail units. Mr. Poignant received a BS in the School of Education & Human Services from Montclair State University in 1986 and a Masters in Public Administration from the Dyson School at Pace University in 2002. We believe Mr. Poignant’s qualifications to serve on our Board include his extensive experience with listed companies’ regulatory and compliance issues, including financial reporting and ongoing disclosure compliance and corporate governance issues.
There are no family relationships among any of our directors, executive officers, or key employees with the exception of Ms. Peterson and Mr. Colby as stated above.
| 47 |
Messrs. Anderson, Poignant, 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. For NYSE MKT purposes, Mr. Rumler’s prior service as our corporate secretary may preclude a determination that qualifies 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 committees until November 20, 2015 (two years from the date of our listing). That exemption requires us to disclose that our board of directors determined that our best interests and those of our stockholders require Mr. Rumler’s membership on the Compensation Committee and Nominating and Corporate Governance Committee.
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 12 formal meetings during the year ended December 31, 2014, at which a quorum of 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.
Each of our Directors was duly elected at our annual general meeting of shareholders, which was held on December 5, 2014. 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. Additionally, we contracted with Lighthouse Services to provide a whistleblower hotline. Employees can report potentially wrongful behavior at 844-990-0002.
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, Poignant, and Whyte, each of which 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. Anderson 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. Anderson’s biography is available on page 46. The charter of the Audit Committee may be found on our website (www.americaneagleenergy.com).
Compensation Committee
Our Compensation Committee is comprised of Messrs. Anderson, Rumler, and Whyte. 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. Whyte as the Compensation Committee’s Chairman. Mr. Whyte’s biography is available on page 47. The charter of the Compensation Committee may be found on our website (www.americaneagleenergy.com).
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As noted in his biography above, Mr. Rumler was our corporate secretary until October 31, 2014 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 prior service as our corporate secretary may preclude a determination that he qualifies 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 of directors 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. The Compensation Committee held one meeting during 2014.
Nominating and Corporate Governance Committee
Our Nominating and Corporate Governance Committee is comprised of Messrs. Anderson, Rumler and Poignant. 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 was our corporate secretary until October 31, 2014 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 prior service as our corporate secretary may preclude a determination that he qualifies 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 the Nominating and Corporate Governance Committee during such two-year period. The Nominating and Corporate Governance Committee did not hold any meetings during 2014.
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
No person who served as a member of the Compensation Committee during fiscal year 2014 was a current or former officer or employee of the Company. As noted above, Mr. Rumler did serve as our corporate secretary until October 31, 2014. None of the current members of our board of directors engaged in certain transactions with us as required to be disclosed under Item 404 of Regulation S-K. Additionally, there were no compensation committee “interlocks” during fiscal year 2014, which generally means that none of our executive officers served as a director or member of the compensation committee of another entity which had an executive officer serving as a director or member of our compensation committee.
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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, 2014, or with respect to such fiscal year, all Section 16(a) filing requirements were met with the exception of Mr. Colby, who was delinquent in the reporting of one transaction in fiscal year 2014 on Form 4. Mr. Colby failed to timely file a Form 4 to report the purchase of 3,500 shares of our common stock at a price of $6.92 per share on January 14, 2014.
Board Leadership Structure
Our board of directors does not have a formal policy on whether the roles of Chief Executive Officer and Chairman of the board should be separate. Our board of directors reviewed our current board leadership structure in light of the composition of the board, our size, the nature and stage of our business, our stockholder base and other relevant factors. Under the current board leadership structure, the position of Chairman of the board and Chief Executive Officer are two separate and distinct positions, with Mr. Colby currently serving as our President and Chief Executive Officer and Mr. Findley serving as our Chairman of the board of directors. Our board of directors is of the view that this board leadership structure is appropriate for us and our stockholders. Our board of directors expects to review its leadership structure periodically to ensure that it continues to meet our needs.
The Board’s Role in Risk Oversight
Our board of directors oversees the risk management of the Company. The full board of directors, as supplemented by the appropriate board committee in the case of risks that are overseen by a particular committee, reviews information provided by management in order for our board of directors to oversee risk identification, risk management, and risk mitigation strategies. Our board committees assist the full board of directors’ oversight of our material risks by focusing on risks related to the particular area of concentration of the relevant committee. For example, our Compensation Committee oversees risks related to our executive compensation plans and arrangements; our Audit Committee oversees the financial reporting and control risks; and our Nominating and Corporate Governance Committee oversees risks associated with the independence of our Board and potential conflicts of interest. Each committee reports on these discussions of the applicable relevant risks to our full board of directors during the committee reports portion of each board meeting, as appropriate. Our full board incorporates the insight provided by these reports into its overall risk management analysis.
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.
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Item 11. Executive Compensation.
Compensation Committee Report
The Compensation Committee has reviewed the Compensation Discussion and Analysis and discussed that analysis with management. Based on its review and discussion with management, the Compensation Committee recommended to our board of directors that the Compensation Discussion and Analysis be included in our Form 10-K for the year ended December 31, 2014.
The information in this report shall not be considered “soliciting material,” or to be “filed” with the Securities and Exchange Commission nor shall this information be incorporated by reference into any previous or future filings under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we incorporated it by specific reference.
| THE COMPENSATION COMMITTEE | |
| James Whyte (Chairman) | |
| John Anderson | |
| Paul Rumler |
Compensation Discussion and Analysis
Compensation Philosophy and Objectives
Our compensation policy is designed to attract and retain qualified key executive officers critical to our achievement of reaching and maintaining profitability and positive cash flow, and subsequently our growth and long-term success. To attract, retain, and motivate the executives officers required to accomplish our business strategy, the Compensation Committee establishes our executive compensation policies and oversees our executive compensation practices.
The Compensation Committee believes that the most effective executive compensation program is one that is designed to reward the achievement of our specific annual, short-term and long-term goals, and which aligns executives’ interests with those of the stockholders by rewarding performance that meets or exceeds established goals, with the ultimate objective of improving stockholder value.
It is the objective of the Compensation Committee to have a portion of each executive officer’s compensation contingent upon our performance as well as upon the individual’s personal performance. Accordingly, each executive officer’s compensation package is comprised of two elements: (i) base salary, which reflects individual performance and expertise and (ii) bonus and long-term equity incentive awards, which are tied to the achievement of certain performance goals that the Compensation Committee establishes from time to time. Based on the foregoing objectives, the Compensation Committee has structured compensation of our executive officers to achieve the business goals set by us and reward the executive officers for achieving such goals.
The Compensation Committee also evaluates our compensation program to ensure that we maintain the ability to attract and retain superior employees in key positions and that compensation provided to key employees remains competitive relative to the compensation paid to similarly situated executive officers. In its evaluation, the Compensation Committee reviews data on prevailing compensation practices of comparable companies in our peer group with whom we compete for executive talent, and evaluating such information in connection with corporate goals and compensation practices. The peer group consists of the following companies: Barnwell Industries, BPZ Resources, Dune Energy Inc., Emerald Oil, Fieldpoint Petroleum Corporation, FX Energy, Inc., Miller Energy Resources, Postrock Energy Corporation, Saratoga Resources, Inc., Synergy Resources, US Energy, and Warren Resources, Inc.
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Setting Executive Compensation
In making compensation decisions, the Compensation Committee relies on the following:
| · | the annual reviews made by the Chief Executive Officer with respect to the performance of each of our other executive officers; |
| · | the annual review conducted by the Compensation Committee with respect to the performance of the Chief Executive Officer; |
| · | compensation paid to executive officers of companies in our peer group; and |
| · | our annual performance with respect to our short-term and long-term strategic plan. |
There is no pre-established policy or target for the allocation between either cash and non-cash or short-term and long-term incentive compensation. Rather, the Compensation Committee annually reviews information to determine the appropriate level and mix of incentive compensation when determining our executive compensation plan.
Based on these factors, the Compensation Committee makes compensation decisions, including salary adjustments, annual bonus awards, and long-term equity incentive awards for our executive officers.
2014 Executive Compensation Components.
For the year ended December 31, 2014, the principal components of compensation for executive officers were: (i) base salary; and (ii) bonus and long-term equity incentive awards.
Base Salary. Base salaries are determined for each executive officer based on his or her individual qualifications and relevant experience, the strategic goals which he or she was responsible for, the compensation levels at companies in our peer group, and other incentives necessary to attract and retain qualified management. Salary levels are reviewed annually as part of our performance review process as well as upon a promotion or other change in job responsibility. Merit based increases to base salaries are based on the annual reviews conducted by the Chief Executive Officer, for all executive officers other than the Chief Executive Officer, the annual review conducted by the Compensation Committee with respect to the Chief Executive Officer and the Compensation Committee’s assessment of each individual executive’s performance. Our named executive officers received merit based pay increases to base salaries in fiscal year 2014 based on 2013 financial performance. No pay increases have been granted for fiscal year 2015.
Bonuses and Long-Term Equity Incentive Awards. We provide executive officers and other key employees with incentive compensation to incentivize and reward them for high performance and achievement of certain Company goals. The bonus program is designed to reward our executive officers for achieving certain financial objections tied to growth and profitability set each year by the Compensation Committee. The long-term equity incentive awards are designed to reward executive officers for achieving strategic milestones, as well as for retaining executive officers and other key employees.
Cash bonuses are periodically award to our employees and to members of our management team. Such bonuses are discretionary in nature, and are based primarily on subjective criteria, such as overall company performance, both financial and operational, successful completion or implementation of process improvement goals, and individual performance merit. On occasion, we have paid small, sign-on bonuses to new employees as part of the hiring process. The dollar value of cash bonuses, other than sign-on bonuses, is determined by our Chief Executive Officer and submitted to the Compensation Committee for discussion and consideration. Based on the Company’s financial performance for the year ended December 31, 2014, we declined to pay any performance or merit based bonuses during the year ended December 31, 2014. Sign-on bonuses awarded during the year ended December 31, 2014 totaled $10,000.
Long-Term Equity Incentive Awards. The Compensation Committee has the latitude to award our executive officers, or other key employees, stock options. Stock options are awarded under the 2013 Equity Incentive Plan. In granting these awards, the Compensation Committee may establish any conditions or restrictions it deems appropriate. Options are awarded at the closing price of the Company’s stock on the date of the grant as determined by the NYSE MKT.
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For the year ended December 31, 2014, the Compensation Committee granted stock options to the executive officers as disclosed in the Narrative Discussion of Summary Compensation section below. The options were granted in connection with the hiring of two employees and the election of one new member to our board of directors.
Retirement Benefits. We do not currently offer any retirement benefits.
Executive Compensation and Risk. Although a substantial portion of the compensation paid to our executive officers is performance-based, we believe our executive compensation programs do not encourage excessive and unnecessary risk-taking by our executive officers because these programs are designed to encourage our executive officers to remain focused on both the short-term and long-term operational and financial goals of the Company. We achieve this balance through a combination of elements in our overall compensation plans, including: elements that reward different aspects of short-term and long-term performance; incentive compensation that rewards performance on a variety of different measures; and cash awards and stock option awards, to encourage alignment with the interests of stockholders.
Summary Compensation Table
The following table presents information concerning compensation paid to our Chief Executive Officer and our other executive officers for the years ended December 31, 2014, 2013, and 2012.
| 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 | 2014 | 350,000 | — | — | — | — | — | — | 350,000 | |||||||||||||||||||||||||||
| President, CEO, | 2013 | 252,000 | 400,000 | — | 325,650 | — | — | — | 977,650 | |||||||||||||||||||||||||||
| and Treasurer | 2012 | 204,000 | 100,000 | — | 100,395 | — | — | — | 404,395 | |||||||||||||||||||||||||||
| Thomas Lantz | 2014 | 300,000 | — | — | — | — | — | — | 300,000 | |||||||||||||||||||||||||||
| Chief Operating | 2013 | 252,000 | 100,000 | — | 244,238 | — | — | — | 596,238 | |||||||||||||||||||||||||||
| Officer | 2012 | 204,000 | 100,000 | — | 44,620 | — | — | — | 348,620 | |||||||||||||||||||||||||||
| Kirk Stingley | 2014 | 185,000 | — | — | — | — | — | — | 185,000 | |||||||||||||||||||||||||||
| Chief Financial | 2013 | 165,000 | 40,000 | — | 97,695 | — | — | — | 302,695 | |||||||||||||||||||||||||||
| Officer | 2012 | 150,000 | 30,000 | 22,310 | — | — | — | 202,310 | ||||||||||||||||||||||||||||
| Richard Pershall | 2014 | 240,000 | 10,000 | — | — | — | — | — | 250,000 | |||||||||||||||||||||||||||
| Operations | 2013 | 207,000 | 50,000 | — | 86,000 | — | — | — | 343,000 | |||||||||||||||||||||||||||
| Manager | 2012 | 180,000 | 45,000 | — | 22,310 | — | — | — | 247,310 | |||||||||||||||||||||||||||
| Steve Dillé | 2014 | 200,000 | — | — | — | — | — | — | 200,000 | |||||||||||||||||||||||||||
| Land Manager | 2013 | 165,000 | 50,000 | — | 81,413 | — | — | — | 296,413 | |||||||||||||||||||||||||||
| 2012 | 27,500 | — | — | 103,775 | — | — | — | 131,275 | ||||||||||||||||||||||||||||
| Marty Beskow | 2014 | 200,000 | — | — | — | — | — | — | 200,000 | |||||||||||||||||||||||||||
| Vice President of | 2013 | 48,750 | 160,000 | — | 252,960 | — | — | — | 461,710 | |||||||||||||||||||||||||||
| Capital Markets (2) | 2012 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
| Laura Peterson Corporate Attorney | 2014 | 75,000 | — | 12,500 | — | — | — | 87,500 | ||||||||||||||||||||||||||||
| Corporate Secretary (3) | ||||||||||||||||||||||||||||||||||||
| (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 2014 and 2013 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 14 (Equity Transactions – Stock Options) to our Consolidated Financial Statements, which is included in Item 8 of this document (see page F-22 ). |
| (2) | Additional compensation disclosures are not available for Mr. Beskow as she was hired in October of 2013. |
| (3) | Additional compensation disclosures are not available for Ms. Peterson as she was hired in May of 2014. |
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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 | ||||
| Richard Pershall | $250,000 per year | 3 Years | 04/30/2016 | ||||
| Steve Dille | $200,000 per year | 2 Years | 04/30/2015 | ||||
| Marty Beskow | $200,000 per year | 2 Years | 10/31/2015 |
Bonus Awards and Stock Option Grants to Named Executive Officers
In November 2012, as part of its review of the compensation program for executive officers, the Compensation Committee reviewed our year-to-date performance, particularly with respect to our drilling programs and activities. The Compensation Committee noted that we dramatically improved the speed, efficiency, and cost effectiveness of our drilling activities and that our frac designs showed consistent improvement. This aggressive drilling program and participation in outside-operated wells led to a significant increase in our oil production since December 2011, and led to a significant increase in our PDP reserves. The Compensation Committee also noted our success in building an internal infrastructure sufficient to accommodate the then current activities and contemplated future growth.
In light of the foregoing, the Compensation Committee approved certain discretionary bonuses and grants of stock options for our named executive officers. We paid bonuses in the total aggregate amount of $275,000 to our named executive officers. We granted we granted five-year options to purchase 162,500 shares of our common stock to named executive officers. The per-share exercise prices ranged from $0.74 to $0.78. 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.
In November 2013, as part of its review of the compensation program for executive officers, the Compensation Committee reviewed a wide variety of our performance metrics, including a large year-over-year increase in our BOPD, BOEPD, proved reserve PV-10 value, oil and gas revenues, EBITDA, the price per share and market capitalization, and substantial year-over-year improvements in costs and expenses per BOE and general and administrative expenses per BOE. The Compensation Committee also reviewed qualitative factors and certain milestones we reached during 2013, such as the closing of a credit facility, the closing of the first tranche of an acquisition, successful equity financing, additions to human resources, and our listing on the NYSE MKT. The Compensation Committee also reviewed the working capital deficits we incurred during 2013. Finally, the Compensation Committee evaluated the expectations for 2014.
In light of the foregoing, the Compensation Committee approved discretionary bonuses and grants of stock options for our named executive officers. We paid bonuses in the total aggregate amount of $800,000 to our named executive officers. We granted five-year options to purchase 248,750 shares of our common stock to our named executive officers. The per-share exercise prices ranged from $1.68 to $2.17. 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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In December 2014, as part of its review of the compensation program for executive officers, the Compensation Committee deferred to management’s recommendations that there be no change to compensation levels nor any bonuses paid. We granted a five-year option to purchase 12,500 shares of our common stock to our named executive officers. The per-share exercise price is $7.05. Fifty percent (50%) of the stock option vests 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 an officer and employee through such dates. The exercise price at which this option was issued was equal to the average closing price of our common stock for the 5-day period preceding the grant date.
In 2014, the Compensation Committee also extended the expiration date from October 30, 2014 to October 30, 2019 for options to purchase 128,195 shares of our common stock granted to Mr. Colby in 2009.
Potential Payments upon Termination of Employment or a Change of Control
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.
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Grants of Plan-Based Awards 2014
The following table provides information about options granted to Ms. Peterson during fiscal year 2014. None of our other named executive officers were granted options during fiscal year 2014.
| Name | Grant Date | Option Awards: Number of Securities Underlying Options (#) | Exercise or Base Price of Option Awards ($/sh) | Grant Date Fair Value of Stock and Option Awards ($) (1) | ||||||||||
| Laura Peterson | 05/05/2014 | 12,500 | $ | 7.05 | $ | 44,160 | ||||||||
(1) These amounts represent the aggregate grant date fair value of these awards computed in accordance with FASB ASC Topic 718 assuming no forfeitures.
The option award granted to Ms. Peterson vests over a two year period, with 50% vesting on the first anniversary of the grant date and the remaining 50% vesting on the second anniversary of the grant date.
Outstanding Equity Awards at 2014 Fiscal Year-End
As of December 31, 2014, the following stock options were outstanding and held by our named executive officers:
| Name | Number of Securities Underlying Unexercised Options Exercisable |
Number of Securities Underlying Unexercised Options Unexercisable |
Option Exercise Price |
Option Expiration Date |
||||||||||||
| Bradley M. Colby | 128,195 | (1) | - | $ | 0.90 | 10/29/2019 | ||||||||||
| 37,500 | (6) | 37,500 | $ | 8.68 | 12/12/2018 | |||||||||||
| 56,250 | (4) | - | $ | 2.96 | 12/31/2017 | |||||||||||
| 36,104 | (2) | - | $ | 2.97 | 12/29/2015 | |||||||||||
| Thomas G. Lantz | 28,125 | (6) | 28,125 | $ | 8.68 | 12/12/2018 | ||||||||||
| 25,000 | (4) | - | $ | 2.96 | 12/13/2017 | |||||||||||
| 37,500 | (2) | - | $ | 2.97 | 12/29/2015 | |||||||||||
| Kirk A. Stingley | 11,250 | (6) | 11,250 | $ | 8.68 | 12/12/2018 | ||||||||||
| 12,500 | (4) | - | $ | 2.96 | 12/13/2017 | |||||||||||
| 37,500 | (3) | - | $ | 4.72 | 12/13/2016 | |||||||||||
| Richard Pershall | 10,000 | (6) | 10,000 | $ | 8.68 | 12/12/2018 | ||||||||||
| 12,500 | (4) | - | $ | 2.96 | 12/13/2017 | |||||||||||
| 56,250 | (3) | - | $ | 4.72 | 12/13/2016 | |||||||||||
| Marty Beskow | 3,125 | (6) | 3,125 | $ | 8.68 | 12/12/2018 | ||||||||||
| 25,000 | (5) | 25,000 | $ | 1.68 | 09/30/2018 | |||||||||||
| Steve Dille | 9,375 | (6) | 9,375 | $ | 8.68 | 12/12/2018 | ||||||||||
| 6,250 | (4) | - | $ | 2.96 | 12/13/2017 | |||||||||||
| 50,000 | (7) | - | $ | 0.78 | 10/31/2017 | |||||||||||
| Laura Peterson | - | 12,500 | $ | 7.05 | 05/05/2019 | |||||||||||
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| (1) | Fifty percent of the options granted on October 30, 2009 vested on October 30, 2010, and 50% of such options vested on October 30, 2011. In October 2014, the Company’s board of directors approved the modification of the terms of these options to extend the life of the options by an additional five years. |
| (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 vested on December 14, 2014. |
| (5) | Fifty percent of the options granted on October 1, 2013 vested on October 1, 2014, and 50% of such options vest on October 1, 2015, in each event subject to the grantee’s continued service as a director or officer, as applicable, of the Company through such dates. |
| (6) | Fifty percent of the options granted on December 13, 2013 vested 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. |
| (7) | Fifty percent of the options granted on November 1, 2012 vested on November 1, 2013, and 50% of such options vest on November 1, 2014, in each event subject to the grantee’s continued service as a director or officer, as applicable, of the Company through such dates. |
Option Exercises and Stock Vested
No shares were acquired by any of our named executive officers during the year ended December 31, 2014 through stock option exercises or vesting.
Pension Benefits
None.
Non-Qualified-Deferred Compensation
None.
Director Compensation
Director Summary Compensation Table
The following table sets forth the compensation granted to our directors for the fiscal year ended December 31, 2014.
| Name (1) | Fees Earned or Paid in Cash ($) | Stock Awards ($) | Option Awards ($) | Non-Equity Incentive Plan Compensation ($) | All Other Compensation ($) | Total ($) | ||||||||||||||||||
| Richard Findley | — | — | — | — | — | — | ||||||||||||||||||
| John Anderson | 36,000 | — | — | — | — | 36,000 | ||||||||||||||||||
| Paul E. Rumler | 43,000 | — | — | — | — | 43,000 | ||||||||||||||||||
| James N. Whyte | 37,000 | — | — | — | — | 37,000 | ||||||||||||||||||
| Bruce Poignant | 5,667 | — | — | — | — | 5,667 | ||||||||||||||||||
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(1) Bradley Colby, our President and Chief Executive Officer during fiscal year 2014, is not included in the table as he was our employee and thus received no compensation for his services as a director. The compensation received by Mr. Colby as our employee is shown in the Summary Compensation Table on page 53.
Narrative Disclosure of Summary Compensation Table of Directors
During fiscal year 2014, independent directors were paid $2,000 for each board or committee meeting that they attended in person, and $1,000 for each board or committee meeting in which they participated via telephone.. Additionally, independent directors were compensated in the amount of $5,000 for each full calendar quarter the independent director served on our board and its committees. We also reimburse our directors for reasonable expenses in connection with attendance at board meetings.
Further, our 2013 Equity Incentive Plan allows for the grant of awards to our directors. During fiscal year 2014, Mr. Poignant was granted 50,000 stock options consistent with the award given to other independent directors upon their nomination to the board of directors.
In fiscal year 2014, the Compensation Committee also extended the expiration date from October 30, 2014 to October 30, 2019 for options to purchase 38,458 shares of our common stock granted to Mr. Anderson in fiscal year 2009.
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 10, 2015 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 10, 2015. 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) | 991,469 | 3.23 | % | |||||
| Kirk A. Stingley (3) | 64,421 | * | ||||||
| Thomas Lantz (4) | 702,252 | 2.29 | % | |||||
| Richard Findley (5) | 737,379 | 2.41 | % | |||||
| John Anderson (6) | 284,486 | * | ||||||
| Paul E. Rumler (7) | 144,236 | * | ||||||
| James N. Whyte (8) | 31,250 | * | ||||||
| Bruce Poignant (9) | — | * | ||||||
| Laura Peterson (10) | 27,466 | * | ||||||
| All directors and executive officers as a group (8 persons) (11) | 2,982,959 | 9.80 | % | |||||
| Five Percent Beneficial Owners(11): | ||||||||
| Power Energy Partners (12) | 2,250,000 | 7.39 | % | |||||
| Wellington Management Group LLP (13) | 2,254,972 | 7.41 | % | |||||
| BlackRock, Inc. (14) | 1,804,573 | 5.9 | % | |||||
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* Less than 1%
| (1) | The applicable percentage ownership is based on 30,448,714 shares of common stock outstanding at March 10, 2015. The number of shares of common stock owned are those “beneficially owned” as determined under the rules of the Securities and Exchange Commission, including any shares of common stock as to which a person has sole or shared voting or investment power and any shares of common stock which the person has the right to acquire within 60 days through the exercise of any option, warrant or right. |
| (2) | Includes 629,955 shares owned by Mr. Colby and an aggregate of 103,446 shares owned by his spouse and their minor child. Also includes 258,048 shares underlying options that are exercisable within 60 days of March 10, 2015. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, Colorado 80120. |
| (3) | Includes 3,171 shares owned by Mr. Stingley and 61,250 shares underlying options that are exercisable within 60 days of March 10, 2015. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, Colorado 80120. |
| (4) | Includes 540,815 shares owned by Mr. Lantz and 161,437 shares underlying options that are exercisable within 60 days of March 10, 2015. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, Colorado 80120. |
| (5) | Includes 574,213 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 163,166 shares underlying options that are exercisable within 60 days of March 10, 2015. 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 82,208 shares underlying options that are exercisable within 60 days of March 10, 2015. The business address for this person is 52 Powell Street, Suite 200, Vancouver, British Columbia V6A 1E7. |
| (7) | Includes 47,790 shares owned by Mr. Rumler and 2,696 shares owned by Mr. Rumler’s child. Also includes 93,750 shares underlying options that are exercisable within 60 days of March 10, 2015. The business address for this person is 1777 South Harrison Street, Suite 1250, Denver, Colorado 80210. |
| (8) | Includes 31,250 shares underlying options that are exercisable within 60 days of March 10, 2015. The business address for this person is c/o Intrepid Potash, Inc., 707 17th Street, Suite 4200, Denver, Colorado 80202. |
| (9) | The business address for this person is 5 Benjamin Green Lane, Mahopac, New York 10541. |
| (10) | Includes 6,250 shares underlying options that are exercisable within 60 days of March 10, 2015. The business address for this person is 2549 W. Main Street, Suite 202, Littleton, CO 80120. |
| (11) | Includes all shares and options referenced in notes 2 through 10. |
| (11) | The following table sets forth, as of March 10, 2015, information with respect to persons who, to the Company’s knowledge, beneficially own more than five percent of the Company’s common stock. |
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| (12) | 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. |
| (13) | Steven M. Hoffman has voting and dispositive power over these shares. Mr. Hoffman disclaims beneficial ownership except to the extent of his pecuniary interests therein. The business address for this holder is 280 Congress Street, Boston, Massachusetts 02210. The Company obtained such information directly from the SEC website and disclaims any knowledge as to the accuracy thereof. |
| (14) | Chris Jones is the Chief Investment Officer and has voting and dispositive power over these shares. Mr. Jones disclaims beneficial ownership except to the extent of his pecuniary interests therein. The business address for this holder is 55 East 52nd Street, New York, NY 10022. The Company obtained such information directly from the SEC website and disclaims any knowledge as to the accuracy thereof |
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Related Party Transactions
The board of directors has not adopted a written policy for review of related party transactions. When we are contemplating entering into any transaction in which any related party would have any direct or indirect interest, regardless of the amount involved, the terms of such transaction must be presented to the full board of directors (other than any interested director) for approval. The discussion of the board of directors is documented in its minutes. A related party would include any executive officer, director, nominee, or any family member of the foregoing, or any beneficial owner of more than five percent owner of our common stock, or any family member of the foregoing.
The following information can also be found in Note 17 to our financial statements on F-26 page.
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 $84,000 and $168,000 of consulting fees from Synergy during each of the years ended December 31, 2014 and 2013, respectively. We terminated our contract with Synergy on June 30, 2014.
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 approximated $56,000 and $37,000 for the years ended December 31, 2014 and 2013, respectively.
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. Royalties paid to Mr. Findley approximated $472,000 and $608,000 for the years ended December 31, 2014 and 2013, 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. Royalties paid to Mr. Lantz approximated $382,000 and $540,000 for the years ended December 31, 2014 and 2013, respectively.
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Power Energy Partners Ltd.
In February 2013, we entered into a contract to sell 100% of our oil, gas and liquids production to Power Energy Partners, Ltd. (“Power Energy”) through 2015. In January 2014, Power Energy purchased 1,000,000 shares of our common stock at a 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.
Item 14. Principal Accountant Fees and Services.
Hein & Associates (“Hein”) audited our financial statements for the years ended December 31, 2014 and 2013 and provided preparation services for our 2013 and 2012 US federal and state tax returns. The aggregate fees billed for professional services by Hein for the years ended December 31, 2014 and 2013 were as follows:
| 2014 | 2013 | |||||||
| Audit Fees | $ | 402,923 | $ | 317,137 | ||||
| Audit Related Fees | 8,700 | 40,000 | ||||||
| Tax Fees | 25,550 | 34,100 | ||||||
| All Other Fees | — | — | ||||||
| Total | $ | 437,173 | $ | 391,237 | ||||
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.
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.) | |
| 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.) |
| 61 |
| 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. (Incorporated by reference to Exhibit 4.13 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.14 | Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Thomas G. Lantz. (Incorporated by reference to Exhibit 4.14 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.15 | Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Kirk A. Stingley. (Incorporated by reference to Exhibit 4.15 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.16 | Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Richard Findley. (Incorporated by reference to Exhibit 4.16 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.17 | Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.17 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.18 | Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.18 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 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 4.19 of our Current Report on Form 8-K filed February 21, 2012.) |
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| 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. (Incorporated by reference to Exhibit 4.21 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.22 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Bradley M. Colby. (Incorporated by reference to Exhibit 4.22 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.23 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Thomas G. Lantz. (Incorporated by reference to Exhibit 4.23 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.24 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Kirk A. Stingley. (Incorporated by reference to Exhibit 4.24 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.25 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Richard Findley. (Incorporated by reference to Exhibit 4.25 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.26 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.26 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.27 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.27 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.28 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Andrew P. Calerich. (Incorporated by reference to Exhibit 4.28 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 4.29 | Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and James N. Whyte. (Incorporated by reference to Exhibit 4.29 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 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.) | |
| 10.6a | 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.) | |
| 10.7 | 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.) |
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| 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.) | |
| 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. (Incorporated by reference to Exhibit 10.11 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 10.12 | Employment Agreement by and between the Registrant and Thomas G. Lantz, effective May 1, 2013. Amended and Restated Employment Agreement between American Eagle Energy Corporation and Thomas G. Lantz, dated January 1, 2014. (Incorporated by reference to Exhibit 10.12 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 10.13 | Employment Agreement by and between the Registrant and Kirk Stingley, effective May 1, 2013. (Incorporated by reference to Exhibit 10.13 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 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, dated August 12, 2013, by and among American Eagle Energy Corporation, AMZG, Inc. and USG Properties Bakken I, LLC. (Incorporated by reference to Exhibit 10.20 of our Quarterly Report on Form 10-Q filed August 19, 2013.) | |
| 10.18 | Farm-Out Agreement, dated August 12, 2013, by and among American Eagle Energy Corporation, AMZG, Inc. and USG Properties Bakken I, LLC. (Incorporated by reference to Exhibit 10.21 of our Quarterly Report on Form 10-Q, filed August 19, 2013.) | |
| 10.19 | Letter Agreement, dated March 21, 2014, by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC. (Incorporated by reference to Exhibit 10.19 of our Annual Report on Form 10-K filed March 28, 2014.) | |
| 10.19a | Amendment and Addendum to Letter Agreement, dated March 27, 2014, by and among American Eagle Energy Corporation and USG Properties Bakken I, LLC. (Incorporated by reference to Exhibit 10.19a of our Annual Report on Form 10-K filed March 28, 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. (Incorporated by reference to Exhibit 10.20a of our Quarterly Report on Form 10-Q filed November 6, 2014.) | |
| 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. (Incorporated by reference to Exhibit 10.20a of our Quarterly Report on Form 10-Q filed November 6, 2014.) | |
| 10.20c | Third Amendment to the Credit Agreement, dated July 21, 2014, by and among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.20c of our Quarterly Report on Form 10-Q filed August 4, 2014.) | |
| 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.) |
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| 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.) | |
| 10.27c | Lease Addendum, dated November 1, 2013, by and between American Eagle Energy Corporation and Oakley Ventures, LLC. | |
| 10.28 | Indenture, dated August 27, 2014, by and between American Eagle Energy Corporation and U.S. Bank National Association. (Incorporated by reference to Exhibit 10.28 of our Quarterly Report on Form 10-Q filed on November 6, 2014.) | |
| 10.29 | Purchase Agreement, dated August 13, 2014, by and between American Eagle Energy Corporation and GMP Securities L.P. (Incorporated by reference to Exhibit 10.29 of our Quarterly Report on Form 10-Q filed on November 6, 2014.) | |
| 10.30 | Registration Rights Agreement, dated August 27, 2014, by and among American Eagle Energy Corporation and GMP Securities L.P. (Incorporated by reference to Exhibit 10.30 of our Quarterly Report on Form 10-Q filed on November 6, 2014.) | |
| 10.31 | Credit Agreement, dated August 27, 2014, by and among American Eagle Energy Corporation, SunTrust Bank and SunTrust Robinson Humphrey, Inc. (Incorporated by reference to Exhibit 10.31 of our Quarterly Report on Form 10-Q filed on November 6, 2014.) | |
| 10.32 | Guarantee and Collateral Agreement, dated August 27, 2014, by and between American Eagle Energy Corporation, Grantors and SunTrust Bank. (Incorporated by reference to Exhibit 10.32 of our Quarterly Report on Form 10-Q filed on November 6, 2014.) | |
| 10.33 | Intercreditor Agreement, dated August 27, 2014, by and among American Eagle Energy Corporation, SunTrust Bank and U.S. Bank National Association. (Incorporated by reference to Exhibit 10.33 of our Quarterly Report on Form 10-Q filed on November 6, 2014.) | |
| 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.) |
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| 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.) | |
| 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. | |
| 23.1* | Consent of Ryder Scott Company LP. | |
| 23.2* | Consent of Independent Registered Public Accounting Firm | |
| 31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1* | Certification of Chief Executive Officer pursuant to 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 March 9, 2015. | |
| 101.INS* | XBRL Instance Document | |
| 101.SCH* | XBRL Taxonomy Schema | |
| 101.CAL* | XBRL Taxonomy Calculation Linkbase | |
| 101.DEF* | XBRL Taxonomy Definition Linkbase | |
| 101.LAB* | XBRL Taxonomy Label Linkbase | |
| 101.PRE* | XBRL Taxonomy Presentation Linkbase | |
* Filed herewith.
^ Portions omitted pursuant to a request for confidential treatment.
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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 31, 2015 | ||
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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 (Principal Executive Officer) |
March 31, 2015 | ||
| Bradley M. Colby | ||||
| /s/ KIRK A. STINGLEY | Chief Financial Officer (Principal Accounting Officer) |
March 31, 2015 | ||
| Kirk A. Stingley | ||||
| /s/ THOMAS LANTZ | Chief Operating Officer | March 31, 2015 | ||
| Thomas Lantz | ||||
| Corporate Attorney | March 31, 2015 | |||
| /s/ LAURA PETERSON | Corporate Secretary | |||
| Laura Peterson | ||||
| /s/ RICHARD PERSHALL | Operations Manager | March 31, 2015 | ||
| Richard Pershall | ||||
| /s/ STEVE DILLE | Land Manager | March 31, 2015 | ||
| Steve Dille | ||||
| /s/ MARTY BESKOW | Vice President of Capital Markets | March 31, 2015 | ||
| Marty Beskow | ||||
| /s/ RICHARD FINDLEY | Director (Chairman) | March 31, 2015 | ||
| Richard Findley | ||||
| /s/ JOHN ANDERSON | Director | March 31, 2015 | ||
| John Anderson | ||||
| /s/ BRUCE POIGNANT | Director | March 31, 2015 | ||
| Bruce Poignant | ||||
| /s/ PAUL E. RUMLER | Director | March 31, 2015 | ||
| Paul E. Rumler | ||||
| /s/ JAMES N. WHYTE | Director | March 31, 2015 | ||
| James N. Whyte |
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