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Randolf W. Katz direct dial: 714.966.8807 rwkatz@bakerlaw.com |
November 8, 2012
United States Securities and Exchange Commission
Division of Corporate Finance
100 F. Street, NE
Washington, DC 20549-7010
VIA EDGAR
| Attn: | Karl Hiller and Jenifer Gallagher |
| Re: | American Eagle Energy Corporation SEC Comment Letter Response |
Ladies and Gentlemen:
American Eagle Energy Corporation, a Nevada corporation (“American Eagle” or the “Company”), is pleased to respond to Staff’s comments in its July 27, 2012 and September 10, 2012 comment letters. The comments have been transcribed, with American Eagle’s responses immediately below. In respect of those responses that confirm the Company’s initial disclosure, references are made to the relevant page in the original 10-K filing. For those responses that expand the Company’s initial disclosure, references are made to the attached page numbers that contain the expanded disclosure.
July 27, 2012 Comments:
Form 10-K for the Fiscal Year ended December 31, 2011
General
| 1. | In your response to prior comment 1, you indicate that certain information that is required to be disclosed by Subpart 1200 of Regulation S-K is presented in the notes to your financial statements or within the third party engineering firm’s report. As an alternative to providing the information required by Subpart 1200 of Regulation S-K in the Properties section of your Form 10-K, you may include cross-references to other sections of the document. However, such references should identify the specific location of the required disclosures. Please revise your document to adhere to this guidance. |
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 2 |
Response
American Eagle has inserted language in the Properties section of its Amended Form 10-K for the year ended December 31, 2011 that refers the readers to Notes 7 and 15 to the Company’s financial statements as of and for the years ended December 31, 2011 and 2010. A copy of the proposed language is attached to this letter.
Properties, page 14
| 2. | We note you intend to present your reserve quantities by geographic location to comply with Item 1202(a) of Regulation S-K and FASB ASC 932-235-50-6. Please disclose your proved developed and proved undeveloped reserves by geographic location as of December 31, 2010 and December 31, 2011. |
Response
American Eagle has expanded its disclosure in Note 15 to its financial statements as of and for the years ended December 31, 2011 and 2010 to include a tabular presentation of proved developed and proved undeveloped reserves as of those dates. A copy of the expanded disclosure is attached to this letter.
| 3. | We note the reserve report includes information about the qualifications of the petroleum engineer of MHA Petroleum Consultants who is responsible for preparing the reserve estimates. To fully comply with Item 1202(a)(7) of Regulation S-K, please describe the internal controls you have in place to assist in the preparation of your reserve estimates and describe the qualifications of the technical person at your company who is responsible for reviewing the reserve estimates prepared by the third-party engineering firm which you disclose. |
Response
American Eagle has expanded its disclosure in Note 15 to its financial statements as of and for the years ended December 31, 2011 and 2010 to include a discussion of its internal controls over the completeness and accuracy of its estimated oil and gas reserves as of such dates. The Company’s operational team consists of the following individuals who, collectively, possess over 71 years of oil and gas exploration and production experience:
| Thomas Lantz | Chief Operations Officer | 35 years |
| Richard Pershall | Operations Manager | 33 years |
| Zach Swanson | Petroleum Engineer | 4 years |
The Company’s operational team performs detailed review procedures on the underlying data provided to the third-party engineering firm. Such procedures include a review of the average monthly price calculation and underlying pricing information, a review of the estimated future operating costs and capital expenditures for reasonableness, and a review of the individual wells included in the overall reserves estimate for completeness.
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 3 |
| 4. | To comply with Item 1203(b) of Regulation S-K, please present a schedule that rolls forward your proved undeveloped oil and gas reserves as of December 31, 2010 to December 31, 2011, quantifying material changes in the proved undeveloped reserves that occurred during the year, such as conversions to proved developed reserves. In addition, disclose the amount of any capital expenditures made during the year to convert proved undeveloped reserves to developed to comply with Item 1203(c) of Regulation S-K. |
Response
American Eagle provided a roll-forward table for total proved reserves in Note 15 to the financial statements as of and for the years ended December 31, 2011 and 2010. The Company has expanded its disclosure to include a separate roll-forward schedule for the proved undeveloped reserves for the year ended December 31, 2011.
The only proved undeveloped reserves claimed by the Company as of December 31, 2010 related to its Hardy Property. The Company has expanded its disclosure to include the amount of capital expenditures incurred to convert a portion of the Hardy proved undeveloped reserves to proved developed reserves during the year ended December 31, 2011.
| 5. | We note that in response to prior comment 1 you state that you did not have proved undeveloped reserves in individual fields or countries that remained undeveloped for five years or more. Please confirm if true that all fields containing proved undeveloped reserved are expected to be developed within five years, as this is a requirement for the reserves to remain classified as proved, based on the definition in Rule 4-10(a)(31) of Regulation S-X. |
Response
To clarify, American Eagle first acquired working interest in fields containing proved undeveloped reserves in 2010, when it acquired a majority working interest in the Hardy Property, located in southeastern Saskatchewan. The Company did not claim any proved undeveloped reserves prior to that time. American Eagle confirms that it intends to develop the fields containing its proved undeveloped reserves in the Hardy Property and has a development plan designed to do so within the next five years.
| 6. | We understand from your response to prior comment 1 that you believe the information required to be disclosed by Item 1208 of Regulation S-K has been presented within MD&A and the notes of your financial statements. However, we do not see that you have provided this information and you have not identified any specific pages where you believe it resides. Accordingly, you will need to revise your filing to present in a tabular format the total gross and net developed and undeveloped acreage by geographic area of your oil and gas properties. |
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 4 |
Response
Note 7 to the financial statements as of and for the years ended December 31, 2011 and 2010 contains narrative descriptions of American Eagle’s producing properties and exploratory prospects. The Company’s exploratory prospects are not yet developed and have not had any reserves, proved or otherwise, assigned to them. The narrative for each oil and gas property or prospect discloses the gross acreage held within the field, the number of leases related to the field, and the range of expiration dates for the Company’s existing leases on lands located within the property / prospect. However, in light of the SEC’s request, the Company has added a table in Item 2 of the Amended Form 10-K/A that includes the total gross and net developed and undeveloped acreage by geographic area of the Company’s oil and gas properties.
Financial Statements
Note 3 – Acquisition of American Eagle Energy Inc., Page F-16
| 7. | We are considering your response to prior comment 2 regarding your accounting for the merger with American Eagle Energy Inc. |
Response
American Eagle appreciates the attention that the Staff is giving to the accounting treatment applied to the transaction between Eternal Energy Corp. and American Eagle Energy Inc., and has responded to the specific comments received from the Staff on such transaction, as included in the SEC comment letter dated September 10, 2012 (see below).
Note 15 – Supplemental Oil and Gas Information (Unaudited), page F-34
| 8. | We note that you have proposed various revisions to your disclosures in response to prior comment 4. However, these should also include costs incurred for property acquisition, exploration and development activities by geographic location to comply with FASB ASC 932-235-50-19. In addition, you should present your results of operations for oil and gas producing activities in the level of detail prescribed by FASB ASC 932-235-50-23. |
Response
American Eagle disclosed the information required by ASC 932-235-50-19 relating to the Hardy Property, which represents 100% of the Company’s Canadian oil and gas properties, in Note 7 to the financial statements as of and for the years ended December 31, 2011 and 2010. However, the Company did not include a similar tabular presentation of acquisition, exploration, and development costs for its US cost center. The Company has expanded its footnote disclosure to include such information relative to its US oil and gas properties as of December 31, 2011 and 2010, and has revised the overall presentation of the information required by ASC 932-235-50-19 to present the information on a cost center basis more clearly.
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 5 |
| 9. | Please revise the disclosure on page 6 of your draft revisions to include the representation about prices utilized in estimating reserves that you provided in response to prior comment 6 if that representation is accurate. |
Response
American Eagle has revised its disclosure to state more clearly that an average of the monthly oil and gas prices realized by the Company during the year was applied to forecasted production rates in order to calculate estimated future cash flows from proved reserves.
September 10, 2012 Comments:
Form 10-K for the Fiscal Year ended December 31, 2011
General
| a. | We issued comments to you on the annual report and response letter referenced above on July 27, 2012. As of the date of this letter, these comments remain outstanding and unresolved. Please submit a written response to the comments in that letter and the additional comments in this letter on EDGAR without further delay. |
Response
American Eagle’s response to the comments included in letter received from the Staff, dated July 27, 2012, have been included with the Company’s response to the comments received on September 10, 2012, all of which are contained in this letter.
| b. | We have further considered your response to prior comment 2, regarding the merger of Eternal Energy Corp. and American Eagle Energy Inc., and your identification of the accounting acquirer. Please address the following points with respect to your application of FASB ASC 805-10-55-11 through 15. |
| · | Provide us with a narrative describing the background to the merger, identify all participants including the party who initiated the merger, and explain how it was determined that Eternal Energy would be the issuer. |
| · | Tell us whether there are any voting arrangements, options, warrants or convertible securities that would allow the former shareholders of Eternal Energy with their 20% voting interest in the consolidated entity to override the former shareholders of American Eagle Energy Inc. having an 80% voting interest. |
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 6 |
| · | Please explain the reasons you believe Mr. Colby’s 7.6% voting interest would be material to your analysis as it does not appear to represent a large minority voting interest in the consolidated company. |
| · | We understand that your board of directors consists of three previous members of Eternal Energy’s Corp.’s board of directors (although two are identified as independent), one previous member of AEE Inc.’s board of directors (who is now the chairman of the board) and one additional independent director. In other words, you now have two directors (one from each former company) who are not independent; and three directors who are independent. Please describe the manner by which your shareholders are able to change the composition of the board and clarify the nature of any alliances which compromises independence among any of the three directors whom you identify as independent. |
| · | Please submit further details about management within the consolidated entity, including a list of all individuals, their date of hire, and the number of hours each person works per week, an indication of whether they were previously with Eternal Energy Corp., American Eagle Energy Inc., or newly hired, and their title and description of responsibilities. |
| · | Tell us how these management positions or personnel within these positions may be changed, identify any persons who are able to make these decisions independently, and describe the level of authority and involvement in these types of decisions by the board of directors. |
| · | Please explain how you applied FASB ASC 805-10-55-12 in evaluating whether either combining entity would be viewed as paying a premium over the pre-combination fair value of the other entity. Submit your computations and explain how you determined the fair value of the equity interests of both companies prior to the combination. |
| · | Tell us how the relative size of both companies were computed and evaluated in applying FASB ASC 805-10-55-13. Please also indicate which company owned the properties which the combined companies intend to further develop, and which are expected to contribute materially to future results of operations. |
Response
Merger discussions between Eternal Energy Corp. (“Eternal”) and American Eagle Energy Inc. (“AEE Inc.”) were initiated by Eternal in February, 2011. Prior to that time, Eternal and AEE Inc. were equal working interest partners in the Hardy Property, for which Eternal, through its wholly-owned subsidiary, EERG Energy ULC, served as the operator. In addition, Eternal and AEE Inc. each held a 50% working interest in a number of undeveloped acreage positions, including the Spyglass and West Spyglass prospects. Eternal held working interests in a number of non-operated wells located within the Spyglass Property. AEE Inc. held smaller working interest positions in some, but not all, of these non-operated wells. The impetus for the proposed merger was the marrying together of similar assets holdings, working interest, and exploration and development concepts.
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 7 |
The participants in the merger included Eternal and AEE Inc. and their respective wholly-owned subsidiaries, EERG Energy ULC and AEE Canada Inc. Preliminary merger discussions were initiated by Brad Colby, Eternal’s President and Chief Operating Officer. Mr. Colby presented the idea to Richard Findley who, at the time, served as AEE Inc.’s President and sole director. Because Eternal initiated the merger discussion, and because Eternal’s stock historically traded more freely in the open market, it was determined that Eternal would be the entity that would issue stock in connection with the amalgamation.
Neither at the date of merger, nor any time subsequent, has Eternal or AEE Inc. had any voting arrangements, warrants or convertible securities outstanding. As of the date of merger, Eternal had 1,570,444 options to purchase shares of its common stock outstanding. The exercise of these options would not materially alter the voting relationship of legacy Eternal and AEE Inc. stockholders.
ASC 805-10-55 states that “Other pertinent facts and circumstances also shall be considered in identifying the acquirer in a business combination effected by exchanging equity interests, including the existence of alarge minority voting interest in the combined entity, if no other owner or organized group of owners has a significant voting interest.” ASC 805-10-55-12b further states that, “The acquirer usually is the combining entity whose single owner or organized group of owners holds thelargest minority voting interest in the combined entity.” Mr. Colby’s 7.6% voting interest represents the largest known block of shares owned by any individual or single entity, making him the largest known individual minority stockholder or organized group of stockholders. Thus, the guidance provided by ASC 805-10-55-12b supports the conclusion that Eternal was the accounting acquirer in the transaction.
The Staff’s understanding of the composition of American Eagle’s current board of directors is correct. However, despite their status as “independent” directors, the fact remains that three of the five current directors were directors of Eternal prior to the merger and only one of the five current directors was a director of AEE Inc. prior to the merger. The status of being an “independent” director merely relates to a minimal economic relationship between a director and a company. Thus, it is accurate to state that the legacy Eternal’s board membership maintains control over the post-merger board membership. Subject to each director’s determination to remain a director of the combined entity, the composition of the post-merger Board of Directors is locked for the first year pursuant to the terms of the Merger Agreement. In addition, there has been no turnover of the legacy directors on the Board, which suggests that the legacy Eternal Energy stockholders will continue to maintain control over the Board beyond the one-year period stipulated in the Merger Agreement.
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 8 |
American Eagle’s Nominating and Corporate Governance Committee is responsible for identifying, vetting, and recommending potential board candidates for nomination or appointment to American Eagle’s board of directors, based on specific membership criteria established by the board of directors. The Nominating and Corporate Governance Committee is also charged with periodically reviewing the size and responsibilities of the board of directors and recommending changes as it determines appropriate. The current membership of the Nominating and Corporate Governance Committee consists of the three independent directors, two of whom are legacy Eternal Energy board members.
The Company’s stockholders have the ability to nominate individuals to be considered for service on American Eagle’s board of directors. Such nominations, when made, are forwarded to the Company’s Nominating and Corporate Governance Committee for review and follow-up, as deemed appropriate.
As of the date of this letter, there are no known alliances that would compromise the integrity or the independence of the three independent board members.
A summary of the Company’s management team is attached to this letter as Exhibit A.
Colorado is an “at will” employment state. As such, employment may be terminated at any time by the employer or employee without cause, subject to the terms of any existing employment agreement. Prior to the merger, Mr. Colby and Mr. Stingley had entered into three-year and two-year employment agreements, respectively, with Eternal. These agreements were authorized by the Company’s board of directors. Unless renewed or extended, Mr. Colby’s and Mr. Stingley’s employment agreements are scheduled to expire in June 2014 and December 2013, respectively. Also prior to the merger, Mr. Lantz had entered into an employment agreement with AEE Inc. that had been authorized by its board of directors. Unless renewed or extended, Mr. Lantz’s employment agreement is scheduled to expire in June 2014. American Eagle’s Board of Directors could authorize the termination of any or all of these employment agreements at any time, subject to certain financial terms outlined in the corresponding employment agreement.
Consideration given by Eternal to acquire AEE Inc. was in the form of shares of Eternal’s common stock. The number of shares issued by Eternal to acquire all of the then-outstanding shares of AEE Inc. was calculated by dividing the then-outstanding number of Eternal common shares outstanding by 20%, which represented the anticipated post-acquisition percentage of shares to be owned by legacy Eternal stockholders. The per-share exchange ratio of 3.641 shares of Eternal common stock for every one share of then-outstanding AEE Inc. common stock was calculated by dividing the sum of the then-outstanding shares of AEE Inc. common stock, plus outstanding stock options, by the total number of Eternal shares to be issued, as described above.
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 9 |
As of the date of merger, AEE Inc. had 43,374,158 shares of common stock outstanding. The closing price of AEE Inc.’s common stock on the day immediately prior to the transaction date was $0.78 per share, resulting in a market capitalization value for AEE Inc.’s common stock of $33,831,843. In connection with the merger, Eternal issued 36,473,543 shares of its common stock. The closing price of Eternal’s common stock on the day immediately prior to the transaction date, affected for the 1-for-4.5 reverse stock split that occurred immediately afterward, was $1.22 per share, resulting in a consideration value of $44,315,155 for all of the AEE Inc. common stock. The consideration value of the shares issued by Eternal to acquire all of the outstanding shares of AEE Inc.’s common stock exceeded the market value of AEE Inc.’s outstanding common shares by $10,483,512, resulting in premium being paid by Eternal. ASC 805-10-55-12e states that, “The acquirer usually is the combining entity that pays a premium over the pre-combination fair value of the equity interests of the other combining entity or entities.” Thus, the guidance provided by ASC 805-10-55-12e also supports the conclusion that Eternal was the accounting acquirer in the transaction.
As of the transaction date, Eternal and AEE Inc. each held working interest investments in properties located within the Spyglass Property (US) and Hardy Property (Canada). The Spyglass and the Hardy properties represent the combined company’s principal area of developmental focus and are expected to provide the majority of the combined company’s future oil and gas revenues.
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 10 |
A summary of the Company’s working interest in the existing and proposed Hardy and Spyglass wells as of December 31, 2011 is as follows:
Well Name | Eternal Working Interest
| AEE Inc. Working Interest
| Well Status as of December 31, 2011 |
| Hardy Property: | |||
| Hardy 7-9 | 50.00% | 50.00% | Producing |
| Hardy 4-16 | 37.50% | 37.50% | Producing |
| Hardy 14-17 | 42.50% | 42.50% | Producing |
| Spyglass Property: | |||
| Aarestad 4-34H-160N-97W | 0.63% | - | Producing |
| Adams 2-18H-163N-100W | 18.52% | - | Waiting to spud |
| Bagley 4-30H-163N-100W | 2.27% | 1.60% | Producing |
| Blazer 2-11-163N-98W | 0.94% | - | Producing |
| Christianson 15-12-163N-101W | 18.21% | 17.29% | Completing |
| Cody 15-11-163N-101W | 13.59% | 17.61% | Drilling |
| Coplan 1-3-163N-101W | 6.83% | 6.03% | Waiting to spud |
| Denali 13-21-163N-98W | 0.03% | - | Producing |
| Gerhardsen 1-10H-160N-97W | 2.37% | - | Producing |
| Gulbranson 2-1H-163N-100W | 6.21% | 5.13% | Waiting to spud |
| Jurasin 32-29-162N-100W | 0.61% | - | Shut-in |
| Lancaster 2-11H-162N-101W | 6.23% | - | Completing |
| Legaard 4-25H-163N-101W | 2.02% | 1.67% | Producing |
| Montclair 1-12-163N-99W | 1.60% | - | Producing |
| Mustang 7-6-163N-98W | 0.32% | - | Producing |
| Nielsen 1-12H-160N-97W | 0.46% | - | Producing |
| Nomad 6-7-163N-99W | 14.47% | - | Producing |
| Olson 15-22-162N-100W | 0.78% | - | Producing |
| Reistad 1-1H-162N-102W | 8.62% | - | Waiting on completion |
| Ridgeway 25-36-163N-101W | 1.88% | - | Shut-in |
| Riede 4-14H-163N-100W | 0.17% | 0.17% | Producing |
| Thomte 8-5-163N-99W | 1.59% | 1.59% | Producing |
| Titan 36-25-163N-99W | 0.81% | - | Producing |
| Torgeson 1-15H-163N-100W | 3.60% | 0.78% | Producing |
| Wolter 1-28H-163N-100W | 1.30% | - | Producing |
| Wolter 13-9H-163N-100W | 2.98% | 2.94% | Producing |
| Wolter 15-8H-163N-100W | 0.77% | 0.77% | Producing |
| Yukon 12-1-163N-98W | 1.25% | - | Producing |
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 11 |
Proven oil and gas reserves associated with the these wells as of December 31, 2011 had an estimated net present value of $37,827,830, of which $22,501,500 (60.1%) was attributable to Eternal’s working interest holdings, compared to $15,326,330 (39.9%) that was attributable to AEE Inc.’s working interest holdings.
The following table summarizes the total assets, revenues from oil and gas operations net earnings for Eternal as of and for the year ended December 31, 2011 and for AEE Inc. as of and for the period January 1 through December 20, 2011, the date of merger:
| Eternal | AEE Inc. | |||||||||||||
| Total assets | $ | 15,469,341 | 52.5 | % | $ | 14,010,519 | 47.5% | |||||||
| Oil and gas revenues | 822,610 | 63.4 | % | 474,010 | 36.6% | |||||||||
| Net earnings | 4,212,579 | 53.7 | % | 3,635,167 | 46.3% | |||||||||
Accounting Treatment Conclusion –American Eagle believes that Eternal was properly identified as the accounting acquirer in the transaction based on the following criteria:
| a. | Merger discussions were initiated by Eternal; |
| b. | Eternal was the entity that issued equity instruments as consideration for the transaction; |
| c. | The value of the equity instruments issued by Eternal as consideration exceeded the fair value of the outstanding shares of AEE Inc. and resulted in Eternal paying a premium to acquire AEE Inc.’s stock; |
| d. | Though relatively equivalent with respect to net asset values prior to the transaction, Eternal’s working interest in the combined oil and gas properties that management believes will be the primary source of the combined entity’s future revenues significantly exceeded AEE Inc.’s working interest in such properties; |
| e. | Eternal’s portion of the proved oil and gas reserves of the combined entity significantly exceeded AEE Inc.’s share of such reserves; |
| f. | The management of the combined entity is dominated by legacy Eternal officers; |
| g. | The combined entity’s board of directors is dominated by legacy Eternal board members. Furthermore, the Merger Agreement requires that the board membership remain the same throughout the first year of combined operations; and |
| h. | Brad Colby, Eternal’s former President and American Eagle’s current President, is the largest known minority stockholder or organized group of minority stockholders of the combined entity. |
| United States Securities and Exchange Commission Karl Hiller and Jenifer Gallagher November 8, 2012 Page 12 |
American Eagle appreciates the Staff’s prompt review and consideration of its responses and hopes that information contained in this letter, and the Company’s proposed disclosure changes to be included in its Amended Form 10-K/A will satisfy all of the Staff’s remaining inquiries.
Very truly yours,
Randolf W. Katz
Baker & Hostetler LLP
RWK/dlp
Encls.
Acknowledgements:
The Company acknowledges that it is responsible for the adequacy and accuracy of the disclosures in its annual filing. The Company further acknowledges that changes to its disclosure in response to SEC staff comments do not foreclose the Commission from taking any action with respect to the filing, and that the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
AMERICAN EAGLE ENERGY CORPORATION
| By: | /s/ Brad Colby | |
| Brad Colby, Chief Executive Officer |
Exhibit A – Summary of Management
| Name | Title | Duties & Responsibilities | Date of Initial Hire | Hours Worked per Week | Previous Affiliation | |
| Brad Colby | President | · | General corporate leadership | November | 45 | Eternal |
| and Chief | · | Corporate strategy development | 2005 | Energy Corp. | ||
| Executive | · | Investor relations contact | ||||
| Officer | · | Mergers and Acquisitions | ||||
| · | Business development / contract negotiations | |||||
| · | Oversee Land Department activities | |||||
| Tom Lantz | Chief | · | Operational leadership | June 2010 | 45 | American |
| Operating | · | Develop and implement the annual drilling program | Eagle Energy | |||
| Officer | · | Oversee well operations and technical drilling activities | Inc. | |||
| Kirk Stingley | Chief | · | Accounting and finance leadership | June 2008 | 50 | Eternal |
| Financial | · | Perform SEC reporting functions | Energy Corp. | |||
| Officer | · | Information Technology strategy development and implementation | ||||
| · | Human Resources management | |||||
| · | Risk management | |||||
| · | Perform treasury and cash management functions | |||||
| · | Website management | |||||
| · | Perform public relations activities |
American Eagle Energy Corporation
Notes to the Consolidated Financial Statements
As of December 31, 2011 and 2010 and
For Each of the Two Years in the Period Ended December 31, 2011
7.Oil and Gas Properties
As of December 31, 2011 and December 31, 2010, net costs included in the Company’s full-cost pool cost centers are as follows:
| December 31, 2011 | December 31, 2010 | ||||||||||||||||
| Amortizable | Non-Amortizable | Amortizable | Non-Amortizable | ||||||||||||||
| United States | $ | 6,816,654 | $ | 7,295,215 | $ | - | $ | 590,368 | |||||||||
| Canada | 8,981,653 | - | 340,321 | - | |||||||||||||
| Total | $ | 15,798,307 | $ | 7,295,215 | $ | 340,321 | $ | 590,368 | |||||||||
Hardy Property
As discussed in Note 5, in April 2010, the Company acquired a 100% working interest in approximately 4,480 net acres located in Saskatchewan, Canada in connection with the sale of certain gross overriding royalty interest to Ryland. The Hardy Property contained one existing well with equipment valued at approximately $238,681 at the time of the purchase. Shortly after the acquisition, the Company sold 50% of its working interest in the Hardy Property to AEE Inc. and received a 50% working interest in the Spyglass Prospect. As a result, the Company reclassified 50% of the Company’s carrying value of the Hardy Property at the time of the sale to the newly acquired Spyglass Prospect.
In August 2010, the Company, along with AEE Inc., its working interest partner at the time, performed a workover and recompletion of the Hardy 7-9 well at an aggregate cost of $475,274. The Company’s portion of the recompletion cost was $237,637. The Hardy 7-9 well was returned to production in September 2010.
On May 2, 2011, the Company entered into a participation agreement with Passport Energy Ltd. (“Passport”), pursuant to which Passport agreed to participate in, and fund 38.5% of the drilling costs of, up to two new wells within the Hardy Property in exchange for a 25% working interest in the wells. Eternal Energy and AEE Inc. each agreed to fund 30.75% of the drilling cost of the two new wells and retain a 37.5% working interest in the new wells.
In May 2011, the Company, along with its then working interest partners, AEE Inc. and Passport, successfully drilled and completed the “Hardy 4-16” well, an offset well located within the Hardy Property. The well was fracture stimulated in July 2011 and placed on production during September 2011.
In December 2011, the Company and Passport modified the terms of their existing participation agreement and commenced drilling of the Hardy 14-17 well. Pursuant to the modified participation agreement, the Company and AEE Inc. each agreed to fund 38.45% of the initial drilling and completion costs of the Hardy 14-17 well, with Passport funding the remaining 23.1% of the drilling and completion costs. Upon completion of the well, the Company will own a consolidated 85% working interest in the well, with Passport retaining a 15% working interest.
As of December 31, 2011, the Company owns a 50% working interest in approximately 4,300 net acres held by 6 leases, each of which is scheduled to expire on April 1, 2014.
The Company recognized depletion expense totaling $89,185 and $104,350 for the years endedDecember 31, 2011 and 2010, respectively, relative to the Hardy Property.
Spyglass Property
For reporting purposes, the Spyglass Property has been redefined to include the historical Spyglass acreage, as well as certain acreage formerly referred to as the Pebble Beach Property.
In 2006, the Company entered into a series of agreements that resulted in the acquisition of a ten percent working interest in a joint venture with Rover. The joint venture was formed to explore and develop certain prospects principally located in Divide County, North Dakota.
As noted in Note 5, the Company sold its working interest in approximately 700 net acres located within the Pebble Beach Property to Rover in April 2010 for cash consideration totaling $1 million. At that time, the sale represented a significant reduction of the full-cost pool that is not subject to amortization. Accordingly, the Company reallocated the costs of the total pool among the properties included within the pool based on relative fair market value at the time of the sale. The Company recognized a $509,934 gain on the sale of the Pebble Beach acreage during the year ended December 31, 2010.
In June 2010, the Company sold half of its 100% working interest in the Hardy Property to AEE Inc. in exchange for a 50% working interest in approximately 6,239 net acres located within Divide County, North Dakota. The Company reclassified 50% of the then-carrying value of its investment in the Hardy Property ($126,029) to the Spyglass Property at the time of the sale. Between June 30, 2010 and May 27, 2011, the Company acquired a 50% working interest in an additional 2,486 net acres at an aggregate cost of $625,557.
Exploratory drilling within the Spyglass Property commenced during the fourth quarter of 2010. During the year ended December 31, 2011, economically recoverable proved reserves were identified within the Spyglass Property. As a result, the Company reassigned its investment in the Spyglass Property to the full-cost pool, subject to amortization.
In May 2011, the Company sold a portion of the acreage that it had previously acquired from Rover for net cash consideration totaling $227,079. Because the sale did not represent the disposal of a significant portion of non-amortizable full-cost pool at the time of the sale, the net proceeds received were recorded as a reduction of the full-cost pool, not subject to amortization.
Also in May 27, 2011, the Company and AEE Inc. each sold a 25% working interest in the Spyglass Property to a third party for cash consideration, net of finder’s fees, totaling $3,823,963 each to the Company and to AEE Inc. After reducing the carrying value of the Company’s full-cost pool, subject to amortization, to zero, the Company recognized a gain in the amount of $3,072,377.
In December 2011, the Company sold an additional portion of the property that it had acquired from Rover for net cash consideration totaling $1,889,973. Because the sale did not represent the disposal of a significant portion of amortizable full-cost pool at the time of the sale, the net proceeds received were recorded as a reduction of the full-cost pool, subject to amortization. The net proceeds from the sale were received in January 2012 and are included in the Company’s receivables balance as of December 31, 2011.
As of December 31, 2011, the Company owns a consolidated 50% working interest in approximately 11,521 net acres within the Spyglass Property, which is held by approximately 438 leases, with expiration dates ranging from August 2012 to February 2017.
Benrude Property
As of December 31, 2011, the Company owns a 100% working interest in approximately 743 net acres located in Roosevelt County, Montana. The acreage is held by 32 leases, with expiration dates ranging from December 2012 to July 2015. The Company is planning to conduct a 3-D seismic study of the Benrude Property during 2012, the results of which will be used to determine the Company’s strategy for pursuing the proved reserves assigned to the Benrude Property.
The net capitalized cost of the Company’s oil and gas properties, subject to amortization, as of December 31, 2011 and December 31, 2010 is summarized below:
| US | Canadian | ||||||||||||
| December 31, 2011: | Cost Center | Cost Center | Total | ||||||||||
| Acquisition costs | $ | 4,336,958 | $ | 5,213,127 | $ | 9,550,085 | |||||||
| Exploration costs | - | - | - | ||||||||||
| Development costs | 4,283,103 | 3,951,764 | 8,234,867 | ||||||||||
| Impairments and sales | (1,803,407 | ) | - | (1,803,407 | ) | ||||||||
| 6,816,654 | 9,164,891 | 15,981,545 | |||||||||||
| Accumulated depletion | - | (183,238 | ) | (183,238 | ) | ||||||||
| Totals | $ | 6,816,654 | $ | 8,981,653 | $ | 15,798,307 | |||||||
| December 31, 2010: | |||||||||||||
| Acquisition costs | $ | - | $ | 135,217 | $ | 135,217 | |||||||
| Exploration Costs | - | - | - | ||||||||||
| Development costs | - | 310,897 | 310,897 | ||||||||||
| Development costs | - | (1,443 | ) | (1,443 | ) | ||||||||
| - | 444,671 | 444,671 | |||||||||||
| Accumulated depletion | - | (104,350 | ) | (104,350 | ) | ||||||||
| Totals | $ | - | $ | 340,321 | $ | 340,321 | |||||||
Exploratory Prospects
As of December 31, 2011, the Company has entered into participation agreements in a number of exploratory oil and gas prospects, all which are located within the continental United States. Unproven exploratory prospects are excluded from the amortizable cost pools. Each prospect’s costs are transferred into the amortization base on an ongoing basis as the prospect is evaluated and proved reserves are established or impairment is determined. The Company paid certain amounts upon execution of the agreements and is obligated to share in the drilling costs of certain exploratory wells being drilled in the prospects. The capitalized costs of the exploratory prospects are not subject to amortization because, to date, no proved reserves have been assigned to the individual prospects. The nature of the capitalized costs of the unproven prospects is as follows:
| Aggregate | |||||||||||||||||
| December 31, | Through | ||||||||||||||||
| 2011 | 2010 | 2009 | Total | ||||||||||||||
| Acquisition costs | $ | 9,442,209 | $ | 386,687 | $ | 1,976,054 | $ | 11,804,950 | |||||||||
| Exploration costs | 520,967 | 69,285 | 136,918 | 727,170 | |||||||||||||
| Reclassifications to the | |||||||||||||||||
| amortizable pool | (758,723 | ) | - | - | (758,723 | ) | |||||||||||
| Impairments and sales | (2,499,605 | ) | (277,355 | ) | (1,701,222 | ) | (4,478,182 | ) | |||||||||
| Total capitalized costs of | |||||||||||||||||
| exploratory prospects | $ | 6,704,848 | $ | 178,617 | $ | 411,750 | $ | 7,295,215 | |||||||||
Glacier Prospect
As a result of its acquisition of AEE Inc., the Company owns an undivided 33% working interest in approximately 25,000 net acres located in Toole County, Montana. The acreage is held by approximately 400 leases, with expiration dates ranging from May 2012 to June 2015.
Because no proved reserves have yet been identified, the Glacier Prospect has been assigned to the full-cost pool that is not subject to amortization. Management is currently in the process of developing its exploration strategy relative to the Glacier Prospect. The Company is evaluating the results of nearby wells drilled by other companies in order to make a determination on the future of the Glacier Prospect. The Glacier Prospect is evaluated for impairment during each reporting period. There were no impairments evident as of December 31, 2011.
Sidney North Prospect
As a result of its acquisition of AEE Inc., the Company owns a 100% working interest in oil and gas leases on approximately 399 net acres located in Richland County, Montana (the “Sidney North Prospect”). The acreage is held by approximately 14 leases, with expiration dates ranging from July 2013 to October 2015. The Company’s management is currently evaluating this prospect. No formal determination of the ultimate viability of this prospect is expected during the next twelve months. Management has reviewed the carrying value of this property and determined that no impairment exists as of December 31, 2011.
West Spyglass Prospect
In June, 2011, the Company began acquiring interests in oil and gas leases located in an area adjacent to the existing Spyglass Prospect. The Company’s management refers to the adjacent acreage as the West Spyglass Prospect.
The Company sold 75% of its then-working interest in the West Spyglass Prospect to a third party during December 2011. The Company received cash consideration totaling $5,456,548 from the sale. At the time of the sale, the West Spyglass Prospect represented the only prospect included in the portion of the Company’s full-cost pool that was not subject to amortization. After again reducing the carrying value of the full-cost pool, not subject to amortization to zero, the Company recognized a gain on the sale of $3,332,737.
The Company acquired an additional 12.5% working interest in the West Spyglass Prospect as a result of its acquisition of AEE Inc. As of December 31, 2011, the Company owns a 25% working interest in approximately 10,593 net acres located within the West Spyglass Prospect. The net acres are held by 283 leases, with expiration dates ranging from April 2012 to February 2017. The Company’s management is currently evaluating this prospect. No formal determination of the ultimate viability of this prospect is expected during the next twelve months. Management has reviewed the carrying value of this property and determined that no impairment exists as of December 31, 2011.
Exploratory Prospect Cost Summary
The following table summarizes the costs of the Company’s aggregate exploratory activities for all unproven prospects for the year ended December 31, 2011 and the year ended December 31, 2010:
| December 31, | December 31, | ||||||||
| 2011 | 2010 | ||||||||
| Balance at the beginning of the period | $ | 590,368 | $ | 412,797 | |||||
| Additions to exploratory costs | 11,407,645 | 455,972 | |||||||
| Disposals | (2,499,605 | ) | (278,401 | ) | |||||
| Reassignments to the amortizable pool | (2,203,193 | ) | - | ||||||
| Balance at the end of the period | $ | 7,295,215 | $ | 590,368 | |||||
15.Supplemental Oil and Gas Information (Unaudited)
During the years ended December 31, 2011 and 2010, the Company capitalized the following costs associated with the acquisition, exploration and development of oil and gas properties:
| 2011 | 2010 | ||||||||
| Acquisition costs | $ | 2,649,493 | 177,570 | ||||||
| Exploration costs | - | - | |||||||
| Development costs | 4,502,832 | 444,671 | |||||||
| Total costs | $ | 7,152,325 | $ | 622,241 | |||||
The Company recognized the following revenues and expenses associated with its oil and gas producing activities for the years ended December 31, 2011 and 2010:
| 2011 | 2010 | ||||||||
| Oil revenues | $ | 864,918 | $ | 207,788 | |||||
| Operating expenses | 537,122 | 145,961 | |||||||
| Net oil and gas revenues | $ | 327,796 | $ | 61,827 | |||||
| Oil revenues by cost center: | |||||||||
| United States | $ | 402,436 | $ | 74,485 | |||||
| Canada | 462,482 | 133,303 | |||||||
| Total oil revenue | $ | 864,918 | $ | 207,788 | |||||
| Oil production by cost center (barrels): | |||||||||
| United States | 5,535 | 1,414 | |||||||
| Canada | 5,802 | 2,001 | |||||||
| Total oil production | 11,337 | 3,415 | |||||||
| Average oil prices by cost center (net of | |||||||||
| royalty interest): | |||||||||
| United States | $ | 72.71 | $ | 52.67 | |||||
| Canada | 79.71 | 66.63 | |||||||
| Oil production costs by cost center: | |||||||||
| United States | $ | 23,264 | $ | 7,487 | |||||
| Canada | 513,858 | 138,474 | |||||||
| Total oil production costs | $ | 537,122 | $ | 145,961 | |||||
| Oil production costs per unit: | |||||||||
| United States | $ | 4.20 | $ | 5.29 | |||||
| Canada | 88.57 | 69.22 | |||||||
The following tables set forth the Company’s net interests in quantities of proved developed and undeveloped reserves of crude oil, condensate and natural gas and changes in such quantities from the prior period. Crude oil reserves estimates include condensate.
The reserve estimation process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of this process, all reserves volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Estimated future cash flows were computed by applying an average of the monthly oil prices for the year to the Company’s share of estimated annual future production from proved oil and gas reserves, net of royalties. Production rate forecasts are derived by a number of methods, including estimates from decline curve analyses, material balance calculations that take into account the volume of substances replacing the volumes produced and associated reservoir pressure changes, or computer simulation of the reservoir performance. Operating costs and capital costs are forecast based on past experience combined with expectations of future cost for the specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary.
The Company has retained an independent petroleum engineering firm to determine its annual estimate of oil and gas reserves as of December 31, 2011 and 2010. The independent petroleum engineering firm estimated the oil and gas reserves associated with the Company’s Hardy, Spyglass and Benrude Properties using generally accepted industry standards, which include the review of technical data, methods and procedures used in estimating reserves volumes, the economic evaluations and reserves classifications.
The Company believes that the methodologies used by the independent petroleum engineering firm in preparing the relevant estimates comply with current Securities and Exchange Commission standards for preparing such estimates. The Company has implemented internal controls regarding the development of reasonable oil and gas reserves estimates. These controls include, among other things, a thorough review of the estimated future development costs and estimated production costs associated with the reserves and a comparison of such estimated future costs to actual development and production costs incurred during the current period. In addition, the Company’s operational team compares the average prices used to estimate discounted net future cash flows from proved reserves to actual prices received during the period for reasonableness. The internal control procedures described above were performed by the Company’s operational team, which includes petroleum engineers having in excess of 71 years of oil and gas exploration and production experience, collectively. Based on the performance of these internal controls, the Company’s management believes that the underlying data provided by the Company to the independent petroleum engineering firm for the purpose of preparing its estimates, is reasonable. Furthermore, the estimated reserves as of December 31, 2011 and 2010, as described in the final report issued by the independent petroleum engineering firm, were reviewed by members of the Company’s operational management and determined to be reasonable based on the underlying data.
The following tables summarize the Company’s proved oil and gas reserves, annual production and other changes in the Company’s proved oil and gas reserves for the years ended December 31, 2011 and 2010:
| Oil | Gas | Total | |||||||||||
| For the year ended December 31, 2011: | (Barrels) | (Mcf) | (Boe) | ||||||||||
| Proved reserves, beginning of | |||||||||||||
| year | 198,825 | - | 198,825 | ||||||||||
| Revisions | 50,484 | - | 50,484 | ||||||||||
| Discoveries | 430,920 | - | 430,920 | ||||||||||
| Purchases of reserves in place | 842,346 | 416,900 | 911,829 | ||||||||||
| Production | (11,337 | ) | - | (11,337 | ) | ||||||||
| Proved reserves, end of year | 1,511,238 | 416,900 | 1,580,721 | ||||||||||
| Proved reserves by cost center: | |||||||||||||
| United States | 909,067 | 416,900 | 978,550 | ||||||||||
| Canada | 602,171 | - | 602,171 | ||||||||||
| Total proved reserves | 1,511,238 | 416,900 | 1,580,721 | ||||||||||
| Proved developed reserves | 274,188 | 59,892 | 284,170 | ||||||||||
| Proved undeveloped reserves | 1,237,050 | 357,008 | 1,296,551 | ||||||||||
| Total proved reserves | 1,511,238 | 416,900 | 1,580,721 | ||||||||||
| Proved developed reserves by cost | |||||||||||||
| center: | |||||||||||||
| United States | 102,937 | 59,892 | 112,919 | ||||||||||
| Canada | 171,251 | - | 171,251 | ||||||||||
| Total proved developed | |||||||||||||
| reserves | 274,188 | 59,892 | 284,170 | ||||||||||
| Proved undeveloped reserves, | |||||||||||||
| beginning of year | 152,348 | - | 152,348 | ||||||||||
| Conversion to developed reserves | (152,348 | ) | - | (152,348 | ) | ||||||||
| Revisions | - | - | |||||||||||
| Discoveries | 430,920 | - | 430,920 | ||||||||||
| Purchases of reserves in place | 806,130 | 357,008 | 865,631 | ||||||||||
| Proved undeveloped reserves, | |||||||||||||
| end of year | 1,237,050 | 357,008 | 1,296,551 | ||||||||||
| Proved undeveloped reserves by cost center: | |||||||||||||
| United States | 806,130 | 357,008 | 865,631 | ||||||||||
| Canada | 430,920 | - | 430,920 | ||||||||||
| Total proved undeveloped | |||||||||||||
| reserves | 1,237,050 | 357,008 | 1,296,551 | ||||||||||
As a result of drilling the Hardy 4-16 well in September 2011, the Company converted 152,348 barrels of oil from proved undeveloped reserves to proved developed reserves. The Company incurred $1,187,598 of capitalized expenditures to drill Hardy 4-16 well.
| Oil | Gas | Total | |||||||||||
| For the year ended December 31, 2010: | (Barrels) | (Mcf) | (Boe) | ||||||||||
| Proved reserves, beginning of | |||||||||||||
| year | - | - | - | ||||||||||
| Revisions | - | - | - | ||||||||||
| Discoveries | - | - | - | ||||||||||
| Purchases of reserves in place | 200,826 | - | 200,826 | ||||||||||
| Production | (2,001 | ) | - | (2,001 | ) | ||||||||
| Proved reserves, end of year | 198,825 | - | 198,825 | ||||||||||
| Proved reserves by cost center: | |||||||||||||
| United States | - | - | - | ||||||||||
| Canada | 198,825 | - | 198,825 | ||||||||||
| Total proved reserves | 198,825 | - | 198,825 | ||||||||||
| Proved developed reserves | 46,477 | - | 46,477 | ||||||||||
| Proved undeveloped reserves | 152,348 | - | 152,348 | ||||||||||
| Total proved reserves | 198,825 | - | 198,825 | ||||||||||
| Oil | Gas | Total | |||||||||||
| Proved developed reserves by cost center: | (Barrels) | (Mcf) | (Boe) | ||||||||||
| United States | - | - | - | ||||||||||
| Canada | 46,477 | - | 46,477 | ||||||||||
| Total proved developed | |||||||||||||
| reserves | 46,477 | - | 46,477 | ||||||||||
| Proved undeveloped reserves, | |||||||||||||
| beginning of year | - | - | - | ||||||||||
| Revisions | - | - | - | ||||||||||
| Discoveries | - | - | - | ||||||||||
| Purchases of reserves in place | 152,348 | - | 152,348 | ||||||||||
| Proved undeveloped reserves, | |||||||||||||
| end of year | 152,348 | - | 152,348 | ||||||||||
| Proved undeveloped reserves by cost center: | |||||||||||||
| United States | - | - | - | ||||||||||
| Canada | 152,348 | - | 152,348 | ||||||||||
| Total proved undeveloped | |||||||||||||
| reserves | 152,348 | - | 152,348 |
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, 2011.
Standardized Measure of Discounted Future Net Cash Flows
| At December 31, | |||||||||
| 2011 | 2010 | ||||||||
| Future cash flows | $ | 132,047,257 | $ | 5,350,175 | |||||
| Future costs: | |||||||||
| Production costs | (28,976,839 | ) | (1,215,802 | ) | |||||
| Development costs | (15,273,800 | ) | (930,000 | ) | |||||
| Income taxes | (31,309,370 | ) | - | ||||||
| Future net cash flows | 56,487,248 | 3,204,373 | |||||||
| Ten percent discount factor | (31,265,211 | ) | (1,265,320 | ) | |||||
| Standardized measure of discounted future net | |||||||||
| cash flows | $ | 25,222,037 | $ | 1,939,053 | |||||
The following table summarizes the changes in the Company’s standardized measure of discounted future net cash flows for the years ended December 31, 2011 and 2010:
| 2011 | 2010 | ||||||||
| Extensions and discoveries | $ | 10,865,465 | $ | - | |||||
| Net changes in sales prices and production | |||||||||
| costs | 370,076 | - | |||||||
| Oil and gas sales, net of production costs | (329,420 | ) | (133,303 | ) | |||||
| Change in estimated future development costs | (710,348 | ) | - | ||||||
| Revision of quantity estimates | 999,954 | - | |||||||
| Purchases of mineral interests | 17,700,515 | 2,072,356 | |||||||
| Additions of mineral interests due to merger | 14,176,308 | - | |||||||
| Previously estimated development costs | |||||||||
| incurred in the current period | 1,640,348 | - | |||||||
| Changes in production rates, timing and other | (5,455,760 | ) | - | ||||||
| Changes in income taxes | (16,258,320 | ) | - | ||||||
| Accretion of discount | 287,166 | - | |||||||
| Net increase | 23,285,984 | 1,939,053 | |||||||
| Standardized measure of discounted future cash | |||||||||
| flows: | |||||||||
| Beginning of year | 1,939,053 | - | |||||||
| End of year | $ | 25,225,037 | $ | 1,939,053 | |||||
Assumed prices used to calculate future cash flows
| At December 31, | |||||||||
| 2011 | 2010 | ||||||||
| Oil price per barrel | $ | 86.47 | $ | 76.87 | |||||
| Gas price per mcf | $ | 3.29 | N/A | ||||||
Item 2. Properties.
Following consummation of the 2011 Merger with AEE Inc., we own a 100% working interest in the Hardy Property, containing approximately 4,300 net acres located in southeastern Saskatchewan, Canada. Our working interest in the Hardy Property is subject to certain, well-specific farmout agreements that reduce our working interests in those particular wells. The Hardy Property includes the 7-9 and the 4-16 operating oil wells that currently collectively produce approximately 130 barrels of oil per day, and related equipment.
To date, we have agreed to participate in 28 exploratory wells located within the Spyglass Project areas, at various levels of participation. As of December 31, 2011, 22 wells are producing / shut in and the remaining 6 wells have been, or are in the process of being, drilled or completed.
A summary of the Company’s working interest in the Spyglass wells and the status of each well as of December 31, 2011 is discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, below.
We own an undivided 50% working interest in approximately 11.521 additional net acres located in the Spyglass Project primarily in Divide County, North Dakota. An unrelated third party owns the other undivided 75% working interest in such net acres. No timetable has been developed for the exploration of this acreage.
We own a 100% working interest in approximately 743 net acres located within the Benrude Property, primarily in Roosevelt County, Montana. We are planning to complete a 3-D seismic analysis of the Benrude Property sometime in 2012, in order to determine our development strategy with respect to the Benrude acreage.
We own a 25% working interest in the 10,593 aggregate net acres located in the West Spyglass Project, primarily in Western Divide County, North Dakota, and eastern Sheridan County, Montana. We sold 75% of the working interest to an unrelated third party during 2011. Post-closing, we will remain the operator on that acreage.
We own a 33% working interest in approximately 25,000 net acres located in the Glacier Prospect, primarily in Toole County, Montana.
We own a 100% working interest in approximately 399 net acres located within the Sidney North Prospect, primarily in Richland County, Montana.
AEE Inc. owns a 12.5% working interest in an oil and gas lease in Willacy County, Texas. The land covered by the lease consists of 908 acres out of the San Juan de Carrieitos, Willacy County, Texas, which covers an undivided 29/32nd of the mineral estate. The area is also subject to another oil and gas lease owned by Exxon Mobil Corporation for the remaining 3/32nds.
AEE Inc. also currently owns an undivided 33.34% working interest in approximately 25,000 net acres located in Toole County, Montana.
The following is a summary of our developed acreage as of December 31, 2011:
Property / Prospect Name | Gross Acres | Net Acres | Number of Leases | Earliest Lease Expiration Date | Latest Lease Expiration Date |
| Hardy | 960 | 960 | 2 | April 2014 | April 2014 |
| Spyglass | 492 | 389 | 8 | August 2012 | February 2017 |
| Totals | 1,452 | 1,349 | 10 |
The following is a summary of our undeveloped acreage as of December 31, 2011:
Property / Prospect Name | Gross Acres | Net Acres | Number of Leases | Earliest Lease Expiration Date | Latest Lease Expiration Date |
| Hardy | 3,740 | 3,340 | 4 | April 2014 | April 2014 |
| Spyglass | 16,750 | 11,132 | 430 | August 2012 | February 2017 |
| Benrude | 800 | 743 | 32 | December 2012 | July 2015 |
| Glacier | 60,000 | 25,000 | 400 | May 2012 | June 2015 |
| Sidney North | 680 | 399 | 14 | July 2013 | October 2015 |
| West Spyglass | 36,405 | 10,593 | 283 | April 2012 | February 2017 |
| Totals | 118,375 | 51,207 | 1,163 |
Additional information regarding our oil and gas properties can be found in Note 7 and Note 15 to our financial statements as of and for the years ended December 31, 2011 and 2010, which are included in Item 8 of this document (see pages F-_and F-_, respectively).
We currently lease 3,207 square feet of office space in Littleton, Colorado, which we believe to be sufficient for the operation of our business for the foreseeable future. We renewed and extended this lease in October 2011. The current lease agreement expires in December 2014.
We do not own or lease any other properties.