-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, WiqHQTI8HZsXvSXnzWXg5yffPZzTCPWUiGGVFWBnwJ6cpeYkTyHAQoz0vCsyLrGB WKRb3/hDZ/w2b0HYYLhepg== 0000950142-08-000685.txt : 20080328 0000950142-08-000685.hdr.sgml : 20080328 20080328160620 ACCESSION NUMBER: 0000950142-08-000685 CONFORMED SUBMISSION TYPE: 40-F PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 20071231 FILED AS OF DATE: 20080328 DATE AS OF CHANGE: 20080328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ADVANTAGE ENERGY INCOME FUND CENTRAL INDEX KEY: 0001259995 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 FILING VALUES: FORM TYPE: 40-F SEC ACT: 1934 Act SEC FILE NUMBER: 001-32677 FILM NUMBER: 08719435 BUSINESS ADDRESS: STREET 1: PETRO-CANADA CENTRE SUITE 3100 STREET 2: 150-6 AVENUE, SW CITY: CALGARY, ALBERTA STATE: A0 ZIP: T2P 3V7 40-F 1 form40f_2007.txt FORM 40-F UNITED STATES SECURITIES AND EXCHANGE COMMISSION ---------------------- WASHINGTON, D.C. 20549 OMB APPROVAL ---------------------- FORM 40-F OMB NUMBER: 3235-0381 Expires: April 30, 2008 [_] REGISTRATION STATEMENT PURSUANT TO SECTION Estimated Average 12 OF THE SECURITIES EXCHANGE ACT OF 1934 burden hours per response ........ 427 OR ----------------------- [X] ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended: December 31, 2007 Commission File Number: 001-32677 ADVANTAGE ENERGY INCOME FUND - -------------------------------------------------------------------------------- (Exact name of Registrant as specified in its charter) N/A - -------------------------------------------------------------------------------- (Translation of Registrant's name into English (if applicable)) ALBERTA - -------------------------------------------------------------------------------- (Province or other jurisdiction of incorporation or organization) 1311 - -------------------------------------------------------------------------------- (Primary Standard Industrial Classification Code Number (if applicable)) N/A - -------------------------------------------------------------------------------- (I.R.S. Employer Identification Number (if applicable)) SUITE 700, 400 - 3 AVENUE SW, CALGARY, ALBERTA T2P 4H2 1-866-393-0393 - -------------------------------------------------------------------------------- (Address and telephone number of Registrant's principal executive offices) CORPORATION SERVICE COMPANY 1133 AVENUE OF AMERICAS, 31ST FLOOR, NEW YORK, NY 10036 1-800-927-9800 - -------------------------------------------------------------------------------- (Name, address (including zip code) and telephone number (including area code) of agent for service in the United States) Securities registered or to be registered pursuant to Section 12(b) of the Act. Title of each class Name of each exchange on which registered TRUST UNITS NEW YORK STOCK EXCHANGE ------------------- ------------------------------ Securities registered or to be registered pursuant to Section 12(g) of the Act. NONE - -------------------------------------------------------------------------------- (Title of Class) Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. NONE - -------------------------------------------------------------------------------- (Title of Class) PERSONS WHO ARE TO RESPOND TO THE COLLECTION OF SEC 2285 (08-03) INFORMATION CONTAINED IN THIS FORM ARE NOT REQUIRED TO RESPOND UNLESS THE FORM DISPLAYS A CURRENTLY VALID OMB CONTROL NUMBER. For annual reports, indicate by check mark the information filed with this Form: [X] Annual information form [X] Audited annual financial statements Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report. 138,269,374 Trust Units. Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the Registrant in connection with such Rule. Yes [_] 82-_________ 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 [_] DOCUMENTS INCLUDED IN THIS FORM The following documents are included in the Form: No. Document 1. Annual Information Form of the Registrant for the year ended December 31, 2007. (filed herein as Exhibit 99.1) 2. Consolidated Financial Statements of the Registrant for the fiscal year ended December 31, 2007; including a reconciliation to US GAAP (Note 15). (filed herein as Exhibit 99.2) 3. Management's Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2007 (filed herein as Exhibit 99.3). 4. Consent of PricewaterhouseCoopers LLP to the inclusion of the Auditors' Report dated March 5, 2008 on the Registrant's Audited Consolidated Financial Statements for the fiscal year ended December 31, 2007. 5. Consent of KPMG LLP. 6. Consent of Sproule Associated Limited to the incorporation by reference herein of its Statement of Reserves Data and other Information in Form 51-101F1, which statement and report is contained in the Registrant's Annual Information Form for the fiscal year ended December 31, 2007. 7. CEO Certification pursuant to rule 13a-14(a) of the Exchange Act. 8. CFO Certification pursuant to rule 13a-14(a) of the Exchange Act. 9. CEO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 10. CFO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 11. Report of KPMG LLP. 3 PRINCIPAL DOCUMENTS A. ANNUAL INFORMATION FORM For the Annual Information Form for the fiscal year ended December 31, 2007, see Exhibit 99.1 included herein. B. AUDITED ANNUAL FINANCIAL STATEMENTS For consolidated audited financial statements, including the report of independent chartered accountants with respect thereto, see the Consolidated Financial Statements of the Registrant for the fiscal year ended December 31, 2007 included herein. The Registrant's financial statements have been reconciled to United States generally accepted accounting principles ("US GAAP") as required by Form 40-F under the Exchange Act. See Note 15 - Reconciliation of Financial Statements to United States Generally Accepted Accounting Principles in the 2007 Consolidated Financial Statements. C. MANAGEMENT'S DISCUSSION AND ANALYSIS For management's discussion and analysis, see Management's Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2007 included herein. CERTIFICATIONS AND DISCLOSURES REGARDING CONTROLS AND PROCEDURES A. CERTIFICATIONS. See Exhibits 32.1 and 32.2 to this Annual Report on Form 40-F. B. DISCLOSURE CONTROLS AND PROCEDURES. As of the end of the registrant's fiscal year ended December 31, 2007, an evaluation of the effectiveness of the registrant's "disclosure controls and procedures" (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) was carried out by the registrant's management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the registrant's principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the registrant's disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to the registrant's management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. It should be noted that while the registrant's principal executive officer and principal financial officer believe that the registrant's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrant's disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Reference is made in the "Controls and Procedures" and "Evaluation of Disclosure Controls and 4 Procedures" sections of Management's Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2007, included herein. C. MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. The required disclosure is included in the "Management Report on Internal Control over Financial Reporting" that accompanies the registrant's Consolidated Financial Statements for the fiscal year ended December 31, 2007, filed as part of this Annual Report on Form 40-F. D. ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM. The required disclosure is included in the "Independent Auditors' Report" that accompanies the registrant's Consolidated Financial Statements for the fiscal year ended December 31, 2007, filed as part of this Annual Report on Form 40-F. E. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. During the fiscal year ended December 31, 2007, there were no significant changes in the registrant's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant's internal control over financial reporting. Reference is made in the "Controls and Procedures" section of Management's Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2007, included herein. NOTICES PURSUANT TO REGULATION BTR None. CODE OF ETHICS FOR CHIEF EXECUTIVE OFFICER AND SENIOR FINANCIAL OFFICERS The Registrant has adopted a Code of Ethics for its senior officers, principal financial officer and controller or principal accounting officer, directors and employees. This code applies to President and Chief Executive Officer, Senior Vice-President, Vice President Corporate Development, the Vice-President, Finance and Chief Financial Officer, Vice President Exploitations, Vice President Operations, Directors and employees. It is available on the Registrant's web site at WWW.ADVANTAGEINCOME.COM and in print to any unitholder who requests it. All amendments to the code, and all waivers of the code with respect to any of the officers covered by it, will be posted on the Registrant's web site and provided in print to any unitholder who requests them. AUDIT COMMITTEE IDENTIFICATION OF AUDIT COMMITTEE The following individuals comprise the entire membership of the Advantage Audit Committee: Carol Pennycook, Rodger Tourigny, Ronald McIntosh. AUDIT COMMITTEE FINANCIAL EXPERTS Rodger Tourigny has been determined by the board of the Registrant to meet the "audit committee financial expert" criteria prescribed by the Securities and 5 Exchange Commission and has been designated as audit committee financial expert for the Audit Committee of the board of the Registrant. Each of the directors serving on the Audit Committee has also been determined by the board of the Registrant to be independent within the criteria established by the New York Stock Exchange, Inc. for audit committee membership. PRINCIPAL ACCOUNTING FEES AND SERVICES - INDEPENDENT AUDITORS Fees payable to the Registrant's independent auditors for the years ended December 31, 2007 and December 31, 2006, totaled $1,091,371 and $797,540, respectively, as detailed in the following tables. All funds are in Canadian dollars. The following table discloses fees billed to the Registrant by its former auditors, KPMG LLP: - ------------------------------------------------------------------------------- YEAR ENDED YEAR ENDED DECEMBER 31, 2007 DECEMBER 31, 2006 - ------------------------------------------------------------------------------- AUDIT FEES $203,089 $617,000 - ------------------------------------------------------------------------------- AUDIT-RELATED FEES $57,508 $144,500 - ------------------------------------------------------------------------------- TAX FEES $110,725 $36,040 - ------------------------------------------------------------------------------- ALL OTHER FEES $0 $0 - ------------------------------------------------------------------------------- TOTAL $371,322 $797,540 =============================================================================== The following table discloses fees billed to the Registrant by its current auditors, PricewaterhouseCoopers LLP: - ------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2007 - ------------------------------------------------------------------------------- AUDIT FEES $694,119 - ------------------------------------------------------------------------------- AUDIT-RELATED FEES $0 - ------------------------------------------------------------------------------- TAX FEES $25,930 - ------------------------------------------------------------------------------- ALL OTHER FEES $0 - ------------------------------------------------------------------------------- TOTAL $720,049 =============================================================================== The nature of the services provided by the Registrant's independent auditors under each of the categories indicated in the table is described below. AUDIT FEES Audit fees were for professional services rendered by the Registrant's independent auditors for the audit of the Registrant's annual financial statements and services provided in connection with statutory and regulatory filings or engagements. These services include prospectus work and audit or review of financials forming part of such prospectus and US GAAP reconciliation matters. AUDIT-RELATED FEES Audit-related fees were for assurance and related services reasonably related to the performance of the audit or review of the annual statements and are not reported under "Audit Fees" above. These services include French translation in connection with prospectus filing. TAX FEES Tax fees were for tax compliance, tax advice and tax planning professional services. These services consisted of: tax compliance, including the preparation and review of tax returns; and general tax planning and advisory services relating to common forms of domestic and international taxation (i.e., income tax, capital tax, goods and services tax). ALL OTHER FEES None. 6 PREAPPROVAL POLICIES AND PROCEDURES In 2007, Advantage's Audit Committee pre-approved all audit, audit-related and tax fees. The Audit Committee will be informed routinely as to the non-audit services actually provided by the auditor pursuant to this pre-approval process. The auditors also present the estimate for the annual audit related services to the Audit Committee for approval prior to undertaking the annual audit of the financial statements. OFF-BALANCE SHEET ARRANGEMENTS None. CONTRACTUAL OBLIGATIONS Payments due by period (Cdn$MM) TOTAL 2008 2009 2010 2011 2012 ------ ----- ----- ----- ----- ---- Building Lease $ 16.6 $ 5.3 $ 4.1 $ 4.1 $ 1.8 $1.3 Capital Lease $ 8.1 $ 1.9 $ 2.1 $ 2.2 $ 1.9 - Pipeline/Transportation $ 6.0 $ 4.4 $ 1.3 $ 0.3 - - Convertible Debentures $224.6 $ 5.4 $87.0 $69.9 $62.3 - TOTAL CONTRACTUAL OBLIGATIONS $255.3 $17.0 $94.5 $76.5 $66.0 $1.3 DISCLOSURES PURSUANT TO REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE PRESIDING DIRECTOR AT MEETINGS OF NON-MANAGEMENT DIRECTORS The Registrant schedules regular executive sessions in which the Registrant's "non-management directors" (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Steven Sharpe serves as the presiding director (the "Chair of the Board") at such sessions. Each of the Registrant's non-management directors is "independent" as such term is used in the rules of the Canadian Securities Commissions and the New York Stock Exchange Corporate Governance Standards. COMMUNICATION WITH NON-MANAGEMENT DIRECTORS Unitholders may send communications to the Registrant's non-management directors by writing to Investors Relations, Canterra Tower, Suite 700, 400 - 3 Avenue SW, Calgary, Alberta T2P 4H2, or calling the toll free number at 1-866-393-0393. Communications will be referred to the Chair of the Board for appropriate action. The status of all outstanding concerns addressed to the Chair of the Board will be reported to the board of directors as appropriate. 7 CORPORATE GOVERNANCE GUIDELINES According to NYSE Rule 303A.09, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics and must disclose any significant ways in which its practices differ from those followed by US domestic companies under the NYSE rules. Such guidelines and disclosures are required to be posted on the listed company's website. The Registrant has adopted the required guidelines and made the required disclosures, all of which are available on the Registrant's website at WWW.ADVANTAGEINCOME.COM and in print to any unitholder who requests them. BOARD COMMITTEE CHARTERS Advantage's Audit Committee Charter, the Terms of Reference of the Human Resources, Compensation and Corporate Governance Committee and the Terms of Reference for the Independent Reserve Evaluation Committee are available for viewing on the Registrant's website at www.advantageincome.com and are available in print to any person who requests them. Requests for copies of these documents should be made by contacting: Investor Relations, Canterra Tower, Suite 700, 400 - 3 Avenue SW, Calgary, Alberta T2P 4H2. UNDERTAKING The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities. CONSENT TO SERVICE OF PROCESS The Registrant has previously filed with the Commission a Form F-X in connection with the Trust Units. Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Securities and Exchange Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement. 8 EXHIBITS The following exhibits are filed as part of this report. Exhibit Number Description 23.1 Consent of PricewaterhouseCoopers LLP to the inclusion of the Auditors' Report dated March 5, 2008 on the Registrant's Audited Consolidated Financial Statements for the fiscal year ended December 31, 2007. 23.2 Consent of KPMG LLP 23.3 Consent of Sproule Associated Limited to the incorporation by reference herein of its Statement of Reserves Data and other Information in Form 51-101F1, which statement and report is contained in the Registrant's Annual Information Form for the fiscal year ended December 31, 2007. 31.1 CEO Certification pursuant to rule 13a-14(a) of the Exchange Act. 31.2 CFO Certification pursuant to rule 13a-14(a) of the Exchange Act. 32.1 CEO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 CFO Certification pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.1 Annual Information Form of the Registrant for the year ended December 31, 2007. 99.2 Consolidated Financial Statements of the Registrant for the fiscal year ended December 31, 2007, including a reconciliation to US GAAP (Note 15). 99.3 Management's Discussion and Analysis of the Registrant for the fiscal year ended December 31, 2007. 99.4 Report of KPMG LLP. 9 SIGNATURE Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report on Form 40-F to be signed on its behalf by the undersigned, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada. Dated: March 28, 2008 ADVANTAGE ENERGY INCOME FUND By: /s/ Peter Hanrahan --------------------------------------- Name: Peter Hanrahan Title: Vice-President, Finance and Chief Financial Officer of Advantage Oil & Gas Ltd. on behalf of Advantage Energy Income Fund 10 EX-23 2 ex23-1form40f_2007.txt EXHIBIT 23.1 EXHIBIT 23.1 ------------ [GRAPHIC OMITTED -- LOGO] PRICEWATERHOUSECOOPERS LLP - ------------------------------------------------------------------------------- | PRICEWATERHOUSECOOPERS LLP | CHARTERED ACCOUNTANTS | 111 5th Avenue SW, Suite 3100 | Calgary, Alberta | Canada T2P 5L3 | Telephone +1 (403) 509 7500 | Facsimile +1 (403) 781 1825 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the inclusion in the Advantage Energy Income Funds' Annual Report on Form 40-F for the year ended December 31, 2007 of our report dated March 5, 2008, on the consolidated balance sheet of Advantage Energy Income Fund at December 31, 2007 and the consolidated statements of income (loss), comprehensive income and accumulated deficit and cash flows for the year ended December 31, 2007 and the effectiveness of internal control over financial reporting as of December 31, 2007. /s/ PricewaterhouseCoopers LLP Chartered Accountants Calgary, Alberta March 5, 2008 PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity. EX-23 3 ex23-2form40f_2007.txt EXHIBIT 23.2 EXHIBIT 23.2 ------------ - -------------------------------------------------------------------------------- [GRAPHIC OMMITTED] KPGM LLP LOGO -- K P M G CHARTERED ACCOUNTANTS Telephone (403) 691-8000 2700 205 - 5th Avenue SW Fax (403) 691-8008 Calgary AB T2P 4B9 Internet www.kpmg.ca - -------------------------------------------------------------------------------- CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Advantage Oil & Gas Limited We consent to the inclusion in this annual report on Form 40-F of: - our Report of Independent Registered Public Accounting Firm dated March 21, 2007 on the consolidated balance sheet of Advantage Energy Income Fund ("the Fund") as at December 31, 2006, and the consolidated statements of income and accumulated deficit and cash flows for the year then ended. - our Report of Independent Registered Public Accounting Firm dated March 21, 2007 on management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 and the effectiveness of internal control over financial reporting as of December 31, 2006 each of which is included in this annual report on Form 40-F of the Company for the fiscal year ended December 31, 2007. /s/ KPMG LLP Chartered Accountants Calgary, Canada March 28, 2008 - -------------------------------------------------------------------------------- KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International, a Swiss cooperative. KPMG Canada provides services to KPMG LLP. - -------------------------------------------------------------------------------- EX-23 4 ex23-3form40f_2007.txt EXHIBIT 23.3 EXHIBIT 23.3 ------------ March 28, 2008 CONSENT OF INDEPENDENT ENGINEERS We refer to our report entitled "Evaluation of the P&NG Reserves of Advantage Energy Income Fund (As of December 31, 2007)", dated February 21, 2008 (the "Report"). We hereby consent to the use of our name and references to excerpts from the Report in the Annual Report on Form 40-F of Advantage Energy Income Fund for the year ended December 31, 2007. Sincerely, SPROULE ASSOCIATES LIMITED ORIGINAL SIGNED BY CAMERON P. SIX Cameron P. Six, P.Eng Manager, Engineering EX-31 5 ex31-1form40f_2007.txt EXHIBIT 31.1 EXHIBIT 31.1 ------------ CEO CERTIFICATION PURSUANT TO RULE 13A-14 (A) OF THE SECURITIES EXCHANGE ACT OF 1934 I, Kelly Drader, certify that: 1. I have reviewed this annual report on Form 40-F of Advantage Energy Income Fund; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; 4. The issuer's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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 principals; c) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. 5. The issuer's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. Date: March 28, 2008 /s/ Kelly Drader --------------------------------- Kelly Drader Chief Executive Officer of Advantage Oil & Gas Ltd. on behalf of Advantage Energy Income Fund EX-31 6 ex31-2form40f_2007.txt EXHIBIT 31.2 EXHIBIT 31.2 ------------ CFO CERTIFICATION PURSUANT TO RULE 13A-14 (A) OF THE SECURITIES EXCHANGE ACT OF 1934 I, Peter Hanrahan, certify that: 1. I have reviewed this annual report on Form 40-F of Advantage Energy Income Fund; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; 4. The issuer's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and c) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. 5. The issuer's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. Date: March 28, 2008 /s/ Peter Hanrahan ---------------------------------- Peter Hanrahan Vice-President, Finance and Chief Financial Officer of Advantage Oil & Gas Ltd. on behalf of Advantage Energy Income Fund EX-32 7 ex32-1form40f_2007.txt EXHIBIT 32.1 EXHIBIT 32.1 ------------ CEO CERTIFICATION PURSUANT TO U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Advantage Energy Income Fund and Advantage Oil & Gas Ltd. on Form 40-F for the fiscal year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Kelly Drader, Chief Executive Officer of Advantage Oil & Gas Ltd., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust. Date: March 28, 2008 /s/ Kelly Drader ----------------------------------- Kelly Drader Chief Executive Officer of Advantage Oil & Gas Ltd. on behalf of Advantage Energy Income Fund EX-32 8 ex32-2form40f_2007.txt EXHIBIT 32.2 EXHIBIT 32.2 ------------ CFO CERTIFICATION PURSUANT TO U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Advantage Energy Income Fund (the "Trust") and Advantage Oil & Gas Ltd. on Form 40-F for the fiscal year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Peter Hanrahan, Vice President, Finance and Chief Financial Officer of Advantage Oil & Gas Ltd., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust. Date: March 28, 2008 /s/ Peter Hanrahan ---------------------------------- Peter Hanrahan Vice-President, Finance and Chief Financial Officer of Advantage Oil & Gas Ltd. on behalf of Advantage Energy Income Fund EX-99 9 ex99-1form40f_2007.txt EXHIBIT 99.1 EXHIBIT 99.1 ------------ [GRAPHIC OMITTED -- LOGO] ADVANTAGE ENERGY INCOME FUND ANNUAL INFORMATION FORM YEAR ENDED DECEMBER 31, 2007 March 28, 2008 TABLE OF CONTENTS PAGE GLOSSARY OF TERMS..............................................................1 ABBREVIATIONS..................................................................4 CONVERSION.....................................................................4 ADVANTAGE ENERGY INCOME FUND...................................................6 GENERAL DEVELOPMENT OF THE BUSINESS............................................7 DESCRIPTION OF OUR BUSINESS AND OPERATIONS....................................10 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................12 ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND................34 ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.....................41 MARKET FOR SECURITIES.........................................................49 ESCROWED SECURITIES...........................................................53 LEGAL PROCEEDINGS.............................................................53 REGULATORY ACTIONS............................................................53 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS....................54 MATERIAL CONTRACTS............................................................54 INTEREST OF EXPERTS...........................................................54 AUDITORS, TRANSFER AGENT AND REGISTRAR........................................54 AUDIT COMMITTEE INFORMATION...................................................54 AUDIT COMMITTEE CHARTER.......................................................55 AUDIT SERVICE FEES............................................................60 INDUSTRY CONDITIONS...........................................................60 RISK FACTORS..................................................................66 DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE........78 ADDITIONAL INFORMATION........................................................79 SCHEDULES "A" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION "B" - REPORT ON RESERVES DATA GLOSSARY OF TERMS "6.50% DEBENTURES" means 6.50% convertible unsecured subordinated debentures of the Trust due June 30, 2010; "7.50% DEBENTURES" means 7.50% convertible unsecured subordinated debentures of the Trust due October 1, 2009; "7.75% DEBENTURES" means 7.75% convertible unsecured subordinated debentures of the Trust due December 1, 2011; "8.00% DEBENTURES" means 8.00% convertible unsecured subordinated debentures of the Trust due December 31, 2011; "8.25% DEBENTURES" means 8.25% convertible unsecured subordinated debentures of the Trust due February 1, 2009; "8.75% DEBENTURES" means 8.75% convertible unsecured subordinated debentures of the Trust due June 30, 2009; "9.00% DEBENTURES" means 9.00% convertible unsecured subordinated debentures of the Trust due August 1, 2008; "ADMINISTRATION AGREEMENT" means the agreement entered into between the Trustee and AOG dated as of June 23, 2006 and providing for the administration of the Trust; "ADMINISTRATOR" means AOG; "ADVANTAGE" or the "TRUST" means Advantage Energy Income Fund, an unincorporated trust formed under the laws of the Province of Alberta pursuant to the Trust Indenture. All references to "ADVANTAGE" or the "TRUST", unless the context otherwise requires, are references to Advantage and its predecessors and subsidiaries; "AIM" means Advantage Investment Management Ltd., a corporation incorporated under the ABCA and which amalgamated with AOG effective June 23, 2006; "AOG" or the "CORPORATION" means Advantage Oil & Gas Ltd., a corporation incorporated under the ABCA and a wholly-owned subsidiary of the Trust. All references to "AOG", unless the context otherwise requires, are references to Advantage Oil & Gas Ltd. and its predecessors; "AOG BOARD OF DIRECTORS" or "BOARD OF DIRECTORS" means the board of directors of Advantage Oil & Gas Ltd.; "ARRANGEMENT" means the plan of arrangement involving Advantage, AOG, Ketch, Ketch Resources Ltd., Advantage ExchangeCo II Ltd., AIM, 1231801 Alberta Ltd., Advantage Unitholders and unitholders of Ketch completed on June 23, 2006 whereby each trust unit of Ketch was exchanged for 0.565 of a Trust Unit on a tax-deferred basis in Canada; "COMMON SHARES" means the common shares of AOG; "DEBENTURES" means, collectively, the 6.50% Debentures, 7.50% Debentures, 7.75% Debentures, 8.00% Debentures, 8.25% Debentures, 8.75% Debentures and 9.00% Debentures; "DISTRIBUTION RECORD DATE" means, until otherwise determined by the Trustee, the last day of each month of each year, provided that if the last day of the month is not a Business Day, then the Distribution Record Date for such month will be the first Business Day following the last day of each month of the year or such other dates in any year determined from time to time by the Trustee, but December 31 in each year shall be a Distribution Record Date; "ESCROW AGREEMENT" means the agreement entered into among the Trustee, the Trust and various securityholders dated as of April 24, 2006; "INITIAL PERMITTED SECURITIES" means any equity or debt securities, or rights thereto, authorized or issued from time to time by AOG including, without limitation, the Common Shares, Preferred Shares and Notes; "KETCH" means Ketch Resources Trust; 2 "LONG TERM NOTE INDENTURE" means the master note indenture dated September 30, 2004 between AOG and the Trustee providing for the issuance of the Long Term Notes; "LONG TERM NOTES" means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Long Term Note Indenture; "MEDIUM TERM NOTE INDENTURE" means the master note indenture dated September 30, 2004 between AOG and the Trustee providing for the issue of Medium Term Notes; "MEDIUM TERM NOTES" means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Medium Term Note Indenture; "NOTE INDENTURES" means, collectively, the Long Term Note Indenture and the Medium Term Note Indenture; "NOTE TRUSTEE" means Computershare Trust Company of Canada, or its successor as trustee under the Note Indentures; "NOTES" means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Note Indentures; "NYSE" means the New York Stock Exchange; "OIL AND NATURAL GAS PROPERTIES" or "PROPERTIES" means the working, royalty or other interests of AOG in any petroleum and natural gas rights, tangibles and miscellaneous interests, including properties which may be acquired by AOG from time to time; "PERMITTED INVESTMENTS" means, with respect to up to 25% of our total assets, (unless otherwise approved by the AOG Board of Directors from time to time): (i) obligations issued or guaranteed by the government of Canada or any province of Canada or any agency or instrumentality thereof; (ii) term deposits, guaranteed investment certificates, certificates of deposit or bankers' acceptances of or guaranteed by any Canadian chartered bank or other financial institutions (including the Trustee and any affiliate of the Trustee) the short-term debt or deposits of which have been rated at least A or the equivalent by Standard & Poor's Corporation, Moody's Investors Service, Inc. or Dominion Bond Rating Service Limited; (iii) commercial paper rated at least A or the equivalent by Dominion Bond Rating Service Limited, in each case maturing within 180 days after the date of acquisition; and (iv) trust units and limited partnership units in trusts and limited partnerships which invest in energy related assets including all types of petroleum and natural gas and energy related assets, and including, without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets; "PETROLEUM SUBSTANCES" means petroleum, natural gas and related hydrocarbons (except coal) including, without limitation, all liquid hydrocarbons, and all other substances, including sulphur, whether gaseous, liquid or solid and whether hydrocarbon or not, produced in association with such petroleum, natural gas or related hydrocarbons; "RESOURCE PROPERTIES" means Canadian resource properties as defined in the Tax Act; "ROYALTY" means the 99% interest in AOG 's Petroleum Substances within, upon or under certain of its Oil and Natural Gas Properties granted pursuant to the Royalty Agreement; "ROYALTY AGREEMENT" means the royalty agreement entered into between AOG and us dated as of June 24, 2006 and providing for the creation of the Royalty; "SET" means SET Resources Inc.; "SETTLED AMOUNT" means the amount of one hundred dollars in lawful money of Canada paid by our settlor to the Trustee for the purpose of settling the Trust; "SOUND" means Sound Resources Trust; 3 "SOUND ARRANGEMENT" means the plan of arrangement involving Advantage, AOG, Sound and SET, various subsidiaries of Advantage, AOG, Sound and SET, holders of trust units of Sound and holders of exchangeable shares of SET, completed on September 5, 2007; "SUBSEQUENT INVESTMENT" means those investments which we are permitted to make pursuant to the Trust Indenture, namely royalties in respect of properties and securities of AOG or any other subsidiary of the Trust to fund the acquisition, development, exploitation and disposition of all types of petroleum and natural gas and energy related assets, including without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets and whether effected through an acquisition of assets or an acquisition of shares or other form of ownership interest in any entity the substantial majority of the assets of which are comprised of like assets; "TAX ACT" means the INCOME TAX ACT (Canada), R.S.C. 1985, c.1 (5th Supp), as amended, including the regulations thereunder; "TRUST FUND", at any time, shall mean such of the following monies, properties and assets that are at such time held by the Trustee for the purposes of the Trust under the Trust Indenture: (i) the Settled Amount; (ii) the Initial Permitted Securities; (iii) the Royalty; (iv) all funds realized from the sale of, or Permitted Investments obtained in exchange for, Trust Units from time to time; (v) any Permitted Investments in which funds may from time to time be invested; (vi) any Subsequent Investments; (vii) any proceeds of disposition of any of the foregoing property including, without limitation, the Royalty but not Trust Units in the case of a redemption thereof to which Section 9.5 of the Trust Indenture applies; and (viii) all income, interest, dividends, return of capital, profit, gains and accretions and additional assets, rights and benefits of any kind or nature whatsoever arising directly or indirectly from or in connection with or accretions to or accruals in respect of any of the foregoing property or such proceeds of disposition from time to time; "TRUST INDENTURE" means the trust indenture between Computershare Trust Company of Canada and AOG made effective as of April 17, 2001, supplemented as of May 22, 2002 and amended and restated as of June 25, 2002, May 28, 2002, May 26, 2004, April 27, 2005, December 13, 2005, June 23, 2006 and December 31, 2007, pursuant to which Advantage was formed, as the same may be further amended, restated or replaced from time to time; "TRUST UNIT" or "UNIT" means a unit of the Trust, each unit representing an equal undivided beneficial interest therein; "TRUSTEE" means Computershare Trust Company of Canada or its successor or successors as trustee under the Trust Indenture; "TSX" means the Toronto Stock Exchange; "UNITHOLDERS" means the holders from time to time of one or more Trust Units, as shown on the register of such holders maintained by the Trust or by the Trustee, as transfer agent of the Trust Units, on behalf of the Trust; and "U.S." means the United States of America. Words importing the singular number only include the plural, and VICE VERSA, and words importing any gender include all genders. All dollar amounts set forth in this annual information form are in Canadian dollars, except where otherwise indicated. 4 ABBREVIATIONS
OIL AND NATURAL GAS LIQUIDS NATURAL GAS bbls barrels Mcf thousand cubic feet Mbbls thousand barrels MMcf million cubic feet MMbbls million barrels bcf billion cubic feet NGLs natural gas liquids Mcf/d thousand cubic feet per day stb stock tank barrels of oil MMcf/d million cubic feet per day Mstb thousand stock tank barrels of oil m(3) cubic metres MMboe million barrels of oil equivalent MMbtu million British Thermal Units boe/d barrels of oil equivalent per day GJ Gigajoule bbls/d barrels of oil per day
OTHER BOEor boe means barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one bbl of oil. The conversion factor used to convert natural gas to oil equivalent is not necessarily based upon either energy or price equivalents at this time. WTI means West Texas Intermediate. (Degree)API means the measure of the density or gravity of liquid petroleum products derived from a specific gravity. psi means pounds per square inch. CONVERSION The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units). TO CONVERT FROM TO MULTIPLY BY Mcf cubic metres 28.174 cubic metres cubic feet 35.494 bbls cubic metres 0.159 cubic metres bbls 6.293 feet metres 0.305 metres feet 3.281 miles kilometres 1.609 kilometres miles 0.621 acres hectares 0.405 hectares acres 2.471 gigajoules MMbtu 0.950 5 YOU SHOULD NOT RELY ON FORWARD-LOOKING STATEMENTS BECAUSE THEY ARE INHERENTLY UNCERTAIN Certain statements contained in this annual information form, and in certain documents incorporated by reference into this annual information form, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We and AOG believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this annual information form should not be unduly relied upon. These statements speak only as of the date of this annual information form or as of the date specified in the documents incorporated by reference into this annual information form, as the case may be. In particular, this annual information form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following: o the performance characteristics of our assets; o oil and natural gas production levels; o the size of the oil and natural gas reserves; o projections of market prices and costs and the related sensitivities of distributions; o supply and demand for oil and natural gas; o expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; o treatment under governmental regulatory regimes; and o capital expenditures programs. The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this annual information form: o volatility in market prices for oil and natural gas; o liabilities inherent in oil and natural gas operations; o uncertainties associated with estimating oil and natural gas reserves; o competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; o incorrect assessments of the value of acquisitions; o fluctuation in foreign exchange or interest rates; o stock market volatility and market valuations; o changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts; o geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and o the other factors discussed under "RISK FACTORS". Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward looking statements contained in this annual information form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Except as required by law, neither the Trust or AOG undertakes any obligation to publicly update or revise any forward-looking statements and readers should also carefully consider the matters discussed under the heading "Risk Factors" in this annual information form. 6 ADVANTAGE ENERGY INCOME FUND GENERAL Advantage Energy Income Fund ("ADVANTAGE", the "TRUST", the "FUND", "US", "WE", or "OUR" and, where the context requires, also includes the Trust's subsidiaries) is an entity that provides monthly cash distributions to its holders ("UNITHOLDERS") of trust units ("TRUST UNITS") of the Trust. Advantage was created under the laws of the Province of Alberta pursuant to the Trust Indenture. It is, for Canadian tax purposes, an open-ended mutual fund trust and is categorized as a "natural resource issuer" for the purposes of Canadian securities laws. The Trust is administered by the Trustee. The beneficiaries of the Trust are the Unitholders. Advantage Oil & Gas Ltd. ("AOG") is our wholly-owned oil and natural gas exploitation and development company. It was originally incorporated in 1979 as Westrex Energy Corp. ("WESTREX"). Through a plan of arrangement under the BUSINESS CORPORATIONS ACT (Alberta) ("ABCA"), Westrex merged with Search Energy Inc. on December 31, 1996, and changed its name to Search Energy Corp. ("SEARCH") on January 2, 1997. Effective May 24, 2001, all of the issued and outstanding common shares of Search were acquired by 925212 Alberta Ltd. ("ACQUISITIONCO"), a company wholly-owned by us. Search and AcquisitionCo amalgamated and continued as "Search Energy Corp.". On July 26, 2001, Search acquired all of the issued and outstanding shares of Due West Resources Inc. ("DUE WEST"). Effective August 1, 2001, Search and Due West amalgamated and continued as "Search Energy Corp.". Effective January 1, 2002, Search acquired a number of natural gas properties located primarily in southern Alberta formerly administered by Gascan Resources Ltd. On June 26, 2002, Search changed its name to Advantage Oil & Gas Ltd. On November 18, 2002, AOG acquired all of the issued and outstanding shares of Best Pacific Resources Ltd. ("BEST PACIFIC"), after which Best Pacific assigned all of its assets to AOG and dissolved. On December 2, 2003, AOG acquired all of the issued and outstanding shares of MarkWest Resources Canada Corp. ("MARKWEST"). MarkWest amalgamated with AOG effective January 1, 2004. On September 15, 2004, we indirectly acquired certain petroleum and natural gas properties and related assets from Anadarko Canada Corporation ("ANADARKO") for approximately $186,000,000 before closing adjustments. On December 21, 2004, we indirectly acquired Defiant Energy Corporation ("DEFIANT") by way of a plan of arrangement involving a combination of cash consideration, Trust Units and Exchangeable Shares of AOG. Effective January 1, 2005, Defiant amalgamated with AOG. Effective February 1, 2006, Advantage ExchangeCo Ltd. amalgamated with AOG. Effective June 23, 2006, Advantage and Ketch completed the Arrangement with the combined entity continuing under the name Advantage Energy Income Fund. See "GENERAL DEVELOPMENT OF THE BUSINESS". Prior to completion of the Arrangement, Advantage Investment Management Ltd. ("AIM") acted as manager of the Trust and of AOG. As part of the Arrangement, Advantage internalized its external management structure and eliminated all related fees by acquiring all of the outstanding shares of AIM for total consideration initially valued at $39.1 million, paid through the issuance of 1,933,208 Trust Units which have been placed in escrow and are releasable as to one-third on each of the first three anniversaries of the Arrangement. Effective September 5, 2007, Advantage and Sound completed the Sound Arrangement whereby Advantage acquired all of the issued and outstanding trust units of Sound and exchangeable shares of SET for consideration of either (i) 0.30 of a Unit; or (ii) $0.66 in cash and 0.2557 of a Unit, for each Sound trust unit or SET exchangeable share held. In connection with the Sound Arrangement, SET, AOG and various other subsidiaries of Advantage, AOG, SET and Sound amalgamated to form "Advantage Oil & Gas Ltd." See "GENERAL DEVELOPMENT OF THE BUSINESS". Our head office, the head office of AOG and the registered office of AOG is located at Suite 700, 400, 3 Avenue S.W., Calgary, Alberta T2P 4H2. 7 OUR ORGANIZATIONAL STRUCTURE The following diagram sets forth our organizational structure as at the date hereof. [GRAPHIC OMITTED -- ORGANIZATIONAL CHART] ------------------------ ADVANTAGE UNITHOLDERS(1) ------------------------ Cash ^ ^ | Distributions | | | Advantage Units | | | (100%) | |Income from | | |Permitted | | |Investment | | | | | | | | | /\ | | | / \ | | | / \ | | | / \ | | |/ \ | | / \ | | / \ v | / \ / \ / ADVANTAGE ENERGY \ / INCOME FUND(2)(3) \ / (Alberta) \ / \ -------------------------- ^ | | | | Interest and | royalty, | pricipal payments, | notes, | royalty payments | 100% | and dividends on | shares | common shares | | v ------------------------------ ADVANTAGE OIL & GAS LTD. ------------------------------ Notes: (1) The Unitholders own 100% of the Trust. (2) All our operations and management are conducted through AOG. (3) Advantage receives regular monthly payments in accordance with the Royalty Agreement as well as principal and interest payments from the Advantage Notes and dividends from the Common Shares. In accordance with the terms of the Trust Indenture, holders of Trust Units are entitled to direct us as to how to vote in respect of all matters to be placed before us, including the selection of directors of AOG, approving AOG's financial statements, and appointing the auditors of AOG, who shall be the same as our auditors. GENERAL DEVELOPMENT OF THE BUSINESS 2005 On February 9, 2005, we completed an issue, by way of short form prospectus, of 5,250,000 Trust Units at $21.65 per Trust Unit for gross proceeds of $113,662,500. The net proceeds of the offering were used to pay down debt incurred in the Defiant Acquisition, for our 2005 capital expenditure program and for general corporate purposes. 8 On December 9, 2005, the Trust Units were listed and posted for trading on the New York Stock Exchange (the "NYSE") under the trading symbol "AAV". The listing on the NYSE has resulted in improved liquidity for all Unitholders, greater access to the U.S. capital markets, and improved cost of capital for future acquisitions. 2006 On March 8, 2006, AOG elected to exercise its redemption right to redeem all of its outstanding exchangeable shares. The redemption price per exchangeable share was satisfied by delivering that number of Trust Units equal to the exchange ratio of 1.22138 in effect on May 9, 2006. During 2006, we issued 127,014 Trust Units for the remaining AOG exchangeable shares. On June 23, 2006 we completed the merger of Advantage and Ketch under the terms of the Arrangement. The merger was accomplished through the exchange of each trust unit of Ketch for 0.565 of a Trust Unit of Advantage and upon completion, Advantage Unitholders owned approximately 65% of the combined trust and Ketch unitholders owed approximately 35%. On July 24, 2006 we announced that we adopted a Premium Distribution(TM), Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "PLAN"). The Plan commenced with the monthly cash distribution payable on August 15, 2006 to Unitholders who elected to participate and have their monthly distribution obligation settled through the issuance of additional Trust Units at 95% of the average market price (as defined in the Plan). On August 1, 2006 we issued 7,500,000 Trust Units under a short-form prospectus offering at $17.30 per Trust Unit. An additional 1,125,000 Trust Units were issued on August 4, 2006 at $17.30 per Trust Unit upon full exercise of the over-allotment option provided to the underwriters. The net proceeds of the offering of approximately $141.4 million were used to pay down bank indebtedness and to subsequently fund capital and general corporate expenditures. 2007 On January 19, 2007, we announced that the cash distribution to be paid on February 15, 2007 to Unitholders of record on January 31, 2007 would be adjusted to $0.15 per Trust Unit from the then current distribution rate of $0.18 per Trust Unit and that the reduction in the monthly distribution rate arose as a result of recent weakness in crude oil and natural gas prices which have been driven by an abnormally mild winter heating season. On January 19, 2007, we also announced that the Board of Directors of AOG approved our 2007 capital expenditure budget at between $120 and $145 million. On February 14, 2007 we issued 7,800,000 Trust Units under a short-form prospectus offering at $12.80 per Trust Unit. An additional 800,000 Trust Units were issued on March 7, 2007 at $12.80 per Trust Unit upon exercise of the over-allotment option provided to the underwriters. The net proceeds of the offering of approximately $104.1 million were used to pay down bank indebtedness and to fund capital and general corporate expenditures. On June 22, 2007, new legislation was passed pursuant to which, commencing January 1, 2011 (provided that we only experience "normal growth" and no "undue expansion" before then) certain distributions will be subject to at trust-level tax, and will be characterized as dividends to the unitholders. See "RISK FACTORS - CHANGES IN LEGISLATION - SIFT TAX". On July 9, 2007 Advantage and Sound jointly announced that their respective boards of directors had approved the Sound Arrangement. On September 5, 2007, the Sound Arrangement was approved by the holders of trust units of Sound ("SOUND UNITS") and holders of exchangeable shares of SET ("SOUND EXCHANGEABLE SHARES") and Advantage completed the acquisition of all of the outstanding Sound Units and Sound Exchangeable Shares. Pursuant to the Sound Arrangement, holders of Sound Units received 0.30 of a Unit for each Sound Unit held or, at the election of the holder of Sound Units ("SOUND UNITHOLDERS"), $0.66 in cash and 0.2557 of a Unit. In addition, all Sound Exchangeable Shares were exchanged for Units or Units and cash at the election of the holders of Sound Exchangeable Shares on the same terms as those offered to Sound Unitholders based on the exchange ratio in effect at the effective date of the Sound Arrangement. In total 16,977,184 Units and $21.4 million in cash was issued to holders of Sound Units and Sound Exchangeable Shares. In addition, Advantage also assumed approximately $108.0 million of bank indebtedness upon closing of the Sound Arrangement. See "SIGNIFICANT ACQUISITIONS" below. 9 On August 16, 2007, we announced that Stephen Balog had been appointed to the Board of Directors of AOG. We negotiated an increase to our credit facilities in September of 2007 and currently have a $710 million credit facility agreement consisting of a $690 million extendible revolving loan facility and a $20 million operating loan facility. The credit facilities are secured by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement covering all assets and cash flows. On September 18, 2007, our former auditors KPMG LLP resigned as auditors of the Trust and PricewaterhouseCoopers LLP were appointed the auditors of the Trust. On December 14, 2007, Advantage announced that in light of the recent strength of the Canadian dollar combined with the continuing weakness in crude oil and natural gas prices, the Board of Directors of Advantage felt it is prudent to adjust the cash distribution beginning with the month of December to $0.12 per Unit from the current $0.15 per Unit. On December 14, 2007, we also announced that the Board of Directors of AOG approved our 2008 capital expenditure budget at between $130 and $145 million. RECENT DEVELOPMENTS Advantage has completed additional hedging for 2008 and 2009 to (i) stabilize cash flows and (ii) ensure that the Trust's capital program is substantially funded out of cash flow. Approximately 53% (net of royalties) of Advantage's natural gas is hedged for the 2008 calendar year at a floor of $7.52/mcf. Advantage also hedged 38% (net of royalties) of its 2008 crude oil production at an average price of $94.07/bbl. ANTICIPATED CHANGES IN THE BUSINESS As at the date hereof, we do not anticipate that any material change in our business shall occur during the balance of the 2008 financial year. SIGNIFICANT ACQUISITIONS On September 5, 2007, Advantage completed the acquisition of all of the Sound Units and Sound Exchangeable Shares. Pursuant to the Arrangement, holders of Sound Units received 0.30 of a Unit for each Sound Unit held or, at the election of the Sound Unitholders, $0.66 in cash and 0.2557 of a Unit. In addition, all Sound Exchangeable Shares were exchanged for Units or Units and cash at the election of the Sound Exchangeable Shareholder on the same terms as those offered to Sound Unitholders based on the exchange ratio in effect at the effective date of the Sound Arrangement. In total 16,977,184 Units and $21.4 million in cash was issued to holders of Sound Units and Sound Exchangeable Shares. In addition, Advantage also assumed approximately $108.0 million of bank indebtedness upon closing of the Sound Arrangement. On completion of the Sound Arrangement, Sound became an indirect wholly-owned subsidiary of AOG and as part of the Sound Arrangement, certain assets owned by Sound and SET were transferred to Advantage and AOG and SET was amalgamated with Sound ExchangeCo Ltd, 1135703 Alberta Ltd. and AOG to form "Advantage Oil & Gas Ltd." Prior to completion of the Sound Arrangement, the Sound Units traded on the TSX under the symbol SND.UN and the debentures issued by Sound (the "SOUND DEBENTURES") traded on the TSX under the symbols SND.DB and SND.DB.A. Following completion of the Arrangement, the Sound Units were delisted from trading on the TSX and Advantage assumed all of Sound's covenants and obligations with respect to the outstanding Sound Debentures. The debentures now trade on the TSX under the symbols "AVN.DB.F" and "AVN.DB.G" for the 8.75% Debentures and the 8.00% Debentures, respectively. Advantage made an offer to purchase all of the outstanding 8.75% Debentures and 8.00% Debentures at a price equal to 101% of the principal amount plus any accrued and unpaid interest. Pursuant to the offer, $35,958,000 principal amount of 8.75% Debentures and 8.00% Debentures plus accrued and unpaid interest were tendered in exchange for the issuance of 3,131,998 Trust Units, and $19,214,000 principal amount of 8.75% Debentures plus accrued and unpaid interest were tendered for cash. The Trust Units issued and cash paid represented 101% of the tendered 8.75% Debentures and 8.00% Debentures principal amount plus accrued and unpaid interest for July 1 to October 18, 2007. 10 The Sound Arrangement had the effect of improving Advantage's payout ratio and provided substantial operating synergies for the combined trust. The combined entity has a significant prospect inventory and an undeveloped land position of approximately 686,000 net acres, providing significant growth opportunities, complementary winter/summer drilling programs, a reduction in general administration costs, and further control and synergies in the common combined properties. Unitholders benefited through the addition of Sound's tax pools of approximately $394 million, a 30% increase, for combined tax pools in excess of approximately $1.7 billion at December 31, 2007. The combined entity had a 2007 exit rate production of approximately 34,300 boe/d weighted 63% natural gas and 37% light oil and NGLs. The combined entity also has a Proved plus Probable Reserve Life Index of approximately 12.1 years using average 2007 fourth quarter production and December 31, 2007 proved plus probable reserves. DESCRIPTION OF OUR BUSINESS AND OPERATIONS ADVANTAGE ENERGY INCOME FUND We are a limited purpose trust and are restricted to: 1. investing in the Initial Permitted Securities, the Permitted Investments, Subsequent Investments and such other securities and investments as AOG may determine, provided that under no circumstances shall the Trustee or AOG purchase or authorize the purchase of any security, asset or investment (collectively a "PROHIBITED INVESTMENT") on our behalf or using any of our assets or property which are defined as "foreign property" under subsection 206(1) of the Tax Act or are a "small business security" as that expression is used in Part LI of the Regulations to the Tax Act or would result in us not being considered either a "unit trust" or a "mutual fund trust" for purposes of the Tax Act at the time such investment was made; 2. disposing of any part of the Trust Fund, including, without limitation, any Permitted Investments; 3. acquiring the Royalty and other royalties in respect of Resource Properties; 4. temporarily holding cash, and Permitted Investments (including investments in AOG) for the purposes of paying Trust expenses and Trust liabilities, paying amounts payable by us in connection with the redemption of any Trust Units, and making distributions to Unitholders; 5. acquiring or investing in securities of AOG or any other subsidiary of ours to fund the acquisition, development, exploitation and disposition of all types of petroleum and natural gas related assets, including, without limitation, facilities of any kind and whether effected through the acquisition of assets or the acquisition of shares or other form of ownership interest in any entity, the substantial majority of the assets of which are comprised of like assets; 6. undertaking such other business and activities including investing in securities as shall be approved by AOG from time to time provided that we shall not undertake any business or activity which is a Prohibited Investment (as defined in the Trust Indenture); and to pay the costs, fees and expenses associated therewith or incidental thereto. In accordance with the terms of the Trust Indenture, we will make cash distributions to our Unitholders of the interest income earned from the Long Term Notes and Medium Terms Notes and principal repayments, royalty income earned on the Royalty, dividends (if any) received on, and amounts, if any, received on redemption of, Common Shares and Preferred Shares, and income and distributions received from any Permitted Investments after expenses and capital expenditures, any cash redemptions of Trust Units, and other expenditures. See "ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND - CASH DISTRIBUTIONS". ADVANTAGE OIL & GAS LTD. AOG is actively engaged in the business of oil and gas exploration, development, acquisition and production in the provinces of Alberta, British Columbia and Saskatchewan. 11 We employ a strategy to maintain production from AOG's existing production base while focusing capital expenditures on low-risk development opportunities. As a practice, AOG may manage the risk associated with changes in commodity prices by entering into oil or natural gas hedges related only to specific acquisition or project economics. See "RISK FACTORS". AOG generally sells or farms out higher risk projects while actively pursuing growth opportunities through oil and gas property acquisitions, as well as through corporate acquisitions. AOG targets acquisitions that are accretive to net asset value and that increase our reserve and production base per Trust Unit outstanding. Acquisitions must also meet reserve life index criteria and exhibit low risk opportunities to increase reserves and production. It is currently intended that AOG will finance acquisitions and investments through bank financing, the issuance of additional Trust Units from treasury and the issuance of subordinated convertible debentures, maintaining prudent leverage. REORGANIZATIONS Other than the Arrangement and the Sound Arrangement, there have been no material reorganizations of Advantage or AOG and or any of our subsidiaries within the three most recently completed financial years or proposed for the current financial year. 12 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION The report of management and directors on oil and gas disclosure in Form 51-101F3 and the report on reserves data by Sproule Associates Limited ("SPROULE") in Form 51-101F2 are attached as Schedules "A" and "B" to this annual information form, which forms are incorporated herein by reference. The statement of reserves data and other oil and gas information set forth below (the "STATEMENT") is dated December 31, 2007. The effective date of the Statement is December 31, 2007 and the preparation date of the Statement is February 21, 2008. DISCLOSURE OF RESERVES DATA The reserves data set forth below (the "RESERVES DATA") is based upon an evaluation by Sproule with an effective date of December 31, 2007 contained in a report of Sproule dated February 21, 2008 (the "SPROULE REPORT"). The Reserves Data summarizes our oil, natural gas liquids and natural gas reserves and the net present values of future net revenue for these reserves using forecast prices and costs. The Reserves Data conforms with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important to the readers of this information. We engaged Sproule to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves. All of our reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia and Saskatchewan. IT SHOULD NOT BE ASSUMED THAT THE ESTIMATES OF FUTURE NET REVENUES PRESENTED IN THE TABLES BELOW REPRESENT THE FAIR MARKET VALUE OF THE RESERVES. THERE IS NO ASSURANCE THAT THE FORECAST PRICES AND COSTS ASSUMPTIONS WILL BE ATTAINED AND VARIANCES COULD BE MATERIAL. THE RECOVERY AND RESERVE ESTIMATES OF OUR CRUDE OIL, NATURAL GAS LIQUIDS AND NATURAL GAS RESERVES PROVIDED HEREIN ARE ESTIMATES ONLY AND THERE IS NO GUARANTEE THAT THE ESTIMATED RESERVES WILL BE RECOVERED. ACTUAL CRUDE OIL, NATURAL GAS AND NATURAL GAS LIQUID RESERVES MAY BE GREATER THAN OR LESS THAN THE ESTIMATES PROVIDED HEREIN. IN CERTAIN OF THE TABLES SET FORTH BELOW, THE COLUMNS MAY NOT ADD DUE TO ROUNDING.
SUMMARY OF OIL AND GAS RESERVES as of December 31, 2007 FORECAST PRICES AND COSTS RESERVES ------------------------------------------------- LIGHT AND MEDIUM OIL HEAVY OIL ---------------------- -------------------- Gross Net Gross Net RESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) - ----------------- ------ ------ ------ ------ PROVED Developed Producing 22,060 19,670 1,814 1,631 Developed Non-Producing 473 392 126 107 Undeveloped 3,621 2,915 297 262 ------ ------ ----- ----- TOTAL PROVED 26,154 22,977 2,237 2,000 PROBABLE 17,477 14,891 3,271 3,061 ------ ------ ----- ----- TOTAL PROVED PLUS PROBABLE 43,630 37,869 5,508 5,061 ====== ====== ===== =====
13
RESERVES -------------------------------------------------- NATURAL GAS NATURAL GAS LIQUIDS ---------------------- --------------------- Gross Net Gross Net RESERVES CATEGORY (MMcf) (MMcf) (Mbbl) (Mbbl) - ----------------- ------ ------ ------ ------ PROVED Developed Producing 285,551 235,061 6,646 4,883 Developed Non-Producing 12,814 10,291 266 193 Undeveloped 52,568 41,340 928 695 ------- ------- ------ ----- TOTAL PROVED 350,933 286,693 7,840 5,772 PROBABLE 190,613 150,765 3,773 2,784 ------- ------- ------ ----- TOTAL PROVED PLUS PROBABLE 541,545 437,457 11,613 8,555 ======= ======= ====== =====
RESERVES ---------------------- TOTAL OIL EQUIVALENT ---------------------- Gross Net RESERVES CATEGORY (Mboe) (Mboe) - ----------------- ------ ------ PROVED Developed Producing 78,111 65,360 Developed Non-Producing 3,001 2,408 Undeveloped 13,608 10,763 ------- ------- TOTAL PROVED 94,720 78,531 PROBABLE 56,289 45,864 ------- ------- TOTAL PROVED PLUS PROBABLE 151,009 124,395 ======= =======
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE as at December 31, 2007 FORECAST PRICES AND COSTS Unit Value Before Income Tax Discounted at 10%/ Before Income Tax Discounted at (%/year) After Income Taxes Discounted at (%/year) year(1) ----------------------------------------------- ---------------------------------------------- ---------- 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% RESERVES CATEGORY ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($/boe) - ----------------- -------- --------- -------- --------- -------- -------- --------- --------- --------- --------- ------- PROVED Developed 2,680,441 1,904,687 1,526,798 1,296,565 1,138,260 2,680,441 1,904,687 1,526,798 1,296,565 1,138,260 23.36 Producing Developed 83,654 67,773 56,479 48,078 41,610 83,654 67,773 56,479 48,078 41,610 23.46 Non-Producing Undeveloped 298,697 217,260 155,502 111,869 80,524 298,697 217,260 155,502 111,869 80,524 14.45 --------- --------- --------- --------- --------- --------- --------- --------- --------- -------- ----- TOTAL PROVED 3,062,792 2,189,720 1,738,779 1,456,512 1,260,395 3,062,792 2,189,720 1,738,779 1,456,512 1,260,395 22.14 PROBABLE 2,038,534 1,100,987 723,831 524,663 402,141 1,725,277 1,009,488 691,311 511,544 396,373 15.78 --------- --------- --------- --------- --------- --------- --------- --------- --------- -------- ----- TOTAL PROVED PLUS PROBABLE 5,101,326 3,290,707 2,462,610 1,981,175 1,662,536 4,788,069 3,199,208 2,430,090 1,968,056 1,656,76 19.80 ========= ========= ========= ========= ========= ========= ========= ========= ========= ======== =====
Note: (1) The unit values are based on net reserve volumes. 14
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as of December 31, 2007 FORECAST PRICES AND COSTS FUTURE FUTURE NET NET REVENUE REVENUE ABANDONMENT AND BEFORE AFTER OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES RESERVES CATEGORY ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ----------------- -------- -------- -------- -------- -------- -------- -------- -------- Proved Reserves 5,949,781 965,309 1,632,590 190,146 98,945 3,062,792 0 3,062,792 Proved Plus Probable 9,876,777 1,632,999 2,627,152 386,792 128,508 5,101,326 313,257 4,788,068 Reserves
FUTURE NET REVENUE BY PRODUCTION GROUP as of December 31, 2007 FORECAST PRICES AND COSTS FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year) UNIT VALUE RESERVES CATEGORY PRODUCTION GROUP ($000's) ($/boe) - ------------------- ---------------------------------------- -------------------- ---------- Proved Reserves Light and Medium Crude Oil (including 746,109 26.74 solution gas and other by-products) Heavy Oil (including solution gas and 44,324 20.00 other by-products) Natural Gas (including by-products but 904,625 19.91 excluding solution gas and by-products from oil wells) Non-Conventional Oil and Gas Activities 43,721 16.57 --------- ----- TOTAL 1,738,779 22.14 ========= ===== Proved Plus Probable Light and Medium Crude Oil (including 1,099,825 24.24 Reserves solution gas and other by-products) Heavy Oil (including solution gas and 87,990 16.36 other by-products) Natural Gas (including by-products but 1,213,197 17.55 excluding solution gas and by-products from oil wells) Non-Conventional Oil and Gas Activities 61,598 15.88 --------- ----- TOTAL 2,462,610 19.80
PRICING ASSUMPTIONS The following tables set forth the benchmark reference prices, as at December 31, 2007, reflected in the Reserves Data. These price assumptions were provided to us by Sproule and were Sproule's then current forecasts at the date of the Sproule Report. 15
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1) as of December 31, 2007 FORECAST PRICES AND COSTS Light Sweet NATURAL NATURAL NATURAL Crude Oil GAS GAS LIQUIDS GAS WTI at Medium Hardisty AECO-C Edmonton LIQUIDS Cushing Edmonton Crude Oil Heavy 12o Spot Pentanes Edmonton INFLATION EXCHANGE Oklahoma 40o API 29o API API ($Cdn/ Plus Butanes RATES RATE (2) Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) MMBtu) ($Cdn/bbl) ($Cdn/bbl) %/Year ($US/$Cdn) ---- --------- ---------- ---------- ---------- ------ ---------- ---------- ------ ---------- Forecast(3) 2008 89.61 88.17 75.83 54.67 6.51 90.30 65.72 2.0 1.000 2009 86.01 84.54 72.71 52.42 7.22 86.58 63.01 2.0 1.000 2010 84.65 83.16 71.52 51.56 7.69 85.17 61.98 2.0 1.000 2011 82.77 81.26 69.89 50.38 7.70 83.23 60.57 2.0 1.000 2012 82.26 80.73 69.43 50.05 7.61 82.68 60.17 2.0 1.000 2013 82.81 81.25 69.88 50.38 7.78 83.21 60.56 2.0 1.000 2014 84.46 82.88 71.28 51.39 7.96 84.88 61.78 2.0 1.000 2015 86.15 84.55 72.71 52.42 8.14 86.59 63.02 2.0 1.000 2016 87.87 86.25 74.17 53.47 8.32 88.33 64.28 2.0 1.000 2017 89.63 87.98 75.66 54.55 8.51 90.10 65.58 2.0 1.000 2018 91.42 89.74 77.17 55.64 8.68 91.90 66.89 2.0 1.000 Thereafter +2%/year +2%/year +2%/year +2%/year +2%/year +2%/year +2%/year +2%/year 1.000
Notes: (1) This summary table identifies benchmark reference pricing schedules that might apply to a REPORTING ISSUER. (2) The exchange rate used to generate the benchmark reference prices in this table. (3) As at December 31. Weighted average historical prices, including hedging, realized by us for the year ended December 31, 2007, were $7.21/Mcf for natural gas, $66.92/bbl for crude oil, and $60.12/bbl for natural gas liquids. RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE
RECONCILIATION OF COMPANY GROSS RESERVES BY PRODUCT TYPE FORECAST PRICES AND COSTS Light And Medium Oil Heavy Oil Natural Gas Liquids --------------------------- ----------------------------- ----------------------------- WI WI WI Proved Proved Proved WI WI Plus WI WI Plus WI WI Plus Proved Probable Probable Proved Probable Probable Proved Probable Probable FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) - ------- ------ ------ ------ ------ ------ ------ ------ ------ ------ December 31, 2006 19,935 13,586 33,521 1,908 688 2,596 7,375 3,833 11,208 Extensions 327 1,340 1,667 55 13 68 232 287 519 Improved Recovery 678 644 1,322 0 0 0 197 349 546 Technical Revisions 177 (1,448) (1,271) (562) (112) (674) (95) (1,015) (1,110) Discoveries 24 17 41 0 0 0 9 2 11 Acquisitions 7,348 3,214 10,562 1,083 2,681 3,764 1,093 345 1,438 Dispositions 0 0 0 0 0 0 0 0 0 Economic Factors 370 123 493 1 1 2 (105) (28) (133) Production (2,705) 0 (2,705) (248) 0 (248) (866) 0 (866) ------ ------ ------ ----- ----- ----- ----- ----- ------ December 31, 2007 26,154 17,476 43,630 2,237 3,271 5,508 7,840 3,773 11,613 ====== ====== ====== ===== ===== ===== ===== ===== ======
16 Associated and Non-Associated Gas Natural Gas - Solution --------------------------------- ------------------------------- WI WI Proved Proved WI WI Plus WI WI Plus Proved Probable Probable Proved Probable Probable FACTORS (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) ------- ------- ------- ====== ======== ======== December 31, 2006 252,290 122,334 374,624 34,648 19,335 53,983 Extensions 9,988 12,411 22,399 1,387 1,443 2,830 Improved Recovery 12,071 27,406 39,477 1,633 1,833 3,466 Technical Revisions 519 (22,926) (22,407) (4,137) (6,096) (10,233) Discoveries 636 159 795 0 0 0 Acquisitions 59,907 21,657 81,564 5,130 2,999 8,129 Dispositions 0 0 0 0 0 0 Economic Factors (1,194) 1,446 252 589 167 756 Production (35,258) 0 (35,258) (5,268) 0 (5,268) ------- ------- ------- ------ ------ ------ December 31, 2007 298,959 162,487 461,446 33,982 19,681 53,663 ======= ======= ======= ====== ====== ====== Coalbed Methane Oil Equivalent ------------------------------- ------------------------------ WI WI Proved Proved WI WI Plus WI WI Plus Proved Probable Probable Proved Probable Probable FACTORS (mmcf) (mmcf) (mmcf) (MBoe) (MBoe) (MBoe) ------- ------- ------- ====== ======== ======== December 31, 2006 5,841 4,896 10,737 78,015 42,534 120,549 Extensions 3,319 1,643 4,962 3,062 4,223 7,285 Improved Recovery 1,012 238 1,250 3,328 5,906 9,234 Technical Revisions 908 (777) 131 (930) (7,542) (8,472) Discoveries 0 0 0 139 45 184 Acquisitions 9,057 2,438 11,495 21,872 10,756 32,628 Dispositions 0 0 0 0 0 0 Economic Factors 33 7 40 170 367 537 Production (2,178) 0 (2,178) (10,936) 0 (10,936) ------- ------- ------- ------ ------ ------ December 31, 2007 17,992 8,445 26,437 94,720 56,289 151,009 ======= ======= ======= ====== ====== ======
Notes: (1) Volumes related to infill drilling are included in the Improved Recovery category, noted above. ADDITIONAL INFORMATION RELATING TO RESERVES DATA UNDEVELOPED RESERVES Undeveloped reserves are attributed by Sproule in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Proved and probable undeveloped reserves have been assigned in accordance with engineering and geological practices as defined under NI 51-101. In general, undeveloped reserves are planned to be developed over the next two years. In some cases, it will take longer than two years to develop these reserves. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out 17 over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). For more information, see "Risk Factors". The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by product type, first attributed to us in each of the following financial years.
PROVED UNDEVELOPED RESERVES Light and Medium Oil Heavy Oil Natural Gas NGLs Year (Mbbl) (Mbbl) (MMcf) (Mbbl) - --------------- ----------------------- ------------------------ ----------------------- ----------------------- First Cumulative First Cumulative First Cumulative First Cumulative Attributed at Year End Attributed at Year End Attributed at Year End Attributed at Year End ---------- ----------- ---------- ----------- ---------- ----------- ---------- ----------- 2004 1,053 1,053 0 0 1,733 1,733 181 181 2005 319 1,372 0 0 2,529 4,262 30 211 2006 1,047 2,419 0 0 10,547 14,809 576 787 2007 1,371 3,790 297 297 30,056 44,865 308 1,095
Sproule has assigned 13.6 MMboe of proven undeveloped reserves in the Sproule Report under forecast prices and costs, together with $177 million of associated undiscounted future capital expenditures. Proven undeveloped capital spending in the first two forecast years of the Sproule Report accounts for $142 million, or 80 percent, of the total forecast. These figures increase to $176 million or 99 percent, during the first five years of the Sproule Report.
PROBABLE UNDEVELOPED RESERVES Light and Medium Oil Heavy Oil Natural Gas NGLs Year (Mbbl) (Mbbl) (MMcf) (Mbbl) - --------------- ----------------------- ------------------------ ----------------------- ----------------------- First Cumulative First Cumulative First Cumulative First Cumulative Attributed at Year End Attributed at Year End Attributed at Year End Attributed at Year End ---------- ----------- ---------- ----------- ---------- ----------- ---------- ----------- 2004 265 265 0 0 1,945 1,945 126 126 2005 764 1,029 0 0 11,109 13,054 320 446 2006 748 1,777 0 0 18,049 31,103 572 1,018 2007 2,410 4,187 2,312 2,312 40,261 71,364 528 1,546
Sproule has assigned 26.6 MMboe of probable undeveloped reserves and has allocated future development capital of $194 million to all probable undeveloped reserves with $193 million scheduled for the first five years. SIGNIFICANT FACTORS OR UNCERTAINTIES High operating costs substantially reduce our netback, which in turn reduces the amount of cash available for reinvestment in drilling opportunities. This becomes most relevant during periods of low commodity prices when profits are more significantly impacted by high costs. 18 FUTURE DEVELOPMENT COSTS The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserve categories noted below. Forecast Prices and Costs ------------------------------------------ Proved Reserves Proved Plus Probable Year (MM$) Reserves (MM$) - --------------------------------- --------------- -------------------- 2008 93 153 2009 62 161 2010 31 60 2011 4 5 2012 0 7 Total: Undiscounted for all years 190 387 To fund our capital program, including future development costs, we have many financing alternatives available including partial retention of cash flow from operations, bank debt financing, issuance of additional Units, and issuance of convertible debentures. We evaluate the appropriate financing alternatives closely and have made use of all these options dependent on the given investment situation and the capital markets. We maintain a capital structure that is similar to our industry peer group and that will maximize the investment return to Unitholders as compared to the cost of financing. We expect to continue using all financing alternatives available to continue pursuing our oil and gas development strategy. The assorted financing instruments have certain inherent costs which we consider in the economic evaluation of pursuing any development opportunity. There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the Sproule Report. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to our reserves. OTHER OIL AND GAS INFORMATION Our properties are spread geographically throughout the Western Canadian Sedimentary Basin. This sedimentary basin covers a large portion of the four western Canadian provinces, with the majority of our properties concentrated in Alberta and northeastern British Columbia and in southeast Saskatchewan. These properties produce from a variety of various aged geological formations and reservoirs. We operate over 85% of our properties. This allows us to control the nature and timing of the capital investments necessary to maximize the potential in developing these assets. Our properties can be divided on the broad basis of commodity and of production type. Light or medium gravity oil accounts for 27% of our production and 29% of our reserves. A further 62% of production and 60% of reserves are natural gas. Rates referenced in the following property descriptions are as of December 31, 2007 unless otherwise noted and reserves quoted are as reported in the Sproule Report to December 31, 2007. MARTIN CREEK, BLACK AND CONROY, BRITISH COLUMBIA The Martin Creek property is located approximately 100 kilometres northwest of Fort St. John, British Columbia. The property is operated with an average 76% overall working interest. This property is in the winter drilling area which requires all drilling, completion and tie in activities to occur essentially between January 1 and the end of March each season. In the latest winter program beginning in January 2008, 10 wells averaging 95% working interest were drilled in the Conroy area in the northern part of the property. These wells were successful in multiple zones including the Cretaceous Bluesky Formation as well as reservoirs within the Triassic Charlie Lake Formation. These zones occur at moderate depths between 800 to 1,300 metres. All 10 wells in the 2008 program were cased with 9 of these completed and tied in along with one additional well from the 2007 program being tied in as well. Total production prior to this winter's drilling program from the greater Martin Creek, including the Black - Conroy areas is approximately 18 MMcf/d or 3,000 boe/d. Additional 19 facilities, pipeline and compression options will be scoped in 2008 to handle subsequent anticipated volumes from current and future drilling programs. Advantage constructed a 26 kilometre all year access road to our major compression sites that will also allow us the flexibility to expand outside of the winter operating season should we choose to bring on extra capacity which resulted from the successful 2008 program. This year's drilling results have set up a similar 2009 drilling program, should we choose to execute on it at that time. In addition we own 60% to 100% working interest ownership in key facilities, including five compressor stations, one gas plant with 24 MMcf/d current throughput and over 290 kilometres of pipelines, which gives us a dominant infrastructure position in this portion of British Columbia. Sproule evaluated our proved reserves in the area and assigned 37.6 bcf of natural gas and 752 Mbbls of crude oil and NGLs. In addition, 22.4 bcf of probable natural gas reserves and 446 Mbbls of probable crude oil and NGLs reserves have been assigned to this property. STODDART (NORTH PINE), BRITISH COLUMBIA The Stoddart/North Pine area lies just 8 kilometres west of the Town of Fort St. John in northeast British Columbia. This area is within the agricultural area and is accessible year round. The property produces from multiple horizons, predominantly natural gas from the Permian Belloy Formation and oil from the Triassic, Charlie Lake Formation. Historically, production from this area has very low decline, is low operating cost and requires minimal capital expenditures. We own an interest in 30 producing wells (22 net) in the area. We operate approximately 80% of the natural gas production and have a 40% working interest in the North Pine Charlie Lake oil pool. Recently this area of British Columbia has become the focus of exploration and development interest for the Triassic Montney tight gas play which is being explored on adjacent lands and developed further along trend to the southeast at Dawson and Swan. Advantage is evaluating the Montney gas resource potential on our lands which include 16,800 gross (11,800 net) acres of undeveloped land with rights to this interval and we are planning for a possible new drilling location or recompletion later in 2008 to evaluate this resource. Current production from the Stoddart area is 580 boe/d. Sproule evaluated our proved reserves in the area and assigned 12.7 bcf of natural gas and 762 Mbbls of crude oil and NGLs. In addition, 3 bcf of probable natural gas reserves and 188 Mbbls of probable crude oil and NGL reserves have been assigned to this property. ZAMA LAKE (SOUSA), ALBERTA The Zama Lake property lies 150 kilometres south/southeast of the Northwest Territories/British Columbia/Alberta border adjacent to the Hay Zama Lake Complex. Productive zones on this property are primarily oil and gas from the Devonian Keg River, Sulphur Point and Slave Point formations as well as gas in the shallow Cretaceous Bluesky formation. Regionally, Keg River oil wells are characterized by prolific carbonate reefs. Bluesky sandstone reservoirs tend to provide lower deliverability, but longer-life sweet-natural-gas production. In February 2008 we drilled and successfully completed two new Keg River reefs as well as two shallow Bluesky wells which were used to validate land leases. We own and operate a sour oil battery, complete with treaters, tanks, oil-pumping station and solution gas compression. The area also has an existing gas-gathering system comprised of three owned and operated compressors complete with a small refrigeration package, dehydration, and sales point. Additional capacity is available for further development of our lands. Production from the Zama Lake/Sousa property is currently 1,100 boe/d. The Sproule Report assigns 6.1 bcf of proven natural gas reserves and 1,195 Mbbls of proven NGL reserves to this property. In addition, 1.2 bcf of probable natural gas reserves and 439 Mbbls of probable NGL reserves have been assigned to this property. RAINBOW, ALBERTA The Rainbow property lies 175 kilometres south/southeast of the Northwest Territories/British Columbia/Alberta border in northwest Alberta. The major focus of production on this property is the Cretaceous Bluesky formation, a shallow sandstone reservoir that covers an extensive area and offers low-risk development. No new wells were drilled in the Bluesky in 2007. 20 With the acquisition of Sound, we are planning to optimize facilities and reviewing opportunities for improving operations prior to commencing a new round of drilling. Upwards of 50 infill and/or step out locations remain available for development on this property. In the winter season of 2006/2007, field compression was added which will support long-term sustained production volumes from the area. Shallow natural gas production at Black is compressed and dehydrated in an owned and operated facility before it is further compressed and processed by a third-party processor in the area. Other Rainbow shallow natural gas production is compressed, refrigerated and dehydrated at an owned and operated facility, then delivered to the TCPL System. Current production from the Rainbow property is 1,000 boe/d. The Sproule Report assigns 18.1 bcf of proven natural gas reserves and 1,001 Mbbls of proven NGL reserves to this property. In addition, 3.4 bcf of probable natural gas reserves and 807 Mbbls of probable NGL reserves have been assigned to this property. FONTAS, ALBERTA The Fontas property is situated about 80 kilometres south of the Rainbow Zama oilfields and about 20 kilometres east of the British Columbia/Alberta border. Fontas is a natural gas property which produces primarily from Mississippian aged reservoirs in the Debolt, Shunda and Elkton Formations. Gas is trapped as these reservoirs are truncated beneath Cretaceous strata and is also trapped in Cretaceous channels which down cut into the older Mississippian rock. We operate this winter only access property at a 65% working interest. We operate six strategically located gas processing/compression facilities and over 200 kilometres of gas gathering pipelines. A winter road was built into the property for well servicing and replenishment of perishables this winter but no drilling program was undertaken. Production from the Fontas property is currently 1,000 boe/d. The Sproule Report assigns 9.8 bcf of proven natural gas reserves to this property. In addition, 4.4 bcf of probable natural gas reserves have been assigned to this property. SUNSET/VALLEYVIEW, ALBERTA This area is located approximately 100 kilometres east of the City of Grande Prairie, just north of the town of Valleyview. It consists of a group of three main producing properties: Sunset Triassic "A" Unit, Sunset "B", and Valleyview-Stump. All three properties produce from the Triassic Montney Formation, which in this area is a fine grained sandstone conventional reservoir. SUNSET "A" - We have a 70% working interest and operate the Sunset Triassic "A" Unit. Production from the unit is predominantly oil (32o API). The unit has a forty year production history with a very stable performance and very low decline, indicating that there is a lot more oil to be recovered. Advantage commenced infill development of the pool in 2005 where two wells were drilled to evaluate the viability of infill drilling. These wells came on-stream at an average rate of 75 bbls/d per well, similar to that in the original wells. An additional 14 oil wells and an injector were added in 2006 followed with the addition of 5 oil wells and one water injection well in 2007, all with similar results. Significant upgrading to oil production and handling facilities and gathering systems has been ongoing throughout 2006 and 2007 to handle increased oil production and additional water injection for pressure maintenance. An additional 22 locations have been identified with 5 wells budgeted for drilling in 2008. SUNSET "B" - Production from this Montney reservoir is predominantly natural gas although there is a thin oil (32o API) column. We have a 100% interest in this pool. We own 100% of a sour gas processing plant and gathering system with throughput capacity of 12 MMcf/d. Associated gas from Sunset "A" and from Valleyview is gathered and streams through this facility. No wells were drilled in 2007 at Sunset "B". VALLEYVIEW - This Montney gas pool is connected to the Sunset "B" gas processing plant by a twelve kilometre pipeline. We have a 93% average working interest in the pool. There was no new drilling in this pool in 2007. Currently production from the Sunset/Valleyview area is approximately 1,400 boe/d. 21 For the three properties, Sunset "A", Sunset "B" and Valleyview, the Sproule Report assigns 12.7 bcf of proven natural gas reserves and 2,465 Mbbls of proven crude oil and NGL reserves. In addition, 17.1 bcf of probable natural gas reserves and 3,130 Mbbls of probable crude oil and NGL reserves have been assigned to these properties. GLACIER, ALBERTA The Glacier property lies along the east side of the border between Grande Prairie, Alberta and Dawson Creek, British Columbia. The property consists of 83 sections with an average working interest of 93%. Current production of 350 boe/d is comprised all of natural gas out of various producing zones in 13 wells, which is at present processed at a third party facility. Although gas is produced out of a variety of horizons in the Cretaceous and Triassic section, the primary zone of interest is the rapidly emerging unconventional gas play in the Triassic Montney formation tight gas siltstones. We are in early stages of drilling and scoping this resource on our lands and in the first three months of 2008 Advantage drilled and completed various intervals within the Montney in 5 vertical wells (4.33 net) on the Glacier property. These wells clearly frame and establish the presence of reservoir in both the Upper Montney shore face portion as well as in the Lower Montney shelf /turbidite portion of the formation similar to adjacent producing fields at Swan and Dawson on the British Columbia side of the border. Drilling locations are being secured for drilling horizontal wells later in the year. These horizontal wells will be split between targeting both the upper and lower prospective portions of the formation. Multiple fracs in each horizontal well will be deployed to achieve maximum production rates. Sproule evaluated our proved reserves in the area and assigned 16.8 bcf of natural gas and 151 Mbbls of crude oil and NGLs. In addition, 36.4 bcf of probable natural gas reserves and 328 Mbbls of probable crude oil and NGLs reserves have been assigned to this property. WORSLEY, CECIL, CLEAR RIVER AND BOUNDARY LAKE, ALBERTA These properties are located 150 kilometres north of the City of Grande Prairie, Alberta in the Peace River Arch region. WORSLEY - The Worsley property is complex geologically with numerous structural and stratigraphic reservoirs ranging from 600 to 2,200 metres. The principle reservoirs are the Devonian, Wabamun Formation, Mississippian Kiskatinaw and Debolt Formations and Cretaceous Bluesky and Gething Formations. We hold varying interests in approximately 35 sections of land in this area, generally in excess of 50%. We hold a 100% working interest a 7 MMcf/d capacity gas processing facility in Worsley. CECIL - The Cecil area consists of varying interests in 16 sections of land adjacent to Worsley, again with multi-zone, shallow and medium drill depth targets. The principal producing pool is the Charlie Lake JJ (Doig Formation) pool. In 2007 our working interest in this pool increased from 30% to 90% with the acquisition of Sound. We hold a 10% working interest in a 50 MMcf/d gas processing facility at Cecil. BOUNDARY LAKE - This property lies immediately west of the Worsley property just east of the British Columbia/Alberta border. The property consists of 15 sections of land (variable but generally greater than 40% working interest.) The principle asset at Boundary Lake is our 65.625% working interest in a Halfway Formation gas pool consisting of two wells which have a combined extended production test rate in excess of 8 MMcf/d. Extensive pooling discussions with partners, ERCB applications and a purchase of partner interests have delayed getting this pool coming on stream; however this should be on production by mid 2008 as most of the regulatory and approval processes are near complete. One additional well is planned for drilling in 2008 on expiring land. CLEAR RIVER - The principle asset on this property is our interest in the Triassic "CC" oil pool which is a Baldonnel Formation reservoir producing 33o API crude oil at a depth of 1,200 metres. Two wells were drilled in 2007 on this property, one early in the year by Sound and a second late in 2007. Current production from these 4 properties is 1,700 boe/d. Sproule evaluated our proved reserves in these areas (Worsley, Cecil, Clear River and Boundary Lake) and assigned 7.1 bcf of natural gas and 795 Mbbls of crude oil and NGLs. In addition, 5.3 bcf of probable natural gas reserves and 539 Mbbls of probable crude oil and NGL reserves have been assigned to these properties. 22 NEVIS, ALBERTA The Nevis property is situated 60 kilometres east of Red Deer. Nevis is an operated property consisting of approximately 90 sections of land with an average working interest of 76%. This property produces natural gas from numerous shallow depth horizons (400 to 800 metres) including the Horseshoe Canyon, Edmonton, Belly River and Viking formations. Oil and natural gas is produced from the slightly deeper reservoirs (1,200 metres) of the Glauconite, Ostacode and Ellerslie formations within the Mannville Group. The main zone of interest however, is an oil and gas reservoir which occurs at 1,600 metres of depth in Devonian aged carbonates of the Big Valley Member of the Wabamun Formation. Because this reservoir is a low permeability carbonate and as such inflow in vertical wells is low, the pool is being developed with horizontal wells numbering 4 per section each with an average horizontal length of 1,200 metres. Crude oil quality ranges between 35o and 42o API. In 2007, approximately 8 sections of land with Wabamun rights were acquired in a property acquisition. An additional 31 sections of land were added in 2007 through the acquisition of Sound which had a significant land position synergy with Advantage at Nevis. Drilling for the Wabamun in 2008 continues to focus on new lands primarily located on the west side of the property. Facilities and compression are being expanded on the west side of the Red Deer River to accommodate additional volumes established in 2007 drilling and anticipated in 2008. Oil on the property from all areas is collected at central facilities and trucked to market. Natural gas is gathered through company owned pipelines and delivered to third party midstream for final processing and sale. Currently, the property is being scoped for suitable secondary recovery potential. In 2007, 12 horizontal wells were drilled into the Wabamun formation and are all currently producing with an average first month initial production of 122 boe/d. The acquisition of Sound added 20 sections (55% net) which have shallow Horseshoe Canyon coal bed methane ("CBM") potential. We have budgeted 37 wells (55% working interest) for CBM in 2008. This program commenced drilling in March. To accommodate shallow pressures encountered with the CBM, appropriate upgrades to facilities and gathering systems are being implemented in 2008 as well. Nevis is Advantage's largest producing property with current production from all zones at Nevis over 4,600 boe/d. The Sproule Report assigns 39.4 bcf of proven natural gas reserves and 4,795 Mbbls of proven crude oil and NGL reserves to this property. In addition, 14.1 bcf of probable natural gas reserves and 1,898 Mbbls of probable crude oil and NGL reserves have been assigned to this property. WILLESDEN GREEN (OPEN LAKE), ALBERTA The Willesden Green property is located approximately 35 kilometres north of the Town of Rocky Mountain House. We operate and have in excess of 90% working interest. In 2007 we successfully drilled and completed five 2,400 metre deep wells (4.2 net) targeting two distinct plays, a Jurassic Rock Creek gas play on the east side of the property and a Cretaceous Ellerslie/Ostracode/Glauconite play on the north side of the property. In addition 3 wells were farmed out and these were successfully completed as well as Rock Creek gas wells. We retain a 15% overriding royalty in these latter three wells. In 2008, 3 additional wells were drilled (100% working interest) in the first quarter resulting in 2 Cretaceous oil wells and one additional Rock Creek gas well. Also, one well was successfully recompleted in the Cretaceous as an oil well. For the remainder of 2008, two additional drilling locations and 3 more recompletions have been budgeted. Current production from all zones at Willesden Green is 1,100 boe/d, with 600 additional boe/d tested and completed from the new 2008 wells drilled to date and which will be coming on-stream in the second quarter of 2008. Sproule evaluated our proved reserves in the Willesden Green area and assigned 6.5 bcf of natural gas and 830 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2.7 bcf of natural gas and 350 Mbbls of crude oil and NGLs. WESTEROSE, ALBERTA The Westerose property is approximately 60 kilometres southwest of Edmonton, Alberta. Westerose is an oil and gas property with production from various Cretaceous reservoirs but produces principally from several pools associated with the erosional subcrop edge of the Mississippian Banff Formation. The primary pool is the Banff "C" Oil Unit in which we hold a 52% interest and operate. The reservoir in the Banff Formation is a dolomitized carbonate that is conducive to secondary recovery through waterflooding. The reservoir is currently under active waterflood pressure maintenance since 2003 and one new injection well was added to the injection scheme in 2007 along with two new additional oil producers. We also 23 operate five compressor stations and 80 kilometres of pipeline gathering facilities that are connected to the Rimbey gas plant. One additional well and one recompletion workover are budgeted for 2008. Current production from all zones at the greater Westerose area, including the Banff "C" Oil Unit is 1,350 boe/d. Sproule evaluated our proved reserves in the Brazeau River area and assigned 8.9 bcf of natural gas and 2,095 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2.3 bcf of natural gas and 1,220 Mbbls of crude oil and NGLs. BRAZEAU RIVER, ALBERTA The Brazeau River property is located approximately 50 kilometres west of the town of Drayton Valley. The property produces sour light oil and natural gas primarily from Devonian aged Nisku pinnacle reefs. The majority of the production is from a non-operated 50% working interest in the Nisku C, D and E pools and a 17% working interest in the Nisku A unit. Major facility interests include a 25.7% working interest in the West Pembina Sour Gas Plant and a 31.6% working interest in the Brazeau River Gas Plant. Current production from the Brazeau area, including the Nisku pinnacles is 725 boe/d. Sproule evaluated our proved reserves in the Brazeau River area and assigned 5.5 bcf of natural gas and 527 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2.8 bcf of natural gas and 273 Mbbls of crude oil and NGLs. LOOKOUT BUTTE, ALBERTA The Lookout Butte property is located approximately 90 kilometres southwest of Lethbridge, Alberta. Production occurs primarily from the Mississippian Rundle Formation where natural gas has been trapped in a foothills overthrust structure in front of Waterton Park. We have a 100% working interest in the Rundle gas production. Production began in 1963 and production decline is low at approximately 12% per year. A well drilled in 2004 in the southern portion of the pool indicates the potential for significant undrained reserves and additional prospective locations targeting the Rundle carbonates. The property includes a 100% operated working interest plant and associated gas gathering system which dehydrates the gas before final processing at Shell's Waterton gas plant. Two wells (50% working interest) have been recompleted in the Cretaceous Dalhousie Formation which occurs at about 3,100 metres. Both wells are producing between 100 and 150 boe/day. A new well (50% working interest) was drilled at year end 2007 and it encountered two overthrust repeats of the pay zone. Completion of this well is still ongoing. One additional well on this play is budgeted for 2008. Current production from Lookout Butte in the Mississippian and Cretaceous intervals combined is 1,300 boe/d. Sproule evaluated our proved reserves at Lookout Butte and assigned 30.6 bcf of natural gas and 1,592 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 11.3 bcf of natural gas and 646 Mbbls of crude oil and NGLs. SHALLOW GAS PROPERTIES A significant portion of our production comes from shallow gas properties at Medicine Hat, Bantry, and Shouldice. These projects are all located in southern Alberta and occur between 500 and 1,200 metres of depth. Typical of shallow gas, these properties are resource plays which require a large number of wells to extract the very large in place reserves at relatively low per well production rates. As a result, they have a long production life (long reserve life index or "RLI"). These reservoirs consist of low permeability strata, requiring fracture stimulation to enhance and induce productivity. The wells are gathered by an extensive network of low pressure pipelines which feed into large central gas compression facilities. All of these properties have been downspaced to allow for multiple gas wells per section. MEDICINE HAT - The Medicine Hat property is located 20 kilometres northeast of the City of Medicine Hat in the heart of the south-eastern shallow gas area. We have a 100% working interest in 24 sections of land from where production is taken from all of the main shallow gas producing formations including the Medicine Hat "A", "C" and "D" sands, as well as both 24 the Upper and Lower Milk River sands. When the property was acquired in January 2002 there were 115 wells producing approximately 5.2 MMcf/d of natural gas. From January 2002 to December 2005, 320 new wells were added. No new wells were added in 2007. Production from this property is currently 9.5 MMcf/d or 1,550 boe/d. Sproule evaluated our reserves in the area and assigned 43.1 bcf of proved natural gas reserves and 10.6 bcf of probable reserves. As such, this property is our largest property on an assigned reserves basis. BANTRY - This property is located immediately east of the town of Brooks straddling the TransCanada Highway. The property consists of 86 sections of land ranging between 50% and 100% working interest. Production occurs primarily from Basal Colorado Formation channel sandstones and various sandstones within the Bow Island Formation. Drilling depth is shallow with average wells less than 1,000 metres. No new wells were added in 2007. Natural gas is gathered into our operated compression and dehydration facilities. Current production from this area is 650 boe/d. The Sproule Report assigns 8.6 bcf of proven natural gas reserves and 33 Mbbls of proven NGL reserves to this property. In addition, 3.9 bcf of probable natural gas reserves and 15 Mbbls of probable NGL reserves have been assigned to this property. SHOULDICE - The Shouldice area of southern Alberta is located approximately 50 kilometres southeast of the City of Calgary. We have an average working interest of more than 85% in 34 sections of land and operate in excess of 90% of our production in the area. Much of this acreage is downspaced to accommodate additional drilling. No new wells were added in 2007. Both natural gas and crude oil are produced and gathered through our facilities of varying working interests. Current natural gas production of 420 boe/d is produced on a co-mingled basis from the Medicine Hat Formation sands with various Belly River Formation sands from approximately 90 wells. The Sproule Report assigns 7.3 bcf of proven natural gas reserves and 67 Mbbls of proven crude oil and NGLs to this property. In addition, 2 bcf of probable natural gas reserves and 34 Mbbls of probable crude oil and NGL reserves have been assigned to this property. SOUTHEAST SASKATCHEWAN This area consists of a host of individual properties within the Williston Sedimentary Basin in the southeast corner of Saskatchewan. Production at the major properties comes principally from the Ordovician Red River Formation at Midale, Hardy and Froude, Devonian Winnipegosis Formation at Steelman and from Mississippian Midale/Frobisher Formations at Steelman, Weyburn and Workman, McCoun and Crystal Hills. In 2007, we drilled 4.7 net wells. These included one (0.6 net) horizontal at Talmage for Ordovician, Red River Oil and 2 net vertical Frobisher Oil wells at Pinto. The remaining wells were drilled at Elswick, Queensdale and Crystal Hills. In addition Advantage farmed out two significant blocks of land to two industry partners in the Midale/Froude area which have resulted in 10 Bakken horizontal wells with a 10% overriding royalty and an additional two additional horizontals with a 5 to 12% sliding scale overriding royalty. We have an additional 6 wells budgeted spread across these properties in 2008. Combined production from all the properties in southeast Saskatchewan (excluding the Wapella area) is 1,755 boe/d. Sproule evaluated our proved reserves in southeast Saskatchewan and assigned 832 Mmcf of natural gas and 5,513 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 353 Mmcf of natural gas and 3,471 Mbbls of crude oil and NGLs. WAPELLA/RED JACKET, SASKATCHEWAN Our Wapella property is located in southeast Saskatchewan, 200 kilometres east of Regina and produces medium-gravity (25(0) API) oil from Cretaceous and Jurassic-aged sandstone reservoirs. This property was acquired in 2007 in the Sound acquisition. It is characterized by its relatively high reserve life index, high working interest and substantial undeveloped acreage. There is a significant inventory of drilling locations. The pool is being developed with a staged waterflood program to enhance reserves and productivity. Future plans call for continued delineation and development of the pool as well as expansion of the waterflood scheme. There are two drilling locations and a number of recompletions budgeted on this property in 2008. 25 Production from the Wapella area is currently 725 boe/d. Sproule evaluated our proved reserves in Wapella/Red Jacket and assigned 2,774 Mbbls of crude oil. Probable reserves in this area were evaluated by Sproule at 1,123 Mbbls of crude oil. HEAVY OIL PROPERTIES (WESTERN SASKATCHEWAN - LLOYDMINSTER AREA) The majority of the east Lloydminster (Lashburn and West Hazel) and Eyehill properties lie on the Saskatchewan side of the Saskatchewan/Alberta border in the heart of the Lloydminster heavy oil producing area. These properties produce primarily from the Cretaceous Sparky Formation and also from the Rex, Cummings and Dina Formations. Crude gravities are all less than 19(0) API but are conventionally produced with some pools under active water flood as pressure maintenance schemes. These properties were added to our portfolio through the Sound Arrangement. Currently production from these heavy oil properties is 475 boe/d. Sproule evaluated our proved reserves in the Heavy Oil Properties of western Saskatchewan and assigned 88 Mmcf of natural gas and 902 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 43 Mmcf of natural gas and 2,666 Mbbls of crude oil and NGLs. OIL AND GAS WELLS The following table sets forth the number and status of wells as at December 31, 2007 in which we have a working interest.
Oil Wells Natural Gas Wells -------------------------------------------- ------------------------------------------ Producing Non-Producing Producing Non-Producing ------------------- ------------------ ------------------ ------------------ Gross Net Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- ----- --- Alberta 986.0 586.8 485.0 259.2 2,090.0 1,549.5 523.0 258.1 British Columbia 5.0 3.4 3.0 0.3 125.0 82.5 50.0 34.6 Saskatchewan 461.0 335.1 161.0 111.2 1.0 1.0 7.0 0.1 Manitoba 85.0 5.1 - - - - - - ------- ----- ----- ----- ------- ------- ----- ----- Total 1,537.0 930.4 649.0 370.7 2,216.0 1,633.0 580.0 292.8 ======= ===== ===== ===== ======= ======= ===== =====
Note: (1) Excluding minor interest in the following units (less than 5% working interest): Steelman Unit No. 3, Pine Creek Second White Specks Pool, Carrot Creek Cardium K Unit No. 1, Delburne Gas Unit, Nevis Unit No. 1, Bonnie Glen D-3A Gas Cap Unit, Bellis Gas Unit No. 2, Turner Valley Unit No. 5, Sunchild Gas Unit No. 1, North Pembina Cardium Unit, Kakwa Cardium A Unit, Bonanza Boundary A Pool Unit No. 1, and Boundary Lake Units No. 1 and No. 2. Injection Wells are categorized as Non-Producing Oil Wells. PROPERTIES WITH NO ATTRIBUTED RESERVES The following table sets out our developed and undeveloped land holdings as at December 31, 2007.
Developed Acres Undeveloped Acres Total Acres --------------------------- -------------------------- ----------------------- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Alberta 1,238,745 647,934 789,914 429,360 2,028,659 1,077,294 British Columbia 159,486 73,877 109,807 64,153 269,293 138,030 Saskatchewan 50,660 38,312 226,301 192,071 276,961 230,383 --------- ------- --------- ------- --------- --------- Total 1,448,891 760,123 1,126,022 685,584 2,574,913 1,445,707 ========= ======= ========= ======= ========= =========
We expect that rights to explore, develop and exploit 164,577 net acres of our undeveloped land holdings will expire by December 31, 2008. The land expirations do not consider our 2008 exploitation and development program that may result in extending or eliminating such potential expirations. We closely monitor land expirations as compared to our development program with the strategy of minimizing undeveloped land expirations relating to significant identified opportunities. 26 FORWARD CONTRACTS Our operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely in recent years. Such prices are primarily determined by economic, and in the case of oil prices, political factors. Supply and demand factors, as well as weather, general economic conditions, and conditions in other oil and natural gas regions of the world also impact prices. Any upward or downward movement in oil and natural gas prices could have an effect on our financial condition, thus impacting the cash distributions made to Unitholders. We have implemented a hedging policy to use costless collars and fixed price swaps to hedge up to 60% of our gross production for a maximum period of 1 1/2 years. These hedging activities could expose us to losses or gains. To the extent that we engage in risk management activities related to commodity prices, we will be subject to credit risk associated with the parties with which we contract. This credit risk will be mitigated by entering into contracts with only stable and creditworthy parties and through the frequent review of our exposure to these entities. Overall, approximately 53% of our gas is now hedged for the 2008 calendar year at a floor of $7.52/mcf. For the first quarter of 2008, we have secured approximately 22% of our net gas production at an $8.85/mcf floor. For the first quarter of 2009, approximately 60% of our net gas production is hedged at a floor of $7.87/mcf. We have also hedged approximately 38% of our 2008 net crude production at an average floor price of Cdn$94.07/bbl and 32% of our first quarter 2009 production at Cdn$95.84/bbl. Advantage has the following derivatives in place:
DESCRIPTION OF DERIVATIVE TERM VOLUME AVERAGE PRICE - --------------------------- --------------------------- ------------ ---------------------------- NATURAL GAS - AECO Fixed price November 2007 to March 2008 7,109 mcf/d Cdn$9.54/mcf Fixed price April 2008 to October 2008 14,217 mcf/d Cdn$6.85/mcf Fixed price April 2008 to October 2008 9,478 mcf/d Cdn$7.25/mcf Fixed price April 2008 to October 2008 14,217 mcf/d Cdn$7.83/mcf Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.10/mcf Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.06/mcf Fixed price November 2008 to March 2009 14,217 mcf/d Cdn$7.77/mcf Fixed price November 2008 to March 2009 4,739 mcf/d Cdn$8.10/mcf Fixed price November 2008 to March 2009 14,217 mcf/d Cdn$9.45/mcf Collar November 2007 to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf Ceiling Cdn$10.29/mcf Collar November 2007 to March 2008 7,109 mcf/d Floor Cdn$8.70/mcf Ceiling Cdn$10.71/mcf CRUDE OIL - WTI Fixed price February 2008 to January 2009 2,000 bbls/d Cdn$90.93/bbl Fixed price April 2008 to March 2009 2,500 bbls/d Cdn$97.15/bbl Collar February 2008 to January 2009 2,000 bbls/d Sold put Cdn$70.00/bbl Purchased call Cdn$105.00/bbl Cost Cdn$1.52/bbl
ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS We estimate the costs to abandon and reclaim all our shut-in and producing wells, facilities, gas plants, pipelines, batteries and satellites. No estimate of salvage value is netted against the estimated cost. Our model for estimating the amount and timing of future abandonment and reclamation expenditures was done on an operating area level. Estimated expenditures for each operating area are initially based upon Sproule's methodology, which details the cost of abandonment for the major properties that we hold. Our initial estimated expenditures are then further adjusted for non-producing wells, pipelines and 27 facilities, and surface reclamation costs. Each property was assigned an average cost per well to abandon and reclaim the wells in an area and abandonment and reclamation costs have been estimated over a 50 year period. We estimate that we will incur reclamation and abandonment costs on 5,425 (gross) producing and non-producing wells. Costs to abandon and reclaim the producing wells totals $20.3 million ($97.0 million discounted at 10%) and are included in the estimate of future net revenue. The additional liability associated with non-producing wells, pipelines and facilities, and surface reclamation costs was estimated to be $22.0 million ($146.9 million discounted at 10%), and was not deducted in estimating future net revenue. Facility reclamation costs are generally scheduled to be incurred in the year following the end of the reserve life of our associated reserves under the assumption that decommissioning of plant/facilities are mobile assets with a long useful life. Abandonment and reclamation costs undiscounted and included in the estimate of future net revenue for the next three years are $0.8 million in 2008, $1.3 million in 2009 and $1.5 million in 2010. TAX HORIZON In 2007, we did not pay any income related taxes. In our structure, the operating company utilizes available tax pools to significantly reduce taxable income and makes other required payments to the Trust transferring both income and associated tax liability to the Unitholders. Therefore, it is expected, based on current legislation that no cash income taxes are to be paid by the operating company prior to 2011 and it is our intent to continue with the current arrangement. For the 2007 distributions, 100% were taxable to Canadian and U.S. Unitholders. The Trust does not expect to pay income taxes until the earlier of January 1, 2011 or if and when it ceases to be a trust. New legislation passed in June 2007 will impose a tax on distributions from entities, such as the Trust, beginning generally on January 1, 2011. Commencing in January 2011 (provided that the Trust experiences only "normal growth" and no "undue expansion" before then) the Trust will be liable for tax at the federal "net corporate income tax rate" combined with the "provincial SIFT tax factor" (effectively the federal general corporate tax rate plus 13% on account of provincial corporate tax) on all income payable to Unitholders, which the Trust will not be able to deduct in computing its taxable income. CAPITAL EXPENDITURES The following tables summarize capital expenditures (including capitalized general and administrative expenses) related to our activities for the year ended December 31, 2007: CAPITAL EXPENDITURES ($ THOUSANDS) 2007 - -------------------------------------------------------------------------------- Land and seismic $ 3,270 Drilling, completions and workovers 94,786 Well equipping and facilities 48,296 Other 2,373 - -------------------------------------------------------------------------------- 148,725 Property acquisitions Proved properties 3,200 Unproved properties 12,851 Property dispositions (1,037) Corporate costs 22,307 - -------------------------------------------------------------------------------- TOTAL CAPITAL EXPENDITURES $ 186,046 - -------------------------------------------------------------------------------- The total capital expenditures for the year ended December 31, 2007 include approximately $18.3 million related to exploration activities. EXPLORATION AND DEVELOPMENT ACTIVITIES The following table sets forth the gross and net wells in which we participated during the year ended December 31, 2007: 28
Exploratory Development Total ---------------------- -------------------- -------------------- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Oil wells 9 9.0 37 22.6 46 31.6 Gas wells 24 15.4 41 16.8 65 32.2 Dry holes - - 1 1.0 1 1.0 ----- ----- ----- ----- ----- ----- Total 33 24.4 79 40.4 112 64.8 ===== ===== ===== ===== ===== =====
Subject to, among other things, the availability of drilling rigs and weather that permits access to drill sites, in 2008, we plan to drill, complete and tie-in 88 net wells and recomplete an additional 14 net wells. We estimate capital expenditures of between $125 million and $145 million in 2008 to execute our capital programs. The primary components of our programs are described under the heading "Other Oil and Gas information - Oil and Natural Gas Properties". PRODUCTION ESTIMATES The following table sets out the volume of our production estimated for the year ended December 31, 2008 reflected in the estimate of future net revenue disclosed in the tables contained under "Disclosure of Reserves Data".
Light and Natural Gas Medium Oil Heavy Oil Natural Gas Liquids Total (bbl/d) (bbl/d) (Mcf/d) (bbl/d) (Boe/d) -------------- -------------- ------------------ -------------- ------------------ Gross Net Gross Net Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- ----- --- ----- --- Proved Producing 8,384 7,068 895 747 116,770 92,775 2,586 1,892 31,327 25,170 Proved Developed Non- Producing 131 107 7 5 3,170 2,452 69 52 735 573 Proved Undeveloped 235 184 25 21 3,795 3,068 52 45 944 761 ----- ----- ----- --- ------- ------- ----- ----- ------ ------ Total Proved 8,750 7,359 927 773 123,735 98,295 2,707 1,989 33,006 26,504 Total Probable 1,059 824 86 65 12,449 9,142 231 181 3,451 2,594 ----- ----- ----- --- ------- ------- ----- ----- ------ ------ Total Proved Plus Probable 9,809 8,183 1,013 838 136,184 107,437 2,938 2,170 36,457 29,098 ===== ===== ===== === ======= ======= ===== ===== ====== ======
PRODUCTION HISTORY The following tables summarize certain information in respect of production, prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:
Quarter Ended 2007 Year Ended -------------------------------------------------- ------------- Mar. 31 June 30 Sept. 30 Dec. 31 Dec. 31, 2007 ------- ------- -------- ------- ------------- Average Daily Production(1) Crude Oil (bbl/d) 7,557 6,615 7,750 10,410 8,090 Gas (MMcf/d) 114.3 109.0 116.0 128.6 117.0 NGLs (bbl/d) 2,401 2,337 2,264 2,485 2,372 Combined (boe/d) 29,012 27,115 29,346 34,321 29,962 Average Net Production Prices Received(2) Crude Oil ($/bbl) 59.03 64.23 70.22 74.19 67.71 Gas ($/Mcf) 7.61 7.54 5.62 6.23 6.72 NGLs ($/bbl) 49.93 55.05 64.95 70.09 60.12 Combined ($/boe) 49.51 50.71 45.79 50.91 49.27
29
Quarter Ended 2007 Year Ended -------------------------------------------------- ------------- Mar. 31 June 30 Sept. 30 Dec. 31 Dec. 31, 2007 ------- ------- -------- ------- ------------- Gain/(Loss) on Derivatives Crude Oil ($/bbl) 2.37 0.14 (0.67) (3.71) (0.79) Gas ($/Mcf) 0.45 (0.02) 0.73 0.74 0.49 Combined ($/boe) 2.39 (0.02) 2.67 1.65 1.70 Royalties Paid Crude Oil ($/bbl) 10.67 10.49 12.81 15.08 12.58 Gas ($/Mcf) 1.51 1.33 0.90 0.79 1.12 NGLs ($/bbl) 15.44 15.23 18.75 14.72 15.99 Combined ($/boe) 10.02 9.22 8.37 8.58 9.02 Operating Expenses(3)(4) Crude oil ($/bbl) 14.15 14.56 16.06 14.91 14.94 Natural gas ($/Mcf) 1.82 1.64 1.62 1.94 1.76 NGLs ($/bbl) 9.00 9.06 9.62 9.24 9.22 Combined ($/boe) 11.59 10.91 11.40 12.46 11.64 Netback Received(5) Crude Oil ($/bbl) 36.58 39.32 40.68 40.49 39.40 Gas ($/Mcf) 4.73 4.55 3.83 4.24 4.33 NGLs ($/bbl) 25.49 30.76 36.58 46.13 34.91 Combined ($/boe) 30.29 30.56 28.69 31.52 30.31
Notes: (1) Before deduction of royalties. (2) Production prices are net of costs to transport the product to market. (3) This figure includes all field operating expenses. (4) We do not record operating expenses on a commodity basis. Information in respect of operating expenses for crude oil and NGLs ($/bbl) and natural gas ($/Mcf) has been determined by allocating expenses on an area by area basis based upon the relative volume of production of crude oil and NGLs and natural gas in those areas. (5) Information in respect of netbacks received for crude oil & NGLs ($/bbl) and natural gas ($/Mcf) is calculated using operating expense figures for crude oil and NGLs ($/bbl) and natural gas ($/Mcf), which figures have been estimated. See note (4) above. The following table indicates our approximate average daily production from our important fields for the quarter ended December 31, 2007: 30
Natural Gas Crude Oil & NGLs Total Properties (Mcf/d) (bbls/d) (boe/d) - --------------------------------------------------------------------------------------------------------------- Nevis 14,770 1,780 4,241 Martin Creek 17,840 310 3,283 Saskatchewan 310 3,170 3,222 Willesden Green/Westerose 9,280 1,180 2,727 Medicine Hat 10,340 - 1,723 Boundary Lake/Cecil 4,740 860 1,650 Sunset 3,830 840 1,478 Sousa 3,350 740 1,298 Brazeau/Ferrier 5,310 370 1,255 Chip Lake 4,400 440 1,173 - --------------------------------------------------------------------------------------------------------------- Major Properties 74,170 9,690 22,050 Other 54,386 3,205 12,271 - --------------------------------------------------------------------------------------------------------------- TOTAL 128,556 12,895 34,321
FUTURE COMMITMENTS We have committed to certain payments over the next five years, in addition to regular payments under our credit facilities, as follows:
($ millions) 2008 2009 2010 2011 2012 - ------------ ---- ---- ---- ---- ---- Building leases 5.3 4.1 4.1 1.8 1.3 Capital leases 1.9 2.1 2.2 1.9 - Pipeline/transportation 4.4 1.3 0.3 - - Convertible debentures(1) 5.4 87.0 69.9 62.3 -
Note: (1) As at December 31, 2007, Advantage had $224.6 million convertible debentures outstanding. Each series of convertible debentures are convertible to Trust Units based on an established conversion price. The Fund expects that the obligations related to convertible debentures will be settled either directly or indirectly through the issuance of Trust Units. DEFINITIONS AND OTHER NOTES 1. Columns set forth above may not add due to rounding. 2. The crude oil, natural gas liquids and natural gas reserve estimates presented in the Sproule Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below. "COGE HANDBOOK" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum; "DEVELOPMENT COSTS" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly; (b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly; 31 (c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (d) provide improved recovery systems. "EXPLORATION COSTS" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (e) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies; (f) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records; (g) dry hole contributions and bottom hole contributions; (h) costs of drilling and equipping exploratory wells; and (i) costs of drilling exploratory type stratigraphic test wells. "GROSS" means: (j) in relation to our interest in production and reserves, our "Trust gross reserves", which are our interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Trust; (k) in relation to wells, the total number of wells in which we have an interest; and (l) in relation to properties, the total area of properties in which we have an interest. "NET" means: (m) in relation to our interest in production and reserves, our interest (operating and non-operating) share after deduction of royalties obligations, plus our royalty interest in production or reserves; (n) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and (o) in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest owned by us. RESERVE CATEGORIES Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: o analysis of drilling, geological, geophysical and engineering data; o the use of established technology; and 32 o specified economic conditions. Reserves are classified according to the degree of certainty associated with the estimates. (a) PROVED RESERVES are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. (b) PROBABLE RESERVES are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook. Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories: (c) DEVELOPED RESERVES are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. (i) DEVELOPED PRODUCING RESERVES are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainly. (ii) DEVELOPED NON-PRODUCING RESERVES are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. (d) UNDEVELOPED RESERVES are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. LEVELS OF CERTAINTY FOR REPORTED RESERVES The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions: (a) at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and (b) at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook. MARKETING Our crude oil and natural gas production is primarily sold through marketing companies at current market prices. These contracts are generally for less than a year and are cancellable on 30 days notice. Approximately 11% of our natural gas 33 production is sold to aggregators who accumulate production from various producers and market the gas on behalf of the group. Such contracts are reserve specific and continue for the life of production from the specified reserves. CYCLICAL AND SEASONAL IMPACT OF INDUSTRY Our operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect on our financial condition. We mitigate such price risk through closely monitoring the various commodity markets and establishing hedging programs, as deemed necessary, to provide stability to Unitholders' cash distributions and lock-in high netbacks on production volumes. See "OTHER OIL AND GAS INFORMATION - FORWARD CONTRACTS" for our current hedging program. RENEGOTIATION OR TERMINATION OF CONTRACTS As at the date hereof, we do not anticipate that any aspect of our business will be materially affected in the remainder of 2008 by the renegotiation or termination of contracts or subcontracts. ENVIRONMENTAL CONSIDERATIONS We are pro-active in our approach to environmental concerns. Procedures are in place to ensure that the utmost care is taken in the day-to-day management of our oil and gas properties. All government regulations and procedures are followed in strict adherence to the law. We believe in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to us. HEALTH, SAFETY AND ENVIRONMENTAL AOG is committed to a comprehensive and effective health, safety and environmental program that meets or exceeds regulatory and corporate requirements. Management, employees and all contractors are responsible and accountable for the overall health, safety and environmental program. AOG will operate in compliance with all applicable regulations and will ensure all staff and contractors employ sound practices to protect the environment and to ensure employee and public health and safety. We will maintain a safe and environmentally responsible work place and provide training, equipment and procedures to all individuals in adhering to our policies. We will also solicit and take into consideration input from our neighbors, communities and other stakeholders in regard to protecting people and the environment. AOG participates in the Environment, Health and Safety Stewardship Program developed by the Canadian Association of Petroleum Producers. Participation requires commitment to continuous improvement in the environment, health and safety management practices including sound planning and implementation, open communication and measured performance against our peers. COMPETITIVE CONDITIONS We are a member of the petroleum industry, which is highly competitive at all levels. We compete with other companies for all of our business inputs, including exploitation and development prospects, access to commodity markets, acquisition opportunities, available capital and staffing. We strive to be competitive by maintaining a strong financial condition and by utilizing current technologies to enhance exploitation, development and operational activities. 34 HUMAN RESOURCES As at December 31, 2007, we employed 172 full-time employees, 139 of which are located in the head office and 33 of which are located in the field. We also employed 27 consultants in the head office. ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND TRUST UNITS An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. As at December 31, 2007, 138,269,374 Trust Units were issued and outstanding. Each Trust Unit represents an equal fractional undivided beneficial interest in any distributions from, and in any net assets of, the Trust in the event of termination or winding up of the Trust. The beneficial interests in the Trust are divided into three classes, as follows: (i) "ordinary trust units", which are entitled to the rights, subject to limitations, restrictions and conditions set out in the Trust Indenture, as summarized herein; (ii) "special voting units", which shall be issued to a trustee and which are entitled to such number of votes at meetings of Unitholders as is equal to the number of Trust Units reserved for issuance that such special voting units represent, such number of votes and any other rights or limitations to be prescribed by the AOG Board of Directors; and (iii) "special trust units", which shall be entitled to the rights and subject to the limitations, restrictions and conditions set out in the Trust Indenture, as summarized herein. As at the date hereof there are no special voting units and no special trust units outstanding. The special voting unit gives AOG the flexibility to acquire the securities of another issuer in consideration for securities which are ultimately exchangeable for Trust Units. All Trust Units (including ordinary trust units and special trust units) are of the same class with equal rights and privileges. Each Trust Unit is transferable, entitles the holder thereof to participate equally in distributions, including the distributions of net income and net realized capital gains of the Trust, and distributions on liquidation, is fully paid and non assessable. Each special trust unit entitles the holder or holders thereof to one-half of one vote at any meeting of the Unitholders and each ordinary trust unit entitles the holder or holders thereof to one vote at any meeting of the Unitholders. The Trust Units do not represent a traditional investment and should not be viewed by investors as "shares" in either AOG or the Trust. Corporate law does not govern the Trust and the rights of Unitholders. As holders of Trust Units in the Trust, the Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions. The rights of Unitholders are specifically set forth in the Trust Indenture. In addition, trusts are not defined as recognized entities within the definitions of legislation such as the BANKRUPTCY AND INSOLVENCY ACT (Canada) and the COMPANIES' CREDITORS ARRANGEMENT ACT (Canada). As a result, in the event of an insolvency or restructuring, a Unitholder's position as such may be quite different than that of a shareholder of a corporation. The price per Trust Unit is a function of anticipated distributable income from AOG and the ability of the AOG Board of Directors to effect long term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates, commodity prices and our ability to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units. A return on an investment in the Trust is not comparable to the return on an investment in a fixed-income security. The recovery of an initial investment in the Trust is at risk, and the anticipated return on such investment is based on many performance assumptions. Although the Trust intends to make distributions of its available cash to holders of Trust Units, these cash distributions may be reduced or suspended. The actual amount distributed will depend on numerous factors including: the financial performance of AOG, debt obligations, working capital requirements and future capital requirements. In addition, the market value of the Trust Units may decline if the Trust's cash distributions decline in the future, and that market value decline may be material. It is important for an investor to consider the particular risk factors that may affect the industry in which it is investing, and therefore the stability of the distributions that it receives. See "RISK FACTORS". The after-tax return from an investment in Trust Units to Unitholders subject to Canadian income tax can be made up of both a return on capital and a return of capital. That composition may change over time, thus affecting an investor's after-tax return. Returns on capital will generally continue to be taxed as ordinary income in the hands of a Unitholder until 35 January 2011 (provided we do not exceed "normal growth" or experience undue expansion), and will be treated as dividends after such time. Returns of capital are generally tax-deferred (and reduce the Unitholder's cost base in the Trust Unit for tax purposes). Legislation affecting the tax treatment of an investment in Trust Units can change at any time. See "RISK FACTORS - CHANGES IN LEGISLATION". TRUST UNITHOLDER LIMITED LIABILITY The Trust Indenture provides that no Trust Unitholder will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines our Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of the Trust Unitholder's share of our assets. Pursuant to the Trust Indenture, we will indemnify and hold harmless each Trust Unitholder from any cost, damages, liabilities, expenses, charges and losses suffered by a Trust Unitholder resulting from or arising out of such Trust Unitholder not having such limited liability. The Trust Indenture provides that all written instruments signed by or on behalf of us must contain a provision to the effect that such obligation will not be binding upon our Unitholders personally. Notwithstanding the terms of the Trust Indenture, Unitholders may not be protected from our liabilities to the same extent as a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against the Trust (to the extent that claims are not satisfied by the Trust Fund) that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability to Unitholders of this nature arising is considered unlikely in view of the fact that our sole business activity is to hold securities, and all of the business operations currently carried on by AOG will be carried on by a corporate entity, directly or indirectly. Our business and that of our wholly-owned subsidiary, AOG, is conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability to our Unitholders for claims against us, including obtaining appropriate insurance, where available, for the operations of AOG and having written agreements, signed by or on our behalf, include a provision that such obligations are not binding upon our Unitholders personally. ISSUANCE OF TRUST UNITS The Trust Indenture provides that Trust Units or rights to acquire Trust Units may be issued at the times, to the persons, for the consideration, and on the terms and conditions that the AOG Board of Directors determines. The Trust Indenture also provides that immediately after any PRO RATA distribution of Trust Units to all Unitholders in satisfaction of any non-cash distribution, the number of outstanding Trust Units will be consolidated such that each Trust Unitholder will hold, after the consolidation, the same number of Trust Units as the Trust Unitholder held before the non-cash distribution. In this case, each certificate representing a number of Trust Units prior to the non-cash distribution is deemed to represent the same number of Trust Units after the non-cash distribution and the consolidation. CASH DISTRIBUTIONS The amount of cash to be distributed annually per Trust Unit shall be equal to a PRO RATA share of interest on the Notes, royalty income from the Royalty, dividends on or in respect of shares of AOG received by us and income from the Permitted Investments; less: (i) our administrative expenses and other obligations; and (ii) amounts which may be paid by us in connection with any cash redemptions of Trust Units. AOG may apply some or all of its cash flow to capital expenditures to develop the Oil and Natural Gas Properties of AOG or to acquire additional Oil and Natural Gas Properties prior to making any distributions to us in the form of principal repayments on the Notes or dividends on the Common Shares, Non-Voting Shares or Preferred Shares. If, on any Distribution Record Date, the Trustee determines that we do not have cash in an amount sufficient to pay the full distribution to be made on such Distribution Record Date in cash or if any cash distribution should be contrary to any subordination agreement, the distribution payable to Unitholders on such Distribution Record Date may, at the option of the Trustee, include a distribution of additional Trust Units having an equal value to the cash shortfall. Trust Units will be issued pursuant to exemptions under applicable securities laws, discretionary exemptions granted by applicable securities regulatory authorities or a prospectus or similar filing. 36 We derive interest income from our holdings of the Notes. It is expected that our income will generally be limited to: (i) the interest received on the principal amount of the Notes; (ii) royalty income received on the Royalty; and (iii) dividends (if any) received on shares of AOG. See "ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD. - NOTES". The AOG Board of Directors intends for the Trust to make monthly cash distributions. Cash distributions will be made monthly to the Unitholders of record on the last day of each month (unless such day is not a Business Day, in which case the date of record shall be the next following Business Day) and shall be payable on the 15th day of each month or, if such day is not a Business Day, the following Business Day or such other date as determined from time to time by the Trustee. Pursuant to the provisions of the Trust Indenture all income earned by the Trust in a fiscal year, not previously distributed in that fiscal year, must be distributed to Unitholders of record on December 31. This excess income, if any, will be allocated to Unitholders of record at December 31 but the right to receive this income, if the amount is not determined and declared payable at December 31, will trade with the Trust Units until determined and declared payable in accordance with the rules of the Toronto Stock Exchange. To the extent that a Unitholder trades Trust Units in this period they will be allocated such income but will dispose of their right to receive such distribution. REDEMPTION RIGHT Trust Units are redeemable at any time on demand by the holders thereof upon delivery to us of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requesting redemption. Upon our receipt of the redemption request, all rights to and under the Trust Units tendered for redemption shall be surrendered and the holder thereof shall be entitled to receive a price per Trust Unit (the "REDEMPTION PRICE") equal to the lesser of: (i) 85% of the "market price" of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading-day period commencing immediately after the date on which the Trust Units are surrendered for redemption (the "REDEMPTION DATE"); and (ii) the "closing market price" on the principal market on which the Trust Units are quoted for trading on the Redemption Date. For the purposes of this calculation, "market price" is an amount equal to the simple average of the closing price of the Trust Units for each of the trading days on which there was a closing price, provided that, if the applicable exchange or market does not provide a closing price but only provides the highest and lowest prices of the Trust Units traded on a particular day, the market price shall be an amount equal to the simple average of the highest and lowest prices for each of the trading days on which there was a trade, and provided further that if there was trading on the applicable exchange or market for fewer than five of the 10 trading days, the market price shall be the simple average of the following prices established for each of the 10 trading days: the average of the last bid and last ask prices for each day on which there was no trading; the closing price of the Trust Units for each day that there was trading if the exchange or market provides a closing price; and the average of the highest and lowest prices of the Trust Units for each day that there was trading, if the market provides only the highest and lowest prices of Trust Units traded on a particular day. The "closing market price" shall be: an amount equal to the closing price of the Trust Units if there was a trade on the date; an amount equal to the average of the highest and lowest prices of the Trust Units if there was trading and the exchange or other market provides only the highest and lowest prices of Trust Units traded on a particular day; and the average of the last bid and last ask prices if there was no trading on the date. The aggregate Redemption Price payable by us in respect of any Trust Units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on or before the last day of the following month; provided that the entitlement of Unitholders to receive cash upon the redemption of their Trust Units is subject to the limitations that: (i) the total amount payable by us in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month shall not exceed $100,000 (provided that the Trustee may, in its sole discretion, waive such limitation in respect of any calendar month); (ii) at the time such Trust Units are tendered for redemption the outstanding Trust Units shall be listed for trading on a stock exchange or traded or quoted on any other market which the Trustee considers, in its sole discretion, provides representative fair market value prices for the Trust Units; and (iii) the normal trading of Trust Units is not suspended or halted on any stock exchange on which the Trust Units are listed (or, if not listed on a stock exchange, on any market on which the Trust Units are quoted for trading) on the Redemption Date or for more than five trading days during the 10-day trading period commencing immediately after the Redemption Date. If a Trust Unitholder is not entitled to receive cash upon the redemption of Trust Units as a result of the foregoing limitations, then the Redemption Price for such Trust Units shall be the Fair Market Value thereof (as defined in the Trust 37 Indenture), as determined by the Trustee in the circumstances described in subparagraphs (ii) and (iii) above, and shall, subject to any applicable regulatory approvals, be paid and satisfied by way of distribution IN SPECIE of a PRO RATA number of Long Term Notes (in a minimum amount of $100.00 and integral multiples of $1.00), from time to time outstanding (i.e., in a principal amount equal to the Redemption Price). No fractional Long Term Notes will be distributed and where the number of Long Term Notes to be received by a Trust Unitholder includes a fraction, such number shall be rounded to the next lowest whole number. We shall be entitled to all interest paid, or accrued and unpaid, on the Long Term Notes on or before the date of the distribution IN SPECIE. If we do not hold Long Term Notes having a sufficient principal amount outstanding to effect such payment, we will be entitled to create and, subject to any applicable regulatory approvals, issue in satisfaction of the Redemption Price our own debt securities (the "REDEMPTION NOTES") having terms and conditions substantially the same as the Long Term Notes, and with recourse of the holder limited to our assets. Holders of such Long Term Notes and Redemption Notes will be required to acknowledge that they are subject to the subordination agreements described below under the heading "ADDITIONAL INFORMATION REGARDING ADVANTAGE OIL & GAS LTD. - NOTES". Long Term Notes and Redemption Notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds and deferred profit sharing plans if the Trust ceases to qualify as a mutual fund trust. It is anticipated that the redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. Long Term Notes or Redemption Notes which may be distributed IN SPECIE to Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such Long Term Notes or Redemption Notes. MEETINGS OF UNITHOLDERS The Trust Indenture provides that meetings of Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of our auditors, the approval of amendments to the Trust Indenture (except as described under "ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND - AMENDMENTS TO THE TRUST INDENTURE"), the sale of our assets in their entirety or substantially in their entirety (other than as part of an internal reorganization), the termination of the Trust and the direction of the Trustee as to the selection of the directors of AOG. Meetings of Unitholders will be called and held annually for, among other things, the election of the Trustee, the appointment of our auditors, and the direction of the Trustee as to the selection of the directors of AOG. A resolution appointing or removing a Trustee, our auditors, or the direction of the Trustee as to the selection of the directors of AOG must be passed by a simple majority of the votes cast by Unitholders. The balance of the foregoing matters must be passed by at least 66 2/3% of the votes cast at a meeting of Unitholders called for such purpose. A meeting of Unitholders may be convened at any time and for any purpose by the Trustee and must be convened if requisitioned by the holders of not less than 20% of the Trust Units then outstanding by a written requisition. A requisition must, among other things, state in reasonable detail the business proposed to be transacted at the meeting. Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxyholder need not be a Trust Unitholder. Two persons present in person or represented by proxy and representing, in the aggregate, at least 10% of the votes attaching to all outstanding Trust Units shall constitute a quorum for the transaction of business at all such meetings. The Trust Indenture contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Unitholders. The next annual and special meeting of Unitholders is scheduled for June 3, 2008. INFORMATION AND REPORTS We will furnish to Unitholders such financial statements (including quarterly and annual financial statements) and other reports as are, from time to time, required by applicable law, including prescribed forms needed for the completion of Unitholders' tax returns under the Tax Act and equivalent provincial legislation. Prior to each meeting of Unitholders, the Trustee will provide the Unitholders (along with notice of such meeting) a proxy form and an information circular containing information similar to that required to be provided to shareholders of a Canadian public corporation. 38 The AOG Board of Directors will ensure that AOG provides us with proper disclosure as to its business and financial operations and sufficient information and materials on a timely basis to allow us to meet our public reporting requirements. With respect to material changes, the AOG Board of Directors will ensure that AOG provides timely disclosure to us as if AOG were a public corporation. TAKEOVER BIDS The Trust Indenture contains provisions to the effect that if a takeover bid is made for the Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Unitholders who did not accept the takeover bid on the terms offered by the offeror. THE TRUSTEE The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances. The initial term of the Trustee's appointment was until the first annual meeting of Unitholders. The Trustee is reappointed or changed every year as may be determined by a majority of the votes cast at a meeting of our Unitholders. The Trustee may resign upon providing 60 days notice to us. The Trustee may also be removed by special resolution of our Unitholders. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee. DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST GOVERNANCE AOG has generally been delegated our significant management decisions. In particular, pursuant to the Administration Agreement, the Trustee has delegated to AOG responsibility for the administration and management of all general and administrative affairs of Advantage, including, among other things: (a) maintaining records and accounts; (b) preparing all tax returns, filings and documents and monitor the tax status of the Trust and of the Trust Units; (c) providing advice with respect to the Trust's obligations as a reporting issuer and ensure compliance under applicable securities legislation; (d) providing investor relations services to the Trust; (e) calling and holding all meetings of the Unitholders; (f) undertaking all matters relating to an offering including; (i) compliance with all applicable laws; (ii) all matters relating to the content of any offering documents, the accuracy of the disclosure and the certification thereof; and (iii) all matters concerning the entering into, terms of, and amendment from time to time of material contracts; (g) retaining professional services and advisors; (h) dealing with banks and other institutional lenders; 39 (i) taking all actions reasonably necessary in relation to the redemption of Trust Units; (j) taking all actions reasonably necessary in relation to voting rights on any investments in the Trust Fund; (k) taking all action reasonably necessary relating to the specific powers and authorities as set forth in the Trust Indenture; (l) taking all actions reasonably necessary in relation to providing indemnities for the directors and officers of the Administrator and any affiliates of the Trust or the Administrator; (m) providing or causing to be provided to the Trustee any services reasonably necessary for the Trustee to be able to consider any future acquisitions or divestitures by the Trustee of any portion of the Trust Fund; (n) providing advice and, at the request and under the direction of the Trustee, direction to the transfer agent; (o) determining and arranging for distributions to Unitholders; (p) providing advice and assistance to the Trustee with respect to the performance of the obligations of the Trust and the enforcement of the rights of the Trust under all agreements entered into by the Trust; (q) withholding the withholding taxes required and promptly remit such taxes to the appropriate taxing authority; (r) providing such additional administrative and support services pertaining to the Trust, the Trust Fund and the Trust Units and matters incidental thereto as may be reasonably requested by the Trustee from time to time; (s) reporting to Unitholders; (t) providing management services, for the economic and efficient exploration, exploitation and development of assets of the Trust; (u) recommending, carrying out and monitoring property acquisitions and dispositions and exploitation and development programs for the Trust; and (v) doing all such things regarding the use of commodity price swaps, hedges or other such instruments or agreements on behalf of the Trust in respect of commodity prices or rates of exchange of currencies or interest rates, the purpose of which is to mitigate or eliminate exposure to the fluctuations and prices of commodities or rates of exchange of one currency for another or interest rates. For more information as to the AOG Board of Directors, see "ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD. - MANAGEMENT OF AOG". LIABILITY OF THE TRUSTEE The Trustee, its directors, officers, employees, shareholders and agents shall not be liable to any Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to the Trust or the Trust Fund, arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, any action taken or not taken in good faith in reliance upon any documents that are, PRIMA FACIE, properly executed, any depreciation of, or loss to, the Trust Fund incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by AOG or any other appropriately qualified person, any reliance upon any such evaluation, any action or failure to act of the AOG, or any other person to whom the Trustee has, with the consent of AOG, delegated any of its duties hereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by AOG to perform its duties under or delegated to it under the Trust Indenture or any material contract), unless such liabilities arise out of the gross negligence, wilful default or fraud of the Trustee or any of its 40 directors, officers, employees, shareholders or agents. If the Trustee has retained an appropriate expert, adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any material contract, the Trustee may act or refuse to act based upon the advice of such expert, adviser or legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based upon the advice of any such expert, adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the Trust Fund. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee. AMENDMENTS TO THE TRUST INDENTURE The Trust Indenture may be amended or altered, from time to time, by at least 66 2/3% of the votes cast at a meeting of our Unitholders called for such purpose. The Trustee may, without the approval of the Unitholders, make certain amendments to the Trust Indenture, including amendments: 1. for the purpose of ensuring continuing compliance with applicable laws (including the Tax Act), regulations, requirements or policies of any governmental or other authority having jurisdiction over the Trustee or over the Trust; 2. ensuring that we will satisfy the provisions of each of Sections 108(2)(a) and 132(6) of the Tax Act, as from time to time amended or replaced; 3. which, in the opinion of the Trustee, provide additional protection for or benefit to the Unitholders; 4. to remove any conflicts or inconsistencies in the Trust Indenture or making corrections, including the correction or rectification of any ambiguities, defective provisions, errors, mistakes or omissions, which are, in the opinion of the Trustee, necessary or desirable and not prejudicial to the Unitholders; 5. which, in the opinion of the Trustee, are necessary or desirable as a result of changes in taxation laws; and 6. removing or curing inconsistencies between the Trust Indenture and the Material Contracts (as such term is defined in the Trust Indenture) which are, in the opinion of the Trustee, necessary or desirable and not prejudicial to the Unitholders. In December 2007, the Trust Indenture was amended to allow the Trust to participate in the DRS. Effective January 1, 2008, all issuers whose securities are listed on the New York Stock Exchange are required to ensure that their listed securities are eligible for participation in the DRS. DRS eligible issuers must provide an investor with the ability to have their securities registered in the investors' name directly on the issuer's books (through its transfer agent) or through the investors' brokerage dealer, thereby eliminating the need for physical certificates to evidence ownership of securities. As a result of the implementation of the need to be DRS eligible, certain amendments were required to be made to the Trust Indenture of the Trust. TERM OF THE TRUST AND SALE OF SUBSTANTIALLY ALL ASSETS The Trust has been established for a term ending December 31, 2095. Pursuant to the Trust Indenture, termination of the Trust or the sale or transfer of our assets in their entirety or substantially in their entirety, except as part of an internal reorganization of the our assets as approved by the AOG Board of Directors, requires approval by at least 66 2/3% of the votes cast at a meeting of the Unitholders. 41 EXERCISE OF VOTING RIGHTS ATTACHED TO COMMON SHARES The Trust Indenture provides that the Trustee may vote securities of AOG held by it at any meeting of shareholders of AOG as well as any Permitted Investments held, from time to time, as part of the Trust Fund which carry voting rights. However, the Trustee may not, under any circumstances whatsoever, vote any AOG securities or any other Permitted Investments which carry voting rights to authorize the sale, lease or exchange of all or substantially all of the property of AOG or any other entity owned directly or indirectly by us which represents more than 51% of the Trust Fund, except as part of a reorganization of AOG and any one or more of our directly or indirectly owned subsidiaries without the approval of at least 66 2/3% of the votes cast at a meeting of the Unitholders called for such purpose. ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.
DIRECTORS AND OFFICERS OF AOG Position Held and Period Served as Name, Province and Country a Director or of Residence Officer(4)(5) Principal Occupations During Past Five Years - --------------------------- ----------------- -------------------------------------------------------------------------- Gary F. Bourgeois Vice President, Vice President, Corporate Development of AOG since May 24, 2001. Vice Ontario, Canada Corporate President of AIM from March 2001 to June 2006. Prior thereto, Managing Development and Director of the EnerPlus Group of Companies, which companies specialize Director since in management of oil and gas income funds and royalty trusts May 24, 2001 (1998-2000). In addition, President of Queen-Yonge Investments Limited (since 1985), a private family-owned investment holding company with holdings in oil and gas royalty trusts, real estate income funds, direct oil and gas properties, private and public exploration and production companies, and direct commercial real estate holdings. Kelly I. Drader Chief Executive Chief Executive Officer of AOG since May 24, 2001. President of AIM from Alberta, Canada Officer and March 2001 to June 2006. Prior thereto, Senior Vice President (1997-2001) Director since and Vice President, Finance and Chief Financial Officer (1990-1997) of May 24, 2001 EnerPlus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts. John A. Howard (3)(8) Director since President of Lunar Enterprises Corp., a private holding company. Alberta, Canada June 23, 2006 Andy J. Mah President and President and Chief Operating Officer since June 23, 2006. Prior Alberta, Canada Chief Operating thereto, President of Ketch Resources Ltd. since October 2005. Chief Officer and a Operating Officer of Ketch Resources Ltd. from January 2005 to September Director since 2005. Prior thereto, Executive Officer and Vice President, Engineering June 23, 2006 and Operations of Northrock Resources Ltd. from August 1998 to January 2005. Ronald A. McIntosh(1)(3) Director since Chairman of North American Energy Partners Inc., a publicly traded Alberta, Canada September 25, corporation. 1998(6) Stephen Balog(3) Director since President, West Butte Management Inc., a private oil and gas consulting Alberta, Canada August 16, 2007 company. Prior thereto, President & Chief Operating Officer and a Director of Tasman Exploration Ltd. from 2001 to June, 2007. Carol Pennycook(1)(2) Director since Partner at the Toronto office of Davies Ward Phillips & Vineberg, LLP, a Ontario, Canada May 26, 2004 national law firm.
42 Position Held and Period Served as Name, Province and Country a Director or of Residence Officer(4)(5) Principal Occupations During Past Five Years - --------------------------- ----------------- -------------------------------------------------------------------------- Steven Sharpe(2) Director since Since, July, 2008, Senior Advisor to Blair Franklin Capital Partners, Ontario, Canada May 24, 2001 and Inc., a Toronto-based investment bank which he co-founded in May, 2003. Non-Executive Prior to that, Mr. Sharpe was Managing Partner of Blair Franklin, from its Chairman since inception. Before then, he was Managing Director of The EBS Corporation, a May 26, 2004 management and strategic consulting firm. Rodger A. Tourigny(1)(2)(7) Director since President of Tourigny Management Ltd., a private oil and gas consulting Alberta, Canada December 31, company. 1996(6) Sheila O'Brien(2) Director since From April 2004, President of Belvedere Investments and Corporate March 21, 2007 Director; from July 1998 to April 2004, Senior Vice President, Human Resources, Public Affairs, Investor and Government Relations with Nova Chemicals Corporation. Among her other accomplishments, Ms. O'Brien was designated as Member, Order of Canada in 1999. Patrick J. Cairns Senior Vice Senior Vice President of AOG since June 2001. Vice President of the Alberta, Canada President Manager since May 2001. Prior thereto, Mr. Cairns was Vice President, Evaluations with the Enerplus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts. Peter Hanrahan Vice President Chief Financial Officer of AOG since January 2003. Prior thereto, Alberta, Canada Finance and Controller of AOG since December 1999. Chief Financial Officer David Cronkhite Vice-President, Vice-President, Operations since July 18, 2006. Prior thereto, Alberta, Canada Operations Production Manager of AOG for five years. Prior thereto, Mr. Cronkhite held engineering positions with several oil and gas companies. Neil Bokenfohr Vice President, Vice-President, Exploitation since June 23, 2006. Prior thereto, Vice Alberta, Canada Exploitation President Exploitation and Operations of Ketch Resources Ltd. since January 2005; Vice President, Engineering of Bear Creek Energy Ltd. (and Crossfield Gas Corp. prior thereto) from March 2002 to January 2005. Prior thereto, Director of Exploitation for Calpine Canada Natural Gas Company from December 2000 to March 2002. Weldon M. Kary Vice President, Vice President, Exploitation since February 14, 2005. Prior thereto, with Alberta, Canada Geosciences and AOG since May 23, 2001, most recently as Manager, Geology and Geophysics. Land Prior thereto, Exploration Manager at Palliser Energy Corp. when Palliser was purchased by Search Energy Corp, the predecessor entity of AOG. Anthony Coombs Controller Controller since September 1, 2004. Prior thereto with AOG since May 23, Alberta, Canada 2001, most recently as Chief Accountant. Prior thereto, Chief Accountant for Search Energy Corp., the predecessor entity of Advantage. Jay P. Reid Corporate Partner, Burnet, Duckworth & Palmer LLP, a Calgary-based law firm. Alberta, Canada Secretary
43 Notes: (1) Member of the Audit Committee. (2) Member of the Human Resources, Compensation and Corporate Governance Committee. (3) Member of the Independent Reserve Evaluation Committee. (4) AOG does not have an executive committee of the Board. (5) AOG's directors shall hold office until the next annual general meeting of Unitholders or until each director's successor is appointed or elected pursuant to the ABCA, the Shareholder Agreement and the Management Agreement. (6) The period of time served as a director of AOG includes the period of time served as a director of Search prior to the Amalgamation, where applicable. Each of these directors were appointed directors of post-Reorganization Search on May 24, 2001. (7) Mr. Tourigny was a director of Shenandoah Resources Ltd. ("SHENANDOAH") prior to it being placed into receivership on September 17, 2002 and prior to the issuance of cease trade orders in respect of Shenandoah's securities by the Alberta Securities Commission and the British Columbia Securities Commission on November 8, 2002 and October 23, 2002, respectively. Cease trade orders were issued because Shenandoah failed to file certain required financial statements. As of the date hereof, the cease trade orders remain outstanding. Shenandoah's common shares were suspended from trading on the TSX Venture Exchange on April 24, 2002. Mr. Tourigny resigned his directorship with Shenandoah effective September 17, 2002. Mr. Tourigny was also a director of Probe Exploration Inc. ("PROBE") prior to its receivership and prior to the issuance of cease trade orders in respect of Probe's securities by the Alberta Securities Commission and the Ontario Securities Commission on July 7, 2000 and July 17, 2000, respectively. The cease trade orders were issued because Probe failed to file certain required financial statements. As at the date hereof, the cease trade orders remain outstanding. Probe's common shares were suspended from trading on the TSX on March 17, 2000, and were subsequently delisted from the TSX at the close of business on March 16, 2001. Mr. Tourigny resigned his directorship with Probe effective April 14, 2000. (8) Mr. Howard was the President, Chief Executive Officer and Director of Sunoma Energy Corp. Immediately upon his resignation from the executive and board of directors, Sunoma Energy Corp. filed for Court protection. As at March 12, 2008, the directors and executive officers of AOG, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 3,208,852 Trust Units, or approximately 2.3% of the issued and outstanding Trust Units. CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS Other than as disclosed above, no current director or officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has, within the last ten years prior to the date of this document, been a director, chief executive officer or chief financial officer of any issuer (including AOG) that, (i) while the person was acting in the capacity as director, chief executive officer or chief financial officer, was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, that was in effect for a period of more than thirty (30) consecutive days; or (ii) was subject to an order that resulted, after the director, executive officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG ceased to be a director, chief executive officer or chief financial officer of an issuer, in the issuer being the subject of a cease trade or similar order or an order that denied the relevant issuer access to any exemption under securities legislation, for a period of more than thirty (30) consecutive days, which resulted from an event that occurred while that person was acting as a director, chief executive officer or chief financial officer if the issuer. No current director or officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has, within the last ten years prior to the date of this document, been a director or executive officer of any company (including AOG) that, while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement for compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. In addition, no current director or officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has, within the last ten years prior to the date of this document, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or securityholder. No current director or officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has been subject to: (i) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities 44 regulatory authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision. CONFLICTS OF INTEREST The directors and officers of AOG may, from time to time, be involved in the business and operations of other issuers, in which case a conflict may arise. The ABCA provides that in the event a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interests arise, such conflicts will be resolved in accordance with the provisions of the ABCA. DISTRIBUTION POLICY It is anticipated that income received will be from: (i) the interest received on the principal amount of the Notes; (ii) royalty income from the Royalty; and (iii) the dividends received from the shares of AOG. The Trustee makes monthly cash distributions to Unitholders of the interest income earned from the Notes, royalty income from the Royalty and dividends, if any, received on Common Shares, after expenses, if any, and any cash redemptions of Trust Units. See "RISK FACTORS - OIL AND NATURAL GAS PRICES/DELAY IN CASH DISTRIBUTIONS/DEPENDENCE ON AOG". SHARE CAPITAL AOG is authorized to issue an unlimited number of Common Shares, non-voting shares, preferred shares and exchangeable shares. Advantage is the sole holder of the issued and outstanding Common Shares. There are no non-voting shares, preferred shares or exchangeable shares issued and outstanding. Advantage is also the sole holder of the outstanding Notes. The following is a description of the rights attaching to the Common Shares, non-voting shares, preferred shares and Notes. COMMON SHARES Each Common Share entitles its holder to receive notice of and to attend all meetings of the shareholders of AOG and to one vote at such meetings. The holders of Common Shares are, at the discretion of the AOG Board of Directors and subject to applicable legal restrictions, entitled to receive any dividends declared by the AOG Board of Directors on the Common Shares. The holders of Common Shares are entitled to share equally in any distribution of the assets of AOG upon the liquidation, dissolution, bankruptcy or winding-up of AOG or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any instruments having priority over the Common Shares. NON-VOTING SHARES The non-voting shares have identical rights to the Common Shares except that holders of non-voting shares are not generally entitled to receive notice of or attend at meetings of shareholders of AOG or to vote their shares at such meetings. PREFERRED SHARES The preferred shares may be issued, from time to time, in one or more series, each series consisting of such number of preferred shares as determined by the AOG Board of Directors, who may also fix the designations, rights, privileges, restrictions and conditions attached to the shares of each series of preferred shares. No preferred shares are presently issued and outstanding. The preferred shares of each series shall, with respect to payment of dividends and distributions of assets in the event of liquidation, dissolution or winding-up of AOG, whether voluntary or involuntary, or any other distribution of the assets of AOG among its shareholders for the purpose of winding-up its affairs, rank on a parity with the preferred shares of every other series and shall be entitled to preference over the Common Shares and the shares of any other class ranking junior to the preferred shares. 45 NOTES The following is a summary of the material attributes and characteristics of the Notes. This summary does not purport to be complete and is qualified in its entirety by reference to the provisions of the Note Indentures, pursuant to which the Notes are issued. PAYMENT UPON MATURITY On maturity and subject to any applicable subordination restrictions, AOG will repay the indebtedness represented by the Notes by paying to the Note Trustee, in lawful money of Canada, an amount equal to the principal amount of the outstanding Notes, together with accrued and unpaid interest thereon. RANKING Payment of the principal and interest (other than regularly scheduled interest and principal at maturity, provided no default on Senior Indebtedness (as hereinafter defined) has occurred and payment of such interest or principal is not otherwise required to be suspended in accordance with the terms of subordination agreements which may be entered into with the holders of Senior Indebtedness (as herein defined)) on the Notes will be subordinated in right of payment, as set forth in the Note Indentures, to the prior payment in full of the principal of and accrued and unpaid interest on, and all other amounts owing in respect of, all senior indebtedness ("SENIOR INDEBTEDNESS") which is defined as: (a) all indebtedness, obligations and liabilities of AOG in respect of borrowed money (including the deferred purchase price of property), other than: (i) indebtedness evidenced by the Note Indentures; and (ii) indebtedness which, by the terms of the instrument creating or evidencing the same, is expressed to rank in right of payment equally with or subordinate to the indebtedness evidenced by the Note Indentures; and (b) from and after the commencement of, and during the continuance of, any creditor proceedings (including bankruptcy, liquidation, winding-up, dissolution, restructuring or arrangement proceedings), all indebtedness, obligations and liabilities of AOG, other than indebtedness, obligations and liabilities of AOG represented by the Notes. The Note Indentures provide that in the event of any creditor proceedings relative to AOG, the holders of all Senior Indebtedness, which would include bank debt and suppliers of AOG, will be entitled to receive payment in full before the holders of the Notes are entitled to receive any payment. Any amount of property received contrary to these provisions shall be held in trust for and paid over to the holders of Senior Indebtedness. In the event of any creditor proceedings, the indebtedness represented by the Notes is not to be classified with any Senior Indebtedness for voting or distribution, which means that holders of Senior Indebtedness may vote separately from the holders of Notes in respect of any restructuring or arrangement proposal regarding AOG. DEFAULT The Note Indentures provides that any of the following shall constitute an "Event of Default": (i) default in payment of the principal of the Notes when the same becomes due; (ii) the failure to pay the interest obligations of the Notes for a period of 12 months; (iii) default on any indebtedness exceeding $10,000,000; (iv) certain events of winding-up, liquidation, bankruptcy, insolvency or receivership; (v) the taking of possession by an encumbrancer of all or substantially all of the property of AOG; or (vi) default in the observance or performance of any other covenant or condition of the Note Indenture and the continuance of such default for a period of 30 days after notice in writing has been given by the Note Trustee to AOG specifying such default and requiring AOG to rectify the same. SUBORDINATION AGREEMENTS Pursuant to the terms of the Note Indentures, the Note Trustee may enter into subordination agreements with the holders of certain Senior Indebtedness under which the Note Trustee, on behalf of the holders of Notes, may agree directly with a holder of Senior Indebtedness in implementation of and/or in addition to the subordination terms described under "Ranking" directly above. The Note Trustee may give a holder of Senior Indebtedness a power of attorney to be exercised in any creditor proceedings to enforce the terms thereof. The Note Trustee may also agree to ensure that any transferee of Notes (or other securities of AOG) agrees to be bound by the provisions of the subordination agreements. 46 LONG TERM NOTES The aggregate principal amount of Long Term Notes as at December 31, 2007 was approximately $634.8 million. The Long Term Notes mature on December 31, 2031. The Long Term Notes consist of a series of notes, which as at the date hereof, includes Long Term Notes bearing interest at a rate of 14% and 12.5% per annum, payable monthly on the 15th day of the month (or, if such day is not a Business Day, the first Business Day thereafter) for interest earned during the preceding month. The principal and interest on the Long Term Notes are payable in lawful money of Canada. The Long Term Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00. REDEMPTION OF LONG TERM NOTES The Long Term Notes will not be redeemable at the option of AOG or by the holders thereof prior to maturity except in the limited circumstances prescribed by Long Term Note Indenture, where the AOG Board of Directors believe the indebtedness represented by the Long Term Notes could not be refinanced on maturity, or where AOG is prevented by applicable law from paying dividends or making other distributions in respect of Common Shares. MEDIUM TERM NOTES The original aggregate principal amount of Medium Term Notes was $344.8 million ("ORIGINAL PRINCIPAL AMOUNT") and the aggregate principal amount of the Medium Term Notes as at December 31, 2007 was approximately $244.7 million. The Medium Term Notes consist of a series of notes, which as of December 31, 2007, includes Medium Term Notes bearing interest at rates between 7.75% and 10.375% per annum, payable twice annually, and maturing between December 31, 2012 and December 21, 2015. The principal and interest on the Medium Term Notes are payable in lawful money of Canada. The Medium Term Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00. PRINCIPAL REPAYMENTS AND REDEMPTION OF MEDIUM TERM NOTES From time to time and in any event not less frequently than each anniversary of December 31, AOG shall make principal repayments on the Notes in an aggregate amount equal to not less than 5% of the Original Principal Amount (and, if applicable, the aggregate principal amount of any additional Notes issued under the Medium Term Note Indenture in excess of the Original Principal Amount (the "SUPPLEMENTAL PRINCIPAL AMOUNT")), provided, however that during the period commencing on September 30, 2004 and ending on December 31 of the year ended five years before the Maturity Date, AOG shall make, in aggregate, principal payments on the Notes in an amount equal to not less than 50% of the Original Principal Amount. In the event that, at any time during the term of this Indenture, a Supplemental Principal Amount is outstanding, during the period commencing with the issue date of the Notes relating to the Supplemental Principal Amount and ending five years from such issue date, AOG shall make principal payments on the Notes relating to the Supplemental Principal Amount in an aggregate amount equal to not less than 50% of the Supplemental Principal Amount. In the event that AOG makes principal repayments on the Notes pursuant to this section of the Medium Note Indenture and there is more than one holder thereof, such principal prepayments shall be made as near as may be pro rata as between the holders and without discrimination or preference, based upon the aggregate principal amount of Notes held by them (rounded, if necessary, to the nearest One Dollar ($1.00)). DEBENTURES The Debentures pay interest semi-annually and are convertible at the option of the holder into Trust Units at the applicable conversion price per Trust Unit plus accrued and unpaid interest. The details of the Debentures including the balance outstanding as at December 31, 2007 are as follows:
10.00% 9.00% 8.25% 8.75% ------------- ------------ ------------ ------------- Trading symbol AVN.DB AVN.DBA AVN.DBB AVN.DBF Issue date Oct. 18, 2002 July 8, 2003 Dec. 2, 2003 June 10, 2004 Maturity date Matured Aug. 1, 2008 Feb. 1, 2009 June 30, 2009 Conversion price Matured $17.00 $16.50 $34.67 Outstanding at December 31, 2007 - $5,392,000 $4,867,000 $29,839,000
47
7.50% 6.50% 7.75% 8.00% TOTAL ------------- ------------- ------------- ------------- ------------ Trading symbol AVN.DBC AVN.DBE AVN.DBD AVN.DBG Issue date Sep. 15, 2004 May 18, 2005 Sep. 15, 2004 Nov. 13, 2006 Maturity date Oct. 1, 2009 June 30, 2010 Dec. 1, 2011 Dec. 31, 2011 Conversion price $20.25 $24.96 $21.00 $20.33 Outstanding at December 31, 2007 $52,268,000 $69,952,000 $46,766,000 $15,528,000 $224,612,000
The convertible debentures are redeemable prior to their maturity dates, at the option of the Fund, upon providing 30 to 60 days advance notification. The redemption prices for the various debentures, plus accrued and unpaid interest, is dependent on the redemption periods and are as follows:
CONVERTIBLE DEBENTURE REDEMPTION PERIODS PRICE - ----------- -------------------------------------------------------- ------- 9.00% After August 1, 2007 and before August 1, 2008 $1,025 8.25% After February 1, 2007 and on or before February 1, 2008 $1,050 After February 1, 2008 and before February 1, 2009 $1,025 8.75% After June 30, 2007 and on or before June 30, 2008 $1,050 After June 30, 2008 and before June 30, 2009 $1,025 7.50% After October 1, 2007 and on or before October 1, 2008 $1,050 After October 1, 2008 and before October 1, 2009 $1,025 6.50% After June 30, 2008 and on or before June 30, 2009 $1,050 After June 30, 2009 and before June 30, 2010 $1,025 7.75% After December 1, 2007 and on or before December 1, 2008 $1,050 After December 1, 2008 and on or before December 1, 2009 $1,025 After December 1, 2009 and before December 1, 2011 $1,000 8.00% After December 31, 2009 and on or before December 31, 2010 $1,050 After December 31, 2010 and before December 31, 2011 $1,025
THE ROYALTY AGREEMENT Pursuant to the Royalty Agreement, AOG has granted to us the Royalty on AOG's interest in Petroleum Substances within, upon or under all of AOG's developed and undeveloped Canadian Oil and Natural Gas Properties The Royalty will consist of the right to receive a monthly payment from AOG equal to the "Royalty Production Income", which in respect of any period for which Royalty is calculated, means 99% of the production revenues from the Properties less an equivalent portion of the amount of all deductions permitted under the Royalty Agreement. The Royalty does not constitute an interest in land and we are not entitled to take our share of production in kind or to separately sell or market our share of Petroleum Substances. Pursuant to the Royalty Agreement approximately 99% of the economic benefit derived from the assets of AOG accrues to the benefit of the Fund and ultimately to us and our Unitholders. The term of the Royalty Agreement will be for so long as there are Properties to which the Royalty Agreement applies. If AOG wishes to acquire or dispose of any properties that will cost or result in proceeds in excess of $5 million, approval of the AOG Board of Directors is required to approve such acquisition or disposition, respectively. 48 CASH DISTRIBUTIONS The following is a summary of the distributions made by us for each of the three most recently completed financial years. For the 2007 Period Ended Distributions per Unit Payment Date - ------------------------- ---------------------- ------------ January 31 $0.15 February 15, 2007 February 28 $0.15 March 15, 2007 March 31 $0.15 April 16, 2007 April 30 $0.15 May 15, 2007 May 31 $0.15 June 15, 2007 June 30 $0.15 July 16, 2007 July 31 $0.15 August 15, 2007 August 31 $0.15 September 17, 2007 September 30 $0.15 October 15, 2007 October 31 $0.15 November 15, 2007 November 30 $0.15 December 17, 2007 December 31 $0.12 January 15, 2008 ----- TOTAL: $1.77 For the 2006 Period Ended Distributions per Unit Payment Date - ------------------------- ---------------------- ------------ January 31 $0.25 February 15, 2006 February 28 0.25 March 15, 2006 March 31 0.25 April 17, 2006 April 30 0.25 May 15, 2006 May 31 0.25 June 15, 2006 June 30 0.25 July 17, 2006 July 31 0.20 August 15, 2006 August 31 0.20 September 15, 2006 September 30 0.20 October 16, 2006 October 31 0.20 November 15, 2006 November 30 0.18 December 15, 2006 December 31 0.18 January 15, 2007 ----- TOTAL: $2.66 48 For the 2005 Period Ended Distributions per Unit Payment Date ------------------------- ---------------------- ------------ January 31 $0.28 February 15, 2005 February 28 0.28 March 15, 2005 March 31 0.28 April 15, 2005 April 30 0.28 May 16, 2005 May 31 0.25 June 15, 2005 June 30 0.25 July 15, 2005 July 31 0.25 August 15, 2005 August 31 0.25 September 15, 2005 September 30 0.25 October 17, 2005 October 31 0.25 November 15, 2005 November 30 0.25 December 15, 2005 December 31 0.25 January 16, 2006 ---- TOTAL $3.12 Note: (1) On February 15, 2008 a distribution of $0.12 per Trust Unit was paid to Unitholders of Record on the close of business on January 31, 2007. We announced on February 15, 2008 that a distribution of $0.12 per Trust Unit will be payable on March 15, 2008 to Unitholders of record on the close of business on February 28, 2008. MARKET FOR SECURITIES Our Trust Units are listed for trading on the TSX under the symbol "AVN.UN" and, since December 9, 2005, on the NYSE under the symbol "AAV". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the Trust Units as reported by the TSX and NYSE for the periods indicated. Period High Low Volume - --------------------- ------- ------- ----------- TSX TRADING ($) ($) 2007 - ---- January 13.41 11.47 7,579,256 February 12.80 12.13 5,898,850 March 12.56 11.46 4,620,757 April 12.87 11.70 5,527,749 May 14.47 12.46 4,881,754 June 15.97 13.14 6,602,894 July 14.95 12.99 9,267,097 August 13.53 11.56 6,126,077 September 12.42 11.30 7,607,438 October 12.50 11.75 5,903,420 November 12.00 9.81 5,535,740 December 10.58 8.54 6,316,637 2008 ==== January 9.92 8.65 5,340,085 February 11.06 9.23 4,168,544 50 Period High Low Volume - --------------------- ------- ------- ----------- NYSE TRADING ($US) 2007 - ---- January 11.40 9.76 5,406,700 February 10.90 10.46 3,333,500 March 10.82 9.75 4,689,000 April 11.50 10.17 3,815,000 May 13.32 11.27 5,579,900 June 14.95 12.40 7,623,900 July 14.24 12.20 5,972,800 August 12.75 10.74 5,210,700 September 12.45 11.05 4,621,500 October 12.89 11.96 5,295,600 November 12.69 10.22 4,971,700 December 10.46 8.68 6,550,900 2008 ==== January 9.84 8.45 4,006,900 February 11.16 9.12 3,789,300 Our 6.50% Debentures are listed for trading on the TSX under the symbol "AVN.DB.E". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 6.50% Debentures as reported by the TSX for the periods indicated. Period High Low Volume - --------------------- ------- ------- ----------- 2007 (%) (%) - ---- January 98.00 95.50 11,970 February 97.99 96.00 31,540 March 97.00 94.25 36,920 April 96.00 94.00 16,710 May 100.50 95.50 29,330 June 99.84 96.50 14,100 July 99.25 96.56 11,940 August 99.19 95.00 8,270 September 97.50 95.00 6,420 October 97.50 94.00 6,300 November 96.48 92.01 8,030 December 94.50 90.00 4,880 2008 ==== January 95.75 93.01 21,780 February 96.99 93.25 41,540 51 Our 7.5% Debentures are listed for trading on the TSX under the symbol "AVN.DB.C". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 7.5% Debentures as reported by the TSX for the periods indicated. Period High Low Volume - --------------------- ------- ------- ----------- 2007 (%) (%) - ---- January 105.00 100.01 5,280 February 102.50 100.37 3,220 March 101.00 99.51 2,300 April 101.25 98.50 11,430 May 102.49 99.51 9,100 June 101.99 100.50 3,880 July 102.50 100.51 3,160 August 102.49 99.51 3,440 September 101.00 99.01 1,210 October 99.95 97.01 3,590 November 99.99 97.51 6,260 December 99.99 95.00 3,470 2008 ==== January 100.25 98.00 12,300 February 101.50 99.81 2,070 Our 7.75% Debentures are listed for trading on the TSX under the symbol "AVN.DB.D". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 7.75% Debentures as reported by the TSX for the periods indicated. Period High Low Volume - --------------------- ------- ------- ----------- 2007 (%) (%) - ---- January 101.50 100.06 7,590 February 101.69 100.01 5,780 March 101.00 99.75 12,160 April 100.50 99.15 14,330 May 101.99 99.91 4,740 June 101.99 100.21 5,880 July 102.00 100.10 6,160 August 102.00 99.00 5,830 September 100.99 95.51 7,210 October 99.49 95.50 5,980 November 97.99 95.00 8,270 December 96.50 90.00 4,990 2008 ==== January 97.99 94.00 12,340 February 99.19 97.00 5,670 Our 8.00% Debentures are listed for trading on the TSX under the symbol "AVN.DB.G". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 8.00% Debentures as reported by the TSX for the periods indicated. 52 Period High Low Volume - --------------------- ------- ------- ----------- 2007 (%) (%) - ---- September 103.75 100.00 155,600 October 102.65 96.51 38,800 November 98.50 97.00 2,790 December 98.50 98.00 3,920 2008 ==== January 99.00 93.00 4,170 February 99.00 98.00 2,370 Our 8.25% Debentures are listed for trading on the TSX under the symbol "AVN.DB.B". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 8.25% Debentures as reported by the TSX for the periods indicated. Period High Low Volume - --------------------- ------- ------- ----------- 2007 (%) (%) - ---- January 103.00 99.52 560 February 103.00 101.00 1,330 March 102.49 100.50 1,430 April 102.50 100.38 940 May 103.00 101.11 760 June 105.50 102.81 340 July 105.00 100.00 1,200 August 103.62 99.61 940 September 102.89 100.01 600 October 101.50 100.00 690 November 100.99 100.99 80 December 102.43 99.61 440 2008 ==== January 101.00 99.76 1,870 February 101.75 101.40 750 Our 8.75% Debentures are listed for trading on the TSX under the symbol "AVN.DB.F". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 8.75% Debentures as reported by the TSX for the periods indicated. Period High Low Volume - --------------------- ------- ------- ----------- 2007 (%) (%) - ---- September 103.50 100.51 55,680 October 103.25 100.00 39,410 November 101.48 100.01 8,790 December 101.99 95.00 4,520 2008 ==== January 101.00 100.00 9,870 February 101.68 99.70 3,890 Our 9.00% Debentures are listed for trading on the TSX under the symbol "AVN.DB.A". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 9.00% Debentures as reported by the TSX for the periods indicated. 53 Period High Low Volume - --------------------- ------- ------- ----------- 2007 (%) (%) - ---- January 103.25 103.00 860 February 104.00 104.00 150 March 105.02 104.65 780 April 103.01 98.00 480 May 101.31 101.31 50 June 105.06 102.47 650 July - - - August 101.28 101.23 420 September 100.00 100.00 100 October 100.06 100.06 13 November 103.75 100.08 440 December 100.84 100.03 300 2008 ==== January 102.65 101.00 760 February 101.47 101.42 830 ESCROWED SECURITIES As part of the Arrangement, shareholders of AIM received Trust Units in payment for the sale of their AIM shares to the Trust. All such shareholders were required to enter into an escrow agreement (the "ESCROW AGREEMENT") providing for the release of Trust Units as to one-third on each anniversary date of the Arrangement for three years. All distributions paid on the Trust Units held in escrow are made directly to the holders of the escrowed Trust Units, notwithstanding that their Trust Units are in escrow. All Trust Units will be released from escrow if a Change in Control (as defined in the Escrow Agreement) occurs. All Trust Units being held in escrow for a particular shareholder will be released upon that shareholder ceasing to be an employee for any reason other than termination for just cause or voluntary departure or resignation. The Board may consent to the transfer within escrow or the release from escrow of Trust Units in such circumstances and on such terms and conditions as it shall determine in its sole discretion. The Trust Units subject to escrow at December 31, 2007 are as follows: NUMBER OF TRUST UNITS HELD IN DESIGNATION OF CLASS ESCROW PERCENTAGE OF CLASS -------------------- ------------------------------ ------------------- Trust Units 1,193,622(1) 0.9% Notes: (1) All Trust Units are held by Computershare Trust Company of Canada as escrow agent. LEGAL PROCEEDINGS There are no outstanding legal proceedings which are for claims in excess of 10% of our current asset value to which we are a party or in respect of which any of our properties are subject, nor are there any such proceedings known to be contemplated. REGULATORY ACTIONS During the year ended December 31, 2007 there were (i) no penalties or sanctions imposed against the Trust or AOG or by a court relating to securities legislation or by a securities regulatory authority; (ii) no other penalties or sanctions imposed by a court or regulatory body against the Trust or AOG that would likely be considered important to a reasonable investor 54 in making an investment decision; and (iii) no settlement agreements the Trust or AOG entered into before a court relating to a securities legislation or with a securities regulatory authority. INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS There were no material interests, direct or indirect, of directors and executive officers of AOG or nominees for director of AOG, any Unitholder who beneficially owns or directs or controls more than 10% of the Trust Units or any known associate or affiliate of such persons in any transaction during 2007 or in any proposed transaction which has materially affected or would materially affect the Trust or AOG other than: (i) certain insiders purchasing Trust Units or Debentures under the public offerings of such securities completed during 2007; and (ii) as disclosed herein. MATERIAL CONTRACTS Except for contracts entered into by us in the ordinary course of business or otherwise disclosed herein, the only material contracts we entered into are the Trust Indenture described herein under the heading "ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND" and the Administrative Agreement described herein under the heading "ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND - DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST GOVERNANCE". Copies of the Trust Indenture and Administration Agreement, in addition to Documents Affecting the Rights of Securityholders, are available on our SEDAR profile at www.sedar.com. INTEREST OF EXPERTS There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by us during, or related to, our most recently completed financial year other than Sproule Associates Limited, our independent engineering evaluator, KPMG LLP, our former auditors, and PricewaterhouseCoopers LLP, our current auditors. As at the date hereof, none of the principals of Sproule Associates Limited had any registered or beneficial interests, direct or indirect, in any securities or other property of Advantage or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. PricewaterhouseCoopers LLP have confirmed that they are independent in accordance with the relevant rules and related interpretation prescribed by the Institute of Chartered Accountants of Alberta. In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of the Trust or of any associate or affiliate of the Trust except for Mr. Jay Reid, the Corporate Secretary of AOG, who is a partner of Burnet, Duckworth & Palmer LLP, which law firm provides the Trust and AOG with legal services. AUDITORS, TRANSFER AGENT AND REGISTRAR Our auditors are PricewaterhouseCoopers LLP, Chartered Accountants, Calgary, Alberta. Computershare Trust Company of Canada at its offices in Calgary, Alberta and Toronto, Ontario acts as the transfer agent and registrar for the Trust Units and Debentures. AUDIT COMMITTEE INFORMATION COMPOSITION OF THE AUDIT COMMITTEE The audit committee (the "AUDIT COMMITTEE") is comprised of Messrs. Rodger Tourigny and Ronald McIntosh and Ms. Carol Pennycook. The following chart sets out the assessment of each Audit Committee member's independence, financial literacy and relevant educational background and experience supporting such financial literacy. 55
NAME, PROVINCE AND COUNTRY OF FINANCIALLY RESIDENCE INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE - ------------------------------ ----------- ----------- --------------------------------------------------------- Rodger A. Tourigny Yes Yes Mr. Tourigny has a Bachelor of Commerce and is a Alberta, Canada Chartered Accountant. He is a director and President of Tourigny Management Ltd., a private company through which he provides consulting services. Mr. Tourigny is also a director and member of the Audit Committee of Burmis Energy Inc. and of Ramparts Energy Ltd., a private oil and gas company. Ronald A. McIntosh Yes Yes Mr. McIntosh is the Chairman and member of audit Alberta, Canada committee of North American Energy Partners Inc., a publicly traded corporation. Mr. McIntosh is also the Chairman and member of the audit committee of Tasman Energy, a private oil and gas company. Carol D. Pennycook Yes Yes Ms. Pennycook is a partner at the Toronto offices of Ontario, Canada Davies Ward Phillips & Vineberg, LLP, a national law firm. Ms. Pennycook received her LLB in 1979 and has been a partner since 1986. A significant portion of Ms. Pennycook's practice involves financing transactions
PRE-APPROVAL OF POLICIES AND PROCEDURES We have adopted polices and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by PricewaterhouseCoopers LLP as set forth in item 15 of the Audit Committee charter, which is reproduced below under the heading "AUDIT COMMITTEE CHARTER". The Audit Committee has approved the provision of a specified list of audit and permitted non-audit services that the audit committee believes to be typical, reoccurring or otherwise likely to be provided by PricewaterhouseCoopers LLP during the current fiscal year. The list of services is sufficiently detailed as to the particular services to be provided to ensure that the audit committee knows precisely what services it is being asked to pre-approve and it is not necessary for any member of management to make a judgment as to whether a proposed service fits within pre-approved services. AUDIT COMMITTEE CHARTER The following is a summary of our Audit Committee Charter which was originally approved by the AOG Board of Directors on April 30, 2002 and amended in April 2003, April 2004, June 2005, August 2005, October 2005 and March 2006: PURPOSE The primary function of the Audit Committee is to assist the Board of Directors of AOG in fulfilling its responsibilities by reviewing: the financial reports and other financial information provided by the Trust to any governmental body or the public; the Trust's systems of internal controls regarding finance, accounting, legal compliance and ethics that management and the Board have established; and the Trust's auditing, accounting and financial reporting processes generally. Consistent with this function, the Audit Committee should endeavour to encourage continuous improvement of, and should endeavour to foster adherence to, the Trust's policies, procedures and practices at all levels. In performing its duties, the external auditor is to report directly to the Audit Committee. The Audit Committee's primary objectives are: 1. To assist directors meet their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Trust and related matters; 2. To provide better communication between directors and external auditors; 3. To assist the Board's oversight of the auditor's qualifications and independence; 4. To assist the Board's oversight of the credibility, integrity and objectivity of financial reports; 56 5. To strengthen the role of the outside directors by facilitating discussions between directors on the Audit Committee, management and external auditors; 6. To assist the Board's oversight of the performance of the Corporation's internal audit function and independent auditors; and 7. To assist the Board's oversight of the Corporation's compliance with legal and regulatory requirements. COMPOSITION The Audit Committee shall be comprised of three or more directors as determined by the Board of Directors, none of whom are members of management of AOG, or the Trust and all of whom are "independent" (as such term is defined in (a) National Instrument 52-110 -- Audit Committees ("NI 52-110") and (b) Section 303A.02 of the Corporate Governance Rules of the New York Stock Exchange). All of the members of the Audit Committee shall be "financially literate". The Board of Directors has adopted the definition for "financial literacy" used in NI 52-110. Audit Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Trust or an outside consultant. In addition, at least one member of the Audit Committee must have accounting or related financial management expertise, as the Corporation's Board of Directors interprets such qualification in its business judgment. The members of the Audit Committee shall be elected by the Board of Directors at the annual organizational meeting of the Board of Directors and remain as members of the Audit Committee until their successors shall be duly elected and qualified. Unless a Chair is elected by the full Board of Directors, the members of the Audit Committee may designate a Chair by majority vote of the full Audit Committee membership. In connection with the election of the members of the Audit Committee, the Board will determine whether any proposed nominee for the Audit Committee serves on the Audit Committees of more than three public companies. To the extent that any proposed nominee of AOG serves on the Audit Committees of more than three public companies, the Board will make a determination as to whether such simultaneous services would impair the ability of such member to effectively serve on AOG's Audit Committee and will disclose such determination in Advantage's annual information circular and annual report on Form 40-F filed with the Securities and Exchange Commission. MEETINGS The Audit Committee shall meet at least four times annually, or more frequently as circumstances dictate. As part of its job to foster open communication, the Audit Committee should meet at least annually with management, internal auditors and the independent auditors in separate executive sessions to discuss any matters that the Audit Committee or each of these groups believe should be discussed privately. In addition, the Audit Committee or at least its Chair should meet with the independent auditors and management quarterly to review the Trust's financials consistent with Section IV.4 below. The Audit Committee should also meet with management and independent auditors on an annual basis to review and discuss annual financial statements and the management's discussion and analysis of financial conditions and results of operations. A quorum for meetings of the Audit Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Audit Committee shall be the same as those governing the Board. RESPONSIBILITIES AND DUTIES To fulfill its responsibilities and duties, the Audit Committee shall endeavour to: DOCUMENTS/REPORTS REVIEW 1. Review and update this Charter periodically, at least annually, as conditions dictate. 2. Review the organization's annual and interim financial statements, MD&A, earnings press releases and any reports or other financial information submitted to any governmental body or the public, including any certification, report, opinion or review rendered by the independent auditors. 57 3. Review the reports to management prepared by the independent auditors and management's responses. 4. Review with financial management and the independent auditors the quarterly financial statements prior to their filing or prior to the release of earnings. The Chair of the Audit Committee may represent the entire Audit Committee for purposes of this review. 5. Review significant findings during the year, including the status of previous significant audit recommendations. 6. Periodically assess the adequacy of procedures for the review of corporate disclosure that is derived or extracted from the financial statements. 7. Periodically discuss guidelines and policies to govern the processes by which the Chief Executive Officer and senior management assess and manage the Corporation's exposure to risk. 8. Report regularly to the Board any issues that arise with respect to the quality or integrity of the Corporation's financial statements, compliance with legal or regulatory requirements, performance and independence of the Corporation's auditors, or performance of the internal audit function. 9. To prepare, if required, an Audit Committee report to be included in Advantage's annual information circular and proxy statement. 10. Preparing an annual performance evaluation of the Audit Committee. 11. At least annually, obtaining and reviewing the report by the independent auditors describing the Trust's internal quality control procedures, any material issues raised by the most recent interim quality-control review, or peer review, of the Trust or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps to deal with any such issues. INDEPENDENT AUDITORS 12. Recommend to the Board the external auditors to be nominated for appointment by the unitholders. 13. Approve the compensation of the external auditors. 14. On an annual basis, the Audit Committee should review and discuss with the auditors all significant relationships the auditors have with the Trust to determine the auditors' independence. In addition, the Audit Committee will ensure the rotation of the lead audit partner every five years and, in order to ensure continuing auditor independence, consider the rotation of the audit firm itself. 15. Review and, as appropriate, resolve any material disagreements between management and the independent auditors and review, consider and make a recommendation to the Board regarding any proposed discharge of the auditors when circumstances warrant. 16. When there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change. 17. Periodically consult with the independent auditors, without the presence of management, about internal controls and the fullness and accuracy of the organization's financial statements. 18. Oversee the establishment of an internal audit function. 19. Periodically assess the Corporation's internal audit function, including the Corporation's risk management processes and system of internal controls. 58 20. Review the audit scope and plan of the independent auditor. 21. Oversee the work of the external auditors engaged for the purpose of preparing or issuing an auditor's report or performing other audit, review or attest services for the Trust. 22. Pre-approve the completion of any non-audit services by the external auditors and determine which non-audit services the external auditor is prohibited from providing. The Audit Committee may delegate to one or more members of the Audit Committee authority to pre-approve non-audit services in satisfaction of this requirement and if such delegation occurs, the pre-approval of non-audit services by the Audit Committee member to whom authority has been delegated must be presented to the Audit Committee at its first scheduled meeting following such pre-approval. The Audit Committee shall be entitled to adopt specific policies and procedures for the engagement of non-audit services if: (a) the pre-approval policies and procedures are detailed as to the particular service; (b) the Audit Committee is informed of each non-audit service; and (c) the procedures do not include delegation of the Audit Committee's responsibilities to management. The Audit Committee will satisfy the pre-approval requirement set forth in this paragraph 22 if: (d) the aggregate amount of all non-audit services that were not pre-approved is reasonably expected to constitute no more than 5% of the total amount of fees paid by the Trust and its subsidiary entities to the auditors during the fiscal year in which the services are provided; (e) the Trust or the subsidiary entity, as the case may be, did not recognize the services as non-audit services at the time of the engagement; (f) the services are promptly brought to the attention of the Audit Committee and approved, prior to completion of the audit, by the Audit Committee or by one or more of its members to whom authority to grant such approvals has been delegated by the Audit Committee; and 23. Review, set and approve hiring policies relating to staff of current and former auditors. FINANCIAL REPORTING PROCESSES 24. In consultation with the independent auditors, annually review the integrity of the organization's financial reporting processes, both internal and external. 25. In consultation with the independent auditors, consider annually the quality and appropriateness of the Corporation's accounting principles as applied in its financial reporting. 26. Consider and approve, if appropriate, major changes to the Trust's auditing and accounting principles and practices as suggested by the independent auditors or management. 27. Review risk management policies and procedures of the Trust and AOG (i.e., litigation and insurance). PROCESS IMPROVEMENT 28. Request reporting to the Audit Committee by each of management and the independent auditors of any significant judgments made in the management's preparation of the financial statements and the view of each group as to appropriateness of such judgments. 59 29. Following completion of the annual audit, review separately with each of management and the independent auditors any significant difficulties encountered during the course of the audit, including any restrictions on the scope of work or access to required information. 30. Review any significant disagreements among management and the independent auditors in connection with the preparation of the financial statements. 31. Review with the independent auditors and management the extent to which changes or improvements in financial or accounting practices, as approved by the Audit Committee, have been implemented. (This review should be conducted at an appropriate time subsequent to implementation of changes or improvements, as decided by the Audit Committee.) 32. Conduct and authorize investigations into any matters brought to the Audit Committee's attention and within the Audit Committee's scope of responsibilities. The Audit Committee shall be empowered to retain and to approve compensation for any independent counsel and other professionals to assist in the conduct of any investigation. 33. Review the systems that identify and manage principal business risks. 34. Establish a procedure for: (a) the receipt, retention and treatment of complaints received by the Trust and AOG regarding accounting, internal accounting controls or auditing matters; and (b) the confidential, anonymous submission by employees of the Trust and AOG of concerns regarding questionable accounting or auditing matters; which procedure shall be set forth in a "whistle blower program" to be adopted by the Audit Committee in connection with such matters. ETHICAL AND LEGAL COMPLIANCE 35. Establish, review and update periodically a Code of Ethical Conduct and ensure that management has established a system to enforce this code. 36. Review management's monitoring of the Trust's compliance with the organization's Ethical Code. 37. In consultation with the auditors, consider the review system established by management regarding the Corporation's financial statements, reports and other financial information disseminated to governmental organizations and the public in the context of the applicable legal requirements. 38. On at least an annual basis, review with the Trust's auditors or counsel, as appropriate, any legal matters that could have a significant impact on the organization's financial statements, the Trust's compliance with applicable laws and regulations and inquiries received from regulators or government agencies. 39. Review with the organization's counsel legal compliance matters including the trading policies of securities. OTHER 40. Perform any other activities consistent with this Charter, the Trust's and AOG's by-laws and governing law, as the Audit Committee or the Board of Directors deems necessary or appropriate. 41. In connection with the performance of its responsibilities as set forth above, the Audit Committee shall have the authority to engage outside advisors and to pay outside auditors and advisors. 60 AUDIT SERVICE FEES AUDITOR SERVICES FEES The following table discloses fees billed to us by our former auditors, KPMG LLP.
TYPE OF SERVICE PROVIDED 2007 2006 - ------------------------ -------- -------- Audit Fees (these services included prospectus work and audit or review of financials $203,089 $617,000 forming part of such prospectus, U.S. GAAP reconciliation, and work related to the Sound Acquisition) Audit-Related Fees (these services included French translation in connection with $57,508 $144,500 prospectus offerings) Tax Fees (these services included review/completion of tax returns and general tax $110,725 $36,040 consultations) The following table discloses fees billed to us by our current auditors, PricewaterhouseCoopers LLP. TYPE OF SERVICE PROVIDED 2007 - ------------------------ -------- Audit Fees (these services included U.S. GAAP reconciliation and work related to the Sound Acquisition) $694,119 Audit-Related Fees $- Tax Fees (these services included review/completion of tax returns and general tax consultations) $25,930
INDUSTRY CONDITIONS The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia, and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas entities of similar size. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry. PRICING AND MARKETING - OIL AND NATURAL GAS The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council. The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any 61 natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council. The governments of Alberta, British Columbia, and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations. PIPELINE CAPACITY Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market natural gas production. In addition, the pro-rationing of capacity on the inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas. THE NORTH AMERICAN FREE TRADE AGREEMENT The North American Free Trade Agreement ("NAFTA") among the governments of Canada, United States of America, and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports. PROVINCIAL ROYALTIES AND INCENTIVES GENERAL In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner's interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests. Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to eliminate, 62 amend or allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative. The Canadian federal corporate income tax rate levied on taxable income is 19.5% effective January 1, 2008 for active business income including resource income. With the elimination of the corporate surtax effective January 1, 2008 and other rate reductions introduced in the October 2007 Economic Statement and Notice of Ways and Means Motion, the federal corporate income tax rate will decrease to 15% in three steps: 19% on January 1, 2009, 18% on January 1, 2010, 18.5% on January 1, 2011, and 15% on January 1, 2012. ALBERTA In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. Currently, the amount of royalties that are payable is influenced by the oil production, density of the oil, and the vintage of the oil. Originally, the vintage classified oil in "new oil" and "old oil" depending on when the oil pools were discovered. If the pool was discovered prior to March 31, 1974 it is considered "old oil", if it was discovered after March 31, 1974 and before September 1, 1992, it is considered "new oil". The Alberta government introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%. The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends on the depth of the well. Oil sands projects are subject to a specific regulation made effective July 1, 1997, and expiring June 30, 2007, which, among other things, determines the Crown's share of crude and processed oil sands products. Regulations made pursuant to the MINES AND MINERALS ACT (Alberta) provided various incentives for exploring and developing oil reserves in Alberta. However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program ("ARTC") was to be eliminated, effective January 1, 2007. The programs affected by this announcement are: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction. The program being introduced is the Innovative Energy Technologies Program (the "IETP") which is intended to promote the producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. The IETP provides royalty reductions which are presumed to reduce financial risk. Alberta Energy will be the one to decide which projects qualify and the level of support that will be provided. The deadline for the IETP's third round of applications was May 31, 2007. The successful applicants have not yet been announced and it appears, based on the previous two rounds, that the selection process can take at least 8 months. The technical information gathered from this program is to be made public once a two year confidentiality period expires. On October 25, 2007, the Alberta government released a report entitled "The New Royalty Framework" (the "NRF") containing the government's proposals for Alberta's new royalty regime, which is scheduled to be effective on January 1, 2009. The proposed NRF includes new royalty formulas for conventional oil and natural gas that will operate on sliding scales that are determined by commodity prices and well productivity. Substantial legislative, regulatory and systems updates will be introduced before changes become fully effective in January 2009. BRITISH COLUMBIA Producers of oil and natural gas in the Province of British Columbia are required to pay annual rental payments with respect to the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands. The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil 63 is produced from a pool discovered before October 31, 1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil), or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable (exempt wells). Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450m(3) produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers would incur. The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation gas. On May 30, 2003, the Ministry of Energy and Mines for the Province of British Columbia announced an Oil and Gas Development Strategy for the Heartlands ("STRATEGY"). The Strategy is a comprehensive program to address road infrastructure, targeted royalties and regulatory reduction, and British Columbia service sector opportunities. In addition, the Strategy will result in economic and employment opportunities for communities in British Columbia's heartlands. Some of the financial incentives in the Strategy include: o Royalty credits of up to $30 million annually towards the construction, upgrading, and maintenance of road infrastructure in support of resource exploration and development. Funding will be contingent upon an equal contribution from industry. o Changes to provincial royalties: new royalty rates for low productivity natural gas to enhance marginally economic resources plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season. On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining the Province's strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world's leader in sustainable environmental management. For this purpose, on December 18, 2007 proposals were sought for applications to the Innovative Clean Energy Fund, in order to attract new technologies that will help solve energy and environmental issues. With regards to the oil and gas industry the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and gas sector. Among the changes to be implemented are: (i) a new of Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishment of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) new the Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves. SASKATCHEWAN In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month, and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered "heavy oil", "southwest designated oil", or "non-heavy oil other than southwest designated oil". The conventional royalty and production tax classifications ("fourth tier oil" introduced October 1, 2002, "third tier oil", "new oil", or "old oil") of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all "fourth tier oil" to 20% for "old oil". Marginal royalty rates are 30% for all "fourth tier oil" to 45% for "old oil". The amount payable as a royalty in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are "fourth tier gas" introduced 64 October 1, 2002, "third tier gas", "new gas", and "old gas". The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for "fourth tier gas" and 20% for "old gas". The marginal royalty rates are between 30% for "fourth tier gas" and 45% for "old gas". On October 1, 2002, the following changes were made to the royalty and tax regime in Saskatchewan: o A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic metres in a month. o A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002, was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of zero per cent. o The elimination of the re entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002, will receive the "fourth tier" royalty/ tax rates and new incentive volumes. In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the federal government disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes. As of January 1, 2007, the remaining balance of any unused RTR limited in its carry forward to five years since the federal government had the initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income. On June 19, 2007, the Government of Saskatchewan introduced the Orphan Well and Facility Liability Management Program pursuant to the amendment of the OIL AND GAS CONSERVATION ACT and the OIL AND GAS CONSERVATION REGULATIONS, 1985. The program includes a security deposit, which has two purposes: (i) preventing the individual with insufficient financial capability from acquiring oil and gas wells or facilities; and (ii) in the case of a bankrupt company, the funds cover for the decommissioning and reclaiming of orphan property. An additional change introduced is the mandatory licensing of all upstream oil and gas facilities in Saskatchewan. LAND TENURE Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms from two years, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated. ENVIRONMENTAL REGULATION The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. Environmental legislation in the Province of Alberta has been consolidated into the ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT (Alberta) (the "EPEA"), which came into force on September 1, 1993, and the OIL AND GAS CONSERVATION ACT (Alberta) (the "OGCA"). The EPEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations, and significantly increased penalties. In 2006, the Alberta Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial 65 operations including the oil and gas industry. In addition, the reduction emission guidelines outlined in the CLIMATE CHANGE AND EMISSIONS MANAGEMENT AMENDMENT ACT came into effect on July 1, 2007. Under this legislation, Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12%. Industries have three options to choose from in order to meet the reduction requirements outlined in this legislation, and these are: (i) by making improvement to operations that result in reductions; (ii) by purchasing emission credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emission; or (iii) by contributing to the Climate Change and Emissions Management Fund. Industries can either choose one of these options or a combination thereof. We will be committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment, and will be taking such steps as required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which it operates. We believe that we are in material compliance with applicable environmental laws and regulations. We also believe that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue. In January 24, 2008, the Alberta Government announced a new climate change action plan that will cut Alberta's projected 400 million tonnes of emissions in half by 2050. This plan is based on three areas: (i) carbon capture and storage, which will be mandatory for IN SITU oil sand facilities that use heavy fuels for steam generation; (ii) energy conservation and efficiency; and (iii) greening production through increased investment in clean energy technology, including supporting research on new oil sands extraction processes, as well as the funding of projects that reduce the cost of separating CO2 from other emissions supporting carbon capture and storage. British Columbia's ENVIRONMENTAL ASSESSMENT ACT became effective June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental review process. On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining the Province's strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world's leader in sustainable environmental management. For this purpose, on December 18, 2007 proposals were sought for applications to the Innovative Clean Energy Fund, in order to attract new technologies that will help solve energy and environmental issues. With regards to the oil and gas industry the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and gas sector. Among the changes to be implemented are: (i) a new of Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishment of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) new the Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves. Furthering these initiatives, on February 19, 2008 the provincial Government announced that starting on July 1, 2008, provided the legislation is approved; a revenue-neutral carbon tax will be applied to all fossil fuels used in the Province. The tax would be phased in, and the initial rate would be based on CO2e of $10 per tonne for the first six months of 2009 and $15 per tonne for the last six months of 2009, following $5 per tonne increases on July of every year until 2012. Tax credits and reductions will be used in order to offset the tax revenues that the Government would receive otherwise. In December, 2002, the Government of Canada ratified the Kyoto Protocol (the "PROTOCOL"). The Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 "business-as-usual" levels between 2008 and 2012. Given revised estimates of Canada's normal emissions levels, this target translates into an approximately 40% gross reduction in Canada's current emissions. It remains uncertain whether the Kyoto target of 6% below 1990 emission levels will be enforced in Canada. The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using a "intensity based" approach, the specifics of which have yet to be determined. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Protocol, was passed by the House of Commons on February 14, 2007. On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "ACTION PLAN") also known as ecoACTION which includes the regulatory framework for air emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy using products. The Government of Canada and the Province of Alberta released on January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through competitive process; and targeting research to lower the cost of technology. 66 Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on us and our operations and financial condition at this time. As details of the implementation of this legislation have not yet been announced, the effect of our operations cannot be determined at this time. TRENDS There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near future of the business. The first trend is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. A tight supply-demand balance for natural gas causes significant elasticity in pricing, whereas higher than average storage levels tend to depress natural gas pricing. Drilling activity, weather, fuel switching and demand for electrical generation are all factors that affect the supply-demand balance. Changes to any of these or other factors create price volatility. Crude oil is influenced by the world economy, Organization of the Petroleum Exporting Countries' ability to adjust supply to world demand and weather. Crude oil prices have been kept high by political events causing disruptions in the supply of oil and concern over potential supply disruptions triggered by unrest in the Middle East and more recently have been impacted by weather and increased storage levels. Political events trigger large fluctuations in price levels. The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. Purchasing land and properties similarly increase in price during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline. A second trend within the Canadian oil and gas industry is the fairly consistent "renewal" of private and small junior oil and gas companies starting up business. These companies often have experienced management teams from previous industry organizations that have disappeared as a part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel. We will have to compete with these companies and others to attract qualified personnel. A third trend currently affecting the oil and gas industry is the impact on capital markets caused by investor uncertainty in the North American economy. The capital market volatility in Canada has also been affected by uncertainties surrounding the economic impact that the Protocol, and other environmental initiatives, will have on the sector and, in more recent times, by the enactment of the SIFT Tax legislation relating to trusts, such as the Trust. Under the legislation, trusts such as the Trust will be liable for tax at a rate consistent with the taxes currently imposed on corporations commencing in January 2011, provided that the SIFT experiences only "normal growth" and no "undue expansion" before then, in which case the tax could be imposed prior to the January 2011 deadline. See "RISK FACTORS - CHANGES IN LEGISLATION - SIFT TAX". Generally during the past year, the economic recovery combined with increased commodity prices has caused an increase in new equity financings in the oil and gas industry, although the level of same was negatively impacted by enactment of the SIFT Tax. We will compete with numerous new companies and their new management teams and development plans in its access to capital. The competitive nature of the oil and gas industry will cause opportunities for equity financings to be selective. We may have to rely on internally generated funds to conduct our exploration and developmental programs. RISK FACTORS The following is a summary of certain risk factors relating to the business of AOG and the Trust. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this annual information form. 67 DEPENDENCE ON AOG We are an open-ended, limited purpose trust which will be entirely dependent upon the operations and assets of AOG through our ownership of the Common Shares, the Notes and the Royalty. Accordingly, the cash distributions to our Unitholders will be dependent upon the ability of AOG to meet its interest and principal repayment obligations under the Notes to declare and pay dividends on the Common Shares, and to pay the Royalty. AOG's income will be received from the production of oil and natural gas from AOG's existing Canadian resource properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. AOG is generally not involved in the exploration for oil and natural gas. As a result, if the oil and natural gas reserves associated with AOG's Canadian resource properties are not supplemented through additional development or the acquisition of additional Oil and Natural Gas Properties, the ability of AOG to meet its obligations to us may be adversely affected. OIL AND NATURAL GAS PRICES AOG's results of operations and financial condition and the monthly cash distributions we pay to Unitholders are highly dependent upon the prices received for AOG's oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of us and AOG. These factors include, among others: o global energy policy, including the ability of OPEC to set and maintain production levels and prices for oil; o political conditions throughout the world, including the risk of hostilities in the Middle East and global terrorism; o worldwide economic conditions; o weather conditions; o the supply and price of foreign oil and natural gas; o the level of consumer demand; o the price and availability of alternative fuels; o the proximity to, and capacity of, transportation facilities; o the effect of worldwide energy conservation measures; and o government regulations. Declines in oil or natural gas prices will have an adverse effect upon our operations, financial condition, reserves and ultimately on our ability to pay distributions to Unitholders. We may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If we hedge our commodity price exposure, we will forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity hedging activities could expose us to losses. To the extent that we engage in risk management activities related to commodity prices, we will be subject to credit risks associated with counterparties with which we contract. Oil prices were relatively high throughout 2007 averaging US$72.37 WTI as compared to an average of US$66.35 WTI in 2006, an increase of 9%. AECO monthly index prices averaged $6.61/Mcf in 2007 as compared to $6.98/Mcf in 2006, a decrease of 5%. The price of oil and natural gas will fluctuate and price and demand are factors beyond our control. Such fluctuations will have a positive or negative effect upon the revenue to be received by it. Such fluctuations will also have an effect upon the acquisition costs of any future Oil and Natural Gas Properties that we may acquire. As well, cash distributions from us will be highly sensitive to the prevailing price of crude oil and natural gas. EXPLOITATION AND DEVELOPMENT Exploitation and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. These risks are mitigated by using highly skilled staff, focusing exploitation efforts in areas in which we have existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods, and controlling costs to maximize returns. Advanced oil and natural gas related technologies such as three- 68 dimensional seismography, reservoir simulation studies and horizontal drilling have been and will be used by us to improve our ability to find, develop and produce oil and natural gas. OPERATING COSTS AND PRODUCTION DECLINES Higher operating costs for the underlying properties of AOG will directly decrease the amount of cash flow received by us and, therefore, may reduce distributions to our Unitholders. Electricity, chemicals, supplies, reclamation and abandonment and labour costs are a few of AOG's operating costs that are susceptible to material fluctuation. The level of production from AOG's existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond AOG's control. A significant decline in production could result in materially lower revenues and cash flow and, therefore, could reduce the amount available for distributions to Unitholders. OPERATIONS AOG's operations are subject to all of the risks normally incident to the operation and development of Oil and Natural Gas Properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injuries, loss of life and damage to the property of AOG and others. AOG has both safety and environmental policies in place to protect its operators and employees, as well as to meet the regulatory requirements in those areas where it operates. In addition, AOG has liability insurance policies in place, in such amounts as it considers adequate, however, it will not be fully insured against all of these risks, nor are all such risks insurable. Costs incurred to repair any of such damage or pay any of such liabilities will reduce Royalty Income. Continuing production from a property, and, to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of AOG to certain Properties. A reduction of the income from the Royalty could result in such circumstances. MARKETING The marketability and price of oil and natural gas that may be acquired or discovered by us will be affected by numerous factors beyond our control. These factors include demand for oil and natural gas, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas. CAPITAL INVESTMENT To the extent that AOG uses cash flow to finance acquisitions, development costs and other significant expenditures, the net cash flow of the Trust will be reduced. Hence, the timing and amount of capital expenditures may affect the amount of net cash flow available to us and, as a consequence, the amount of cash available to distribute to Unitholders. Therefore, distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made. The AOG Board of Directors has the discretion to determine the extent to which cash flow will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under the credit facility. As a consequence, the amount of funds retained by AOG to pay debt services charges or reduce debt will reduce the amount of cash distributed to Unitholders during those periods in which funds are so retained. ASSESSMENTS OF VALUE OF ACQUISITIONS Acquisitions of resource issuers and resource assets will be based in large part upon engineering and economic assessments made by independent engineers. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures 69 and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. In particular, the prices of and markets for resource products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based upon reports by a firm of independent engineers that are not the same as the firm that we use for our year end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm used by us. Any such instance may offset the return on and value of the Trust Units. DEBT SERVICE AOG has credit facilities in the amount of $710,000,000. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to us. Although it is believed that the bank line of credit is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of AOG or that additional funds can be obtained. The lenders have been provided with security over substantially all of the assets of AOG. If AOG becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lenders may foreclose on or sell the Properties free from or together with the Royalty. The payment of interest and principal on debt may also result in us or our subsidiaries having taxable income and cash taxes payable as taxable income would no longer be reduced by royalty payments at the time debt repayment occurs. PRIOR RANKING INDEBTEDNESS; ABSENCE OF COVENANT PROTECTION The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of our creditors. The payment of principal and interest on the Debentures will be subordinated to the Senior Indebtedness of us and to indebtedness of our trade creditors. The Debentures will also be effectively subordinate to claims of creditors of our subsidiaries except to the extent we are a creditor of such subsidiaries ranking at least pari passu with such other creditors. The Indentures will not limit the ability of us to incur additional liabilities (including Senior Indebtedness) or to make distributions, except, in respect of distributions, where an Event of Default has occurred or would occur and such default has not been cured or waived. The Indentures do not contain any provision specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving Advantage. However, the Indentures, among other things, restrict our level of indebtedness, provides operating investment guidelines, mandates the making of distributions and specify the nature of our business. ENVIRONMENTAL CONCERNS All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. In 2002, the Government of Canada ratified the Protocol which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. On March 10, 2008, the Government of Canada released "Turning the Corner - Taking Action to Fight Climate Change" (the "UPDATED ACTION PLAN") which provides some additional guidance with respect to the Government's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the oil sands, oil and gas and refining. The Updated Action Plan is intended to create a carbon emissions trading market, including an offset system, to provide incentive to reduce greenhouse gas emission and establish a market price for carbon. There are mandatory reductions of 18% from the 2006 baseline starting in 2010 and an additional 2% in subsequent years 70 for existing facilities. This target will be applied to regulated sectors on a facility-specific, sector-wide or corporate basis; in the case of oils sands production, petroleum refining, natural gas pipelines and upstream oil and gas the target will be considered facility-specific (sectors in which the facilities are complex and diverse, or where emissions are affected by factors beyond the control of the facility operator). Emissions from new facilities, which are those built between 2004 and 2011, will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time, and will be granted a 3-year grace period during which no emissions intensity targets will apply. Targets will begin to apply on the fourth year of commercial operation and the baseline will be the third year's emissions intensity, with a 2% continuous annual emission intensity improvement required. The definition of new facility also includes greenfield facilities, major expansions constituting more than a 25% increase in a facility's physical capacity, as well as transformations to a facility that involve significant changes to its processes. For upstream oil and gas and natural gas pipelines, it will be applied using a sector-specific approach. For the oil sands, its application will be process-specific, oil sands plants built in 2012 and later, those which use heavier hydrocarbons, up-graders and IN-SITU production will have mandatory standards in 2018 that will be based on carbon capture and storage. In the following regulated sectors, the Updated Action Plan will apply only to facilities exceeding a minimum annual emissions threshold: (i) 50,000 tonnes of CO2 equivalent per year for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalent per upstream oil and gas facilities; and (iii) 10,000 boe/d/company. These proposed thresholds are significantly stricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facility. Four separate compliance mechanisms are provided in respect of the above targets: Technology Fund contributions, offset credits, clean development credits and credits for early action. The most significant of these compliance mechanisms, at least initially, will be the Technology Fund and for which regulated entities will be able to contribute in order to comply with emissions intensity reductions. The contribution rate will increase over time, beginning at $15 for the 2010-12 period, rising to $20 in 2013, and thereafter increasing at the nominal rate of GDP growth. Contribution limits will correspondingly decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as mentioned above. The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to participate in and benefit from emissions reduction activities. In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities that will be verified before offset credits will be issued to the project proponent. Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either cancel the offset credits or bank them for future use or sale. Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Protocol. The purchase of such Emissions Reduction Credits will be restricted to 10% of each firm's regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations. Finally, a one-time credit of up to 15 Mt worth of emissions credits will be awarded to regulated entities for emissions reduction activities undertaken between 1992 and 2006. These credits will be both tradable and bankable. Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or the new regulatory framework, could have a material impact on the nature of oil and natural gas operations, including those of the Trust. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict at this time either the nature of those requirements or the impact on the Trust and its operations and financial condition. Although AOG has established a reclamation fund for the purpose of funding its currently estimated future environmental and reclamation obligations based upon its current knowledge, there can be no assurance that we will be able to satisfy our actual future environmental and reclamation obligations. Although AOG maintains insurance coverage considered to be customary in the industry, it is not fully insured against certain environmental risks, either because such insurance is not available, or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (compared to sudden and catastrophic damages) is not available. Accordingly, AOG's properties may be subject to liability due to hazards which cannot be insured against, or 71 have not been insured against due to prohibitive premium costs or for other reasons. In such an event, these environmental obligations will be funded out of AOG's cash flow and could therefore reduce distributable income payable to Unitholders. UNFORESEEN TITLE DEFECTS Although title reviews are generally conducted prior to any purchase of resource issuers or resource assets, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise to defeat AOG's title to certain assets. A reduction of the distributable cash flow of the Trust and possible reduction of capital could result from such defects. Any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of cash flow and, therefore, will reduce the amounts available for distribution to Unitholders. Should we be unable to fully fund the cost of remedying an environmental problem, it might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy. DELAY IN CASH DISTRIBUTIONS In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of the Properties, and by the operator to the Manager or AOG, payments between any of such parties may also be delayed by restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of the Properties, or the establishment by the operator of reserves for such expenses. Any of these delays could adversely affect distributions to Unitholders. FOREIGN CURRENCY EXCHANGE RATES AND INTEREST RATES World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the $Cdn/$US exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar, which occurred in 2007, negatively impacted our net production revenue and may affect the future value of our reserves as determined by independent evaluations at this time. The Canadian dollar strengthened in 2007 to an average $0.94 US/Cdn compared to $0.88 US/Cdn in 2006. The impact is reduced to the extent that we have engaged in, or in the future will engage in risk management activities related to commodity prices and foreign exchange rates. We will be subject to unfavourable price changes and credit risks associated with the counterparties with which it contracts. We have not entered into any foreign exchange contracts at this time. Variations in interest rates could result in a significant increase in the amount we pay to service debt which may result in a decrease in distributions to Unitholders, as well as impact the market price of the Trust Units on the TSX and the NYSE. RELIANCE UPON THE SENIOR EXECUTIVES OF AOG Unitholders will be dependent upon the management of AOG in respect of the administration and management of all matters relating to the Properties, the Royalty, the Trust and the Trust Units. The loss of the services of key individuals who currently comprise our management team could have a detrimental effect upon us. Investors who are not willing to rely on the management of AOG should not invest in the Trust Units. RESERVES The value of the Trust Units will depend upon, among other things, the reserves attributable to our properties. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for our properties will vary from estimates and those variations could be material. The reserve and cash flow information contained in this annual information form represent estimates only. Reserves and estimated future net cash flow from our properties have been independently evaluated at the dates indicated by independent oil and gas reservoir engineering firms. These firms consider a number of factors and make assumptions when estimating reserves. These factors and assumptions include: o historical production in the area compared with production rates from similar producing areas; o the assumed effect of governmental regulation; 72 o assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures; o initial production rates; o production decline rates; o ultimate recovery of reserves; o timing and amount of capital expenditures; o marketability of production; o future prices of oil and natural gas; o operating costs and royalties; and o other government levies that may be imposed over the producing life of reserves. These factors and assumptions were based upon prices at the date the relevant evaluations were prepared. If these factors and assumptions prove to be inaccurate, actual results may vary materially from the reserve estimates. Many of these factors are subject to change and are beyond our control. For example, evaluations are based in part upon the assumed success of exploitation activities intended to be undertaken in future years. Actual reserves and estimated cash flows will be less than those contained in the evaluations to the extent that such exploitation activities do not achieve the level of success assumed in the evaluations. Furthermore, cash flows may differ from those contained in the evaluations depending upon whether capital expenditures and operating costs differ from those estimated in the evaluations. DEPLETION OF RESERVES We have certain unique attributes that differentiate it from other oil and gas industry participants. Distributions of distributable income in respect of Properties, absent commodity price increases or cost effective acquisition and development activities will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. AOG will not be reinvesting cash flow in the same manner as other industry participants. Accordingly, absent capital injections, AOG's initial production levels and reserves will decline. AOG's future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent upon AOG's success in exploiting its reserve base and acquiring additional reserves. Without reserve additions through acquisition or development activities, AOG's reserves and production will decline over time as reserves are exploited. To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, AOG's ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. To the extent that AOG is required to use cash flow to finance capital expenditures or property acquisitions, the level of distributable income will be reduced. There can be no assurance that we will be successful in developing or acquiring additional reserves on terms that meet our investment objectives. RELIANCE UPON THIRD PARTY OPERATORS Continuing production from a property and marketing of product produced from the property are dependent to a large extent upon the ability of the operator of the property. We currently operate properties that represent approximately 85% of our total daily production. To the extent the operator fails to perform these functions properly or becomes insolvent, revenue may be reduced. ENFORCEMENT OF OPERATING AGREEMENTS Operations of the wells on properties not operated by us are generally governed by operating agreements, which typically require the operator to conduct operations in a good and workmanlike manner. Operating agreements generally provide, however, that the operator will have no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except such as may result from gross negligence or wilful misconduct. In addition, third-party operators are generally not fiduciaries with respect to us or our Unitholders. As an owner of working interests in properties we do not operate, we will generally have a cause of action for damages arising from a breach of such duty. Although not established by definitive legal precedent, it is unlikely that the Trust or Unitholders would be entitled to bring suit against third-party 73 operators to enforce the terms of the operating agreements; thus, Unitholders will be dependent upon us, as owner of the working interest, to enforce such rights. CHANGES IN LEGISLATION - SIFT TAX New legislation passed in June 2007 will apply a tax ("SIFT TAX") at the trust level on distributions of certain income from publicly traded mutual fund trusts, known as specified investment flow-through ("SIFT") trusts at rates comparable to the combined federal and provincial corporation tax, and will treat such distributions as dividends to the unitholders. The Trust is a SIFT and will be subject to the SIFT Tax. The SIFT Tax results in adverse consequences to the Trust and certain Unitholders (including most particularly Unitholders that are tax deferred, or non-residents of Canada) and may impact cash distributions from the Trust. Trusts that were in existence on October 31, 2006 will generally have a four-year transition period, and will not be subject to the SIFT Tax until January 1, 2011. However, the new legislation provides that there are circumstances under which an existing trust may lose its transitional relief before 2011, including where the "normal growth" of a trust existing on October 31, 2006 is exceeded. "Normal growth" includes equity growth within certain "safe harbour" limits, measured by reference to a SIFT's market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units). Those safe harbour limits are 40% for the period from November 1, 2006 to December 31, 2007, and 20% each for calendar 2008, 2009 and 2010. Moreover, the safe harbour limits are cumulative, so that any unused limit for a period carries over into the subsequent period. The Trust's market capitalization was approximately $1.6 billion as at October 31, 2006, which means that the Trust's safe harbour amount for the period ending December 31, 2007 was approximately $640 million, and is an additional $320 million for each of 2008, 2009 and 2010. The Trust's growth since October 31, 2006 has not been in excess of "normal growth". While it is unlikely that the restrictions on "normal growth" will affect our ability to raise the capital required to maintain and grow our existing operations in the ordinary course, they could adversely affect the cost of raising capital and our ability to undertake more significant acquisitions. Currently, the SIFT Rules provide that the SIFT Tax rate will be the federal general corporate income tax rate (which is anticipated to be 16.5% in 2011, and 15% in 2012) plus the provincial SIFT tax factor (which is set at a fixed rate of 13%), for a combined SIFT tax rate of 29.5% in 2011, and 28% in 2012. On February 26, 2008, the Minister of Finance announced, and on March 11, 2008, draft legislation was introduced (the "PROVINCIAL SIFT TAX PROPOSAL"), under which the effect will be that instead of basing the provincial component of the SIFT tax on a flat rate of 13%, the provincial component will instead be based on the general provincial corporate income tax rate in each province in which the SIFT has a permanent establishment. For purposes of calculating this component of the tax, the general corporate taxable income allocation formula will be used. Specifically, the Trust's taxable distributions will be allocated to provinces by taking half of the aggregate of: o that proportion of the Trust's taxable distributions for the year that the Trust's wages and salaries in the province are of its total wages and salaries in Canada; and o that proportion of the Trust's taxable distributions for the year that the Trust's gross revenues in the province are of its total gross revenues in Canada. Under the Provincial SIFT Tax Proposal the Trust would likely be considered to have a permanent establishment in Alberta, where the provincial tax rate in 2011 is expected to be 10%, which will result in an effective SIFT Tax rate of 26.5% in 2011 and 25% in 2012. Taxable distributions that are not allocated to any province would instead be subject to a 10% rate constituting the provincial component. There can be no assurance, however, that the Provincial SIFT Tax Proposal will be enacted as proposed. 74 The new legislation has reduced the value of the Trust Units, which has increased the cost to the Trust of raising capital in the public capital markets. In addition management of AOG believes that the SIFT Tax: (a) substantially eliminates the competitive advantage that the Trust and other Canadian energy trusts enjoyed relative to their corporate peers in raising capital in a tax-efficient manner, and (b) places the Trust and other Canadian energy trusts at a competitive disadvantage relative to industry competitors, including U.S. master limited partnerships, which will continue to not be subject to entity level taxation. The SIFT Tax also makes the Trust Units less attractive as an acquisition currency. As result, it may become more difficult for the Trust to compete effectively for acquisition opportunities. There can be no assurance that the Trust will be able to reorganize its legal and tax structure to substantially mitigate the expected impact of the SIFT Tax. No assurance can be provided that the SIFT Tax will not apply to the Trust prior to 2011, or that the income tax legislation will not be further changed in a manner which affects the Trust and its Unitholders. CHANGES IN TAX AND OTHER LAWS MAY ADVERSELY AFFECT UNITHOLDERS. Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource allowance, may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders. The Tax Act provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of unitholders must not be non-residents of Canada), unless at all times after February 21, 1990, "all or substantially all" of the trust's property consisted of property other than taxable Canadian property (the "TCP EXCEPTION"). Based on the most recent information obtained by us through our transfer agent and financial intermediaries, in February 2007 an estimated 70% of our issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Tax Act) at that time. We are currently able to take advantage of the TCP Exception, and as a result, the Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by non-residents. There is no assurance that the TCP Exception will continue to be available to the Trust or that the Canadian federal government will not introduce new changes or proposals to tax regulations directed at non-resident ownership which, given our level of non-resident ownership, may result in us losing our mutual fund trust status or could otherwise detrimentally affect us and the market price of the Trust Units. We intend to continue to take the necessary measures in order to ensure that we continue to qualify as a mutual fund trust under the Tax Act. There would be material adverse consequences if we lost our status as a mutual fund trust under Canadian tax laws. See "CHANGES IN LEGISLATION - MATERIAL ADVERSE TAX CONSEQUENCES TO LOSS OF MUTUAL FUND TRUST STATUS". We may not be able to take steps necessary to ensure that we maintain our mutual fund trust status. Even if we are successful in taking such measures, these measures could be adverse to certain holders of Trust Units, particularly "non-residents" of Canada (as defined in the Tax Act). There can be no assurance that such circumstances would not detrimentally affect the market price of the Trust Units. Additionally, legislation may be implemented to limit the investment in income funds and royalty trusts by certain investors or to change the manner in which these entities are taxed. Tax authorities having jurisdiction over us or our Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment or the detriment of our Unitholders. CHANGES IN LEGISLATION - MATERIAL ADVERSE TAX CONSEQUENCES TO LOSS OF MUTUAL FUND TRUST STATUS There can be no assurance that the treatment of mutual fund trusts will not be changed in a manner adversely affecting Unitholders. If we cease to qualify as a "mutual fund trust" under the Tax Act, the Trust Units will cease to be qualified investments for registered retirement savings plans, registered education savings plans, deferred profit sharing plans and registered retirement income funds. Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource taxation, may in the future be changed or interpreted in a manner that adversely affects us 75 and our Unitholders. Tax authorities having jurisdiction over the Trust or the Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practises to the detriment of us or the detriment of our Unitholders. We expect that we will continue to qualify as a mutual fund trust for purposes of the Tax Act. We may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for us and our Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows: o We would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties held by us. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax. o We would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws if it ceased to be a mutual fund trust. o Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them. o Trust Units would not constitute qualified investments for registered retirement savings plans ("RRSPS"), registered retirement income funds ("RRIFS"), registered education savings plans ("RESTS") or deferred profit sharing plans ("DPSPS"). If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to 1% of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have our registration revoked by the Canada Customs and Revenue Agency. In addition, we may take certain measures in the future to the extent it believes necessary to ensure that we maintain our status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units. INVESTMENT ELIGIBILITY We will endeavour to ensure that the Trust Units continue to be qualified investments for registered retirement savings plans, registered education savings plans, deferred profit sharing plans and registered retirement income funds. The Tax Act imposes penalties for the acquisition or holding of non-qualified or ineligible investments and there is no assurance that the conditions prescribed for such qualified or eligible investments will be adhered to at any particular time. NATURE OF TRUST UNITS The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in AOG. The Trust Units represent a fractional interest in the Trust. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions. Our primary assets will be the Notes, the Common Shares, the Royalty and other investments in securities. The price per Trust Unit is a function of anticipated distributable income, the Properties acquired by AOG, and the Manager's ability to effect long-term growth in our value. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and our ability to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units. The Trust Units are also unlike conventional debt instruments in that there is no principal amount owing to Unitholders. The Trust Units will have minimal value when reserves from our properties can no longer be economically produced or marketed. Unitholders will only be able to obtain a return of the capital they invested during the period when reserves may 76 be economically recovered and sold. Accordingly, the distributions received over the life of the investment may not be equal to or greater than the initial capital investment. THE TRUST UNITS ARE NOT "DEPOSITS" WITHIN THE MEANING OF THE CANADA DEPOSIT INSURANCE CORPORATION ACT (CANADA) AND ARE NOT INSURED UNDER THE PROVISIONS OF THAT ACT OR ANY OTHER LEGISLATION. FURTHERMORE, THE TRUST IS NOT A TRUST COMPANY AND, ACCORDINGLY, IS NOT REGISTERED UNDER ANY TRUST AND LOAN COMPANY LEGISLATION AS IT DOES NOT CARRY ON OR INTEND TO CARRY ON THE BUSINESS OF A TRUST COMPANY. NET ASSET VALUE The net asset value of our assets from time to time will vary depending upon a number of factors beyond the control of management, including oil and gas prices. The trading prices of the Trust Units from time to time is also determined by a number of factors which are beyond the control of management and such trading prices may be greater than the net asset value of our assets. ADDITIONAL FINANCING In the normal course of making capital investments to maintain and expand our oil and gas reserves, additional Trust Units are issued from treasury which may result in a decline in production per Trust Unit and reserves per Trust Unit. Additionally, from time to time we issue Trust Units from treasury in order to reduce debt and maintain a more optimal capital structure. To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, our ability and AOG's ability to make the necessary capital investments to maintain or expand our oil and gas reserves will be impaired. To the extent that the Trust and AOG are required to use cash flow to finance capital expenditures or property acquisitions or to pay debt service charges or to reduce debt, the level of distributable income will be reduced. COMPETITION There is strong competition relating to all aspects of the oil and gas industry. There are numerous trusts in the oil and gas industry, who are competing for the acquisitions of properties with longer life reserves and properties with exploitation and development opportunities. As a result of such increasing competition, it will be more difficult to acquire reserves on beneficial terms. The Trust and AOG also compete for reserve acquisitions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial and other resources than the Trust and AOG. RETURN OF CAPITAL Trust Units will have no value when reserves from the Properties can no longer be economically produced and, as a result, cash distributions do not represent a "yield" in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Distributions represent a blend of a return of Unitholders' initial investment and a return on Unitholders' initial investment. Unitholders have a limited right to require us to repurchase their Trust Units, which is referred to as a redemption right. See "INFORMATION RELATING TO THE TRUST - RIGHT OF REDEMPTION". It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investment. The right to receive cash in connection with a redemption is subject to limitations. Any securities which may be distributed IN SPECIE to Unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right. REDEMPTION RIGHT It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investments. Long Term Notes or Redemption Notes which may be distributed IN SPECIE to Unitholders in connection with a redemption will not be listed on any stock exchange and no established market is expected to develop for such Long Term Notes or 77 Redemption Notes. Cash redemptions are subject to limitations. See "ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND - REDEMPTION RIGHT". UNITHOLDER LIMITED LIABILITY The Trust Indenture provides that no Unitholder will be subject to any liability in connection with us or our affairs or obligations and, in the event that a court determines that Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, such Unitholder's share of our assets. The Trust Indenture provides that all written instruments signed by or on behalf of us must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Notwithstanding the provisions of the Trust Indenture and the fact that Alberta (our governing jurisdiction) has adopted legislation purporting to limit trust unitholder liability, because of uncertainties in the law relating to investment trusts, there is a risk that a Unitholder could be held personally liable for obligations of the Trust in respect of contracts or undertakings which the Trust enters into and for certain liabilities arising otherwise than out of contracts including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely. FUTURE DILUTION One of our objectives is to continually add to our reserves through acquisitions and through development, and because we does not reinvest our cash flow, our success is in part dependent upon our ability to raise capital from time to time. Holders of Trust Units may also suffer dilution in connection with future issuances of Trust Units, whether issued pursuant to a financing or acquisition or otherwise. REGULATORY MATTERS Our operations are subject to a variety of federal and provincial laws and regulations, including laws and regulations relating to the protection of the environment. THE ECONOMIC IMPACT ON ADVANTAGE OF CLAIMS OF ABORIGINAL TITLE IS UNKNOWN. Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada. We are unable to assess the effect, if any, that any such claim would have on our business and operations. EXPANSION OF OPERATIONS The operations and expertise of our management are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside this geographic area. In addition, the Trust Indenture does not limit our activities to oil and gas production and development, and we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines, or an interest in an oil sands project. Expansion of our activities into new areas may present new additional risks or alternatively, may significantly increase the exposure to one or more of the present risk factors which may result in our future operational and financial conditions being adversely affected. CONFLICTS OF INTEREST The directors and officers of AOG are engaged in and will continue to be engaged in other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of AOG may become subject to conflicts of interest. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA. 78 RISKS PARTICULAR TO UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS In addition to the risk factors set forth above, the following risk factors are particular to unitholders who are not residents of Canada. UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS MAY BE SUBJECT TO ADDITIONAL TAXATION. The Tax Act and the tax treaties between Canada and other countries may impose additional withholding or other taxes on the cash distributions or other property paid by us to Unitholders who are not residents of Canada, and these taxes may change from time to time. For instance, since January 1, 2005, a 15% withholding tax is applied to return of capital portion of distributions made to non-resident unitholders. Additionally, the reduced "Qualified Dividend" rate of 15% tax applied to our distributions under current U.S. tax laws is scheduled to expire at the end of 2010 and there is no assurance that this reduced tax rate will be renewed by the U.S. government at such time. Furthermore, the SIFT Tax is anticipated to result in adverse tax consequences to certain Unitholders including non-resident Unitholders. See "RISK FACTORS - CHANGES IN LEGISLATION - SIFT TAX". NON-RESIDENT UNITHOLDERS ARE SUBJECT TO FOREIGN EXCHANGE RISK ON THE DISTRIBUTIONS THAT THEY MAY RECEIVE FROM THE TRUST. Distributions from the Trust are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors are subject to foreign exchange risk. To the extent that the Canadian dollar weakens with respect to the currency of a non-resident, the amount of the distribution will be reduced when converted to the home currency of a non-resident. THE ABILITY OF UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS INVESTORS TO ENFORCE CIVIL REMEDIES MAY BE LIMITED. We are a trust organized under the laws of Alberta, Canada, and our principal place of business is in Canada. All of the directors and officers of AOG are residents of Canada and most of the experts who provide services to us (such as its auditors and some of its independent reserve engineers) are residents of Canada, and all or a substantial portion of their assets and our assets are located within Canada. As a result, it may be difficult for investors in the United States or other non-Canadian jurisdictions (a "FOREIGN JURISDICTION") to effect service of process within such Foreign Jurisdiction upon such directors, officers and representatives of experts who are not residents of the Foreign Jurisdiction or to enforce against them judgments of courts of the applicable Foreign Jurisdiction based upon civil liability under the securities laws of such Foreign Jurisdiction, including United States federal securities laws or the securities laws of any state within the United States. In particular, there is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or the securities laws of any state within the United States. DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE As a Canadian issuer listed on the New York Stock Exchange (the "NYSE"), we are not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic requirements. As a foreign private issuer, we are only required to comply with four of the NYSE Rules: 1) have an audit committee that satisfies the requirements of the United States Securities Exchange Act of 1934; 2) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE Rules; 3) provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. companies listed under the NYSE; and 4) submit an executed annual written affirmation, as well as an interim affirmation each time a change occurs to the Audit Committee. We have reviewed the NYSE listing standards and confirm that our corporate governance practices do not differ significantly from such standards. 79 ADDITIONAL INFORMATION Additional information, including directors' and officers' remuneration and indebtedness, principal holders of securities and interests of insiders in material transactions, where applicable, is contained in our information circular for the most recent annual meeting of shareholders that involved the election of directors. Additional financial information is provided in our financial statements and management's discussion and analysis for the year ended December 31, 2007. Documents affecting the rights of securityholders, along with additional information relating to Advantage, may be found on SEDAR at www.sedar.com. 79 SCHEDULE "A" REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION (FORM 51-101F3) Management of Advantage Oil & Gas Ltd. ("AOG") on behalf of Advantage Energy Income Fund (collectively, the "TRUST") is responsible for the preparation and disclosure of information with respect to the Trust's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs. An independent qualified reserves evaluator has evaluated the Trust's reserves data. The report of the independent qualified reserves evaluator is presented below. The independent reserves evaluation committee of the Trust has: (a) reviewed the Trust's procedures for providing information to the independent qualified reserves evaluator; (b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and (c) reviewed the reserves data with management and the independent qualified reserves evaluator. The independent reserves evaluation committee has reviewed the Trust's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the independent reserves evaluation committee, approved: (a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; (b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and (c) the content and filing of this report. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery. (signed) "KELLY I. DRADER" (signed) "PETER A. HANRAHAN" Kelly I. Drader Peter A. Hanrahan Chief Executive Officer Vice President, Finance and Chief Financial Officer (signed) "RONALD A. MCINTOSH" (signed) "JOHN HOWARD" Ronald A. McIntosh John Howard Director Director February 21, 2008 SCHEDULE "B" REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR (FORM 51-101 F2) To the Board of Directors of Advantage Oil & Gas Ltd., on behalf of Advantage Energy Income Fund (the "TRUST"): 1. We have evaluated the Trust's Reserves Data as at December 31, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs. 2. The Reserves Data are the responsibility of the Trust's management. Our responsibility is to express an opinion on the Reserves Data based on our evaluation. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE HANDBOOK"), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). 3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook. 4. The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Trust evaluated by us as of December 31, 2007, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Trust's management and Board of Directors:
Net Present Value of Future Net Revenue Before Income Taxes (10% Discount Rate) Independent Qualified -------------------------------------------- Reserves Evaluator or Description and Preparation Location of Audited Evaluated Reviewed Total Auditor Date of Evaluation Report Reserves (County) (M$) (M$) (M$) (M$) - -------------------------- --------------------------- ----------------- ------- --------- -------- ----- Evaluation of the P&NG Reserves of Advantage Oil & Sproule Associates Gas Ltd., Limited Canada As of December 31, 2007, prepared September 2007 to February 2008 TOTAL 261,420 2,201,190 NIL 2,462,610
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook. 6. We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date. 7. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery. (signed) "SPROULE ASSOCIATES LIMITED" Sproule Associates Limited Calgary, Alberta February 21, 2008 EX-99 10 ex99-2form40f_2007.txt EXHIBIT 99.2 EXHIBIT 99.2 ------------ [GRAPHIC OMITTED -- LOGO] ADVANTAGE ENERGY INCOME FUND CONSOLIDATED FINANCIAL STATEMENTS MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The Management of Advantage Energy Income Fund (the "Fund") is responsible for the preparation and presentation of the consolidated financial statements together with all operational and other financial information contained in the annual report. The financial statements have been prepared by Management in accordance with Canadian generally accepted accounting principles and utilize the best estimates and careful judgments of Management, where appropriate. Operational and other financial information contained throughout the annual report is consistent with that provided in the consolidated financial statements. Management has developed and maintains a system of internal controls designed to provide reasonable assurance that all transactions are accurately and reliably recorded, that the consolidated financial statements accurately report the Fund's operating and financial results within acceptable limits of materiality, that all other operational and financial information presented is accurate, and that the Fund's assets are properly safeguarded. The Audit Committee, comprised of non-management directors, acts on behalf of the Board of Directors to ensure that Management fulfills its financial reporting and internal control responsibilities. The Audit Committee is responsible for meeting regularly with Management, the external auditors, and the internal auditors to discuss internal controls over financial reporting processes, auditing matters and various aspects of financial reporting. The Audit Committee reviewed the consolidated financial statements with Management and the external auditors, and recommended approval to the Board of Directors. The Board of Directors has approved these consolidated financial statements. PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, appointed by the Board of Directors as the external auditor of the Fund, has audited the consolidated balance sheet as at December 31, 2007 and the consolidated statements of income, comprehensive income, accumulated deficit and cash flows for the year then ended. KPMG LLP, an independent firm of Chartered Accountants, has audited the consolidated balance sheet as at December 31, 2006 and the consolidated statements of income, accumulated deficit and cash flows for the year then ended. The external auditors conducted their audits in accordance with Canadian generally accepted auditing standards and have unlimited and unrestricted access to the Audit Committee. /s/ Kelly I. Drader /s/ Peter A. Hanrahan Kelly I. Drader Peter A. Hanrahan CEO VP Finance & CFO March 5, 2008 Advantage Energy Income Fund - 1 MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING The Management of Advantage Energy Income Fund (the "Fund") is responsible for establishing and maintaining adequate internal control over financial reporting for the Fund as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision of our Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on our assessment, we have concluded that as of December 31, 2007, our internal control over financial reporting was effective. 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. PricewaterhouseCoopers LLP, the Fund's independent firm of Chartered Accountants, was appointed by the Board of Directors to audit and provide independent opinions on both the Consolidated Financial Statements and the Fund's internal control over financial reporting as at December 31, 2007, as stated in their Auditor's Report. PricewaterhouseCoopers LLP has provided such opinions. /s/ Kelly I. Drader /s/ Peter A. Hanrahan Kelly I. Drader Peter A. Hanrahan CEO VP Finance & CFO March 5, 2008 Advantage Energy Income Fund - 2 INDEPENDENT AUDITORS' REPORT To the Unitholders of Advantage Energy Income Fund We have completed an integrated audit of the consolidated financial statements and internal control over financial reporting of Advantage Energy Income Fund (the "Fund") as at December 31, 2007. Our opinions, based on our audits, are presented below. CONSOLIDATED FINANCIAL STATEMENTS We have audited the accompanying consolidated balance sheet of the Fund as at December 31, 2007, and the related consolidated statements of income (loss) and comprehensive income (loss) and accumulated deficit and cash flows for the year then ended. These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of the Fund's financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides 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 the Fund as at December 31, 2007 and the results of its operations and its cash flows for the year then ended in accordance with Canadian generally accepted accounting principles. The financial statements as at December 31, 2006 and for the year then ended were audited by other auditors who expressed an opinion without reservation on those statements in their report dated March 21, 2007. INTERNAL CONTROL OVER FINANCIAL REPORTING We have also audited Advantage Energy Income Fund's internal control over financial reporting as at December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Fund's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the effectiveness of the Fund's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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. An audit of internal control over financial reporting includes 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 consider 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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, the Fund maintained, in all material respects, effective internal control over financial reporting as at December 31, 2007 based on criteria established in Internal Control -- Integrated Framework issued by the COSO. /s/ PricewaterhouseCoopers LLP Chartered Accountants Calgary, Canada March 5, 2008 Advantage Energy Income Fund - 3
CONSOLIDATED BALANCE SHEETS (thousands of dollars) DECEMBER 31, 2007 DECEMBER 31, 2006 - -------------------------------------------------------------------------------------------------------------------------------- ASSETS Current assets Accounts receivable $ 95,474 $ 79,537 Prepaid expenses and deposits 21,988 16,878 Derivative asset (note 12) 7,027 9,840 - -------------------------------------------------------------------------------------------------------------------------------- 124,489 106,255 Deposit on property acquisition - 1,410 Derivative asset (note 12) 174 593 Fixed assets (note 4) 2,177,346 1,753,058 Goodwill (note 3) 120,271 120,271 - -------------------------------------------------------------------------------------------------------------------------------- $ 2,422,280 $ 1,981,587 - -------------------------------------------------------------------------------------------------------------------------------- LIABILITIES Current liabilities Accounts payable and accrued liabilities $ 122,087 $ 116,109 Distributions payable to Unitholders 16,592 18,970 Current portion of capital lease obligations (note 5) 1,537 2,527 Current portion of convertible debentures (note 6) 5,333 1,464 Derivative liability (note 12) 2,242 - - -------------------------------------------------------------------------------------------------------------------------------- 147,791 139,070 Derivative liability (note 12) 2,778 - Capital lease obligations (note 5) 5,653 305 Bank indebtedness (note 7) 547,426 410,574 Convertible debentures (note 6) 212,203 170,819 Asset retirement obligations (note 8) 60,835 34,324 Future income taxes (note 9) 66,727 61,939 - -------------------------------------------------------------------------------------------------------------------------------- 1,043,413 817,031 - -------------------------------------------------------------------------------------------------------------------------------- UNITHOLDERS' EQUITY Unitholders' capital (note 10) 2,027,065 1,592,758 Convertible debentures equity component (note 6) 9,632 8,041 Contributed surplus (note 10) 2,005 863 Accumulated deficit (note 11) (659,835) (437,106) - -------------------------------------------------------------------------------------------------------------------------------- 1,378,867 1,164,556 - -------------------------------------------------------------------------------------------------------------------------------- $ 2,422,280 $ 1,981,587 - --------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS (note 14) see accompanying Notes to Consolidated Financial Statements On behalf of the Board of Directors of Advantage Oil & Gas Limited: /s/ Rodger A. Tourigny /s/ Kelly I. Drader Rodger A. Tourigny, Director Kelly I. Drader, Director Advantage Energy Income Fund - 4
CONSOLIDATED STATEMENTS OF INCOME (LOSS), COMPREHENSIVE INCOME AND ACCUMULATED DEFICIT YEAR ENDED YEAR ENDED (thousands of dollars, except for per Trust Unit amounts) DECEMBER 31, 2007 DECEMBER 31, 2006 - -------------------------------------------------------------------------------------------------------------------------------- REVENUE Petroleum and natural gas $ 538,764 $ 414,430 Realized gain on derivatives (note 12) 18,594 5,297 Unrealized gain (loss) on derivatives (note 12) (11,049) 10,242 Royalties, net of Alberta Royalty Credit (98,614) (76,456) - -------------------------------------------------------------------------------------------------------------------------------- 447,695 353,513 - -------------------------------------------------------------------------------------------------------------------------------- EXPENSES Operating 127,309 82,911 General and administrative 21,449 13,738 Management fee (note 13) - 887 Performance incentive (note 13) - 2,380 Management internalization (note 13) 15,708 13,449 Interest 24,351 18,258 Interest and accretion on convertible debentures 17,436 13,316 Depletion, depreciation and accretion 272,175 194,309 - -------------------------------------------------------------------------------------------------------------------------------- 478,428 339,248 - -------------------------------------------------------------------------------------------------------------------------------- Income (loss) before taxes and non-controlling interest (30,733) 14,265 Future income tax reduction (note 9) (24,642) (37,087) Income and capital taxes (note 9) 1,444 1,509 - -------------------------------------------------------------------------------------------------------------------------------- (23,198) (35,578) - -------------------------------------------------------------------------------------------------------------------------------- Net income (loss) before non-controlling interest (7,535) 49,843 Non-controlling interest - 29 - -------------------------------------------------------------------------------------------------------------------------------- NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) (7,535) 49,814 Accumulated deficit, beginning of year (437,106) (269,674) Distributions declared (215,194) (217,246) - -------------------------------------------------------------------------------------------------------------------------------- ACCUMULATED DEFICIT, END OF YEAR $ (659,835) $ (437,106) - -------------------------------------------------------------------------------------------------------------------------------- Net income (loss) per Trust Unit (note 10) Basic $ (0.06) $ 0.62 Diluted $ (0.06) $ 0.61 - --------------------------------------------------------------------------------------------------------------------------------
see accompanying Notes to Consolidated Financial Statements Advantage Energy Income Fund - 5
CONSOLIDATED STATEMENTS OF CASH FLOWS YEAR ENDED YEAR ENDED (thousands of dollars) DECEMBER 31, 2007 DECEMBER 31, 2006 - -------------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net income (loss) $ (7,535) $ 49,814 Add (deduct) items not requiring cash: Unrealized loss (gain) on derivatives 11,049 (10,242) Unit-based compensation 929 - Performance incentive - 2,380 Management internalization 15,708 13,449 Non-cash interest expense 890 - Accretion on convertible debentures 2,569 2,106 Depletion, depreciation and accretion 272,175 194,309 Future income tax (24,642) (37,087) Non-controlling interest - 29 Expenditures on asset retirement (6,951) (5,974) Changes in non-cash working capital (15,060) 20,303 - -------------------------------------------------------------------------------------------------------------------------------- Cash provided by operating activities 249,132 229,087 - -------------------------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Units issued, net of costs (note 10) 104,215 141,908 Debentures redeemed (note 6) (19,406) - Increase (decrease) in bank indebtedness 28,893 (30,767) Reduction of capital lease obligations (3,184) (1,019) Distributions to Unitholders (170,915) (185,015) - -------------------------------------------------------------------------------------------------------------------------------- Cash used in financing activities (60,397) (74,893) - -------------------------------------------------------------------------------------------------------------------------------- INVESTING ACTIVITIES Expenditures on property and equipment (148,725) (159,487) Property acquisitions (16,051) (244) Property dispositions 1,037 8,727 Acquisition of Sound Energy Trust (note 3) (22,307) - Acquisition of Ketch Resources Trust (note 3) - (10,109) Changes in non-cash working capital (2,689) 6,919 - -------------------------------------------------------------------------------------------------------------------------------- Cash used in investing activities (188,735) (154,194) - -------------------------------------------------------------------------------------------------------------------------------- Net change in cash - - Cash, beginning of year - - - -------------------------------------------------------------------------------------------------------------------------------- Cash, end of year $ - $ - - -------------------------------------------------------------------------------------------------------------------------------- SUPPLEMENTARY CASH FLOW INFORMATION Interest paid $ 42,017 $ 34,680 Taxes paid $ 2,062 $ 1,783
see accompanying Notes to Consolidated Financial Statements Advantage Energy Income Fund - 6 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2007 All tabular amounts in thousands except as otherwise indicated 1. BUSINESS AND STRUCTURE OF THE FUND Advantage Energy Income Fund ("Advantage" or the "Fund") was formed on May 23, 2001 as a result of a plan of arrangement. For Canadian tax purposes, Advantage is an open-ended unincorporated mutual fund trust created under the laws of the Province of Alberta pursuant to a Trust Indenture originally dated April 17, 2001, and as occasionally amended, between Advantage Oil & Gas Ltd. ("AOG") and Computershare Trust Company of Canada, as trustee. The Fund commenced operations on May 24, 2001. The beneficiaries of the Fund are the holders of the Trust Units (the "Unitholders"). The principal undertaking of the Fund is to indirectly acquire and hold interests in petroleum and natural gas properties and assets related thereto. The business of the Fund is carried on by its wholly-owned subsidiary, AOG. The Fund's primary assets are currently the common shares of AOG, a royalty in the producing properties of AOG (the "AOG Royalty") and notes of AOG (the "AOG Notes"). The Fund's strategy, through AOG, is to minimize exposure to exploration risk while focusing on growth through acquisition and development of producing crude oil and natural gas properties. The purpose of the Fund is to distribute available cash flow to Unitholders on a monthly basis in accordance with the terms of the Trust Indenture. The Fund's available cash flow includes principal repayments and interest income earned from the AOG Notes, royalty income earned from the AOG Royalty, and any dividends declared on the common shares of AOG less any expenses of the Fund including interest on convertible debentures. Cash received on the AOG Notes, AOG Royalty and common shares of AOG result in the effective transfer of the economic interest in the properties of AOG to the Fund. However, while the royalty is a contractual interest in the properties owned by AOG, it does not confer ownership in the underlying resource properties. Distributions from the Fund to Unitholders are entirely discretionary and are determined by Management and the Board of Directors. We closely monitor our distribution policy considering forecasted cash flows, optimal debt levels, capital spending activity, taxability to Unitholders, working capital requirements, and other potential cash expenditures. Distributions are announced monthly and are based on the cash available after retaining a portion to meet such spending requirements. The level of distributions are primarily determined by cash flows received from the production of oil and natural gas from existing Canadian resource properties and are highly dependent upon our success in exploiting the current reserve base and acquiring additional reserves. Furthermore, monthly distributions we pay to Unitholders are highly dependent upon the prices received for such oil and natural gas production. It is our long-term objective to provide stable and sustainable distributions to the Unitholders, while continuing to grow the Fund. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The Management of the Fund prepares its consolidated financial statements in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") and all amounts are stated in Canadian dollars. The preparation of consolidated financial statements requires Management to make estimates and assumptions that affect the reported amount of assets, liabilities and equity and disclosures of contingencies at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. The following significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements and, together with the notes, should be considered an integral part of the consolidated financial statements. (a) CONSOLIDATION AND JOINT OPERATIONS These consolidated financial statements include the accounts of the Fund and all subsidiaries, including AOG. All intercompany balances and transactions have been eliminated. The Fund conducts exploration and production activities jointly with other participants. The accounts of the Fund reflect its proportionate interest in such joint operations. Advantage Energy Income Fund - 7 (b) FIXED ASSETS (i) PETROLEUM AND NATURAL GAS PROPERTIES The Fund follows the "full cost" method of accounting in accordance with the guideline issued by the Canadian Institute of Chartered Accountants ("CICA") whereby all costs associated with the acquisition of and the exploration for and development of petroleum and natural gas reserves, whether productive or unproductive, are capitalized in a Canadian cost centre and charged to income as set out below. Such costs include lease acquisition, drilling and completion, production facilities, asset retirement costs, geological and geophysical costs and overhead expenses related to exploration and development activities. Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion and depreciation of 20% or more. Depletion of petroleum and natural gas properties and depreciation of lease, well equipment and production facilities is provided on accumulated costs using the "unit-of-production" method based on estimated net proved petroleum and natural gas reserves, before royalties, as determined by independent engineers. For purposes of the depletion and depreciation calculation, proved petroleum and natural gas reserves are converted to a common unit-of-measure on the basis of one barrel of oil or liquids being equal to six thousand cubic feet of natural gas. The depletion and depreciation cost base includes total capitalized costs, less costs of unproved properties, plus a provision for future development costs of proved undeveloped reserves. Costs of acquiring and evaluating unproved properties are excluded from depletion calculations until it is determined whether or not proved reserves are attributable to the properties or impairment occurs. Petroleum and natural gas assets are evaluated in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre (the "ceiling test"). The carrying amounts are assessed to be recoverable when the sum of the undiscounted net cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted net cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The net cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. There has been no impairment of the Fund's petroleum and natural gas properties since inception. (ii) FURNITURE AND EQUIPMENT The Fund records furniture and equipment at cost and provides depreciation on the declining balance method at a rate of 20% per annum which is designed to amortize the cost of the assets over their estimated useful lives. (c) GOODWILL Goodwill is the excess purchase price of a business over the fair value of identifiable assets and liabilities acquired. Goodwill is stated at cost less impairment and is not amortized. Goodwill impairment is assessed at year-end, or as economic events dictate, by comparing the fair value of the reporting unit (the Fund) to its carrying value, including goodwill. If the fair value of the Fund is less than its carrying value, a goodwill impairment loss is recognized by allocating the fair value of the Fund to the identifiable assets and liabilities as if the Fund had been acquired in a business acquisition for a purchase price equal to the fair value. The excess of the fair value of the Fund over the values assigned to the identifiable assets and liabilities is the implied fair value of the goodwill. Any excess of the carrying value of the goodwill over the implied fair value is the impairment amount and is charged to income in the period incurred. There has been no impairment of the Fund's goodwill since inception. (d) DISTRIBUTIONS Distributions are calculated on an accrual basis and are paid to Unitholders monthly. (e) FINANCIAL INSTRUMENTS Effective January 1, 2007, the Fund adopted CICA Handbook sections 3855 "Financial Instruments - Recognition and Measurement", 3862 "Financial Instruments - Disclosures", 3863 "Financial Instruments - Presentation", and 3865 "Hedges". Advantage Energy Income Fund - 8 Section 3855 "Financial Instruments - Recognition and Measurement" establishes criteria for recognizing and measuring financial instruments including financial assets, financial liabilities and non-financial derivatives. Under this standard, all financial instruments must initially be recognized at fair value on the balance sheet. Measurement of financial instruments subsequent to the initial recognition, as well as resulting gains and losses, are recorded based on how each financial instrument was initially classified. The Fund has classified each identified financial instrument into the following categories: held for trading, loans and receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Held for trading financial instruments are measured at fair value with gains and losses recognized in earnings immediately. Available for sale financial assets are measured at fair value with gains and losses, other than impairment losses, recognized in other comprehensive income and transferred to earnings when the asset is derecognized. Loans and receivables, held to maturity investments and other financial liabilities are recognized at amortized cost using the effective interest method and impairment losses are recorded in earnings when incurred. Upon adoption and with all new financial instruments, an election is available that allows entities to classify any financial instrument as held for trading. Only those financial assets and liabilities that must be classified as held for trading by the standard have been classified as such by the Fund. As the Fund frequently utilizes non-financial derivative instruments to manage market risk associated with volatile commodity prices, such instruments must be classified as held for trading and recorded on the balance sheet at fair value as derivative assets and liabilities. Section 3865 "Hedges" provides an alternative to recognizing gains and losses on derivatives in earnings if the instrument is designated as part of a hedging relationship and meets the necessary criteria. Under the alternative hedge accounting treatment, gains and losses on derivatives classified as effective cash flow hedges are included in other comprehensive income until the time at which the hedged item is realized. The Fund does not utilize derivative instruments for speculative purposes but has elected not to apply hedge accounting. Therefore, gains and losses on these instruments are recorded as unrealized gains and losses on derivatives in the consolidated statement of income, comprehensive income and accumulated deficit in the period they occur and as realized gains and losses on derivatives when the contracts are settled. Since unrealized gains and losses on derivatives are non-cash items, there is no impact on the statement of cash flows as a result of their recognition. In some instances, derivative financial instruments can be embedded within other contracts. Embedded derivatives within a host contract must be recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative, and the combined contract is not classified as held for trading or designated at fair value. The Fund selected January 1, 2003, as its accounting transition date for any potential embedded derivatives and has not identified any embedded derivatives that would require separation from the host contract and fair value accounting. Transaction costs are frequently attributed to the acquisition or issue of a financial asset or liability. Section 3855 requires that such transaction costs incurred on held for trading financial instruments be expensed immediately. For other financial instruments, an entity can adopt an accounting policy of either expensing transaction costs as they occur or adding such transaction costs to the fair value of the financial instrument. The Fund has chosen a policy of adding transaction costs to the fair value initially recognized for financial assets and liabilities that are not classified as held for trading. The Fund has adopted the new standards prospectively as required which allows amendments to the carrying values of financial instruments, effective as of the adoption date, to be recognized as an adjustment to the beginning balance of accumulated deficit. As the new standards have not resulted in any significant changes to the recognition and measurement of the Fund's financial instruments, no adjustment to accumulated deficit was required. The new standards also require several additional disclosures in the notes to the financial statements. Among the disclosures required, the Fund must disclose the exposure to various risks associated with financial instruments and the policies that exist to manage these risks. (f) COMPREHENSIVE INCOME Effective January 1, 2007, the Fund adopted CICA Handbook section 1530 "Comprehensive Income". Comprehensive income consists of net income and other comprehensive income ("OCI") with amounts included in OCI shown net of tax. Accumulated other comprehensive income is a new equity category comprised of the cumulative amounts of OCI. To date, the Fund does not have any adjustments in OCI and therefore comprehensive income is currently equal to net income. (g) CONVERTIBLE DEBENTURES The Fund's convertible debentures are financial liabilities consisting of a liability with an embedded conversion feature. As such, the debentures are segregated between liabilities and equity based on the relative fair market value of the liability and equity portions. Therefore, the debenture liabilities are presented at less than their eventual maturity values. The liability and equity components are further reduced for issuance costs initially incurred. The discount of the liability component as compared to maturity value is accreted by the "effective interest" method over the debenture term and expensed accordingly. As debentures are converted to Trust Units, an appropriate portion of the liability and equity components are transferred to Unitholders' capital. Advantage Energy Income Fund - 9 (h) ASSET RETIREMENT OBLIGATIONS The Fund follows the "asset retirement obligation" method of recording the future cost associated with removal, site restoration and asset retirement costs. The fair value of the liability for the Fund's asset retirement obligations is recorded in the period in which it is incurred, discounted to its present value using the Fund's credit adjusted risk-free interest rate and the corresponding amount recognized by increasing the carrying amount of fixed assets. The asset recorded is depleted on a "unit-of-production" basis over the life of the reserves consistent with the Fund's depletion and depreciation policy for petroleum and natural gas properties. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to income in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligations are charged against the obligation to the extent of the liability recorded. (i) INCOME TAXES The Fund is considered an open-ended unincorporated mutual fund trust under the Income Tax Act (Canada). Any taxable income is allocated to the Unitholders and therefore no provision for current income taxes relating to the Fund is included in these financial statements. The Fund and its subsidiaries follow the "liability" method of accounting for income taxes. Under this method future tax assets and liabilities are determined based on differences between financial reporting and income tax bases of assets and liabilities, and are measured using substantially enacted tax rates and laws expected to apply when the differences reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change is substantially enacted. (j) UNIT-BASED COMPENSATION Advantage accounts for compensation expense based on the "fair value" of rights granted under its unit-based compensation plans. The Fund has Trust Units held in escrow relating to the management internalization (note 13) as well as a unit-based compensation plan for external directors of the Fund, a Restricted Trust Unit Plan and Trust Units issuable for the retention of certain employees of the Fund (note 10). The escrowed Trust Units relating to the management internalization vest equally over three years, the period during which employees are required to provide service to receive the Trust Units. Therefore, the management internalization consideration is being deferred and amortized into income as management internalization expense over the specific vesting periods during which employee services are provided, including an estimate of future Trust Unit forfeitures. Awards under the external directors' unit-based compensation plan vest immediately with associated compensation expense recognized in the current period earnings and estimated forfeiture rates are not incorporated in the determination of fair value. The compensation expense results in the creation of contributed surplus until the rights are exercised. Consideration paid upon the exercise of the rights together with the amount previously recognized in contributed surplus is recorded as an increase in Unitholders' capital. Advantage's current employee compensation includes a Restricted Trust Unit Plan (the "Plan"), as approved by the Unitholders on June 23, 2006, and Trust Units issuable for the retention of certain employees of the Fund. The Plan authorizes the Board of Directors to grant Restricted Trust Units ("RTUs") to directors, officers, or employees of the Fund. The number of RTUs granted is based on the Fund's Trust Unit return for a calendar year and compared to a peer group approved by the Board of Directors. The Trust Unit return is calculated at the end of the year and is primarily based on the year-over-year change in the Trust Unit price plus distributions. The RTU grants vest one third immediately on grant date, with the remaining two thirds vesting evenly on the following two yearly anniversary dates. The holders of RTUs may elect to receive cash upon vesting in lieu of the number of Trust Units to be issued, subject to consent of the Fund. Compensation cost related to the Plan is recognized as compensation expense over the service period and incorporates the period end Trust Unit price, the estimated number of RTUs to vest, and certain management estimates. The maximum amount of RTUs granted in any one calendar year is limited to 175% of the base salaries of those individuals participating in the Plan for such period. (k) REVENUE RECOGNITION Revenue associated with the sale of crude oil, natural gas and natural gas liquids is recognized when the title and risks pass to the purchaser, normally at the pipeline delivery point for natural gas and at the wellhead for crude oil. Advantage Energy Income Fund - 10 (l) PER TRUST UNIT AMOUNTS Net income per Trust Unit is calculated using the weighted average number of Trust Units outstanding during the year. Diluted net income per Trust Unit is calculated using the "if-converted" method to determine the dilutive effect of convertible debentures and exchangeable shares and the "treasury stock" method for trust unit rights granted to directors and the management internalization escrowed Trust Units. (m) MEASUREMENT UNCERTAINTY The amounts recorded for depletion and depreciation of property and equipment, the provision for asset retirement obligation costs and related accretion expense, impairment calculations for fixed assets and goodwill, derivative fair value calculations, future income tax provisions, as well as fair values assigned to any identifiable assets and liabilities in business combinations are based on estimates. These estimates are significant and include proved and probable reserves, future production rates, future crude oil and natural gas prices, future costs, future interest rates, fair value assessments, and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in such estimates in future years could be material. (n) ACCOUNTING CHANGES Effective January 1, 2007, the Fund adopted the revised recommendations of CICA section 1506 "Accounting Changes". The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including the changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007. (o) RECENT ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT IMPLEMENTED The CICA has issued section 1535 "Capital Disclosures", which will be effective January 1, 2008 for the Fund. Section 1535 will require the Fund to provide additional disclosures relating to capital and how it is managed. It is not anticipated that the adoption of section 1535 will impact the amounts reported in the Fund's financial statements as they primarily relate to disclosure. (p) COMPARATIVE FIGURES Certain comparative figures have been reclassified to conform to the current year's presentation. 3. ACQUISITIONS (a) SOUND ENERGY TRUST On September 5, 2007, Advantage acquired all of the issued and outstanding Trust Units and Exchangeable Shares of Sound Energy Trust ("Sound") for $21.4 million cash consideration, 16,977,184 Advantage Trust Units and $0.9 million of acquisition costs. Sound Unitholders and Exchangeable Shareholders could elect to receive 0.30 Advantage Trust Units for each Sound Trust Unit or receive $0.66 in cash and 0.2557 Advantage Trust Units for each Sound Trust Unit. All of the Sound Exchangeable Shares were exchanged for Advantage Trust Units on the same ratio as the Sound Trust Units based on the conversion ratio in effect at the effective date of the acquisition. Sound was an energy trust engaged in the development, acquisition and production of, natural gas and crude oil in western Canada. The acquisition is being accounted for using the "purchase method" with the results of operations included in the consolidated financial statements as of the closing date of the acquisition. The purchase price has been allocated as follows:
NET ASSETS ACQUIRED AND LIABILITIES ASSUMED: CONSIDERATION: Fixed assets $ 509,656 16,977,184 Trust Units issued $ 228,852 Accounts receivable 27,433 Cash 21,403 Prepaid expenses and deposits 3,873 Acquisition costs incurred 904 Derivative asset, net 2,797 ---------- Bank indebtedness (107,959) $ 251,159 Convertible debentures (101,553) ---------- Accounts payable and accrued liabilities (35,396) Future income taxes (29,430) Asset retirement obligations (16,695) Capital lease obligations (1,567) ------------ $ 251,159 ------------
Advantage Energy Income Fund - 11 The value of the Trust Units issued as consideration was determined based on the weighted average trading value of Advantage Trust Units during the two-day period before and after the terms of the acquisition were agreed to and announced. The allocation of the purchase price has been revised due to the realization of estimates and is subject to further refinement as additional cost estimates and tax balances are finalized. (b) KETCH RESOURCES TRUST On June 23, 2006, Advantage acquired all of the issued and outstanding Trust Units of Ketch Resources Trust ("Ketch") in return for 32,870,465 Advantage Trust Units, utilizing an exchange ratio of 0.565 Advantage Trust Units for each Ketch Trust Unit outstanding. Ketch was an energy trust engaged in the development, acquisition and production of, natural gas and crude oil in western Canada. The acquisition is being accounted for using the "purchase method" with the results of operations included in the consolidated financial statements as of the closing date of the acquisition. The purchase price has been allocated as follows:
NET ASSETS ACQUIRED AND LIABILITIES ASSUMED: CONSIDERATION: Fixed assets $ 877,463 32,870,465 Trust Units issued $ 688,636 Goodwill 74,798 Acquisition costs incurred 10,109 Accounts receivable 55,806 ---------- Prepaid expenses and deposits 6,406 $ 698,745 Cash 2,713 ---------- Bank indebtedness (191,578) Convertible debentures (69,952) Accounts payable (46,834) Asset retirement obligations (7,930) Capital lease obligation (2,147) ------------- $ 698,745 -------------
The value of the Trust Units issued as consideration was determined based on the weighted average trading value of Advantage Trust Units during the two-day period before and after the terms of the acquisition were agreed to and announced. 4. FIXED ASSETS
ACCUMULATED NET BOOK DECEMBER 31, 2007 COST DEPLETION AND DEPRECIATION VALUE ------------------------------------------------------------------------------------------------------------------------ Petroleum and natural gas properties $ 3,016,243 $ 844,671 $2,171,572 Furniture and equipment 10,548 4,774 5,774 ------------------------------------------------------------------------------------------------------------------------ $ 3,026,791 $ 849,445 $2,177,346 ------------------------------------------------------------------------------------------------------------------------ ACCUMULATED NET BOOK DECEMBER 31, 2006 COST DEPLETION AND DEPRECIATION VALUE ------------------------------------------------------------------------------------------------------------------------ Petroleum and natural gas properties $ 2,324,948 $ 576,707 $1,748,241 Furniture and equipment 8,175 3,358 4,817 ------------------------------------------------------------------------------------------------------------------------ $ 2,333,123 $ 580,065 $1,753,058 ------------------------------------------------------------------------------------------------------------------------
During the year ended December 31, 2007, Advantage capitalized general and administrative expenditures directly related to exploration and development activities of $9,653,000 (2006 - $6,444,000). Costs of $60,238,000 (2006 - $43,467,000) for unproved properties have been excluded from the calculation of depletion expense, and future development costs of $190,146,000 (2006 - $123,464,000) have been included in costs subject to depletion. Advantage Energy Income Fund - 12 The Fund performed a ceiling test calculation at December 31, 2007 to assess the recoverable value of fixed assets. Based on the calculation, the carrying amounts are recoverable as compared to the sum of the undiscounted net cash flows expected from the production of proved reserves based on the following benchmark prices:
WTI CRUDE OIL EXCHANGE RATE AECO GAS YEAR ($US/BBL) ($US/$CDN) ($CDN/MMBTU) ------------------------------------------------------------------------------------------- 2008 $ 89.61 $ 1.00 $ 6.51 2009 $ 86.01 $ 1.00 $ 7.22 2010 $ 84.65 $ 1.00 $ 7.69 2011 $ 82.77 $ 1.00 $ 7.70 2012 $ 82.26 $ 1.00 $ 7.61 2013 $ 82.81 $ 1.00 $ 7.78 ------------------------------------------------------------------------------------------- Approximate escalation rate after 2013 2.0% - 2.0% -------------------------------------------------------------------------------------------
Benchmark prices are adjusted for a variety of factors such as quality differentials to determine the expected price to be realized by the Fund when performing the ceiling test calculation. 5. CAPITAL LEASE OBLIGATIONS The Fund has capital leases on a variety of fixed assets. Future minimum lease payments at December 31, 2007 consist of the following: 2008 $ 1,906 2009 2,040 2010 2,200 2011 1,925 --------------------------------------------------- 8,071 Less amounts representing interest (881) 7,190 Current portion (1,537) --------------------------------------------------- $ 5,653 --------------------------------------------------- On June 23, 2006, Advantage assumed a total capital lease obligation of $2.1 million in the acquisition of Ketch (note 3). The lease ends in March 2008 and interest expense is recognized at 5.3%. During the second quarter of 2007, Advantage entered a new lease arrangement that resulted in the recognition of a fixed asset addition and capital lease obligation of $4.1 million. The lease obligation bears interest at 5.8% and is secured by the related equipment. The lease term expires June 2011 with a final purchase obligation of $1.5 million at which time ownership of the equipment will transfer to Advantage. Effective September 4, 2007, Advantage entered a new lease arrangement that resulted in the recognition of a fixed asset addition and capital lease obligation of $1.8 million. The lease obligation bears interest at 6.7% and is secured by the related equipment. The lease term expires August 2010 with a final payment obligation of $0.7 million. Distributions to Unitholders are not permitted if the Fund is in default of such capital lease. On September 5, 2007, Advantage assumed two capital lease obligations in the acquisition of Sound (note 3) resulting in the recognition of capital lease obligations of $1.6 million. Both of the lease obligations bear interest at 5.6% and are secured by the related equipment. The lease terms expire December 2009 and April 2010 with a total final payment obligation of $0.9 million. Fixed assets subject to capital leases are depreciated on a "unit-of-production" basis over the life of the reserves consistent with the Fund's depletion and depreciation policy for petroleum and natural gas properties and is included in depletion and depreciation expense. Advantage Energy Income Fund - 13 6. CONVERTIBLE DEBENTURES The convertible unsecured subordinated debentures pay interest semi-annually and are convertible at the option of the holder into Trust Units of Advantage at the applicable conversion price per Trust Unit plus accrued and unpaid interest. The details of the convertible debentures including fair market values initially assigned and issuance costs are as follows:
10.00% 9.00% 8.25% 8.75% ------------------------------------------------------------------------------------------------ Trading symbol AVN.DB AVN.DBA AVN.DBB AVN.DBF Issue date Oct. 18, 2002 July 8, 2003 Dec. 2, 2003 June 10, 2004 Maturity date Matured Aug. 1, 2008 Feb. 1, 2009 June 30, 2009 Conversion price Matured $ 17.00 $ 16.50 $ 34.67 Liability component $ 52,722 $ 28,662 $ 56,802 $ 48,700 Equity component 2,278 1,338 3,198 11,408 ------------------------------------------------------------------------------------------------ Gross proceeds 55,000 30,000 60,000 60,108 Issuance costs (2,495) (1,444) (2,588) - ------------------------------------------------------------------------------------------------ Net proceeds $ 52,505 $ 28,556 $ 57,412 $ 60,108 ------------------------------------------------------------------------------------------------
7.50% 6.50% 7.75% 8.00% TOTAL ----------------------------------------------------------------------------------------------------------- Trading symbol AVN.DBC AVN.DBE AVN.DBD AVN.DBG Issue date Sep. 15, 2004 May 18, 2005 Sep. 15, 2004 Nov. 13, 2006 Maturity date Oct. 1, 2009 June 30, 2010 Dec. 1, 2011 Dec. 31, 2011 Conversion price $ 20.25 $ 24.96 $ 21.00 $ 20.33 Liability component $ 71,631 $ 66,981 $ 47,444 $ 14,884 $387,826 Equity component 3,369 2,971 2,556 26,561 53,679 ----------------------------------------------------------------------------------------------------------- Gross proceeds 75,000 69,952 50,000 41,445 441,505 Issuance costs (3,190) - (2,190) - (11,907) ----------------------------------------------------------------------------------------------------------- Net proceeds $ 71,810 $ 69,952 $ 47,810 $ 41,445 $429,598 -----------------------------------------------------------------------------------------------------------
The convertible debentures are redeemable prior to their maturity dates, at the option of the Fund, upon providing 30 to 60 days advance notification. The redemption prices for the various debentures, plus accrued and unpaid interest, is dependent on the redemption periods and are as follows:
CONVERTIBLE REDEMPTION DEBENTURE REDEMPTION PERIODS PRICE ----------------------------------------------------------------------------------------------------- 9.00% After August 1, 2007 and before August 1, 2008 $1,025 ----------------------------------------------------------------------------------------------------- 8.25% After February 1, 2007 and on or before February 1, 2008 $1,050 After February 1, 2008 and before February 1, 2009 $1,025 ----------------------------------------------------------------------------------------------------- 8.75% After June 30, 2007 and on or before June 30, 2008 $1,050 After June 30, 2008 and before June 30, 2009 $1,025 ----------------------------------------------------------------------------------------------------- 7.50% After October 1, 2007 and on or before October 1, 2008 $1,050 After October 1, 2008 and before October 1, 2009 $1,025 ----------------------------------------------------------------------------------------------------- 6.50% After June 30, 2008 and on or before June 30, 2009 $1,050 After June 30, 2009 and before June 30, 2010 $1,025 ----------------------------------------------------------------------------------------------------- 7.75% After December 1, 2007 and on or before December 1, 2008 $1,050 After December 1, 2008 and on or before December 1, 2009 $1,025 After December 1, 2009 and before December 1, 2011 $1,000 ----------------------------------------------------------------------------------------------------- 8.00% After December 31, 2009 and on or before December 31, 2010 $1,050 After December 31, 2010 and before December 31, 2011 $1,025 -----------------------------------------------------------------------------------------------------
Advantage Energy Income Fund - 14 The balance of debentures outstanding at December 31, 2007 and changes in the liability and equity components during the years ended December 31, 2007 and 2006 are as follows:
10.00% 9.00% 8.25% 8.75% ------------------------------------------------------------------------------------------------------ Debentures outstanding $ - $ 5,392 $ 4,867 $ 29,839 ------------------------------------------------------------------------------------------------------ Liability component: Balance at Dec. 31, 2005 $ 2,453 $ 7,259 $ 8,150 $ - Assumed on Ketch acquisition - - - - Accretion of discount 30 107 103 - Converted to Trust Units (1,019) (2,131) (3,577) - ------------------------------------------------------------------------------------------------------ Balance at Dec. 31, 2006 1,464 5,235 4,676 - Assumed on Sound acquisition - - - 48,700 Accretion of discount 22 98 91 96 Converted to Trust Units (1,486) - - (8) Redeemed for cash - - - (19,406) ------------------------------------------------------------------------------------------------------ Balance at Dec. 31, 2007 $ - $ 5,333 $ 4,767 $ 29,382 ------------------------------------------------------------------------------------------------------ Equity component: Balance at Dec. 31, 2005 $ 100 $ 323 $ 441 $ - Assumed on Ketch acquisition - - - - Converted to Trust Units (41) (94) (193) - ------------------------------------------------------------------------------------------------------ Balance at Dec. 31, 2006 59 229 248 - Assumed on Sound acquisition - - - 11,408 Converted to Trust Units - - - (10,556) Expired (59) - - - ------------------------------------------------------------------------------------------------------ Balance at Dec. 31, 2007 $ - $ 229 $ 248 $ 852 ------------------------------------------------------------------------------------------------------
7.50% 6.50% 7.75% 8.00% TOTAL ---------------------------------------------------------------------------------------------------------------------- Debentures outstanding $ 52,268 $ 69,952 $46,766 $ 15,528 $224,612 ---------------------------------------------------------------------------------------------------------------------- Liability component: Balance at Dec. 31, 2005 $ 62,321 $ - $45,898 $ - $126,081 Assumed on Ketch acquisition - 66,981 - - 66,981 Accretion of discount 897 380 589 - 2,106 Converted to Trust Units (13,436) - (2,722) - (22,885) ---------------------------------------------------------------------------------------------------------------------- Balance at Dec. 31, 2006 49,782 67,361 43,765 - 172,283 Assumed on Sound acquisition - - - 14,884 63,584 Accretion of discount 889 731 595 47 2,569 Converted to Trust Units - - - - (1,494) Redeemed for cash - - - - (19,406) ---------------------------------------------------------------------------------------------------------------------- Balance at Dec. 31, 2007 $ 50,671 $ 68,092 $44,360 $ 14,931 $217,536 ---------------------------------------------------------------------------------------------------------------------- Equity component: Balance at Dec. 31, 2005 $ 2,865 $ - $ 2,430 $ - $ 6,159 Assumed on Ketch acquisition - 2,971 - - 2,971 Converted to Trust Units (617) - (144) - (1,089) ---------------------------------------------------------------------------------------------------------------------- Balance at Dec. 31, 2006 2,248 2,971 2,286 - 8,041 Assumed on Sound acquisition - - - 26,561 37,969 Converted to Trust Units - - - (25,763) (36,319) Expired - - - - (59) ---------------------------------------------------------------------------------------------------------------------- Balance at Dec. 31, 2007 $ 2,248 $ 2,971 $ 2,286 $ 798 $ 9,632 ----------------------------------------------------------------------------------------------------------------------
Advantage Energy Income Fund - 15 As part of the acquisition of Ketch (note 3), the 6.50% convertible debentures, originally issued May 18, 2005, were assumed by Advantage on June 23, 2006. Due to the acquisition of Sound (note 3), 8.75% and 8.00% convertible debentures were assumed by Advantage on September 5, 2007. As a result of the change in control of Sound, the Fund was required by the debenture indentures to make an offer to purchase all of the outstanding convertible debentures assumed from Sound at a price equal to 101% of the principal amount plus accrued and unpaid interest. On October 17, 2007, the expiry date of the offer, 911,709 Trust Units were issued and $19.9 million in total cash consideration was paid in exchange for $29,665,000 8.75% convertible debentures and 2,220,289 Trust Units were issued in exchange for $25,507,000 8.0% convertible debentures. During the year ended December 31, 2007, $24,000 debentures (2006 - $24,333,000) were converted resulting in the issuance of 1,386 Trust Units (2006 - 1,286,901 Trust Units) and all of the remaining $1,470,000 10% convertible debentures matured on November 1, 2007 and were settled with the issuance of 127,493 Trust Units. 7. BANK INDEBTEDNESS Advantage has a credit facility agreement with a syndicate of financial institutions which provides for a $690 million extendible revolving loan facility and a $20 million operating loan facility. The loan's interest rate is based on either prime, US base rate, LIBOR or bankers' acceptance rates, at the Fund's option, subject to certain basis point or stamping fee adjustments ranging from 0.00% to 1.25% depending on the Fund's debt to cash flow ratio. The credit facilities are secured by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement from the Fund covering all assets and cash flows. The credit facilities are subject to review on an annual basis with the next renewal due in June 2008. Various borrowing options are available under the credit facilities, including prime rate-based advances, US base rate advances, US dollar LIBOR advances and bankers' acceptances loans. The credit facilities constitute a revolving facility for a 364 day term which is extendible annually for a further 364 day revolving period at the option of the syndicate. If not extended, the revolving credit facility is converted to a two year term facility with the first payment due one year and one day after commencement of the term. The credit facilities contain standard commercial covenants for facilities of this nature. The only financial covenant is a requirement for AOG to maintain a minimum cash flow to interest expense ratio of 3.5:1, determined on a rolling four quarter basis. Breach of any covenant will result in an event of default in which case AOG has 20 days to remedy such default. If the default is not remedied or waived, and if required by the majority of lenders, the administrative agent of the lenders has the option to declare all obligations of AOG under the credit facilities to be immediately due and payable without further demand, presentation, protest, or notice of any kind. Distributions by AOG to the Fund (and effectively by the Fund to Unitholders) are subordinated to the repayment of any amounts owing under the credit facilities. Distributions to Unitholders are not permitted if the Fund is in default of such credit facilities or if the amount of the Fund's outstanding indebtedness under such facilities exceeds the then existing current borrowing base. Interest payments under the debentures are also subordinated to indebtedness under the credit facilities and payments under the debentures are similarly restricted. For the year ended December 31, 2007, the effective interest rate on the outstanding amounts under the facility was approximately 5.7% (2006 - 5.1%). 8. ASSET RETIREMENT OBLIGATIONS The Fund's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Fund estimates the total undiscounted and inflated amount of cash flows required to settle its asset retirement obligations is approximately $243.9 million which will be incurred between 2008 to 2057. A credit-adjusted risk-free rate of 7% and an inflation factor of 2% were used to calculate the fair value of the asset retirement obligations. A reconciliation of the asset retirement obligations is provided below:
YEAR ENDED YEAR ENDED DECEMBER 31, 2007 DECEMBER 31, 2006 --------------------------------------------------------------------------------------- Balance, beginning of year $ 34,324 $ 21,263 Accretion expense 2,795 1,684 Assumed in Sound acquisition (note 3) 16,695 - Assumed in Ketch acquisition (note 3) - 7,930 Liabilities incurred 13,972 9,421 Liabilities settled (6,951) (5,974) --------------------------------------------------------------------------------------- Balance, end of year $ 60,835 $ 34,324 ---------------------------------------------------------------------------------------
Advantage Energy Income Fund - 16 9. INCOME TAXES The taxable income of the Fund is comprised of interest income related to the AOG Notes and royalty income from the AOG Royalty less deductions for Canadian Oil and Gas Property Expense, Trust Unit issue costs, and interest on convertible debentures. Given that taxable income of the Fund is allocated to the Unitholders, no provision for current income taxes relating to the Fund is included in these financial statements. On December 14, 2007, the Federal government enacted legislation phasing in corporate income tax rate reductions which will reduce federal tax rates from 22.1% to 15.0% by 2012. Rate reductions will also apply to the new tax on distributions of income trusts and other specified investment flow-through entities as of 2011, reducing the tax rate in 2011 to 29.5% and in 2012 to 28.0%. These rates include a deemed provincial rate of 13%. The provision for income taxes varies from the amount that would be computed by applying the combined Canadian federal and provincial income tax rates for the following reasons:
YEAR ENDED YEAR ENDED DECEMBER 31, 2007 DECEMBER 31, 2006 ----------------------------------------------------------------------------------------------------------------- Income (loss) before taxes $ (30,733) $ 14,265 ----------------------------------------------------------------------------------------------------------------- Canadian combined federal and provincial income tax rates 32.57% 34.78% Expected income tax expense (recovery) at statutory rates (10,011) 4,961 Increase (decrease) in income taxes resulting from: Amounts included in trust income (57,766) (39,940) Change in enacted tax rates 550 (5,692) Management internalization 4,554 4,678 Specified Investment Flow-Through 42,862 - Non-deductible Crown charges - 6,925 Resource allowance - (8,108) Other (4,831) 89 ----------------------------------------------------------------------------------------------------------------- Future income tax reduction (24,642) (37,087) Income and capital taxes 1,444 1,509 ----------------------------------------------------------------------------------------------------------------- $ (23,198) $ (35,578) -----------------------------------------------------------------------------------------------------------------
The components of the future income tax liability are as follows:
DECEMBER 31, 2007 DECEMBER 31, 2006 ------------------------------------------------------------------------------------------------------------------ Fixed assets in excess of tax basis $ 29,240 $ 85,648 Asset retirement obligations (16,330) (10,141) Non-capital tax loss carry forward (20,369) (8,851) Trust assets in excess of tax basis 82,642 - Other (8,456) (4,717) ------------------------------------------------------------------------------------------------------------------ Future income tax liability $ 66,727 $ 61,939 ------------------------------------------------------------------------------------------------------------------
AOG has a non-capital tax loss carry forward of approximately $76 million of which $1 million expires in 2008, $18 million in 2011, $11 million in 2012 and $46 million after 2020. Advantage Energy Income Fund - 17 10. UNITHOLDERS' EQUITY (a) UNITHOLDERS' CAPITAL (i) AUTHORIZED Unlimited number of voting Trust Units (ii) ISSUED
NUMBER OF UNITS AMOUNT ---------------------------------------------------------------------------------------------- Balance at December 31, 2005 57,846,324 $ 681,574 2005 non-cash performance incentive 475,263 10,544 Issued on conversion of debentures 1,286,901 23,974 Issued on conversion of exchangeable shares 127,014 2,398 Issued on exercise of Trust Unit rights 122,500 682 Issued for Ketch acquisition (note 3) 32,870,465 688,636 Management internalization 1,913,842 38,716 2006 non-cash performance incentive 117,662 2,380 Distribution reinvestment plan 2,005,499 27,722 Issued for cash, net of costs 8,625,000 141,399 ---------------------------------------------------------------------------------------------- Balance at December 31, 2006 105,390,470 1,618,025 Issued on conversion of debentures 128,879 1,494 Issued on exercise of Trust Unit rights 37,500 562 Issued for cash, net of costs 8,600,000 104,094 Distribution reinvestment plan 4,028,252 46,657 Issued for Sound acquisition, net of costs (note 3) 16,977,184 228,583 Issued on offer to purchase Sound debentures (note 6) 3,131,998 37,209 Management internalization forfeitures (24,909) (503) ---------------------------------------------------------------------------------------------- 138,269,374 $ 2,036,121 ---------------------------------------------------------------------------------------------- Management internalization escrowed Trust Units (9,056) ---------------------------------------------------------------------------------------------- Balance at December 31, 2007 $ 2,027,065 ----------------------------------------------------------------------------------------------
On January 20, 2006, Advantage issued 475,263 Trust Units to satisfy the obligation related to the 2005 year end performance incentive fee. On June 23, 2006, Advantage issued 32,870,465 Trust Units as consideration for the acquisition of Ketch (note 3). Concurrent with the Ketch acquisition, Advantage internalized the external management contract structure and eliminated all related fees for total original consideration of 1,933,208 Advantage Trust Units initially valued at $39.1 million and subject to escrow provisions over a 3-year period, vesting one-third each year beginning June 23, 2007 (note 13). For the year ended December 31, 2007, a total of 24,909 Trust Units issued for the management internalization were forfeited (2006 - 19,366 Trust Units) and $15.7 million has been recognized as management internalization expense (2006 - $13.4 million). As at December 31, 2007, 1,193,622 Trust Units remain held in escrow (December 31, 2006 - 1,822,098 Trust Units). The Fund also issued 117,662 Trust Units on June 23, 2006, valued at $2.4 million, to satisfy the final obligation related to the 2006 first quarter performance fee. On July 24, 2006, Advantage announced that it adopted a Premium Distribution(TM), Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan"). The Plan commenced with the monthly cash distribution payable on August 15, 2006 to Unitholders of record on July 31, 2006. For eligible Unitholders that elect to participate in the Plan, Advantage will settle the monthly distribution obligation through the issuance of additional Trust Units at 95% of the Average Market Price (as defined in the Plan). Unitholder enrollment in the Premium Distribution(TM) component of the Plan effectively authorizes the subsequent disposal of the issued Trust Units in exchange for a cash payment equal to 102% of the cash distributions that the Unitholder would otherwise have received if they did not participate in the Plan. During the year ended December 31, 2007, 4,028,252 Trust Advantage Energy Income Fund - 18 Units (2006 - 2,005,499 Trust Units) were issued under the Plan, generating $46.7 million (2006 - $27.7 million) reinvested in the Fund. On August 1, 2006, Advantage issued 7,500,000 Trust Units, plus an additional 1,125,000 Trust Units upon full exercise of the Underwriters' over-allotment option on August 4, 2006, at $17.30 per Trust Unit for net proceeds of $141.4 million (net of Underwriters' fees and other issue costs of $7.8 million). The net proceeds of the offering were used to pay down bank indebtedness and to subsequently fund capital and general corporate expenditures. On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus an additional 800,000 Trust Units upon exercise of the Underwriters' over-allotment option on March 7, 2007, at $12.80 per Trust Unit for approximate net proceeds of $104.1 million (net of Underwriters' fees and other issue costs of $6.0 million). On September 5, 2007, Advantage issued 16,977,184 Trust Units, valued at $228.9 million, as partial consideration for the acquisition of Sound (note 3). Trust Unit issuance costs of $0.3 million were incurred for the Sound acquisition. Due to the acquisition of Sound (note 3), 8.75% and 8.00% convertible debentures were assumed by Advantage on September 5, 2007. As a result of the change in control of Sound, the Fund was required by the debenture indentures to make an offer to purchase all of the outstanding convertible debentures assumed from Sound at a price equal to 101% of the principal amount plus accrued and unpaid interest. On October 17, 2007, the expiry date of the offer, 911,709 Trust Units were issued and $19.9 million in total cash consideration was paid in exchange for $29,665,000 8.75% convertible debentures and 2,220,289 Trust Units were issued in exchange for $25,507,000 8.0% convertible debentures.
(b) CONTRIBUTED SURPLUS YEAR ENDED YEAR ENDED DECEMBER 31, 2007 DECEMBER 31, 2006 ------------------------------------------------------------------------------------------------ Balance, beginning of year $ 863 $ 1,036 Unit-based compensation 1,255 - Expiration of convertible debentures equity component 59 - Exercise of Trust Unit Rights (172) (173) ------------------------------------------------------------------------------------------------ Balance, end of year $ 2,005 $ 863 ------------------------------------------------------------------------------------------------
(c) TRUST UNITS RIGHTS INCENTIVE PLAN Effective June 25, 2002, a Trust Units Rights Incentive Plan for external directors of the Fund was established and approved by the Unitholders of Advantage. A total of 500,000 Trust Units have been reserved for issuance under the plan with an aggregate of 400,000 rights granted since inception. The initial exercise price of rights granted under the plan may not be less than the current market price of the Trust Units as of the date of the grant and the maximum term of each right is not to exceed ten years with all rights vesting immediately upon grant. At the option of the rights holder, the exercise price of the rights can be adjusted downwards over time based upon distributions paid by the Fund to Unitholders. SERIES B NUMBER PRICE --------------------------------------------------------------------------- Balance at December 31, 2005 225,000 $ 13.63 Exercised (37,500) - Reduction of exercise price - (2.66) --------------------------------------------------------------------------- Balance at December 31, 2006 187,500 10.97 Exercised (37,500) - Reduction of exercise price - (1.77) --------------------------------------------------------------------------- Balance at December 31, 2007 150,000 $ 9.20 --------------------------------------------------------------------------- Expiration date June 17, 2008 --------------------------------------------------------------------------- Advantage Energy Income Fund - 19 (d) UNIT-BASED COMPENSATION Advantage's current employee compensation includes a Restricted Trust Unit Plan (the "Plan"), as approved by the Unitholders on June 23, 2006, and Trust Units issuable for the retention of certain employees of the Fund. The purpose of the long-term compensation plans is to retain and attract employees, to reward and encourage performance, and to focus employees on operating and financial performance that results in lasting Unitholder return. The Plan authorizes the Board of Directors to grant Restricted Trust Units ("RTUs") to directors, officers, or employees of the Fund. The number of RTUs granted is based on the Fund's Trust Unit return for a calendar year and compared to a peer group approved by the Board of Directors. The Trust Unit return is calculated at the end of the year and is primarily based on the year-over-year change in the Trust Unit price plus distributions. The RTU grants vest one third immediately on grant date, with the remaining two thirds vesting evenly on the following two yearly anniversary dates. The holders of RTUs may elect to receive cash upon vesting in lieu of the number of Trust Units to be issued, subject to consent of the Fund. As the Fund did not meet the 2007 or 2006 grant thresholds, there were no RTU grants made during these years. For the year ended December 31, 2007, the Fund has accrued unit-based compensation expense of $0.9 million recorded in general and administrative expense (December 31, 2006 - nil) and has capitalized $0.3 million (December 31, 2006 - nil) related to Trust Units issuable for the retention of certain employees of the Fund. (e) NET INCOME (LOSS) PER TRUST UNIT The calculation of basic and diluted net income (loss) per Trust Unit are derived from both income (loss) available to Unitholders and weighted average Trust Units outstanding calculated as follows:
YEAR ENDED YEAR ENDED DECEMBER 31, 2007 DECEMBER 31, 2006 ----------------------------------------------------------------------------------------------- Income (loss) available to Unitholders Basic and Diluted $ (7,535) $ 49,814 ----------------------------------------------------------------------------------------------- Weighted average Trust Units outstanding Basic 119,604,019 80,958,455 Trust Units Rights Incentive Plan - Series A - 43,548 Trust Units Rights Incentive Plan - Series B - 78,287 Management Internalization - 113,556 ----------------------------------------------------------------------------------------------- Diluted 119,604,019 81,193,846 -----------------------------------------------------------------------------------------------
The calculation of diluted net income per Trust Unit excludes all series of convertible debentures for the years as the impact would be anti-dilutive. Total weighted average Trust Units issuable in exchange for the convertible debentures and excluded from the diluted net income per Trust Unit calculation for the year ended December 31, 2007 were 9,083,663 (2006 - 7,182,276). As at December 31, 2007, the total convertible debentures outstanding were immediately convertible to 9,847,253 Trust Units (2006 - 8,334,453). All of the Series B Trust Unit Rights and Management Internalization escrowed Trust Units have been excluded from the calculation of diluted net income per Trust Unit for the year ended December 31, 2007, as the impact would be anti-dilutive. Total weighted average Trust Units issuable in exchange for the Series B Trust Unit Rights and Management Internalization escrowed Trust Units and excluded from the diluted net income per Trust Unit calculation for the year ended December 31, 2007 were 42,918 and 582,861, respectively. All of the remaining Series A Trust Unit Rights were exercised July 7, 2006. Exchangeable Shares have been excluded from the calculation of diluted net income per Trust Unit for the year ended December 31, 2006 as the impact would have been anti-dilutive. All of the remaining Exchangeable Shares were redeemed May 9, 2006. Total weighted average Trust Units issuable in exchange for the Exchangeable Shares and excluded from the diluted net income per Trust Unit calculation for the year ended December 31, 2006 were 36,448. Advantage Energy Income Fund - 20 11. ACCUMULATED DEFICIT Accumulated deficit consists of accumulated income and accumulated distributions for the Fund since inception as follows:
DECEMBER 31, 2007 DECEMBER 31, 2006 --------------------------------------------------------------------------------------- Accumulated Income $ 219,988 $ 227,523 Accumulated Distributions (879,823) (664,629) --------------------------------------------------------------------------------------- Accumulated Deficit $ (659,835) $ (437,106) ---------------------------------------------------------------------------------------
The Fund has historically paid distributions in excess of accumulated income as distributions are typically based on cash flows generated in the period while accumulated income is based on such cash flows less other non-cash charges such as depletion, depreciation, and accretion expense recorded on the original investment in petroleum and natural gas properties and management internalization expense. For the year ended December 31, 2007 the Fund declared $215.2 million in distributions representing $1.77 per distributable Trust Unit (2006 - $217.2 million in distributions representing $2.66 per distributable Trust Unit). 12. FINANCIAL INSTRUMENTS Financial instruments of the Fund include accounts receivable, deposits, accounts payable and accrued liabilities, distributions payable to Unitholders, bank indebtedness, convertible debentures and derivative assets and liabilities. Accounts receivable and deposits are classified as loans and receivables and measured at amortized cost. Accounts payable and accrued liabilities, distributions payable to Unitholders and bank indebtedness are all classified as other liabilities and similarly measured at amortized cost. As at December 31, 2007, there were no significant differences between the carrying amounts reported on the balance sheet and the estimated fair values of these financial instruments due to the short terms to maturity and the floating interest rate on the bank indebtedness. The Fund has convertible debenture obligations outstanding, of which the liability component has been classified as other liabilities and measured at amortized cost. The convertible debentures have different fixed terms and interest rates (note 6) resulting in fair values that will vary over time as market conditions change. As at December 31, 2007, the estimated fair value of the total outstanding convertible debenture obligation was $215.4 million (December 31, 2006 - $180.0 million). The fair value of the liability component of convertible debentures was determined primarily based on a discounted cash flow model assuming no future conversions and continuation of current interest and principal payments as well as taking into consideration the current public trading activity of such debentures. The Fund applied discount rates of between 7 and 8% considering current available market information, assumed credit adjustments, and various terms to maturity. Advantage has an established strategy to manage the risk associated with changes in commodity prices by entering into derivatives, which are recorded at fair value as derivative assets and liabilities with gains and losses recognized through earnings. As the fair value of the contracts varies with commodity prices, they give rise to financial assets and liabilities. The fair values of the derivatives are determined through valuation models completed by third parties. Various assumptions based on current market information were used in these valuations, including settled forward commodity prices, interest rates, foreign exchange rates, volatility and other relevant factors. The actual gains and losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. CREDIT RISK Accounts receivable, deposits, and derivative assets are subject to credit risk exposure and the carrying values reflect Management's assessment of the associated maximum exposure to such credit risk. Substantially all of the Fund's accounts receivable are due from customers and joint operation partners concentrated in the Canadian oil and gas industry. As such, accounts receivable are subject to normal industry credit risks. Advantage mitigates such credit risk by closely monitoring significant counterparties and dealing with a broad selection of partners that diversify risk within the sector. The Fund's deposits are primarily due from the Alberta Provincial government and are viewed by Management as having minimal associated credit risk. To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities. In addition, the Fund generally enters into derivative contracts with investment grade institutions that are members of Advantage's credit facility syndicate to further mitigate associated credit risk. Advantage Energy Income Fund - 21 LIQUIDITY RISK The Fund is subject to liquidity risk attributed from accounts payable and accrued liabilities, distributions payable to Unitholders, bank indebtedness, convertible debentures, and derivative liabilities. Accounts payable and accrued liabilities, distributions payable to Unitholders and derivative liabilities are primarily due within one year of the balance sheet date and Advantage does not anticipate any problems in satisfying the obligations due to the strength of cash provided by operating activities and the existing credit facility. The Fund's bank indebtedness is subject to a $710 million credit facility agreement which mitigates liquidity risk by enabling Advantage to manage interim cash flow fluctuations. The credit facility constitutes a revolving facility for a 364 day term which is extendible annually for a further 364 day revolving period at the option of the syndicate. If not extended, the revolving credit facility is converted to a two year term facility with the first payment due one year and one day after commencement of the term. The terms of the credit facility are such that it provides Advantage adequate flexibility to evaluate and assess liquidity issues if and when they arise. Additionally, the Fund regularly monitors liquidity related to obligations by evaluating forecasted cash flows, optimal debt levels, capital spending activity, working capital requirements, and other potential cash expenditures. This continual financial assessment process further enables the Fund to mitigate liquidity risk. Advantage has several series of convertible debentures outstanding that mature from 2008 to 2011 (note 6). Interest payments are made semi-annually with excess cash provided by operating activities. As the debentures become due, the Fund can satisfy the obligations in cash or issue Trust Units at a price determined in the applicable debenture agreements. This settlement alternative allows the Fund to adequately manage liquidity, plan available cash resources and implement an optimal capital structure. To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to liquidity risk as derivative liabilities become due. While the Fund has elected not to follow hedge accounting, derivative instruments are not entered for speculative purposes and Management closely monitors existing commodity risk exposures. As such, liquidity risk is mitigated since any losses actually realized are subsidized by increased cash flows realized from the higher commodity price environment. INTEREST RATE RISK The Fund is exposed to interest rate risk to the extent that bank indebtedness is at a floating rate of interest and the Fund's maximum exposure to interest rate risk is based on the effective interest rate and the current carrying value of the bank indebtedness. The Fund monitors the interest rate markets to ensure that appropriate steps can be taken if interest rate volatility compromises the Fund's cash flows. A 1% interest rate fluctuation for the year ended December 31, 2007 could potentially have impacted net income by approximately $3.0 million for that period. PRICE AND CURRENCY RISK Advantage's derivative assets and liabilities are subject to both price and currency risks as their fair values are based on assumptions including forward commodity prices and foreign exchange rates. The Fund enters derivative financial instruments to manage commodity price risk exposure relative to actual commodity production and does not utilize derivative instruments for speculative purposes. Changes in the price assumptions can have a significant effect on the fair value of the derivative assets and liabilities and thereby impact net income. It is estimated that a 10% change in the forward natural gas prices used to calculate the fair value of the natural gas derivatives at December 31, 2007 could impact net income by approximately $8.7 million for the year ended December 31, 2007. As well, a change of 10% in the forward crude oil prices used to calculate the fair value of the crude oil derivatives at December 31, 2007 could impact net income by $3.7 million for the year ended December 31, 2007. A change of 10% in the forward power prices used to calculate the fair value of the power derivatives at December 31, 2007 could impact net income by $0.1 million for the year ended December 31, 2007. A similar change in the currency rate assumption underlying the derivatives fair value does not have a material impact on net income. Advantage Energy Income Fund - 22 As at December 31, 2007 the Fund had the following derivatives in place:
DESCRIPTION OF DERIVATIVE TERM VOLUME AVERAGE PRICE ---------------------------------------------------------------------------------------------------------------- NATURAL GAS - AECO Fixed price November 2007 to March 2008 7,109 mcf/d Cdn$9.54/mcf Fixed price April 2008 to October 2008 14,217 mcf/d Cdn$6.85/mcf Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.10/mcf Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.06/mcf Fixed price November 2008 to March 2009 14,217 mcf/d Cdn$7.77/mcf Collar November 2007 to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf Ceiling Cdn$10.29/mcf Collar November 2007 to March 2008 7,109 mcf/d Floor Cdn$8.70/mcf Ceiling Cdn$10.71/mcf CRUDE OIL - WTI Fixed price February 2008 to January 2009 2,000 bbls/d Cdn$90.93/bbl Collar February 2008 to January 2009 2,000 bbls/d Sold put Cdn$70.00/bbl Purchase call Cdn$105.00/bbl Cost Cdn$1.52/bbl ELECTRICITY - ALBERTA POOL PRICE Fixed price January 2008 to December 2008 3.0 MW Cdn$54.00/MWh
As at December 31, 2007, the fair value of the derivatives outstanding resulted in an asset of approximately $7,201,000 (December 31, 2006 - $10,433,000) and a liability of approximately $5,020,000 (December 31, 2006 - nil). For the year ended December 31, 2007, $11,049,000 was recognized in income as an unrealized derivative loss (December 31, 2006 - $10,242,000 unrealized derivative gain) and $18,594,000 was recognized in income as a realized derivative gain (December 31, 2006 - $5,297,000). As a result of the Sound acquisition (note 3), the Fund assumed several derivatives, which had an estimated net fair market value of $2,797,000 on closing. 13. MANAGEMENT FEE, PERFORMANCE INCENTIVE, AND MANAGEMENT INTERNALIZATION Concurrent with the Ketch acquisition (note 3), Advantage internalized the external management contract structure and eliminated all related fees. The Fund reached an agreement with Advantage Investment Management Ltd. ("AIM" or the "Manager") to purchase all of the outstanding shares of AIM pursuant to the terms of the Plan of Arrangement for total original consideration of 1,933,208 Advantage Trust Units. The Trust Units were initially valued at $39.1 million using the weighted average trading value for Advantage Trust Units on the Unitholder approval date of June 22, 2006 and are subject to escrow provisions over a 3-year period, vesting one-third each year beginning in 2007. The management internalization consideration is being deferred and amortized into income as management internalization expense over the specific vesting periods during which employee services are provided, including an estimate of future Trust Unit forfeitures. For the year ended December 31, 2007, a total of 24,909 Trust Units issued for the management internalization were forfeited (2006 - 19,366 Trust Units) and $15.7 million has been recognized as management internalization expense (2006 - $13.4 million). As at December 31, 2007, 1,193,622 Trust Units remain held in escrow (2006 - 1,822,098 Trust Units). The Fund also issued 117,662 Trust Units to satisfy the final obligation related to the 2006 first quarter performance fee along with $0.9 million in cash to settle the first quarter management fee. AIM agreed to forego fees from the period April 1, 2006 to the closing of the Arrangement. Prior to the internalization, the Manager received both a management fee and a performance incentive fee as compensation pursuant to the Management Agreement approved by the Board of Directors. Management fees were calculated based on 1.5% of operating cash flow defined as revenues less royalties and operating costs and were paid quarterly. The Manager of the Fund was also entitled to earn an annual performance incentive fee when the Fund's total annual return exceeded 8%. The total annual return was calculated at the end of the year by dividing the year-over-year change in Unit price plus cash distributions by the opening Unit price, as defined in the Management Agreement. Ten percent of the amount of the total annual return in excess of 8% was multiplied by the market capitalization (defined as the opening Unit price multiplied by the weighted average number of Trust Units outstanding during the year) to determine the performance incentive fee. The Management Agreement provided an option to the Manager to receive the performance incentive fee in equivalent Trust Units. The Manager exercised the option and on January 20, 2006, the Fund issued 475,263 Advantage Trust Units at the closing Unit Advantage Energy Income Fund - 23 price of $22.19 to satisfy the 2005 performance fee obligation. The Manager did not receive any form of compensation in respect of acquisition or divestiture activities nor was there any form of stock option or bonus plan for the Manager or the employees of Advantage outside of the management and performance fees prior to the internalization. The management fees and performance fees were shared amongst all management and employees. 14. COMMITMENTS Advantage has several lease commitments relating to office buildings. The Fund has assumed office lease commitments from prior corporate acquisitions and has renegotiated leases to accommodate the growth of the Fund. The estimated annual minimum operating lease rental payments for buildings are as follows: 2008 $ 5,319 2009 4,111 2010 4,127 2011 1,731 2012 1,314 --------------------------------------- $16,602 --------------------------------------- 15. RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The consolidated financial statements of Advantage have been prepared in accordance with accounting principles generally accepted in Canada. Canadian GAAP, in most respects, conforms to generally accepted accounting principles in the United States. Any differences in accounting principles between Canadian GAAP and US GAAP, as they apply to Advantage, are not material, except as described below. (a) UNIT-BASED COMPENSATION Advantage accounts for compensation expense based on the fair value of the equity awards on the grant date and the initial fair value is not subsequently remeasured. Advantage's unit-based compensation consists of a Trust Units Rights Incentive Plan, Trust Units held in escrow subject to service requirement provisions, and Trust Units issuable for the retention of certain employees of the Fund. The initial fair value is expensed over the vesting period of the Trust Units or rights granted. Under US GAAP, the Fund adopted SFAS 123(R) "Share-Based Payment" on January 1, 2006 using the modified prospective approach and applies the fair value method of accounting for all Unit-based compensation granted after January 1, 2006. A US GAAP difference exists as unit-based compensation grants are considered liability awards for US GAAP and equity awards for Canadian GAAP. Under US GAAP, the fair value of a liability award is measured at the grant date and is subsequently remeasured at each reporting period. When the rights are exercised and the Trust Units vested, the amount recorded as a liability is recognized as temporary equity and the fair value at adoption of the new standard has been charged to income as the cumulative effect of a change in accounting policy. (b) CONVERTIBLE DEBENTURES The Fund applies CICA 3863 "Financial Instruments - Presentation" in accounting for convertible debentures which results in their classification as liabilities. The convertible debentures also have an embedded conversion feature which must be segregated between liabilities and equity, based on the relative fair market value of the liability and equity portions. Therefore, the debenture liabilities are presented at less than their eventual maturity values. The liability and equity components are further reduced for issuance costs initially incurred. The discount of the liability component, net of issuance costs, as compared to maturity value is accreted by the effective interest method over the debenture term. As debentures are converted to Trust Units, an appropriate portion of the liability and equity components are transferred to Unitholders' capital. Interest and accretion expense on the convertible debentures are shown on the Consolidated Statements of Income. Under US GAAP, the entire convertible debenture balance would be shown as a liability. The embedded conversion feature would not be accounted for separately as a component of equity. Additionally, under US GAAP, issuance costs are generally shown as a deferred charge rather than netted from the convertible debenture balance. As a result of these US GAAP differences, the convertible debenture balance in liabilities represents the actual maturity value of the outstanding debentures. Issuance costs are shown separately as a deferred charge and are amortized to interest expense over the term of the debenture. Given that the convertible debentures are carried at maturity value, it is not necessary to accrete the balance over the term of the debentures which results in an expense reduction. Interest and accretion on convertible debentures represents interest expense on the convertible debentures and amortization of the associated deferred issuance costs. Advantage Energy Income Fund - 24 (c) DEPLETION AND DEPRECIATION For Canadian GAAP, depletion of petroleum and natural gas properties and depreciation of lease and well equipment is provided on accumulated costs using the unit-of-production method based on estimated net proved petroleum and natural gas reserves, before royalties, based on forecast prices and costs. US GAAP provides for a similar accounting methodology except that estimated net proved petroleum and natural gas reserves are net of royalties and based on constant prices and costs. Therefore, depletion and depreciation under US GAAP will be different since changes to royalty rates will impact both proved reserves and production and differences between constant prices and costs as compared to forecast prices and costs will impact proved reserve volumes. Additionally, differences in depletion and depreciation will result in divergence of net book value for Canadian GAAP and US GAAP from year-to-year and impact future depletion and depreciation expense as well as the net book value utilized for future ceiling test calculations. (d) CEILING TEST Under Canadian GAAP, petroleum and natural gas assets are evaluated each reporting period to determine that the carrying amount is recoverable and does not exceed the fair value of the properties in the cost centre (the "ceiling test"). The carrying amounts are assessed to be recoverable when the sum of the undiscounted net cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted net cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. For Canadian GAAP purposes, Advantage has not recognized an impairment loss since inception. Under US GAAP, the carrying amounts of petroleum and natural gas assets, net of deferred income taxes, shall not exceed an amount equal to the sum of the present value of estimated net future after-tax cash flows of proved reserves (at current prices and costs as of the balance sheet date) computed using a discount factor of ten percent plus the lower of cost or estimated fair value of unproved properties. Any excess is charged to expense as an impairment loss. Under US GAAP, Advantage recognized an impairment loss of $49.5 million in 2001, $28.3 million net of tax, and an impairment loss of $535.4 million in 2006, $477.8 million net of tax. The impairment loss decreases net book value of property and equipment which reduces depletion and depreciation expense subsequently recorded as well as future ceiling test calculations. (e) INCOME TAX The future income tax accounting standard under Canadian GAAP is substantially similar to the deferred income tax approach as required by US GAAP. Pursuant to Canadian GAAP, substantively enacted tax rates are used to calculate future income tax, whereas US GAAP applies enacted tax rates. However, there were no tax rate differences for the years ended December 31, 2007 and 2006. The differences between Canadian GAAP and US GAAP relate to future income tax impact on GAAP differences for fixed assets. Under US GAAP, an entity that is subject to income tax in multiple jurisdictions is required to disclose income tax expense in each jurisdiction. The total amount of income taxes in 2006 and 2007 is entirely at the provincial level. (f) UNITHOLDERS' EQUITY Unitholders' equity of Advantage consists primarily of Trust Units. The Trust Units are redeemable at any time on demand by the holders, which is required for the Fund to retain its Canadian mutual fund trust status. The holders are entitled to receive a price per Trust Unit equal to the lesser of: (i) 85% of the simple average of the closing market prices of the Trust Units, on the principal market on which the Trust Units are quoted for trading, during the 10 trading-day period commencing immediately after the date on which the Trust Units are surrendered for redemption; and (ii) the closing market price on the principal market on which the Trust Units are quoted for trading on the redemption date. For Canadian GAAP purposes, the Trust Units are considered permanent equity and are presented as a component of Unitholders' equity. Under US GAAP, it is required that equity with a redemption feature be presented as temporary equity between the liability and equity sections of the balance sheet. The temporary equity is shown at an amount equal to the redemption value based on the terms of the Trust Units. Changes in the redemption value from year-to-year are charged to deficit. All components of Unitholders' equity related to Trust Units are eliminated. When calculating net income per Trust Unit, increases in the redemption value during a period results in a reduction of net income available to Unitholders while decreases in the redemption Advantage Energy Income Fund - 25 value increases net income available to Unitholders. For the years ended December 31, 2007 and 2006, net income available to Unitholders was increased by $390.3 million and $898.0 million corresponding to changes in the Trust Units redemption value for the respective periods. A continuity schedule of significant equity accounts for each reporting period is required disclosure under US GAAP. The following table is a continuity of deficit, the Fund's only significant equity account:
DEFICIT YEAR ENDED YEAR ENDED (thousands of Canadian dollars) DECEMBER 31, 2007 DECEMBER 31, 2006 ------------------------------------------------------------------------------------------------ Balance, beginning of year $ (402,158) $ (665,627) Net income (loss) and comprehensive income (loss) 50,610 (417,274) Distributions declared (215,194) (217,246) Change in redemption value of temporary equity 390,349 897,989 ------------------------------------------------------------------------------------------------ Balance, end of year $ (176,393) $ (402,158) ------------------------------------------------------------------------------------------------
(g) BALANCE SHEET DISCLOSURE US GAAP requires disclosure of certain line items for balances that would be aggregated in the Canadian GAAP financials. The following are the additional line items to be disclosed for accounts receivable and accounts payable:
(thousands of Canadian dollars) DECEMBER 31, 2007 DECEMBER 31, 2006 ------------------------------------------------------------------------------------------------ Accounts receivable Trade receivables $ 94,959 $ 78,698 Other receivables 515 839 ------------------------------------------------------------------------------------------------ Total accounts receivable $ 95,474 $ 79,537 ------------------------------------------------------------------------------------------------ (thousands of Canadian dollars) DECEMBER 31, 2007 DECEMBER 31, 2006 ------------------------------------------------------------------------------------------------ Accounts payable and accrued liabilities Accounts payable $ 72,691 $ 75,500 Accrued liabilities 48,994 39,999 Other payables 402 610 ------------------------------------------------------------------------------------------------ Total accounts payable and accrued liabilities $ 122,087 $ 116,109 ------------------------------------------------------------------------------------------------
(h) STATEMENTS OF CASH FLOW The differences between Canadian GAAP and US GAAP have not resulted in any significant variances concerning the statements of cash flows as reported. (i) KETCH ACQUISITION On June 23, 2006, Advantage acquired all of the issued and outstanding Trust Units of Ketch to benefit from an increase in property diversification, the ability to pursue a greater range of high impact growth opportunities available to a larger entity and complimentary summer/winter drilling programs. The merger provides increased liquidity and presence in the Canadian markets as well as greater exposure to the United States capital markets for previous Ketch Unitholders through Advantage's NYSE listing. The purchase price for the acquisition and resulting goodwill is due to both US and Canadian GAAP requiring the purchase price to be determined using Trust Unit prices at the announcement date, while the fair value of the assets and liabilities is determined at the closing date of the acquisition. As commodity prices decreased significantly between the announcement and closing dates, the fair value of the assets acquired also decreased and as a result, goodwill was recorded. Advantage Energy Income Fund - 26 (j) SOUND ACQUISITION On September 5, 2007, Advantage acquired all of the issued and outstanding Trust Units and Exchangeable Shares of Sound. The accounting for business combinations is effectively the same under US and Canadian GAAP. However, the purchase price under US GAAP is different as a result of AOG realizing a future income tax asset from previously unrecognized temporary differences. The purchase price under US GAAP has been allocated as follows:
NET ASSETS ACQUIRED AND LIABILITIES ASSUMED: CONSIDERATION: Fixed assets $ 480,226 16,977,184 Trust Units issued $ 228,852 Future income tax asset 29,430 Cash 21,403 Accounts receivable 27,433 Acquisition costs incurred 904 Prepaid expenses and deposits 3,873 ---------- Derivative asset, net 2,797 $ 251,159 Bank indebtedness (107,959) ---------- Convertible debentures (101,553) Accounts payable and accrued liabilities (35,396) Future income tax liability (29,430) Asset retirement obligations (16,695) Capital lease obligations (1,567) ------------ $ 251,159 ------------
(k) RECENT US ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT IMPLEMENTED SFAS 157 FAIR VALUE MEASUREMENTS: This Statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, this Statement does not require any new fair value measurements. The implementation effective date for this standard is as of the beginning of the first interim or annual reporting period that begins after November 15, 2007. The Fund has assessed the impact of this interpretation and does not anticipate any significant impact on the consolidated financial statements. SFAS 141 (R) BUSINESS COMBINATIONS: This Statement requires assets and liabilities acquired in a business combination, contingent consideration, and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination. This standard applies to business combinations entered into after January 1, 2009. The Fund has not yet assessed the full impact, if any, of this standard on the consolidated financial statements. Advantage Energy Income Fund - 27 The application of US GAAP would have the following effect on net income as reported:
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME YEAR ENDED YEAR ENDED (thousands of Canadian dollars, except for per Trust Unit amount DECEMBER 31, 2007 DECEMBER 31, 2006 ------------------------------------------------------------------------------------------------------------------ Net income (loss) - Canadian GAAP, as reported $ (7,535) $ 49,814 US GAAP Adjustments: General and administrative - note 15 (a) 606 1,453 Management internalization - note 15(a) 7,450 4,684 Interest and accretion on convertible debentures - note 15(b) 1,741 1,254 Depletion, depreciation and accretion - notes 15(c) and (d) 72,990 (528,734) Future income tax reduction - note 15(e) (24,642) 55,526 ------------------------------------------------------------------------------------------------------------------ Net income (loss) before cumulative effect of a change in accounting principle 50,610 (416,003) Cumulative effect of a change in accounting principle - note 15(a) - (1,271) ------------------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) - US GAAP $ 50,610 $(417,274) ------------------------------------------------------------------------------------------------------------------ Net income (loss) per Trust Unit before cumulative effect of a change in accounting principle - US GAAP: Basic $ 0.42 $ (5.14) Diluted $ 0.42 $ (5.14) Net income (loss) per Trust Unit before change in redemption value of Trust Units - US GAAP: Basic $ 0.42 $ (5.15) Diluted $ 0.42 $ (5.15) Net income per Trust Unit - US GAAP: Basic $ 3.69 $ 5.94 Diluted $ 3.54 $ 5.59 ------------------------------------------------------------------------------------------------------------------
Advantage Energy Income Fund - 28 The application of US GAAP would have the following effect on the balance sheets as reported:
DECEMBER 31, 2007 DECEMBER 31, 2006 ----------------- ----------------- CONSOLIDATED BALANCE SHEETS CANADIAN US CANADIAN US (thousands of Canadian dollars) GAAP GAAP GAAP GAAP ------------------------------------------------------------------------------------------------------------------------- ASSETS Deferred charge - note 15(b) $ - $ 1,984 $ - $ 2,810 Fixed assets, net - notes 15(c) and (d) 2,177,346 1,673,251 1,753,058 1,205,465 LIABILITIES AND UNITHOLDERS' EQUITY Current portion of convertible debentures 5,333 5,392 1,464 1,485 - note 15(b) Trust Unit liability - note 15(a) - 7,515 - 7,633 Convertible debentures - note 15(b) 212,203 219,674 170,819 179,245 Future income taxes - note 15(e) 66,727 - 61,939 - Temporary equity - note 15(f) - 1,104,831 - 1,067,790 Unitholders' capital - note 15(f) 2,027,065 - 1,592,758 - Convertible debentures equity component 9,632 - 8,041 - - note 15(b) Contributed surplus - note 15(a) 2,005 - 863 - Accumulated deficit - note 15(f) (659,835) (176,393) (437,106) (402,158)
Advantage Energy Income Fund - 29 EX-99 11 ex99-3form40f_2007.txt EXHIBIT 99.3 EXHIBIT 99.3 ------------ [GRAPHIC OMITTED -- LOGO] ADVANTAGE ENERGY INCOME FUND 2007 MANAGEMENT'S DISCUSSION & ANALYSIS The following Management's Discussion and Analysis ("MD&A"), dated as of March 5, 2008, provides a detailed explanation of the financial and operating results of Advantage Energy Income Fund ("Advantage", the "Fund", "us", "we" or "our") for the quarter and year ended December 31, 2007 and should be read in conjunction with the audited consolidated financial statements. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and all references are to Canadian dollars unless otherwise indicated. All per barrel of oil equivalent ("boe") amounts are stated at a conversion rate of six thousand cubic feet of natural gas being equal to one barrel of oil or liquids. NON-GAAP MEASURES The Fund discloses several financial measures in the MD&A that do not have any standardized meaning prescribed under GAAP. These financial measures include funds from operations, funds from operations per Trust Unit and cash netbacks. Management believes that these financial measures are useful supplemental information to analyze operating performance, leverage and provide an indication of the results generated by the Fund's principal business activities prior to the consideration of how those activities are financed or how the results are taxed. Investors should be cautioned that these measures should not be construed as an alternative to net income, cash provided by operating activities or other measures of financial performance as determined in accordance with GAAP. Advantage's method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies. Funds from operations, as presented, is based on cash provided by operating activities before expenditures on asset retirement and changes in non-cash working capital. Funds from operations per Trust Unit is based on the number of Trust Units outstanding at each distribution record date. Cash netbacks are dependent on the determination of funds from operations and include the primary cash revenues and expenses on a per boe basis that comprise funds from operations. Funds from operations reconciled to cash provided by operating activities is as follows:
THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 ($000) 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Cash provided by operating activities $ 83,366 $ 65,495 27% $ 249,132 $229,087 9% Expenditures on asset retirement 2,116 3,462 (39)% 6,951 5,974 16% Changes in non-cash working capital (4,963) (6,220) (20)% 15,060 (20,303) (174)% - ------------------------------------------------------------------------------------------------------------------------------- FUNDS FROM OPERATIONS $ 80,519 $ 62,737 28% $ 271,143 $214,758 26% - -------------------------------------------------------------------------------------------------------------------------------
FORWARD-LOOKING INFORMATION The information in this report contains certain forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar expressions. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Advantage's control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; changes in income tax laws or changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry and income trusts; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; obtaining required approvals of regulatory authorities and other risk factors set forth in Advantage's Annual Information Form which is available at www.advantageincome.com or www.sedar.com. Advantage's actual results, Advantage Energy Income Fund - 1 performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Advantage will derive from them. Except as required by law, Advantage undertakes no obligation to publicly update or revise any forward-looking statements. ACQUISITION OF SOUND ENERGY TRUST On September 5, 2007, the previously announced acquisition of Sound Energy Trust ("Sound") was completed. The financial and operational information for the quarter and year ended December 31, 2007 reflects operations from the Sound properties effective from the closing date, September 5, 2007. The acquisition was accomplished through a Plan of Arrangement (the "Arrangement") by the exchange of each Sound Trust Unit for 0.30 of an Advantage Trust Unit or, at the election of the holder of Sound Trust Units, $0.66 in cash and 0.2557 of an Advantage Trust Unit. In addition, all Sound Exchangeable Shares were exchanged for Advantage Trust Units on the same ratio based on the conversion ratio in effect at the effective date of the Arrangement. Advantage issued 16,977,184 Trust Units and paid $21.4 million cash as consideration to acquire Sound. The transaction is accretive to Advantage's Unitholders on a production, cash flow, reserves and net asset value basis and has significantly increased Advantage's tax pool position to a total of approximately $1.7 billion, and Safe Harbour expansion room to approximately $2.0 billion. Sound's higher oil weighting, synergy with many of Advantage's core properties and significant undeveloped land holdings of approximately 400,000 net undeveloped acres will further enhance the operating platform of Advantage.
OVERVIEW THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Cash provided by operating activities ($000) $ 83,366 $ 65,495 27% $ 249,132 $ 229,087 9% Funds from operations ($000) $ 80,519 $ 62,737 28% $ 271,143 $ 214,758 26% per Trust Unit (1) $ 0.58 $ 0.59 (2)% $ 2.22 $ 2.63 (16)% Net income (loss) ($000) $ 13,795 $ 8,736 58% $ (7,535) $ 49,814 (115)% per Trust Unit - Basic $ 0.10 $ 0.08 25% $ (0.06) $ 0.62 (110)% - Diluted $ 0.10 $ 0.08 25% $ (0.06) $ 0.61 (110)%
(1) Based on Trust Units outstanding at each distribution record date. Cash provided by operating activities increased 27%, funds from operations increased 28%, and funds from operations per Trust Unit modestly decreased 2% for the three months ended December 31, 2007, as compared to the same period of 2006. For the year ended December 31, 2007, cash provided by operating activities increased 9%, funds from operations increased 26%, and funds from operations per Trust Unit decreased 16%. Cash provided by operating activities and funds from operations for the quarter and year were positively impacted by increased revenues due to additional production from the Sound acquisition and the year was further impacted by a full year of production from the Ketch acquisition that closed in 2006. Funds from operations per Trust Unit decreased during the periods due to a higher average number of Trust Units outstanding. The weighted average number of Trust Units has increased 32% for the three months and 48% for the year ended in 2007 compared to 2006, mainly due to the Sound acquisition, the Trust Unit financing in the first quarter of 2007 and the distribution reinvestment plan. When compared to the third quarter of 2007, funds from operations increased 29% due to production increases of 17% from the acquisition of Sound and stronger commodity prices. Natural gas prices, excluding hedging, increased 11% and crude oil and NGL prices, excluding hedging, increased 6% for the fourth quarter of 2007 as compared to the prior quarter. The Fund also realized net derivative gains of $5.2 million in the three months and $18.6 million for the year ended December 31, 2007 which also helped to strengthen cash provided by operating activities and funds from operations. Net income for the quarter increased 58% over prior year due to higher crude oil prices and higher production from the Sound acquisition, offset somewhat by higher costs from the acquisition and general growth of the Fund. Net income for the year decreased to a net loss for the twelve months ended December 31, 2007 primarily due to higher operating costs, as well as non-cash expenses such as amortization of the management contract internalization and higher depletion and depreciation expense. The primary factor that causes significant variability of Advantage's cash provided by operating activities, funds from operations, and net income is Advantage Energy Income Fund - 2 commodity prices. Refer to the section "Commodity Prices and Marketing" for a more detailed discussion of commodity prices and our price risk management.
DISTRIBUTIONS THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - ------------------------------------------------------------------------------------------------------------------------------- Distributions declared ($000) $ 57,875 $ 58,791 (2)% $ 215,194 $ 217,246 (1)% per Trust Unit (1) $ 0.42 $ 0.56 (25)% $ 1.77 $ 2.66 (33)%
(1) Based on Trust Units outstanding at each distribution record date. Total distributions declared decreased 2% for the three months and 1% for the year ended December 31, 2007 when compared to the same periods in 2006. Total distributions declared are slightly lower as a result of the decreases in the distribution per Trust Unit in January and December 2007. The decreases in per Trust Unit distributions are offset by additional distributions due to the increased Trust Units outstanding from the continued growth and development of the Fund. Since natural gas prices were very weak during the 2006/2007 winter season, we reduced the distribution level in January 2007 and as natural gas prices continued to show prolonged weakness throughout 2007, we decreased the distribution level further in December 2007 to more appropriately reflect the current commodity price environment. Distributions per Trust Unit were $0.42 for the three months and $1.77 for the year ended December 31, 2007, representing a decrease of 25% and 33% from same periods in 2006. The monthly distribution is currently $0.12 per Trust Unit. To mitigate the persisting risk associated with lower commodity prices and the resulting negative impact on cash flows, the Fund implemented a hedging program with 51% of natural gas production and 38% of crude oil production, net of royalties, hedged for 2008. See "Commodity Price Risk" section for a more detailed discussion of our price risk management. Distributions from the Fund to Unitholders are entirely discretionary and are determined by Management and the Board of Directors. We closely monitor our distribution policy considering forecasted cash flows, optimal debt levels, capital spending activity, taxability to Unitholders, working capital requirements, and other potential cash expenditures. Distributions are announced monthly and are based on the cash available after retaining a portion to meet such spending requirements. The level of distributions are primarily determined by cash flows received from the production of oil and natural gas from existing Canadian resource properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. If the oil and natural gas reserves associated with the Canadian resource properties are not supplemented through additional development or the acquisition of additional oil and natural gas properties, our distributions will decline over time in a manner consistent with declining production from typical oil and natural gas reserves. Therefore, distributions are highly dependent upon our success in exploiting the current reserve base and acquiring additional reserves. Furthermore, monthly distributions we pay to Unitholders are highly dependent upon the prices received for such oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond our control. Declines in oil or natural gas prices will have an adverse effect upon our operations, financial condition, reserves and ultimately on our ability to pay distributions to Unitholders. The Fund attempts to mitigate the volatility in commodity prices through our hedging program. It is our long-term objective to provide stable and sustainable distributions to the Unitholders, while continuing to grow the Fund. However, given that funds from operations can vary significantly from month-to-month due to these factors, the Fund may utilize various financing alternatives as an interim measure to maintain stable distributions. For Canadian and U.S. holders of Advantage Trust Units, the distributions paid for 2007 were 100% taxable. All Unitholders of the Fund are encouraged to consult their tax advisors as to the proper treatment of Advantage distributions for income tax purposes. Advantage Energy Income Fund - 3
REVENUE THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 ($000) 2007 2006 % CHANGE 2007 2006 % CHANGE - ------------------------------------------------------------------------------------------------------------------------------- Natural gas excluding hedging $ 73,662 $ 74,309 (1)% $ 286,777 $ 231,548 24% Realized hedging gains 8,762 4,046 117% 20,933 4,164 403% - ------------------------------------------------------------------------------------------------------------------------------- Natural gas including hedging $ 82,424 $ 78,355 5% $ 307,710 $ 235,712 31% - ------------------------------------------------------------------------------------------------------------------------------- Crude oil and NGLs excluding hedging $ 87,079 $ 48,051 81% $ 251,987 $ 182,882 38% Realized hedging gains (losses) (3,552) 1,133 (414)% (2,339) 1,133 (306)% - ------------------------------------------------------------------------------------------------------------------------------- Crude oil and NGLs including hedging $ 83,527 $ 49,184 70% $ 249,648 $ 184,015 36% - ------------------------------------------------------------------------------------------------------------------------------- TOTAL REVENUE $ 165,951 $ 127,539 30% $ 557,358 $419,727 33% - -------------------------------------------------------------------------------------------------------------------------------
Natural gas revenues, excluding hedging, have decreased 1% for the three months and increased 24% for the year ended December 31, 2007, compared to 2006. The decrease in natural gas revenues for the three months is mainly due to a 10% decrease in natural gas prices, excluding hedging, offset by an equivalent 10% increase in production, primarily from the Sound acquisition. Conversely, the increase in natural gas revenues for the 2007 year is mainly due to the inclusion of a full year of production from the Ketch merger that closed in 2006 and production from the Sound acquisition since September 5, 2007, while natural gas prices remained fairly constant. Crude oil and NGL revenues, excluding hedging, have increased by 81% for the three months and 38% for the year ended December 31, 2007, compared to 2006. Crude oil and NGL revenue increased due to additional production from the Sound acquisition and the inclusion of a full year of production from the Ketch merger combined with an increase in crude oil and NGL prices of 34% for the three months and 6% for the year ended December 31, 2007. For the three months and year ended December 31, 2007, the Fund recognized natural gas and crude oil net hedging gains of $5.2 million and $18.6 million primarily due to derivative contracts in place that offset commodity prices fluctuations which can jeopardize revenues and corresponding distributions.
PRODUCTION THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - ------------------------------------------------------------------------------------------------------------------------------- Natural gas (mcf/d) 128,556 117,134 10% 116,998 94,074 24% Crude oil (bbls/d) 10,410 7,148 46% 8,090 6,273 29% NGLs (bbls/d) 2,485 2,422 3% 2,372 1,802 32% - ------------------------------------------------------------------------------------------------------------------------------- TOTAL (BOE/D) 34,321 29,092 18% 29,962 23,754 26% - ------------------------------------------------------------------------------------------------------------------------------- Natural gas (%) 63% 67% 65% 66% Crude oil (%) 30% 25% 27% 26% NGLs (%) 7% 8% 8% 8%
The Fund's total daily production averaged 34,321 boe/d for the three months and 29,962 boe/d for the year ended December 31, 2007, an increase of 18% and 26%, respectively, compared with the same periods of 2006. Natural gas production increased 10%, crude oil production increased 46%, and NGLs production increased 3% for the fourth quarter of 2007. For the year ended December 31, 2007, natural gas production increased 24%, crude oil production increased 29%, and NGLs production increased 32%. Production for the quarter increased due to the additional properties from the Sound acquisition. The increase in production for the year ended December 31, 2007 has been primarily attributed to a full year of production from the Ketch acquisition which closed June 23, 2006 and production from the Sound acquisition which closed September 5, 2007. Production for the fourth quarter increased 17% from the third quarter of 2007 also due to a full quarter of production from the acquisition of Sound. Our successful first quarter 2007 drilling program at Martin Creek, followed by continued success at Sunset, Nevis, Willesden Green, as well as other areas in Southern Alberta and Saskatchewan throughout the year has helped offset natural declines. In addition, our flattening production platform, resulting from our continued focus on long life assets, is contributing to a stable operating foundation. For 2008 we expect production to average approximately 32,000 to 34,000 boe/d, weighted 62% to natural gas. Advantage Energy Income Fund - 4 Approximately 55% of our capital spending will be directed to natural gas and 45% toward light oil projects which will enable us to increase our crude oil production and capitalize on the stronger crude oil pricing environment. COMMODITY PRICES AND MARKETING
NATURAL GAS THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 ($/MCF) 2007 2006 % CHANGE 2007 2006 % CHANGE - ------------------------------------------------------------------------------------------------------------------------------- Realized natural gas prices Excluding hedging $ 6.23 $ 6.90 (10)% $ 6.72 $ 6.74 - Including hedging $ 6.97 $ 7.27 (4)% $ 7.21 $ 6.86 5% AECO monthly index $ 6.00 $ 6.36 (6)% $ 6.61 $ 6.98 (5)%
Realized natural gas prices, excluding hedging, decreased 10% for the three months and remained constant for the year ended December 31, 2007, as compared to 2006. The price of natural gas is primarily based on supply and demand fundamentals in the North American marketplace; however market speculation activity has increased price volatility. Natural gas prices declined for the current quarter and continued to remain weak for the entire 2007 year, as in 2006, due to exceedingly high storage levels, mild summer and winter weather and a lack of storm activity in the Gulf of Mexico. Fourth quarter natural gas inventory levels remained well above average, causing continued downward pressure on commodity prices. However, early 2008 has brought colder weather and significant inventory withdrawals have been experienced, resulting in a rebound of natural gas prices. Natural gas storage levels are now closer to expectation and only slightly above the five-year average. In addition, there has been a tighter supply of natural gas, putting further upward pressure on prices. These developments have been encouraging and we continue to believe that the long-term pricing fundamentals for natural gas remain strong. These fundamentals include (i) the continued strength of crude oil prices, which has eliminated the economic advantage of fuel switching away from natural gas evidenced by the increase in proposed gas fired electrical generation facilities, (ii) significantly less natural gas drilling in Canada projected for 2008, which will reduce productivity to offset declines, (iii) the increasing focus on resource style natural gas wells, which have high initial declines and require a higher threshold economic price than conventional gas drilling and (iv) the demand for natural gas for the Canadian oil sands projects.
CRUDE OIL AND NGLS THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 ($/BBL) 2007 2006 % CHANGE 2007 2006 % CHANGE - ------------------------------------------------------------------------------------------------------------------------------- Realized crude oil prices Excluding hedging $ 74.19 $ 56.10 32% $67.71 $ 63.85 6% Including hedging $ 70.48 $ 57.82 22% $66.92 $ 64.34 4% Realized NGLs prices Excluding hedging $ 70.09 $ 50.09 40% $60.12 $ 55.81 8% Realized crude oil and NGLs prices Excluding hedging $ 73.40 $ 54.58 34% $65.99 $ 62.05 6% Including hedging $ 70.40 $ 55.86 26% $65.38 $ 62.44 5% WTI ($US/bbl) $ 90.63 $ 60.21 51% $72.37 $ 66.35 9% $US/$Canadian exchange rate $ 1.02 $ 0.88 16% $ 0.94 $ 0.88 7%
Realized crude oil and NGLs prices, excluding hedging, increased 34% for the three months and 6% for the year ended December 31, 2007, as compared to the same periods of 2006. Advantage's crude oil prices are based on the benchmark pricing of West Texas Intermediate Crude ("WTI") adjusted for quality, transportation costs and $US/$Canadian exchange rates. For the three months and year ended December 31, 2007, WTI increased 51% and 9%, respectively, with momentous increases experienced in the fourth quarter of 2007. Advantage's realized crude oil price has not changed to the same extent as WTI due to the strengthening of the Canadian dollar relative to the US dollar and widened Canadian crude oil differentials relative to WTI. The price of WTI fluctuates based on worldwide supply and demand fundamentals. There has been significant price volatility experienced over the last several years whereby WTI has reached historic high levels. Many developments have resulted in the current price levels, including significant continuing geopolitical issues and general market speculation. In fact, the impact of market fundamentals has diminished Advantage Energy Income Fund - 5 as geopolitical events and speculation has prevailed. As a result, prices have remained strong throughout 2007 and into early 2008. With the current high price levels, it is notable that demand has remained resilient even as the United States, the world's largest crude oil consumer, experiences an economic slowdown. Regardless whether the current price level is sustainable or just a short-term anomaly, we believe that the pricing fundamentals for crude oil remain strong with many factors affecting the continued strength including (i) supply management and supply restrictions by the OPEC cartel, (ii) ongoing civil unrest in Venezuela, Nigeria, and the Middle East, (iii) strong world wide demand, particularly in China, India and the United States and (iv) North American refinery capacity constraints. COMMODITY PRICE RISK The Fund's operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by economic and, in the case of oil prices, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions, impact prices. Any movement in oil and natural gas prices could have an effect on the Fund's financial condition and therefore on the distributions to holders of Advantage Trust Units. As current and future practice, Advantage has established a financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivatives. These commodity price risk management activities could expose Advantage to losses or gains. To the extent that Advantage engages in risk management activities related to commodity prices, it will be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities. We have been active in entering new financial contracts to protect future cash flows and currently the Fund has the following derivatives in place:
DESCRIPTION OF DERIVATIVE TERM VOLUME AVERAGE PRICE - ------------------------------------------------------------------------------------------------------------------------------- NATURAL GAS - AECO Fixed price November 2007 to March 2008 7,109 mcf/d Cdn$9.54/mcf Fixed price April 2008 to October 2008 14,217 mcf/d Cdn$6.85/mcf Fixed price April 2008 to October 2008 9,478 mcf/d Cdn$7.25/mcf Fixed price April 2008 to October 2008 14,217 mcf/d Cdn$7.83/mcf Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.10/mcf Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.06/mcf Fixed price November 2008 to March 2009 14,217 mcf/d Cdn$7.77/mcf Fixed price November 2008 to March 2009 4,739 mcf/d Cdn$8.10/mcf Collar November 2007 to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf Ceiling Cdn$10.29/mcf Collar November 2007 to March 2008 7,109 mcf/d Floor Cdn$8.70/mcf Ceiling Cdn$10.71/mcf CRUDE OIL - WTI Fixed price February 2008 to January 2009 2,000 bbls/d Cdn$90.93/bbl Fixed price April 2008 to March 2009 2,500 bbls/d Cdn$97.15/bbl Collar February 2008 to January 2009 2,000 bbls/d Sold put Cdn$70.00/bbl Purchased call Cdn$105.00/bbl Cost Cdn$1.52/bbl
As at December 31, 2007 the fair value of the derivatives outstanding was a net asset of approximately $2.2 million. For the year ended December 31, 2007, $11.0 million was recognized in income as an unrealized derivative loss due to changes in the fair value and settlement of such contracts since December 31, 2006. For the same period we recognized in income a realized derivative gain of $18.6 million upon the settlement of these financial contracts, which partially alleviated lower revenue from continued weak natural gas prices. As a result of the Sound acquisition, the Fund assumed several derivatives which had an estimated net fair value on closing of $2.8 million. The change in fair value of these derivatives since acquisition to the end of the period has been recognized in income as an unrealized derivative gain or loss. The valuation of the derivatives is the estimated fair value to settle the contracts as at December 31, 2007 and is based on pricing models, estimates, assumptions and market data available at that time. The actual gain or loss realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. The Fund does not apply hedge accounting and current accounting standards require changes in the fair value Advantage Energy Income Fund - 6 to be included in the consolidated statement of income and comprehensive income as an unrealized derivative gain or loss with a corresponding derivative asset and liability recorded on the balance sheet. The Fund has fixed the commodity price on anticipated production as follows:
APPROXIMATE PRODUCTION AVERAGE AVERAGE COMMODITY HEDGED, NET OF ROYALTIES FLOOR PRICE CEILING PRICE - ------------------------------------------------------------------------------------------------------------------------------- NATURAL GAS - AECO January to March 2008 22% Cdn$8.85/mcf Cdn$10.19/mcf April to June 2008 66% Cdn$7.22/mcf Cdn$7.22/mcf July to September 2008 64% Cdn$7.22/mcf Cdn$7.22/mcf October to December 2008 53% Cdn$7.32/mcf Cdn$7.32/mcf - ------------------------------------------------------------------------------------------------------------------------------- TOTAL 2008 51% CDN$7.43/MCF CDN$7.58/MCF - ------------------------------------------------------------------------------------------------------------------------------- January to March 2009 46% Cdn$7.39/mcf Cdn$7.39/mcf CRUDE OIL - WTI January to March 2008 13% Cdn$90.93/bbl Cdn$90.93/bbl April to June 2008 47% Cdn$94.39/bbl Cdn$94.39/bbl July to September 2008 46% Cdn$94.39/bbl Cdn$94.39/bbl October to December 2008 46% Cdn$94.39/bbl Cdn$94.39/bbl - ------------------------------------------------------------------------------------------------------------------------------- TOTAL 2008 38% CDN$94.07/BBL CDN$94.07/BBL - ------------------------------------------------------------------------------------------------------------------------------- January to March 2009 32% Cdn$95.84/bbl Cdn$95.84/bbl
ROYALTIES THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Royalties, net of Alberta Royalty Credit ($000) $27,099 $ 23,349 16% $ 98,614 $76,456 29% per boe $ 8.58 $ 8.72 (2)% $ 9.02 $ 8.82 2% As a percentage of revenue, excluding hedging 16.9% 19.1% (2.2)% 18.3% 18.4% (0.1)%
Advantage pays royalties to the owners of mineral rights from which we have leases. The Fund currently has mineral leases with provincial governments, individuals and other companies. Royalties for 2006 are shown net of the Alberta Royalty Credit, which was a royalty rebate provided by the Alberta government to certain producers and was eliminated effective January 1, 2007. Royalties have increased in total for the 2007 periods due to the increase in revenue from higher production related to acquisitions but remains comparable on a per boe basis. Royalties as a percentage of revenue, excluding hedging, remained consistent for the year as compared to 2006 but decreased in the fourth quarter of 2007 due to the lower natural gas prices experienced by Advantage during the last six months of the year. We expect the royalty rate to be in the range of 17% to 19% for 2008 given the current environment. On October 25, 2007, the Alberta Provincial Government announced changes to royalties for conventional oil, natural gas and oil sands that will become effective January 1, 2009. Given the methodology used in the new royalty regime, royalties and as a result, cash flows will be affected by depths and productivity of wells. In addition, royalties are price sensitive with higher royalty levels applying when commodity prices are higher. A review of the initial information released by the Alberta Provincial Government indicates that lower rate natural gas wells will see a benefit of lower royalties while conventional oil will be subject to an increase in royalties but is again less punitive at lower rates. Commodity prices and individual well production rates are both key factors in the calculation. The majority of Advantage's production in Alberta comes from lower rate wells due to well-established large, long life properties. In addition, we have a significant presence in British Columbia and Saskatchewan. Therefore, early indications are that the impact may not be significant based on our current production and the current commodity price environment. Advantage continues to analyze the impact of the decision and will take the new royalty regime into consideration in preparing future development projects. Project economics are evaluated taking into consideration all relevant factors including the new royalty regime given the commodity pricing environment anticipated. Those projects that maximize return to Advantage Unitholders will continue to be selected for development. Advantage Energy Income Fund - 7
OPERATING COSTS THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Operating costs ($000) $39,330 $ 27,803 41% $127,309 $82,911 54% per boe $ 12.46 $ 10.39 20% $ 11.64 $ 9.56 22%
Total operating costs increased 41% for the three months and 54% for the year ended December 31, 2007 as compared to 2006, mainly due to increased production from the Ketch acquisition which was completed June 23, 2006 and the Sound acquisition, which closed on September 5, 2007. Operating costs per boe increased 20% for the three months and 22% for the year ended December 31, 2007, mainly due to lower production levels related to third party turnaround activity, an extended spring break-up, increased service and supply costs as the industry experienced overall cost increases, and higher relative operating costs from recent acquisitions. However, fourth quarter 2007 per boe operating costs came in modestly lower than our expectation of $12.50 to $13.50, due to optimization initiatives put in place by the Fund in 2007. We will continue to be opportunistic and proactive in pursuing programs that will improve our operating cost structure. Consistent with this strategy, the Fund entered hedges for power costs, one of our more significant operating costs, of 3.0 MW at $54.00/MWh for 2008. We expect that operating costs per boe will be in the range of $12.50 to $13.30 for the 2008 year.
GENERAL AND ADMINISTRATIVE THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- General and administrative expense ($000) $ 7,173 $ 4,586 56% $ 21,449 $ 13,738 56% per boe $ 2.27 $ 1.71 33% $ 1.96 $ 1.58 24% Employees at December 31 172 135 27%
General and administrative ("G&A") expense has increased 56% for the three months and year ended December 31, 2007, as compared to 2006. G&A per boe increased 33% for the three months and 24% for the year when compared to the same periods of 2006. G&A expense for the year ended December 31, 2007 has increased overall and per boe primarily due to an increase in staff levels that have resulted from the Ketch and Sound acquisitions and general growth of the Fund. Additionally, the Ketch acquisition was conditional on Advantage internalizing the external management contract structure and eliminating all related fees for a more typical employee compensation arrangement. The new employee compensation plan has resulted in higher G&A expense, including unit-based compensation, which is offset by the elimination of future management fees and performance incentive. Prior to elimination of the management contract, the quarterly management fee and annual performance incentive were not included within G&A. Current employee compensation includes salary, benefits, a short-term incentive plan and a long-term incentive plan. The long-term incentive plan consists of a Restricted Trust Unit Plan (the "Plan"), as approved by the Unitholders on June 23, 2006, and Trust Units issuable for the retention of certain employees of the Fund. The purpose of the long-term compensation plans is to retain and attract employees, to reward and encourage performance, and to focus employees on operating and financial performance that results in lasting Unitholder return. The Plan authorizes the Board of Directors to grant Restricted Trust Units ("RTUs") to directors, officers, or employees of the Fund. The number of RTUs granted is based on the Fund's Trust Unit return for a calendar year and compared to a peer group approved by the Board of Directors. The Trust Unit return is calculated at the end of the year and is primarily based on the year-over-year change in the Trust Unit price plus distributions. The RTU grants vest one third immediately on grant date, with the remaining two thirds vesting evenly on the following two yearly anniversary dates. The holders of RTUs may elect to receive cash upon vesting in lieu of the number of Trust Units to be issued, subject to consent of the Fund. Compensation cost related to the Plan is based on the "fair value" of the RTUs at the grant date and is recognized as compensation expense over the service period. This valuation incorporates the period end Trust Unit price, the estimated number of RTUs to vest, and certain management estimates. The maximum fair value of RTUs granted in any one calendar year is limited to 175% of the base salaries of those individuals participating in the Plan for such period. As the Fund did not meet the 2007 or 2006 grant thresholds, there were no RTU grants made during these years and no related compensation expense has been recognized. Advantage Energy Income Fund - 8 For the year ended December 31, 2007, the Fund has accrued unit-based compensation expense of $0.9 million in general and administrative expense and has capitalized $0.3 million related to Trust Units issuable for the retention of certain employees of the Fund.
MANAGEMENT FEE, PERFORMANCE INCENTIVE, AND MANAGEMENT INTERNALIZATION THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Management fee ($000) $ - $ - - $ - $ 887 (100)% per boe $ - $ - - $ - $ 0.10 (100)% Performance incentive ($000) $ - $ - - $ - $ 2,380 (100)% Management internalization ($000) $ 2,534 $ 5,497 (54)% $ 15,708 $13,449 17%
Prior to the Ketch merger, the Manager received both a management fee and a performance incentive fee as compensation pursuant to the Management Agreement approved by the Board of Directors. As a condition of the merger with Ketch, the Fund and the Manager reached an agreement to internalize the management contract arrangement. As part of the agreement, Advantage agreed to purchase all of the outstanding shares of the Manager pursuant to the terms of the Arrangement, thereby eliminating the management fee and performance incentive effective April 1, 2006. The Trust Unit consideration issued in exchange for the outstanding shares of the Manager was placed in escrow for a 3-year period and is being deferred and amortized into income as management internalization expense over the specific vesting periods during which employee services are provided. The management internalization is lower for the quarter since one third vested and was paid in June 2007 while two thirds remains outstanding.
INTEREST THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Interest expense ($000) $ 7,917 $ 5,414 46% $ 24,351 $ 18,258 33% per boe $ 2.51 $ 2.02 24% $ 2.23 $ 2.11 6% Average effective interest rate 6.2% 5.5% 0.7% 5.7% 5.1% 0.6% Bank indebtedness at December 31 ($000) $547,426 $410,574 33%
Interest expense has increased 46% for the three months and 33% for the year ended December 31, 2007, as compared to 2006. Interest expense per boe has increased 24% for the three months and 6% for the year ended December 31, 2007. The increase in total interest expense is primarily attributable to a higher average debt level associated with the growth of the Fund, an increase in the average effective interest rates and increased bank indebtedness assumed on the Ketch and Sound acquisitions. We monitor the debt level to ensure an optimal mix of financing and cost of capital that will provide a maximum return to Unitholders. Our current credit facilities have been a favorable financing alternative with an effective interest rate of only 5.7% for the year ended December 31, 2007. The Fund's interest rates are primarily based on short term Bankers Acceptance rates plus a stamping fee.
INTEREST AND ACCRETION ON CONVERTIBLE DEBENTURES THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Interest on convertible debentures ($000) $ 4,426 $ 3,289 35% $ 14,867 $11,210 33% per boe $ 1.40 $ 1.23 14% $ 1.36 $ 1.29 5% Accretion on convertible debentures ($000) $ 721 $ 604 19% $ 2,569 $ 2,106 22% per boe $ 0.23 $ 0.23 - $ 0.23 $ 0.24 (4)% Convertible debentures maturity value at December 31 ($000) $224,612 $180,730 24%
Interest on convertible debentures has increased 35% for the three months and 33% for the year ended December 31, 2007, as compared to 2006. Accretion on convertible debentures has increased 19% for the three months and 22% for the year ended December 31, 2007. The increases in total interest and accretion are due to Advantage assuming Sound's 8.75% and 8.00% convertible debentures and Ketch's 6.50% convertible debentures in the 2006 merger. The increased interest and accretion from the additional debentures has been slightly offset due to the exchange of convertible debentures to Trust Units during 2006 that pay distributions rather than interest. Interest per boe for the quarter is higher as our convertible debentures outstanding have slightly increased relative to our level of production. Advantage Energy Income Fund - 9
CASH NETBACKS THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 2007 2006 - ------------------------------------------------------------------------------------------------------------------------------- $000 PER BOE $000 PER BOE $000 PER BOE $000 PER BOE - ------------------------------------------------------------------------------------------------------------------------------- Revenue $ 160,741 $ 50.91 $ 122,360 $ 45.72 $ 538,764 $ 49.27 $ 414,430 $ 47.80 Realized gain on derivatives 5,210 1.65 5,179 1.93 18,594 1.70 5,297 0.61 Royalties, net of Alberta Royalty Credit (27,099) (8.58) (23,349) (8.72) (98,614) (9.02) (76,456) (8.82) Operating costs (39,330) (12.46) (27,803) (10.39) (127,309) (11.64) (82,911) (9.56) - ------------------------------------------------------------------------------------------------------------------------------- OPERATING $ 99,522 $ 31.52 $ 76,387 $ 28.54 $ 331,435 $ 30.31 $ 260,360 $ 30.03 General and administrative (1) (7,029) (2.23) (4,586) (1.71) (20,520) (1.88) (13,738) (1.58) Management fee - - - - - - (887) (0.10) Interest (7,917) (2.51) (5,414) (2.02) (24,351) (2.23) (18,258) (2.11) Interest on convertible debentures (1) (3,536) (1.12) (3,289) (1.23) (13,977) (1.28) (11,210) (1.29) Income and capital taxes (521) (0.16) (361) (0.13) (1,444) (0.13) (1,509) (0.17) - ------------------------------------------------------------------------------------------------------------------------------- FUNDS FROM OPERATIONS $ 80,519 $ 25.50 $ 62,737 $ 23.45 $ 271,143 $ 24.79 $ 214,758 $ 24.78 - -------------------------------------------------------------------------------------------------------------------------------
(1) General and administrative expense and interest on convertible debentures exclude unit-based compensation and non-cash interest expense. Funds from operations of Advantage for the quarter ended December 31, 2007 increased to $80.5 million from $62.7 million in the prior year. Funds from operations for the year ended December 31, 2007 increased to $271.1 million from $214.8 million compared to 2006. The cash netback per boe for the three months ended December 31, 2007 increased 9% from $23.45 to $25.50 for the quarter, but remained comparable for the year ended December 31, 2007. The higher cash netback per boe for the three months ended December 31, 2007 is primarily due to higher revenues, resulting from additional production from the accretive Sound acquisition and strong oil prices offset somewhat by lower natural gas prices as well as higher operating and general and administrative costs. Operating costs have steadily increased over the past year due to significantly higher field costs associated with supplies and services that have resulted from the high level of industry activity, an overall industry labour cost increase, and higher relative operating costs from recent acquisitions. However, it is noteworthy that due to several of our initiatives this year, operating costs for the quarter were less than anticipated. The increased general and administrative costs are due to higher staff levels and general growth of the Fund. When compared to the third quarter of 2007, funds from operations per boe increased 10%, again mainly due to the acquisition of Sound.
DEPLETION, DEPRECIATION AND ACCRETION THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 2007 2006 % CHANGE 2007 2006 % CHANGE - -------------------------------------------------------------------------------------------------------------------------------- Depletion, depreciation & accretion ($000) $78,149 $ 63,521 23% $272,175 $194,309 40% per boe $ 24.75 $ 23.73 4% $ 24.89 $ 22.41 11%
Depletion and depreciation of fixed assets is provided on the "unit-of-production" method based on total proved reserves. Accretion represents the increase in the asset retirement obligation liability each reporting period due to the passage of time. The depletion, depreciation and accretion ("DD&A") provision has increased 23% for the three months and 40% for the year ended December 31, 2007. The higher DD&A is due to considerable increases in daily production volumes, mainly from the Ketch and Sound acquisitions and the increase in the DD&A rate per boe compared to the prior year. The increased DD&A rate per boe was due to a higher valuation assigned for reserves from recent acquisitions than accumulated from prior acquisitions and development activities. We evaluate the recoverability of our petroleum and natural gas assets each reporting period to ensure the carrying amount does not Advantage Energy Income Fund - 10 exceed the fair value. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized. There has been no impairment of the Fund's petroleum and natural gas properties under Canadian GAAP since inception. TAXES Current taxes paid or payable for the quarter ended December 31, 2007 amounted to $0.5 million, comparable to the $0.4 million expensed for the same period of 2006. The higher current taxes are due to the increased Saskatchewan properties and activity within these properties from the Ketch and Sound acquisitions. Current taxes primarily represent Saskatchewan resource surcharge, which is based on the petroleum and natural gas revenues within the province of Saskatchewan. Future income taxes arise from differences between the accounting and tax bases of the assets and liabilities. For the year ended December 31, 2007, the Fund recognized a future income tax reduction of $24.6 million compared to $37.1 million for 2006. Under the Fund's current structure, payments are made between the operating company and the Fund transferring income tax obligations to Unitholders and as a result no cash income taxes would be paid by the operating company or the Fund prior to 2011. However, the Specified Investment Flow-Through Entity ("SIFT") tax legislation was enacted on June 22, 2007 altering the tax treatment by subjecting income trusts to a two-tier tax structure, similar to that of corporations, whereby the taxable portion of distributions paid by trusts will be subject to tax at the trust level and at the Unitholder level. The rules are effective for tax years beginning in 2011 for existing publicly-traded trusts. The impact of the new tax law is reflected in 2007 and resulted in an additional future income tax expense of $42.9 million. As at December 31, 2007, we had a future income tax liability balance of $66.7 million, compared to $61.9 million at December 31, 2006. Canadian generally accepted accounting principles require that a future income tax liability be recorded when the book value of assets exceeds the balance of tax pools. It further requires that a future tax liability be recorded on an acquisition when a corporation acquires assets with associated tax pools that are less than the purchase price. As a result of the Sound acquisition, Advantage recorded a future tax liability of $29.4 million. On December 14, 2007, the Federal government enacted legislation phasing in corporate income tax rate reductions which will reduce federal tax rates from 22.1% to 15.0% by 2012. Rate reductions will also apply to the new tax on distributions of income trusts and other specified investment flow-through entities as of 2011, reducing the tax rate in 2011 to 29.5% and in 2012 to 28.0%. These rates include a deemed provincial rate of 13%. The Fund has approximately $1.7 billion in tax pools and deductions at December 31, 2007, which can be used to reduce the amount of taxes paid by Advantage. The Fund and Advantage Oil & Gas Ltd. ("AOG") had the following estimated tax pools in place at December 31, 2007: DECEMBER 31, 2007 ESTIMATED TAX POOLS ($ MILLIONS) ------------ Undepreciated Capital Cost $ 641 Canadian Oil and Gas Property Expenses 462 Canadian Development Expenses 435 Canadian Exploration Expenses 65 Non-capital losses 76 Other 25 -------- $ 1,704 Advantage Energy Income Fund - 11 CONTRACTUAL OBLIGATIONS AND COMMITMENTS The Fund has contractual obligations in the normal course of operations including purchases of assets and services, operating agreements, transportation commitments, sales contracts and convertible debentures. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner. The following table is a summary of the Fund's remaining contractual obligations and commitments. Advantage has no guarantees or off-balance sheet arrangements other than as disclosed.
PAYMENTS DUE BY PERIOD ($ MILLIONS) TOTAL 2008 2009 2010 2011 2012 - ------------------------------------------------------------------------------------------------------------------------------- Building leases $ 16.6 $ 5.3 $ 4.1 $ 4.1 $ 1.8 $ 1.3 Capital leases 8.1 1.9 2.1 2.2 1.9 - Pipeline/transportation 6.0 4.4 1.3 0.3 - - Convertible debentures (1) 224.6 5.4 87.0 69.9 62.3 - - ------------------------------------------------------------------------------------------------------------------------------- TOTAL CONTRACTUAL OBLIGATIONS $ 255.3 $ 17.0 $ 94.5 $ 76.5 $ 66.0 $ 1.3 - -------------------------------------------------------------------------------------------------------------------------------
(1) As at December 31, 2007, Advantage had $224.6 million convertible debentures outstanding. Each series of convertible debentures are convertible to Trust Units based on an established conversion price. The Fund expects that the obligations related to convertible debentures will be settled either directly or indirectly through the issuance of Trust Units. (2) Bank indebtedness of $547.4 million has been excluded from the contractual obligations table as the credit facilities constitute a revolving facility for a 364 day term which is extendible annually for a further 364 day revolving period at the option of the syndicate. If not extended, the revolving credit facility is converted to a two year term facility with the first payment due one year and one day after commencement of the term. LIQUIDITY AND CAPITAL RESOURCES The following table is a summary of the Fund's capitalization structure. ($000, EXCEPT AS OTHERWISE INDICATED) DECEMBER 31, 2007 - -------------------------------------------------------------------------------- Bank indebtedness (long-term) $ 547,426 Working capital deficit (1) 28,087 - -------------------------------------------------------------------------------- Net debt $ 575,513 - -------------------------------------------------------------------------------- Trust Units outstanding (000) 138,269 Trust Unit closing market price ($/Trust Unit) $ 8.73 - -------------------------------------------------------------------------------- Market value $ 1,207,088 - -------------------------------------------------------------------------------- Capital lease obligations (long-term) $ 5,653 Convertible debentures maturity value (long-term) 219,220 - -------------------------------------------------------------------------------- TOTAL CAPITALIZATION $ 2,007,474 - -------------------------------------------------------------------------------- (1) Working capital deficit includes accounts receivable, prepaid expenses and deposits, accounts payable and accrued liabilities, distributions payable, and the current portion of capital lease obligations and convertible debentures. UNITHOLDERS' EQUITY AND CONVERTIBLE DEBENTURES Advantage has utilized a combination of Trust Units, convertible debentures and bank debt to finance acquisitions and development activities. As at December 31, 2007, the Fund had 138.3 million Trust Units outstanding. On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus an additional 800,000 Trust Units upon exercise of the Underwriters' over-allotment option on March 7, 2007, at $12.80 per Trust Unit for approximate net proceeds of $104.1 million (net of Underwriters' fees and other issue costs of $6.0 million). The net proceeds of the offering were used to pay down bank indebtedness and to subsequently fund capital and general corporate expenditures. On September 5, 2007, Advantage issued 16,977,184 Trust Units as partial consideration for the acquisition of Sound. As at March 5, 2008, Advantage had 139.0 million Trust Units issued and outstanding. On July 24, 2006, Advantage adopted a Premium Distribution(TM), Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan"). For Unitholders that elect to participate in the Plan, Advantage will settle the monthly distribution obligation through Advantage Energy Income Fund - 12 the issuance of additional Trust Units at 95% of the Average Market Price (as defined in the Plan). Unitholder enrollment in the Premium Distribution(TM) component of the Plan effectively authorizes the subsequent disposal of the issued Trust Units in exchange for a cash payment equal to 102% of the cash distributions that the Unitholder would otherwise have received if they did not participate in the Plan. During the year ended December 31, 2007, 4,028,252 Trust Units were issued as a result of the Plan, generating $46.7 million reinvested in the Fund and representing an approximate 18% participation rate. As at December 31, 2007, the Fund had $224.6 million convertible debentures outstanding that were convertible to 9.8 million Trust Units based on the applicable conversion prices. During the year ended December 31, 2007, $24,000 debentures were converted resulting in the issuance of 1,386 Trust Units and all of the remaining $1,470,000 10% convertible debentures matured on November 1, 2007 and were settled with the issuance of 127,493 Trust Units. Due to the acquisition of Sound, $59,513,000 8.75% and $41,035,000 8.00% convertible debentures were assumed by Advantage on September 5, 2007. As a result of the change in control of Sound, the Fund was required by the debenture indentures to make an offer to purchase all of the outstanding convertible debentures assumed from Sound as at a price equal to 101% of the principal amount plus accrued and unpaid interest. On October 17, 2007, the expiry date of the offer, 911,709 Trust Units were issued and $19.9 million in total cash consideration was paid in exchange for $29,665,000 8.75% convertible debentures and 2,220,289 Trust Units were issued in exchange for $25,507,000 8.00% convertible debentures. As at March 5, 2008, the convertible debentures have not changed from December 31, 2007. Effective June 25, 2002, a Trust Units Rights Incentive Plan for external directors of the Fund was established and approved by the Unitholders of Advantage. A total of 500,000 Trust Units have been reserved for issuance under the plan with an aggregate of 400,000 rights granted since inception. The initial exercise price of rights granted under the plan may not be less than the current market price of the Trust Units as of the date of the grant and the maximum term of each right is not to exceed ten years with all rights vesting immediately upon grant. At the option of the rights holder, the exercise price of the rights can be adjusted downwards over time based upon distributions paid by the Fund to Unitholders. In exchange for an equivalent number of Trust Units, 37,500 Series B Trust Unit Rights were exercised in the second quarter of 2007. As at March 5, 2008, 150,000 Series B Trust Unit Rights remain outstanding. As a result of the new SIFT tax legislation, an income trust is permitted to double its market capitalization as it stands on October 31, 2006 by growing a maximum of 40% in 2007 and 20% for the years 2008 to 2010. Any unused expansion from the prior year can be brought forward into the following year until the new tax rules take effect. In addition, an income trust may replace debt that was outstanding as of October 31, 2006 with new equity or issue new, non-convertible debt without affecting the normal growth percentage. An income trust may also merge with another income trust without a change to their normal growth percentage, provided there is no net addition to equity as a result of the merger. As of October 31, 2006, the Fund had an approximate market capitalization of $1.6 billion and bank indebtedness of $0.4 billion. Therefore, as a result of the "normal growth" guidelines, the Fund is permitted to issue $2.0 billion of new equity from October 31, 2006 to January 1, 2011, which we believe is adequate for any growth we expect to incur. BANK INDEBTEDNESS, CREDIT FACILITY AND OTHER OBLIGATIONS At December 31, 2007, Advantage had bank indebtedness outstanding of $547.4 million. The Fund has a $710 million credit facility agreement consisting of a $690 million extendible revolving loan facility and a $20 million operating loan facility. The current credit facilities are secured by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement from the Fund covering all assets and cash flows. At December 31, 2007, Advantage had a working capital deficiency of $28.1 million. Our working capital includes items expected for normal operations such as trade receivables, prepaids, deposits, trade payables and accruals as well as the current portion of capital lease obligations and convertible debentures. Working capital varies primarily due to the timing of such items, the current level of business activity including our capital program, commodity price volatility, and seasonal fluctuations. Advantage has no unusual working capital requirements. We do not anticipate any problems in meeting future obligations as they become due given the strength of our funds from operations. It is also important to note that working capital is effectively integrated with Advantage's operating credit facility, which assists with the timing of cash flows as required. In the second quarter of 2007, Advantage entered a new lease arrangement that resulted in the recognition of a fixed asset addition and capital lease obligation of $4.1 million. The lease obligation bears interest at 5.8% and is secured by the related equipment. The lease term expires June 2011 with a final purchase obligation of $1.5 million at which time ownership of the equipment will transfer to Advantage. We entered a second lease arrangement during the third quarter of 2007 that resulted in the recognition of a fixed asset addition and capital lease obligation of $1.8 million. This lease obligation bears interest at 6.7% and is also secured by the related equipment. The lease term expires August 2010 with a final payment obligation of $0.7 million. Distributions to Unitholders are not permitted if the Fund is in default of this capital lease. Advantage Energy Income Fund - 13 On September 5, 2007, Advantage assumed two capital lease obligations in the acquisition of Sound resulting in the recognition of capital lease obligations of $1.6 million. Both of the assumed lease obligations bear interest at 5.6% and are secured by the related equipment. The lease terms expire December 2009 and April 2010 with a total final payment obligation of $0.9 million.
CAPITAL EXPENDITURES THREE MONTHS ENDED YEAR ENDED DECEMBER 31 DECEMBER 31 ($000) 2007 2006 2007 2006 - -------------------------------------------------------------------------------------------------------------- Land and seismic $ 64 $ 522 $ 3,270 $ 5,261 Drilling, completions and workovers 30,020 42,612 94,786 113,146 Well equipping and facilities 9,971 17,690 48,296 39,437 Other 878 285 2,373 1,643 - -------------------------------------------------------------------------------------------------------------- $ 40,933 $ 61,109 $ 148,725 $159,487 Acquisition of Sound Energy Trust (67) - 22,307 - Property acquisitions 3,200 46 16,051 244 Property dispositions (610) - (1,037) (8,727) - -------------------------------------------------------------------------------------------------------------- TOTAL CAPITAL EXPENDITURES $ 43,456 $ 61,155 $ 186,046 $151,004 - --------------------------------------------------------------------------------------------------------------
Advantage's growth strategy has been to acquire properties in or near areas where we have large land positions, shallow to medium depth drilling opportunities, and a balance of year round access. We focus on areas where past activity has yielded long-life reserves with high cash netbacks. With the integration of the Ketch and Sound assets, Advantage is very well positioned to selectively exploit the highest value-generating drilling opportunities given the size, strength and diversity of our asset base. As a result, the Fund has a high level of flexibility to distribute its capital program and ensure a risk-balanced platform of projects. Our preference is to operate a high percentage of our properties such that we can maintain control of capital expenditures, operations and cash flows. For the three month period ended December 31, 2007, the Fund spent a net $40.9 million and drilled a total of 16.6 net (32 gross) wells at a 100% success rate. Total capital spending in the quarter included $7.1 million at Nevis, $5.7 million at Chip Lake, $5.3 million at Martin Creek, $3.9 million at Southeast Saskatchewan and $3.4 million at Willesden Green. For the year ended December 31, 2007, the Fund spent a net $148.7 million and drilled a total of 64.8 net (112 gross) wells at a 99% success rate. Total capital spending for the year included $33.6 million at Martin Creek, $26.2 million at Nevis, $17.5 million at Willesden Green, $10.5 million in Southeast Saskatchewan, $8.5 million at Chip Lake, and $7.2 million at Sunset. Property acquisitions year to date include a $12.9 million property acquisition in the first quarter for producing properties and undeveloped land at the Fund's core area, Nevis, and a $3.2 million property acquisition in the Boundary Lake area during the fourth quarter. Costs of $22.3 million were incurred related to the Sound acquisition representing the cash portion paid due to the exercise of the cash option offered to Sound Unitholders and other costs. Advantage Energy Income Fund - 14 The following table summarizes the various funding requirements during the years ended December 31, 2007 and 2006 and the sources of funding to meet those requirements. SOURCES AND USES OF FUNDS YEAR ENDED DECEMBER 31 ($000) 2007 2006 - -------------------------------------------------------------------------------- SOURCES OF FUNDS Funds from operations $ 271,143 $ 214,758 Units issued, net of costs 104,215 141,908 Increase in bank indebtedness 28,893 - Property dispositions 1,037 8,727 Decrease in working capital - 27,222 - -------------------------------------------------------------------------------- $ 405,288 $ 392,615 - -------------------------------------------------------------------------------- USES OF FUNDS Distributions to Unitholders $ 170,915 $ 185,015 Expenditures on property and equipment 148,725 159,487 Acquisition of Sound Energy Trust 22,307 - Debentures redeemed 19,406 - Increase in working capital 17,749 - Property acquisitions 16,051 244 Expenditures on asset retirement 6,951 5,974 Reduction of capital lease obligations 3,184 1,019 Decrease in bank indebtedness - 30,767 Acquisition of Ketch Resources Trust - 10,109 - -------------------------------------------------------------------------------- $ 405,288 $ 392,615 - -------------------------------------------------------------------------------- ANNUAL FINANCIAL INFORMATION The following is a summary of selected financial information of the Fund for the periods indicated.
YEAR ENDED YEAR ENDED YEAR ENDED DEC. 31, 2007 DEC. 31, 2006 DEC. 31, 2005 - ------------------------------------------------------------------------------------------------------------ Total revenue (before royalties) ($000) $ 557,358 $ 419,727 $ 376,572 Net income (loss) ($000) $ (7,535) $ 49,814 $ 75,072 per Trust Unit - Basic $ (0.06) $ 0.62 $ 1.33 - Diluted $ (0.06) $ 0.61 $ 1.32 Total assets ($000) $ 2,422,280 $ 1,981,587 $1,012,847 Long term financial liabilities ($000) ((1)) $ 768,060 $ 581,698 $ 379,903 Distributions declared per Trust Unit $ 1.77 $ 2.66 $ 3.12
(1) Long term financial liabilities exclude asset retirement obligations and future income taxes. Advantage Energy Income Fund - 15
QUARTERLY PERFORMANCE 2007 2006 ($000, EXCEPT AS OTHERWISE INDICATED) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 - ----------------------------------------------------------------------------------- ----------------------------------------- Daily production Natural gas (mcf/d) 128,556 115,991 108,978 114,324 117,134 122,227 70,293 65,768 Crude oil and NGLs (bbls/d) 12,895 10,014 8,952 9,958 9,570 9,330 6,593 6,760 Total (boe/d) 34,321 29,346 27,115 29,012 29,092 29,701 18,309 17,721 Average prices Natural gas ($/mcf) Excluding hedging $ 6.23 $ 5.62 $ 7.54 $ 7.61 $ 6.90 $ 5.89 $ 6.18 $ 8.69 Including hedging $ 6.97 $ 6.35 $ 7.52 $ 8.06 $ 7.27 $ 5.90 $ 6.18 $ 8.69 AECO monthly index $ 6.00 $ 5.62 $ 7.37 $ 7.46 $ 6.36 $ 6.03 $ 6.28 $ 9.31 Crude oil and NGLs ($/bbl) Excluding hedging $ 73.40 $ 69.03 $ 61.84 $ 56.84 $ 54.58 $ 67.77 $ 68.69 $ 58.26 Including hedging $ 70.40 $ 68.51 $ 61.93 $ 58.64 $ 55.86 $ 67.77 $ 68.69 $ 58.26 WTI (US$/bbl) $ 90.63 $ 75.33 $ 65.02 $ 58.12 $ 60.21 $ 70.55 $ 70.75 $ 63.88 Total revenues (before royalties) $ 165,951 $130,830 $125,075 $135,502 $127,539 $124,521 $ 80,766 $ 86,901 Net income (loss) $ 13,795 $(26,202) $ 4,531 $ 341 $ 8,736 $ 1,209 $ 23,905 $ 15,964 per Trust Unit - basic $ 0.10 $ (0.22) $ 0.04 $ 0.00 $ 0.08 $ 0.01 $ 0.38 $ 0.27 - diluted $ 0.10 $ (0.22) $ 0.04 $ 0.00 $ 0.08 $ 0.01 $ 0.38 $ 0.27 Funds from operations $ 80,519 $ 62,345 $ 62,634 $ 65,645 $ 62,737 $ 63,110 $ 42,281 $ 46,630 Distributions declared $ 57,875 $ 55,017 $ 52,096 $ 50,206 $ 58,791 $ 60,498 $ 53,498 $ 44,459
The table above highlights the Fund's performance for the fourth quarter of 2007 and also for the preceding seven quarters. Production significantly increased in the third quarter of 2006 as the Ketch acquisition that closed on June 23, 2006 was fully integrated with Advantage. The second quarter of 2007 encountered a temporary production decrease as expected due to several facility turnarounds that had been planned for that period. The third quarter of 2007 includes the financial and operating results from the acquired Sound properties for 26 days, and fourth quarter of 2007 includes the full integration of the Sound properties. Advantage's revenues and funds from operations increased significantly beginning in the third quarter of 2006 primarily due to the production from the merger with Ketch and surged again in the fourth quarter of 2007 due to the Sound acquisition, partially offset by lower natural gas prices. Net income was lower in the first three quarters of 2007 due to reduced natural gas prices realized during the periods, amortization of the management internalization consideration and increased depletion and depreciation expense due to the Ketch and Sound mergers. Net income increased in the fourth quarter of 2007 due to the full integration of the Sound acquisition and stronger crude oil prices. CRITICAL ACCOUNTING ESTIMATES The preparation of financial statements in accordance with GAAP requires Management to make certain judgments and estimates. Changes in these judgments and estimates could have a material impact on the Fund's financial results and financial condition. Management relies on the estimate of reserves as prepared by the Fund's independent qualified reserves evaluator. The process of estimating reserves is critical to several accounting estimates. The process of estimating reserves is complex and requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development and production activities becomes available and as economic conditions impact crude oil and natural gas prices, operating costs, royalty burden changes, and future development costs. Reserve estimates impact net income through depletion and depreciation of fixed assets, the provision for asset retirement costs and related accretion expense, and impairment calculations for fixed assets and goodwill. The reserve estimates are also used to assess the borrowing base for the Fund's credit facilities. Revision or changes in the reserve estimates can have either a positive or a negative impact on net income and the borrowing base of the Fund. Management's process of determining the provision for future income taxes, the provision for asset retirement obligation costs and related accretion expense, and the fair values assigned to any acquired company's assets and liabilities in a business combination is based on estimates. These estimates are significant and can include reserves, future production rates, future crude oil and natural gas Advantage Energy Income Fund - 16 prices, future costs, future interest rates, future tax rates and other relevant assumptions. Revisions or changes in any of these estimates can have either a positive or a negative impact on asset and liability values and net income. FINANCIAL REPORTING UPDATE CONVERGENCE OF CANADIAN GAAP WITH INTERNATIONAL FINANCIAL REPORTING STANDARDS In 2006, Canada's Accounting Standards Board ("AcSB") issued a strategic plan that will result in Canadian GAAP, as it applies to publicly accountable entities, being converged with International Financial Reporting Standards over a transitional period, initially indicated to be five years. The AcSB released a detailed implementation plan in May 2007 and the Fund will consider the effects that this implementation plan might have on the consolidated financial statements during the transition period. CAPITAL DISCLOSURES The CICA has issued section 1535 "Capital Disclosures", which will be effective January 1, 2008 for the Fund. Section 1535 will require the Fund to provide additional disclosures relating to capital and how it is managed. It is not anticipated that the adoption of section 1535 will impact the amounts reported in the Fund's financial statements as they primarily relate to disclosure. CONTROLS AND PROCEDURES The Fund has established procedures and internal control systems to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Management of the Fund is committed to providing timely, accurate and balanced disclosure of all material information about the Fund. Disclosure controls and procedures are in place to ensure all ongoing reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and Vice-President, Finance and Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regular filings, fairly present in all material respects the financial condition, results of operations, and cash flows as of the dates and for the periods presented in the filings. The certifications further acknowledge that the filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the filings. During 2007, there were no significant changes that would materially affect, or are reasonably likely to materially affect, the internal controls over financial reporting. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation. Further, 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. EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The Fund has established a Disclosure Committee consisting of seven executive members with the responsibility of overseeing the Fund's disclosure practices and designing disclosure controls and procedures to ensure that all material information is communicated to the Disclosure Committee. All written public disclosures are reviewed and approved by at least one member of the Disclosure Committee prior to issuance. Additionally, the Disclosure Committee assists the Chief Executive Officer and Chief Financial Officer of the Fund in making certifications with respect to the disclosure controls of the Fund required under applicable regulations and ensures that the Board of Directors is promptly and fully informed regarding potential disclosure issues facing the Fund. The Fund's Management is responsible for establishing and maintaining effective internal control over financial reporting. Management of Advantage, including our Chief Executive Officer and Vice-President, Finance and Chief Financial Officer, has evaluated the effectiveness of the design and operation of the disclosure controls and procedures as of December 31, 2007. Based on that evaluation, Management has concluded that the disclosure controls and procedures are effective as of the end of the period, in all material respects. It should be noted that while the Chief Executive Officer and Chief Financial Officer believe that the Fund's design of disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system does not provide absolute, but rather is designed to provide reasonable, assurance that the objective of the control system is met. CORPORATE GOVERNANCE The Board of Directors' mandate is to supervise the management of the business and affairs of the Fund including the business and affairs of the Fund delegated to AOG. In particular, all decisions relating to: (i) the acquisition and disposition of properties for a Advantage Energy Income Fund - 17 purchase price or proceeds in excess of $5 million; (ii) the approval of annual operating and capital expenditure budgets; and (iii) the establishment of credit facilities and the issuance of additional Trust Units, will be made by the Board. Computershare Trust Company of Canada, the Trustee of the Fund, has delegated certain matters to the Board of Directors. These include all decisions relating to issuance of additional Trust Units and the determination of the amount of distributions. Any amendment to any material contract to which the Fund is a party will require the approval of the Board of Directors and, in some cases, Unitholder approval. The Board of Directors meets regularly to review the business and affairs of the Fund and AOG and to make any required decisions. The Board of Directors consists of ten members, seven of whom are unrelated to the Fund. The Independent Reserve Evaluation Committee and Audit Committee each have three members, all of whom are independent. The Human Resources, Compensation and Corporate Governance Committee has four members, all of whom are independent. One member of the Audit Committee has been designated a "Financial Expert" as defined in applicable regulatory guidance. In addition, the Chairman of the Board is not related and is not an executive officer of the Fund. The Board of Directors approved and Management implemented a Code of Business Conduct and Ethics. The purpose of the code is to lay out the expectation for the highest standards of professional and ethical conduct from our directors, officers and employees. The code reflects our commitment to a culture of honesty, integrity and accountability and outlines the basic principles and policies with which all employees are expected to comply. Our Code of Business Conduct and Ethics is available on our website at www.advantageincome.com. As a Canadian issuer listed on the New York Stock Exchange (the "NYSE"), Advantage is not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic requirements. As a foreign private issuer, Advantage is only required to comply with four of the NYSE Rules: (i) have an audit committee that satisfies the requirements of the United States Securities Exchange Act of 1934; (ii) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE Rules; (iii) submit an executed annual written affirmation, as well as an interim affirmation each time a change occurs to the audit committee; and (iv) provide a brief description of any significant differences between its corporate governance practices and those followed by U.S. companies listed under the NYSE. Advantage has reviewed the NYSE listing standards and confirms that its corporate governance practices do not differ significantly from such standards. A further discussion of the Fund's corporate governance practices can be found in the Management Proxy Circular. OUTLOOK The Fund's 2008 Budget, as approved by the Board of Directors, retains a high degree of activity and focus on drilling in many of our key properties where a high level of success was realized through 2007. Capital has also been directed to delineate a natural gas resource play at Glacier in Northwest Alberta and to accommodate facility expansions and enhanced recovery schemes as necessary. New drill bit additions are expected to be more effective in replacing production as corporate declines have continued to subside throughout 2007. Advantage's production now contains very little flush production from high impact wells and concentrated drilling programs (from 2004 and 2005 activities) creating a balanced and predictable platform. During the fourth quarter of 2007, production was on-track and operating costs were lower than expected. We realized some impact to our production due to third party related facilities outages in December, however, continued efforts in operating cost optimization is providing efficiency gains. For 2008, we are forecasting production to be in the range of 32,000 to 34,000 boe/d. Advantage's 2008 capital expenditures budget is estimated to be approximately $125 to $145 million with approximately 143 gross (88 net) wells. An active winter program at Martin Creek, Glacier, Nevis and Willesden Green will be followed by a relatively even paced program in Q3 and Q4 of 2008. Capital spending is estimated to be split evenly between oil and gas activities. Per unit operating costs on an annual basis are expected to range between the $12.50 to $13.30/boe range. Advantage is continuing with several operating cost reduction initiatives throughout 2008 to help offset these increases and we have begun to realize some key achievements in this area. We expect industry servicing and maintenance costs to generally remain stable in 2008 with some potential for natural gas related costs to increase during the latter part of 2008 if natural gas prices strengthen at that time. On October 25, 2007, the Alberta Provincial Government announced changes to royalties for conventional oil, natural gas and oil sands that will become effective January 1, 2009. Preliminary indications are that the changes will have a negligible impact on Advantage since we have a significant number of lower rate wells within our long life properties producing in Alberta. Advantage also has a significant Horseshoe Canyon coal bed methane drilling inventory that can be pursued which will also have a favorable royalty treatment due to lower rate per well characteristics. Our exposure in Northeast British Columbia and Saskatchewan also affords us further flexibility with mitigating the royalty impact in our capital program. We expect our royalty rates to range from 17% to 19% in 2008. Advantage Energy Income Fund - 18 Advantage's funds from operations in 2008 will continue to be impacted by the volatility of crude oil and natural gas prices and the $US/$Canadian exchange rate. Additional hedging has been completed for 2008 to i) stabilize cash flows and ii) ensure that the Fund's capital program is substantially funded out of cash flow. Approximately 51% of our natural gas production, net of royalties, is now hedged for the 2008 calendar year at a floor of $7.43/mcf. Advantage has also hedged 38% of its 2008 crude oil production, net of royalties, at an average price of $94.07/bbl. Advantage will continue to follow its strategy of acquiring properties that provide low risk development opportunities and enhance long-term cash flow. Advantage will also continue to focus on low cost production and reserve additions through low to medium risk development drilling opportunities that have arisen as a result of the acquisitions completed in prior years and from the significant inventory of drilling opportunities that has resulted from the Ketch and Sound mergers. Looking forward, Advantage's high quality assets combined with a greater than five year drilling inventory, hedging program and excellent tax pools provides many options for the Fund and we are committed to maximizing value generation for our Unitholders. SENSITIVITIES The following table displays the current estimated sensitivity on funds from operations and funds from operations per Trust Unit to changes in production, commodity prices, exchange rates and interest rates for 2008.
ANNUAL ANNUAL FUNDS FROM OPERATIONS FUNDS FROM OPERATIONS PER TRUST UNIT ($000) ($/TRUST UNIT) - ------------------------------------------------------------------------------------------------------- Natural gas AECO monthly price change of $1.00/mcf $ 17,800 $ 0.12 Production change of 6.0 mmcf/d $ 7,200 $ 0.05 Crude oil and NGLs WTI price change of US$10.00/bbl $ 27,900 $ 0.20 Production change of 1,000 bbls/d $ 22,200 $ 0.16 $US/$Canadian exchange rate change of $0.01 $ 5,900 $ 0.04 Interest rate change of 1% $ 5,600 $ 0.04
ADDITIONAL INFORMATION Additional information relating to Advantage can be found on SEDAR at www.sedar.com and the Fund's website at www.advantageincome.com. Such other information includes the annual information form, the annual information circular - proxy statement, press releases, material contracts and agreements, and other financial reports. The annual information form will be of particular interest for current and potential Unitholders as it discusses a variety of subject matter including the nature of the business, structure of the Fund, description of our operations, general and recent business developments, risk factors, reserves data and other oil and gas information. Advantage Energy Income Fund - 19 EX-99 12 ex99-4form40f_2007.txt EXHIBIT 99.4 EXHIBIT 99.4 ------------ AUDITORS' REPORT To the Unitholders of Advantage Energy Income Fund We have audited the consolidated balance sheet of Advantage Energy Income Fund (the "Trust") as at December 31, 2006 and the consolidated statements of income, accumulated deficit and cash flows for the year then ended. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance 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. In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2006 and the results of its operations and its cash flow for the year then ended in accordance with Canadian generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Trust's internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 21, 2007 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting. /s/ KPMG LLP Chartered Accountants Calgary, Canada March 21, 2007 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Advantage Energy Income Fund on behalf of Advantage Energy Income Fund and the Unitholders of Advantage Energy Income Fund We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Advantage Energy Income Fund ("the Fund") maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Fund's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Fund's internal control over financial reporting based on our audit. 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. An entity'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. An entity'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 entity; (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 entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity'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, management's assessment that the Fund maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Fund maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We also have conducted our audit on the consolidated financial statements in accordance with Canadian generally accepted auditing standards. With respect to the year ended December 31, 2006, we also have conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated March 21, 2007, expressed an unqualified opinion on those consolidated financial statements. /s/ KPMG LLP Chartered Accountants Calgary, Canada March 21, 2007 -----END PRIVACY-ENHANCED MESSAGE-----