AAV Artemis Aim Vct

(TSX: AVN.UN, NYSE: AAV) CALGARY, March 18 /PRNewswire-FirstCall/ -- Advantage Energy Income Fund ("Advantage" or the "Fund") is pleased to announce the financial and operating results for the year ended December 31, 2008. Funds from Operations Increased 33% and Annual Production Increased 8% - Strong average natural gas and crude oil prices and excellent drilling results resulted in a 33% increase in funds from operations to $361.1 million for 2008 compared to $271.1 for 2007. Funds from operations on a per unit basis increased 16% to $2.57 per Trust Unit compared to $2.22 per Trust Unit for the year ended December 31, 2007. - Average 2008 daily production increased 8% to 32,273 boe/d compared to 29,962 boe/d for 2007. This was achieved despite 1,100 boe/d (73% natural gas) being curtailed since August 2008 as a result of a third party facility outage at the Lookout Butte property. Fourth quarter production of 31,529 boe/d was impacted by severe cold weather in December and the continuing outage at Lookout Butte. - Natural gas production for 2008 increased 5% to 122.9 mmcf/d, compared to 117.0 mmcf/d for 2007. Crude oil and natural gas liquids production increased 13% to 11,793 bbls/d compared to 10,462 bbls/d in 2007. - Operating costs for 2008 increased to $13.89 per boe due to higher cost of service and supplies driven by the increasing commodity price environment for most of the year. Fourth quarter 2008 operating costs was $14.71 per boe due to lower production, the impact of higher third party processing costs, increased property taxes and additional costs due to the severe cold weather that created unplanned equipment repairs. - The Fund declared distributions totaling $1.40 per Trust Unit with a 2008 payout ratio of just 54% as compared to 79% for 2007. Since inception, the Fund has distributed $1.1 billion or $17.66 per Trust Unit. Highly Efficient Reserve Additions from a Very Successful 2008 Drilling Program - Overall, the Fund replaced 290% of annual production with the vast majority of reserve additions realized through our successful 2008 drilling program at Glacier, Alberta where the Fund commenced a significant development drilling program on our Montney natural gas resource play (refer to Advantage's year-end reserves press release dated March 5, 2009). - Proven and probable reserves increased 15% to 174.8 mmboe from 152.2 mmboe at year end 2007. Proven reserves increased 7% to 102.3 mmboe from 95.6 mmboe at year end 2007. The Fund's proven plus probable reserve life index increased 26% to 15.2 years compared to 12.1 years at the end of 2007. Natural gas reserves calculate to a reserve life index of 15.9 years, and crude oil and natural gas liquids calculate to a reserve life index of 13.9 years, indicative of a very stable producing platform with significant upside potential. - In 2008, all-in Finding, Development and Acquisition ("FD&A") costs were $7.67 per proven plus probable boe before changes in future development capital ("FDC") and $16.70 per boe including changes in FDC. Drill bit reserve additions alone resulted in the replacement of 285% of annual production at a Finding and Development ("F&D") cost of $7.61 per proven and probable boe before consideration of changes in FDC and $16.95 per boe including the change in FDC. - The 2008 capital program totaled $263.2 million of which $255.6 million was invested in development activities and $7.6 million was expended on a complimentary acquisition at our Nevis property. Advantage invested $101 million at Glacier, which dramatically increased proven and probable reserves. Included in our 2008 capital expenditures were $20 million of strategic undeveloped land acquisitions, the majority of which was located at Glacier. A total of 124 gross (86.8 net) wells were drilled in 2008 at a 99% success rate. The $7.6 million Nevis acquisition resulted in increasing our working interest in 9 gross sections of land and provided future drilling locations on an additional 4 gross sections for Horseshoe Canyon coal bed methane. Glacier Montney Results Confirms Significant Resource Play Potential - Advantage invested $101 million at Glacier in 2008 and increased proven and probable reserves by 29 mmboe and confirmed horizontal well rates of 2.5 to 7.5 mmcfd (417 to 1,250 boe per day). - The 2008 F&D cost at Glacier was $3.48 per proven and probable boe before changes in FDC and $13.14 per boe including changes in FDC. - Montney reserves are assigned to only 32 of our 89 sections. The reserve assignment is based on an average well density of 2.4 wells per section of land although we currently have regulatory approval to drill up to 8 wells per section consisting of 4 wells in the Upper and 4 wells in the Lower Montney zones. Adjacent operators are currently evaluating 16 wells per section which may lead to significant future reserve additions. Further delineation drilling is required to evaluate the undeveloped land potential in the remaining 57 sections. Based on results to date, 440 locations have been confirmed in our extensive Montney land block. The drilling inventory at Glacier could exceed 800 locations depending on the density of horizontal wells that will ultimately be drilled per section of land. - Advantage estimates that fully developing the Montney resource potential at Glacier will require additional capital expenditures in excess of $2.5 billion over the life of the project which, if properly deployed, could result in significant reserve and production growth. Advantage will utilize a disciplined financial approach to development in order to yield significant long term value growth for Unitholders. Hedging Update - Advantage's hedging program includes 56% of our net natural gas production hedged for 2009 at an average price of $8.09 Cdn per mcf and 48% hedged for 2010 at an average price of $7.46 per mcf. Crude oil hedges include 46% of our net crude oil production hedged at an average floor price of $69.38 Cdn per bbl and 26% hedged for 2010 at an average price of $67.83 Cdn per bbl. Details on our hedging program are available on our website. Looking Forward - The Board of Directors approved a 2009 budget with capital expenditures between $100 and $135 million with approximately 46% directed to further developing our Montney natural gas reserves and production at Glacier. As a result of a much lower commodity price environment driven by global economic concerns, Advantage will be very disciplined and proactive to undertake actions as required to balance our capital and cash flows as we prepare for a challenging 2009. However, our capital expenditure priority will be to ensure the funding of further development in our Montney resource play at Glacier where the Fund sees significant reserves and production growth potential. - On March 18, 2009, Advantage announced that our Board of Directors had approved conversion to a growth oriented corporation and a strategic asset disposition program to increase financial flexibility. - The corporate conversion will be subject to two-thirds Unitholder approval as well as customary court and regulatory approvals, anticipated to be completed on or about June 30, 2009. The conversion will enable Advantage to pursue a business plan that is focused on the development and growth of the Montney natural gas resource play at Glacier. The conversion will have the added benefit of removing the uncertainty surrounding the upcoming changes in Canadian tax law whereby the government will begin imposing taxes on income trusts on January 1, 2011. - The Fund has retained Tristone Capital Inc. to assist with the disposition of properties producing up to 11,300 boe/d of light oil and natural gas properties located in Northeast British Columbia, West Central Alberta and Northern Alberta. The net proceeds from these sales or other oil and natural gas property sales will initially be used to reduce outstanding bank debt to improve Advantage's financial flexibility. Advantage may also draw down its credit facilities in the future to redeem certain of the Fund's convertible debentures. Proposals are anticipated by mid May 2009 and the selected assets will be available in four distinct packages varying in size from approximately 1,600 to 5,400 boe/d of production. - As another step to increase Advantage's financial flexibility and to focus on development and growth at Glacier, Advantage will discontinue payment of cash distributions with the final cash distribution paid on March 16, 2009 to unitholders of record as of February 27, 2009. Going forward, Advantage does not anticipate paying distributions or dividends in the immediate future and will instead, direct cash flow to capital expenditures and debt repayment. Financial and Operating Highlights Year ended December 31, 2008 2007 2006 2005 2004 Financial ($000, except per Trust Unit, per boe or as otherwise indicated) Revenue before royalties(1) 741,962 557,358 419,727 376,572 241,481 per Trust Unit(2) 5.32 4.66 5.18 6.65 5.89 per boe 62.82 50.97 48.41 51.27 38.92 Funds from operations 361,087 271,143 214,758 211,541 126,478 per Trust Unit(3) 2.57 2.22 2.65 3.72 3.05 per boe 30.58 24.79 24.78 28.80 20.39 Net income (loss) (20,577) (7,535) 49,814 75,072 24,038 per Trust Unit(2) (0.15) (0.06) 0.62 1.33 0.59 Distributions declared 196,642 215,194 217,246 177,366 117,655 per Trust Unit(3) 1.40 1.77 2.66 3.12 2.82 Expenditures on property and equipment 255,591 148,725 159,487 103,229 107,893 Working capital deficit(4) 146,397 28,087 42,655 31,612 56,408 Bank indebtedness 587,404 547,426 410,574 252,476 267,054 Convertible debentures (face value) 219,195 224,612 180,730 135,111 148,450 Trust Units outstanding at end of year (000) 142,825 138,269 105,390 57,846 49,675 Basic weighted average Trust Units (000) 139,483 119,604 80,958 56,593 41,008 Operating Daily Production Natural gas (mcf/d) 122,878 116,998 94,074 78,561 77,188 Crude oil and NGLs (bbls/d) 11,793 10,462 8,075 7,029 4,084 Total boe/d at 6:1 32,273 29,962 23,754 20,123 16,949 Average pricing (including hedging) Natural gas ($/mcf) 8.14 7.21 6.86 7.98 6.08 Crude oil and NGLs ($/bbl) 87.08 65.38 62.44 57.58 46.58 Proved plus probable reserves Natural gas (bcf) 704.3 546.4 442.7 286.9 296.9 Crude oil & NGLs (mbbls) 57,386 61,131 47,524 36,267 34,316 Total mboe 174,767 152,203 121,317 84,082 83,799 Reserve life index (years)(5) 15.2 12.1 11.4 12.0 9.9 (1) includes realized derivative gains and losses (2) based on basic weighted average Trust Units outstanding (3) based on Trust Units outstanding at each distribution record date (4) working capital deficit excludes derivative assets and liabilities (5) based on year end exit production rates Management's Discussion & Analysis The following Management's Discussion and Analysis ("MD&A"), dated as of March 18, 2009, 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, 2008 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) 2008 2007 %change 2008 2007 %change ------------------------------------------------------------------------- Cash provided by operating activities $ 83,754 $ 83,366 0% $374,750 $249,132 50% Expenditures on asset retirement 2,968 2,116 40% 9,259 6,951 33% Changes in non-cash working capital (17,352) (4,963) 250% (22,922) 15,060 (252)% ------------------------------------------------------------------------- Funds from operations $ 69,370 $ 80,519 (14)% $361,087 $271,143 33% ------------------------------------------------------------------------- Forward-Looking Information This MD&A contains certain forward-looking statements, which are based on our current internal expectations, estimates, projections, assumptions and beliefs. 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 or related expressions. These statements are not guarantees of future performance. In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to average production and projected exit rates; areas of operations; spending and capital budgets; availability of funds for our capital program; the size of, and future net revenues from, reserves; the focus of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; projections of market prices and costs; the performance characteristics of our properties; our future operating and financial results; capital expenditure programs; supply and demand for oil and natural gas; average royalty rates; and amount of general and administrative expenses. In addition, 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. These forward-looking statements involve substantial known and unknown risks and uncertainties, many of which are beyond our control, including the effect of acquisitions; changes in general economic, market and business conditions; changes or fluctuations in production levels; unexpected drilling results, changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; changes to legislation and regulations and how they are interpreted and enforced, changes to investment eligibility or investment criteria; our ability to comply with current and future environmental or other laws; our success at acquisition, exploitation and development of reserves; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties; competition from other producers; the lack of availability of qualified personnel or management; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry and income trusts; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties are described in Advantage's Annual Information Form which is available at http://www.sedar.com/ and http://www.advantageincome.com/. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities. With respect to forward-looking statements contained in this MD&A, Advantage has made assumptions regarding: current commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the price of oil and natural gas; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; royalty rates and future operating costs. Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide Unitholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this MD&A and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. Corporate Conversion and Asset Disposition On March 18, 2009, we announced that our Board of Directors had approved conversion to a growth oriented corporation and a strategic asset disposition program to increase financial flexibility. The corporate conversion will be subject to approval by at least two-thirds of the Fund's Unitholders as well as customary court and regulatory approvals, anticipated to be completed on or about June 30, 2009. The conversion will enable Advantage to pursue a business plan that is focused on the development and growth of the Montney natural gas resource play at Glacier. The conversion will have the added benefit of removing the uncertainty surrounding the upcoming changes in Canadian tax law whereby the government will begin imposing taxes on income trusts on January 1, 2011. The Fund has retained Tristone Capital Inc. to assist with the disposition of properties producing up to 11,300 boe/d of light oil and natural gas properties located in Northeast British Columbia, West Central Alberta and Northern Alberta. The net proceeds from these sales or other oil and natural gas property sales will initially be used to reduce outstanding bank debt to improve Advantage's financial flexibility. Advantage may also draw down its credit facilities in the future to redeem certain of the Fund's convertible debentures. Proposals are anticipated by mid May 2009 and the selected assets will be available in four distinct packages varying in size from approximately 1,600 to 5,400 boe/d of production. As another step to increase Advantage's financial flexibility and to focus on development and growth at Glacier, Advantage will discontinue payment of cash distributions with the final cash distribution paid on March 16, 2009 to unitholders of record as of February 27, 2009. Going forward, Advantage does not anticipate paying distributions or dividends in the immediate future and will instead direct cash flow to capital expenditures and debt repayment. Given these business developments, historical operating and financial performance may not be indicative of future performance depending on the magnitude of the asset disposition process and pending approval of the corporate conversion. Overview Three months ended Year ended December 31 December 31 2008 2007 %change 2008 2007 %change ------------------------------------------------------------------------- Cash provided by operating activities ($000) $ 83,754 $ 83,366 -% $374,750 $249,132 50% Funds from operations ($000) $ 69,370 $ 80,519 (14)% $361,087 $271,143 33% per Trust Unit(1) $ 0.49 $ 0.58 (16)% $ 2.57 $ 2.22 16% (1) Based on Trust Units outstanding at each distribution record date. Cash provided by operating activities and funds from operations have increased significantly for the year ended December 31, 2008 as compared to 2007 due to considerably higher revenue. Our 2008 annual revenue has benefited from both higher average commodity prices and production. Improved production is substantially due to the Sound Energy Trust ("Sound") acquisition, which closed on September 5, 2007, and incremental production from our 2008 drilling program. The financial and operating results from the acquired Sound properties are included in all 2008 figures but are only included in the year ended December 31, 2007 effective from the closing date. Funds from operations per Trust Unit has also increased significantly, but not in the same proportion due to the higher number of Trust Units outstanding for 2008. Trust Units outstanding has increased due to Trust Units issued in exchange for the Sound acquisition and our distribution reinvestment plan that allows Unitholders to purchase Trust Units in exchange for their regular monthly cash distributions. Although cash provided by operating activities for the three months ended December 31, 2008 is comparable with the same period of 2007, funds from operations for the current quarter has decreased 14% and funds from operations per Trust Unit has decreased 16%. These decreases have been due to a slightly lower average production and a dramatic reduction in crude oil prices. The fourth quarter of 2008 has seen significant negative economic developments as a direct result of the global recession, which has triggered a sharp decline in crude oil prices from lower demand. This challenging situation has continued into 2009 placing continued downward pressure on commodity prices. The primary factor that causes significant variability of Advantage's cash provided by operating activities, funds from operations, and net income is 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 2008 2007 %change 2008 2007 %change ------------------------------------------------------------------------- Distributions declared ($000) $ 45,514 $ 57,875 (21)% $196,642 $215,194 (9)% per Trust Unit(1) $ 0.32 $ 0.42 (24)% $ 1.40 $ 1.77 (21)% (1) Based on Trust Units outstanding at each distribution record date. Total distributions declared decreased 21% for the three months and 9% for the year ended December 31, 2008 when compared to the same periods in 2007. Total distributions are lower as a result of decreases in the distribution declared per Trust Unit during these periods. Lower total distributions were partially offset by additional distributions due to increased Trust Units outstanding. As commodity prices have weakened, we have reduced the distribution level to more appropriately reflect the current price environment. Distributions per Trust Unit were $0.32 for the three months and $1.40 for the year ended December 31, 2008, representing decreases of 24% and 21% from the same periods in 2007. For the majority of 2008, we paid a monthly distribution of $0.12 per Trust Unit and reduced the distribution to $0.08 per Trust Unit effective for the December distribution paid in January. We further reduced the monthly distribution to $0.04 per Trust Unit for the February distribution paid in March. On March 18, 2009, we discontinued all future distributions, consistent with our strategy to reduce debt and convert to a growth oriented corporation that will focus capital on the Glacier Montney natural gas resource play. Distribution Taxability For Canadian and U.S. holders of Advantage Trust Units, the distributions paid for 2008 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. Revenue Three months ended Year ended December 31 December 31 ($000) 2008 2007 %change 2008 2007 %change ------------------------------------------------------------------------- Natural gas excluding hedging $ 79,402 $ 73,662 8% $382,701 $286,777 33% Realized hedging gains (losses) 5,051 8,762 (42)% (16,580) 20,933 (179)% ------------------------------------------------------------------------- Natural gas including hedging $ 84,453 $ 82,424 2% $366,121 $307,710 19% ------------------------------------------------------------------------- Crude oil and NGLs excluding hedging $ 56,330 $ 87,079 (35)% $386,700 $251,987 53% Realized hedging gains (losses) 8,422 (3,552) (337)% (10,859) (2,339) 364% ------------------------------------------------------------------------- Crude oil and NGLs including hedging $ 64,752 $ 83,527 (22)% $375,841 $249,648 51% ------------------------------------------------------------------------- Total revenue $149,205 $165,951 (10)% $741,962 $557,358 33% ------------------------------------------------------------------------- Revenues were significantly higher for the year ended December 31, 2008 due to the full year of additional production from the Sound acquisition and stronger average commodity prices. During this period, the higher revenue was partially offset by realized hedging losses that also resulted from the higher average commodity price environment. Unfortunately, the fourth quarter of 2008 experienced a significant decrease in crude oil and NGL prices, due to the global recession, and our revenues were substantially impacted. As we had hedged a significant portion of our production, we also realized hedging gains during the quarter that partially offset the reduced revenues. The Fund enters derivative contracts whereby realized hedging gains and losses partially offset commodity price fluctuations, which can positively or negatively impact revenues. Production Three months ended Year ended December 31 December 31 2008 2007 %change 2008 2007 %change ------------------------------------------------------------------------- Natural gas (mcf/d) 120,694 128,556 (6)% 122,878 116,998 5% Crude oil (bbls/d) 9,443 10,410 (9)% 9,543 8,090 18% NGLs (bbls/d) 1,970 2,485 (21)% 2,250 2,372 (5)% ------------------------------------------------------------------------- Total (boe/d) 31,529 34,321 (8)% 32,273 29,962 8% ------------------------------------------------------------------------- Natural gas (%) 64% 63% 63% 65% Crude oil (%) 30% 30% 30% 27% NGLs (%) 6% 7% 7% 8% The Fund's total daily production averaged 32,273 boe/d for the year ended December 31, 2008, an increase of 8% realized primarily due to the Sound acquisition, which closed September 5, 2007, and drilling results from our successful 2008 capital program. Production for the three months ended December 31, 2008 was 31,529 boe/d, a decrease of 3% from the 32,418 boe/d realized in the third quarter of 2008. Production of 1,100 boe/d at our Lookout Butte property in Southern Alberta remained shut-in during the fourth quarter by an extended third party facility outage that began in August 2008 at the Waterton gas plant where a significant modification project is underway. Original estimates provided by the third party indicated a potential outage of approximately 55 to 75 days. However, subsequent information now indicates that the gas plant may be down until April 1, 2009. Additionally, in the fourth quarter of 2008 we also experienced freezing conditions from cold weather that reduced production in December. On March 18, 2009, we announced the intention to dispose of properties producing up to 11,300 boe/d of light oil and natural gas properties located in Northeast British Columbia, West Central Alberta and Northern Alberta. The net proceeds from these sales or other oil and natural gas property sales will initially be used to reduce outstanding bank debt to improve Advantage's financial flexibility. Proposals are anticipated by mid May 2009 and the selected assets will be available in four distinct packages varying in size from approximately 1,600 to 5,400 boe/d of production. Assuming asset sales of approximately 10,000 to 11,300 boe/d of production are completed, we expect production of approximately 20,000 to 22,000 boe/d from a focused asset base (60% natural gas, 40% oil and natural gas liquids). Commodity Prices and Marketing Natural Gas Three months ended Year ended December 31 December 31 ($/mcf) 2008 2007 %change 2008 2007 %change ------------------------------------------------------------------------- Realized natural gas prices Excluding hedging $ 7.15 $ 6.23 15% $ 8.51 $ 6.72 27% Including hedging $ 7.61 $ 6.97 9% $ 8.14 $ 7.21 13% AECO monthly index $ 6.79 $ 6.00 13% $ 8.13 $ 6.61 23% Realized natural gas prices, excluding hedging, were considerably higher for the three months and year ended December 31, 2008 compared to 2007 but have decreased approximately 17% from the third quarter of 2008. The 2007/2008 winter season in North America caused inventory levels, that had been high prior to winter, to decline to approximately the five-year average. In addition, reduced liquefied natural gas imports into the US and the slowdown in natural gas drilling in Western Canada provided upward price support in the first half of this year. However, during the third and fourth quarters of 2008, there has been significant softening of natural gas prices from higher US domestic natural gas production, mild weather conditions and forecasts, and the ongoing global recession that has impacted demand. These factors have resulted in much higher inventory levels that continue to place considerable downward pressure on natural gas prices. Unfortunately, these conditions have also continued well into 2009 with AECO gas presently trading at approximately $3.80/GJ. Although we continue to believe in the longer-term pricing fundamentals for natural gas, we are concerned about the current pricing and economic environment that has the potential to extend for a considerable period of time. The global recession could delay the recovery of natural gas pricing longer than anticipated. While the current pricing situation is quite weak, some of the factors that we believe will support stronger future natural gas prices include: (i) significantly less natural gas drilling in Canada projected for 2009, which will reduce productivity to offset declines, (ii) signs of reduced natural gas drilling in the US, (iii) the increasing focus on resource style natural gas wells, which have high initial declines, and which are becoming a larger proportion of the total natural gas supply based in Canada and the US, and (iv) the demand for natural gas for the Canadian oil sands projects. Crude Oil and NGLs Three months ended Year ended December 31 December 31 ($/bbl) 2008 2007 %change 2008 2007 %change ------------------------------------------------------------------------- Realized crude oil prices Excluding hedging $ 57.46 $ 74.19 (23)% $ 92.81 $ 67.71 37% Including hedging $ 67.16 $ 70.48 (5)% $ 89.71 $ 66.92 34% Realized NGLs prices Excluding hedging $ 35.38 $ 70.09 (50)% $ 75.93 $ 60.12 26% Realized crude oil and NGL prices Excluding hedging $ 53.65 $ 73.40 (27)% $ 89.59 $ 65.99 36% Including hedging $ 61.67 $ 70.40 (12)% $ 87.08 $ 65.38 33% WTI ($US/bbl) $ 58.75 $ 90.63 (35)% $ 99.65 $ 72.37 38% $US/$Canadian exchange rate $ 0.83 $ 1.02 (19)% $ 0.94 $ 0.94 -% Advantage's realized 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. Advantage's realized crude oil price may not change to the same extent as WTI, due to changes in the $US/$Canadian exchange rate, and changes in 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 reached historic high levels in 2008, producing a 36% increase in our average realized crude oil and NGL price, excluding hedging, for the year. However, as we have seen remarkable crude oil price increases, we have also seen a similarly dramatic reduction in the later half of 2008 whereby WTI decreased 35% for the three months ended December 31, 2008 as compared to the same period of 2007 and decreased 50% from the third quarter of 2008. This decline has had a significant negative impact on our realized crude oil and NGL price, excluding hedging, that has dropped 27% for the fourth quarter of 2008 as compared to same quarter of 2007 and decreased 50% from the third quarter of 2008. WTI has continued to decline in 2009 to approximately US$47/bbl, the result of demand destruction brought on by the current global recession. The impact from this decrease in WTI will be somewhat mitigated for Advantage due to the strengthening US dollar relative to the Canadian dollar. As with natural gas, it seems evident that the global recession will likely prolong depressed crude oil prices through the coming year. Regardless of this significant decrease, we believe that the longer-term 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) frequent civil unrest in various crude oil producing countries and regions, (iii) strong relative worldwide demand in developing countries, particularly in China and India, and (iv) production declines and reduced drilling due to the lower price environment. 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 performance. 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. Although these commodity price risk management activities could expose Advantage to losses or gains, entering derivative contracts helps us to stabilize cash flows and ensures that our capital expenditure program is substantially funded by such cash flows. 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 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 Fixed price April 2009 to December 2009 9,478 mcf/d Cdn$8.66/mcf Fixed price April 2009 to December 2009 9,478 mcf/d Cdn$8.67/mcf Fixed price April 2009 to December 2009 9,478 mcf/d Cdn$8.94/mcf Fixed price April 2009 to March 2010 14,217 mcf/d Cdn$7.59/mcf Fixed price April 2009 to March 2010 14,217 mcf/d Cdn$7.56/mcf Fixed price January 2010 to June 2010 14,217 mcf/d Cdn$8.23/mcf Fixed price January 2010 to December 2010 18,956 mcf/d Cdn$7.29/mcf(1) Fixed price April 2010 to January 2011 18,956 mcf/d Cdn$7.25/mcf(1) 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 Fixed price April 2008 to March 2009 2,500 bbls/d Cdn$97.15/bbl Collar April 2009 to December 2009 2,000 bbls/d Bought put Cdn$62.00/bbl Sold call Cdn$76.00/bbl Fixed price April 2009 to March 2010 2,000 bbls/d Cdn$62.80/bbl(1) Fixed price April 2010 to January 2011 2,000 bbls/d Cdn$69.50/bbl(1) (1) The Fund entered into these hedges after December 31, 2008. The Fund has fixed the commodity price on anticipated production as follows: Approximate Production Hedged, Average Average Commodity Net of Royalties Floor Price Ceiling Price ------------------------------------------------------------------------- Natural gas - AECO January to March 2009 62% Cdn$7.87/mcf Cdn$7.87/mcf April to June 2009 53% Cdn$8.17/mcf Cdn$8.17/mcf July to September 2009 54% Cdn$8.17/mcf Cdn$8.17/mcf October to December 2009 56% Cdn$8.17/mcf Cdn$8.17/mcf ----------------------------------------------------------------------- Total 2009 56% Cdn$8.09/mcf Cdn$8.09/mcf ----------------------------------------------------------------------- January to March 2010 62% Cdn$7.64/mcf Cdn$7.64/mcf April to June 2010 53% Cdn$7.53/mcf Cdn$7.53/mcf July to September 2010 38% Cdn$7.27/mcf Cdn$7.27/mcf October to December 2010 38% Cdn$7.27/mcf Cdn$7.27/mcf ----------------------------------------------------------------------- Total 2010 48% Cdn$7.46/mcf Cdn$7.46/mcf ----------------------------------------------------------------------- January to March 2011 6% Cdn$7.25/mcf Cdn$7.25/mcf ----------------------------------------------------------------------- Crude Oil - WTI January to March 2009 38% Cdn$95.84/bbl Cdn$95.84/bbl April to June 2009 48% Cdn$62.40/bbl Cdn$69.40/bbl July to September 2009 48% Cdn$62.40/bbl Cdn$69.40/bbl October to December 2009 50% Cdn$62.40/bbl Cdn$69.40/bbl ----------------------------------------------------------------------- Total 2009 46% Cdn$69.38/bbl Cdn$74.92/bbl ----------------------------------------------------------------------- January to March 2010 26% Cdn$62.80/bbl Cdn$62.80/bbl April to June 2010 26% Cdn$69.50/bbl Cdn$69.50/bbl July to September 2010 26% Cdn$69.50/bbl Cdn$69.50/bbl October to December 2010 26% Cdn$69.50/bbl Cdn$69.50/bbl ----------------------------------------------------------------------- Total 2010 26% Cdn$67.83/bbl Cdn$67.83/bbl ----------------------------------------------------------------------- January to March 2011 9% Cdn$69.50/bbl Cdn$69.50/bbl ----------------------------------------------------------------------- For the year ended December 31, 2008, we recognized in income a realized derivative loss of $27.4 million on settled derivative contracts (2007 - $18.6 million realized derivative gain). As at December 31, 2008, the fair value of derivative contracts remaining to be settled was an approximate $41.0 million net asset (December 31, 2007 - $2.2 million net asset) resulting in the recognition of a $38.8 million unrealized derivative gain for the 2008 year (2007 - $11.0 million unrealized derivative loss) due to changes in fair value since December 31, 2007. The valuation of the derivatives is the estimated fair value to settle the contracts as at December 31, 2008 and is based on pricing models, estimates, assumptions and market data available at that time. As such, the unrealized amounts are not cash and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. These fair values are extremely sensitive to assumptions regarding forward commodity prices as demonstrated from our recognized $34.0 million unrealized derivative gain during the fourth quarter of 2008 as commodity prices continued to decrease and the $7.0 million net derivative asset recognized at September 30, 2008 is now valued as a $41.0 million net asset. The Fund does not apply hedge accounting and current accounting standards require changes in the fair value to be included in the consolidated statement of loss and comprehensive loss as an unrealized derivative gain or loss with a corresponding derivative asset and liability recorded on the balance sheet. Our outstanding derivative contracts will settle from January 2009 to March 2011 corresponding to when Advantage will receive revenues from production. Royalties Three months ended Year ended December 31 December 31 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- Royalties ($000) $ 23,338 $ 27,099 (14)% $146,349 $ 98,614 48% per boe $ 8.05 $ 8.58 (6)% $ 12.39 $ 9.02 37% As a percentage of revenue, excluding hedging 17.2% 16.9% 0.3% 19.0% 18.3% 0.7% 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 the year have increased in total due to the increase in revenue from higher production and commodity prices. However, total royalties for the fourth quarter have decreased as both production and prices are lower as compared to the same quarter of 2007. Royalties as a percentage of revenue, excluding hedging, have modestly increased as higher prices generally attract a higher royalty rate. Royalty rates are dependent on prices and individual well production levels such that average royalty rates will vary as the nature of our properties change through ongoing development activities and acquisitions. Our royalty rate for the fourth quarter of 2008 was slightly lower than expected due to the recognition of several royalty credits during the period. We expect the royalty rate to be in the range of 18% to 20% for 2009 given current commodity prices and the Fund's production levels. The Alberta Provincial Government implemented a new royalty framework for conventional oil, natural gas and oil sands 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. Lower rate natural gas wells will see a benefit of lower royalties while conventional oil will be subject to an increase in royalties that 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, the impact may not be significant based on our current production and the current commodity price environment. Advantage 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. On March 3, 2009, the Alberta Government released a three-part incentive program aimed to stimulate new economic activity. The first part of the plan includes a one-year drilling royalty credit of $200 per metre drilled based on a sliding scale dependant on 2008 corporate production in the Province of Alberta. The second part of the plan includes a one-year new well incentive program which offers a maximum five percent royalty rate for the first year of production from new oil or gas wells. Lastly, to encourage the clean-up of inactive oil and gas wells, the province will invest $30 million in a fund committed to abandoning and reclaiming oil well sites. We are currently evaluating the program and our initial assessment is that Advantage will realize financial benefits from the drilling incentive and reduced royalty rate. Operating Costs Three months ended Year ended December 31 December 31 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- Operating costs ($000) $ 42,673 $ 39,330 8% $164,091 $127,309 29% per boe $ 14.71 $ 12.46 18% $ 13.89 $ 11.64 19% Total operating costs increased 29% for the year ended December 31, 2008 as compared to 2007 primarily due to increased production from the Sound acquisition, which closed September 5, 2007, and cost escalation driven by the strong oil and natural gas environment during the first half of 2008. Operating costs for the fourth quarter of 2008 were up just 4% from $41.2 million incurred in the third quarter of 2008 and 8% higher from the fourth quarter of 2007. Operating costs reflect a general industry increase which has continued despite recessionary pressures. Operating costs in the fourth quarter are 6% higher than the $13.82 realized during the third quarter of 2008. Fourth quarter operating costs per boe were higher primarily due to lower average quarterly production due primarily to freezing conditions experienced in December, increased third party processing fees, and higher property taxes than expected. We anticipate that operating costs in the latter half of 2009 will decrease as the slower economy will reduce the cost of services and supplies. We will continue to be opportunistic and proactive in pursuing optimization initiatives that will improve our operating cost structure. In 2009, the Fund entered into fixed price power hedges commencing March 2009 and continuing to December 2009. Under these arrangements, 2.0 MW have been hedged at an average fixed price of $69.38/MWh. We expect that operating costs will be in the range of $13.95 to $14.45 per boe for 2009; however, this will be impacted by the magnitude of our asset disposition program. General and Administrative Three months ended Year ended December 31 December 31 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- General and administrative expense ($000) $ 3,198 $ 7,173 (55)% $ 22,493 $ 21,449 5% per boe $ 1.10 $ 2.27 (51)% $ 1.90 $ 1.96 (3)% Employees at December 31 176 172 2% Total general and administrative ("G&A") expense has decreased 55% for the three months ended and increased 5% for the year ended December 31, 2008. The higher total G&A expense for the year has been primarily due to an increase in average staff levels that have resulted from the Sound acquisition, general growth of the Fund, and a one-time payment to terminate an office lease that occurred in the first quarter of 2008. G&A was lower in the fourth quarter of 2008 as compared to the same quarter of 2007 due to several large nonrecurring expenditures that were recognized in the 2007 period. 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. The purpose of the long-term compensation plan 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. If the Trust Unit return for a year is positive, an RTU grant will be calculated based on the return and market capitalization. If the Trust Unit return for a year is negative, but the return is still within the top two-thirds of the approved peer group performance, the Board of Directors may choose a discretionary RTU grant. 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 beginning at the grant date and incorporates the Trust Unit grant 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. For 2008, although Advantage experienced a negative return for the year, the approved peer group also experienced likewise negative returns. As a result, Advantage's 2008 annual return was within the top two-thirds of the approved peer group and the Board of Directors granted an RTU at their discretion. The RTU was deemed to be granted at January 15, 2009 and was valued at $3.8 million to be issued in Trust Units at $5.49 per Trust Unit. No compensation expense was included in general and administration expense for the year ended December 31, 2008 as the RTU was granted after year-end. A total of 171,093 Trust Units were issued to employees in early 2009 in satisfaction of the first third of the grant that vested immediately. The remaining two-thirds of the RTU grant will vest evenly on the following two yearly anniversary dates. Since implementing the Plan in 2006, the grant thresholds have not been previously met, and there have been no RTU grants made during prior years and no related compensation expense has been recognized. Management Internalization Three months ended Year ended December 31 December 31 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- Management internalization ($000) $ 916 $ 2,534 (64)% $ 6,964 $ 15,708 (56)% per boe $ 0.32 $ 0.80 (60)% $ 0.59 $ 1.44 (59)% In 2006, the Fund and Advantage Investment Management Ltd. (the "Manager") reached an agreement to internalize the pre-existing 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 three months and year ended December 31, 2008 as one third vested and was paid in June 2007 with an additional one third vested and paid in June 2008. Interest on Bank Indebtedness Three months ended Year ended December 31 December 31 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- Interest expense ($000) $ 6,430 $ 7,917 (19)% $ 27,893 $ 24,351 15% per boe $ 2.22 $ 2.51 (12)% $ 2.36 $ 2.23 6% Average effective interest rate 4.5% 6.2% (1.7)% 5.0% 5.7% (0.7)% Bank indebtedness at December 31 ($000) $587,404 $547,426 7% Interest expense in total and per boe for the full year 2008 has increased modestly as compared to 2007 primarily due to the additional debt assumed by the Fund from the Sound acquisition on September 5, 2007. However, interest expense in total and per boe for the three months ended December 31, 2008 have decreased as compared to the same period of 2007 as a result of declining interest rates in the fourth quarter. Bank lending rates have declined significantly in response to rate reductions enacted by central banks to stimulate the economy. We monitor the debt level to ensure an optimal mix of financing and cost of capital that will provide a maximum return to our Unitholders. Our current credit facilities have been a favorable financing alternative with an effective interest rate of only 5.0% for the year ended December 31, 2008. 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 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- Interest on convertible debentures ($000) $ 4,080 $ 4,426 (8)% $ 16,627 $ 14,867 12% per boe $ 1.41 $ 1.40 1% $ 1.41 $ 1.36 4% Accretion on convertible debentures ($000) $ 703 $ 721 (2)% $ 2,855 $ 2,569 11% per boe $ 0.24 $ 0.23 4% $ 0.24 $ 0.23 4% Convertible debentures maturity value at December 31 ($000) $219,195 $224,612 (2)% Interest and accretion on convertible debentures has increased for the year ended December 31, 2008 compared to 2007 due to Advantage assuming Sound's 8.75% and 8.00% convertible debentures on the acquisition. The increased interest and accretion from the additional debentures has been partially offset by the maturation of both the 10% convertible debentures with a face value of $1.4 million on November 1, 2007 and the 9% convertible debentures with a face value of $5.4 million on August 1, 2008. These debenture maturities have resulted in lower total interest and accretion for the three months ended December 31, 2008 as compared to the same period of 2007. Depletion, Depreciation and Accretion Three months ended Year ended December 31 December 31 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- Depletion, depreciation and accretion ($000) $ 72,100 $ 78,149 (8)% $302,104 $272,175 11% per boe $ 24.86 $ 24.75 0% $ 25.58 $ 24.89 3% Depletion and depreciation of property and equipment 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 in total for the year ended December 31, 2008 compared to the same period of 2007, due to the increase in production and fixed assets, mainly attributed to the Sound acquisition and our ongoing capital development program. The slight increase in the DD&A rate per boe for this period is due to high capital expenditures in 2008 and the higher value assigned to the Sound acquisition than accumulated from prior development activities. The total DD&A provision for the three months ended December 31, 2008 is less than the same period of 2007, because of lower production. The D&D rate per boe in the fourth quarter was comparable to 2007. Goodwill The Fund frequently assesses goodwill impairment which is effectively a comparison of the fair value of the Fund to the values assigned to the identifiable assets and liabilities. The fair value of the Fund is typically determined by reference to the market capitalization adjusted for a number of potential valuation factors. The values of the identifiable assets and liabilities include the current assessed value of our reserves and other assets and liabilities. Near the end of 2008, Advantage and the entire oil and gas industry, experienced a substantial decline in market capitalization as a result of the worldwide recession, resulting soft commodity prices, and general negative market reaction. As a result, the entire $120.3 million balance of goodwill was determined to be impaired at December 31, 2008, as there is no market perception of goodwill. Taxes Current taxes paid or payable for the quarter ended December 31, 2008 amounted to $0.1 million, comparable to the $0.5 million expensed for the same period of 2007. The higher current taxes for the year 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, 2008, the Fund recognized a future income tax reduction of $10.8 million compared to $24.6 million for 2007. 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 has been reflected in both 2008 and 2007 and resulted in an additional future income tax expense of $Nil (2007 - $42.9 million). As at December 31, 2008, we had a future income tax liability balance of $55.9 million, compared to $66.7 million at December 31, 2007. 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. During the year ended December 31, 2007, Advantage recorded a future tax liability of $29.4 million with the acquisition of Sound. 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 $1.8 billion in tax pools and deductions at December 31, 2008, which can be used to reduce the amount of taxes paid by Advantage. The Fund and Advantage Oil & Gas Ltd. ("AOG") had the following estimated tax pools in place at December 31, 2008: December 31, 2008 Estimated Tax Pools ($ millions) ---------- Undepreciated Capital Cost $ 658 Canadian Oil and Gas Property Expenses 444 Canadian Development Expenses 555 Canadian Exploration Expenses 67 Non-capital losses 75 Other 16 ---------- $ 1,815 ---------- ---------- Net Income (Loss) Three months ended Year ended December 31 December 31 2008 2007 % change 2008 2007 % change ------------------------------------------------------------------------- Net income (loss) ($000) $(95,477) $ 13,795 (792)% $(20,577) $ (7,535) 173% per Trust Unit - Basic $ (0.67) $ 0.10 (775)% $ (0.15) $ (0.06) 146% - Diluted $ (0.67) $ 0.10 (775)% $ (0.15) $ (0.06) 146% Advantage experienced a net loss for the three months and year ended December 31, 2008 primarily due to a $120.3 million impairment of goodwill. Excluding this one-time non-cash item, Advantage had net income of $99.7 million for 2008, delivering significant financial results. For the full year, we experienced considerably higher revenues from increased production and average commodity prices. This was partially offset by some higher expenses, including operating costs, depletion and depreciation. Although overall Advantage had a successful year, the fourth quarter began to show strains from the sudden drop in commodity prices that reduced revenues and negatively impacted net income. Commodity prices have continued to worsen in 2009, presenting a significant challenge for the entire oil and gas industry. We expect this situation to have a wide-ranging impact on the sector for the coming year. Net loss for the quarter and year also included unrealized derivative gains of $34.0 million and $38.8 million, respectively, from the low commodity price environment (see "Commodity Price Risk" section). The unrealized amounts are not cash and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices. The Fund does not apply hedge accounting and current accounting standards require changes in the fair value to be included in the consolidated statement of loss and comprehensive loss as an unrealized derivative gain or loss with a corresponding derivative asset and liability recorded on the balance sheet. These derivative contracts currently outstanding will settle from January 2009 to March 2011 corresponding to when Advantage will receive revenues from production. Cash Netbacks Three months ended December 31 2008 2007 $000 per boe $000 per boe ------------------------------------------------------------------------- Revenue $ 135,732 $ 46.79 $ 160,741 $ 50.91 Realized gain (loss) on derivatives 13,473 4.64 5,210 1.65 Royalties (23,338) (8.05) (27,099) (8.58) Operating costs (42,673) (14.71) (39,330) (12.46) ------------------------------------------------------------------------- Operating $ 83,194 $ 28.67 $ 99,522 $ 31.52 General and administrative(1) (3,198) (1.10) (7,029) (2.23) Interest (6,430) (2.22) (7,917) (2.51) Interest on convertible debentures(2) (4,080) (1.41) (3,536) (1.12) Income and capital taxes (116) (0.04) (521) (0.16) ------------------------------------------------------------------------- Funds from operations $ 69,370 $ 23.90 $ 80,519 $ 25.50 ------------------------------------------------------------------------- Year ended December 31 2008 2007 $000 per boe $000 per boe ------------------------------------------------------------------------- Revenue $ 769,401 $ 65.14 $ 538,764 $ 49.27 Realized gain (loss) on derivatives (27,439) (2.32) 18,594 1.70 Royalties (146,349) (12.39) (98,614) (9.02) Operating costs (164,091) (13.89) (127,309) (11.64) ------------------------------------------------------------------------- Operating $ 431,522 $ 36.54 $ 331,435 $ 30.31 General and administrative(1) (23,422) (1.98) (20,520) (1.88) Interest (27,893) (2.36) (24,351) (2.23) Interest on convertible debentures(2) (16,627) (1.41) (13,977) (1.28) Income and capital taxes (2,493) (0.21) (1,444) (0.13) ------------------------------------------------------------------------- Funds from operations $ 361,087 $ 30.58 $ 271,143 $ 24.79 ------------------------------------------------------------------------- (1) General and administrative expense excludes non-cash unit-based compensation expense. (2) Interest on convertible debentures excludes non-cash accretion expense and interest expense. Funds from operations and cash netbacks increased in total and per boe for the year ended December 31, 2008, compared to 2007, due primarily to additional production from the Sound acquisition and higher average commodity prices through the first three quarters of 2008. Increased cash netbacks per boe for the year ended December 31, 2008 were partially offset by realized losses on derivatives, and increased operating expenses and royalties. Realized hedging losses resulted from the higher commodity price environment as the Fund entered derivative contracts to lessen commodity price fluctuations, which can positively or negatively impact cash flows. Operating costs increased during 2008 due to significantly higher field costs associated with a general industry escalation and higher relative operating costs from the Sound acquisition. Royalties also increased as would be expected since they are generally based on current commodity prices. Funds from operations and cash netbacks per boe for the three months ended December 31, 2008 decreased from the same period of 2007, a direct result of the commodity price drops that occurred in the fourth quarter of 2008 as the financial crisis deepened into a global recession. The decrease in commodity prices was significantly offset by realized gains on derivatives during the period. Operating costs per boe were higher for the three months ended December 31, 2008 due to early cold weather conditions that increased some operating costs and lowered corresponding production volumes. However, we expect to see some easing of operating costs in 2009 as the poor economic environment continues to have an impact on the service sector. 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 2009 2010 2011 2012 ------------------------------------------------------------------------- Building leases $ 10.3 $ 3.8 $ 3.9 $ 1.5 $ 1.1 Capital leases 6.2 2.1 2.2 1.9 - Pipeline/transportation 4.9 3.2 1.4 0.3 - Convertible debentures (1) 219.2 87.0 69.9 62.3 - ------------------------------------------------------------------------- Total contractual obligations $ 240.6 $ 96.1 $ 77.4 $ 66.0 $ 1.1 ------------------------------------------------------------------------- (1) As at December 31, 2008, Advantage had $219.2 million convertible debentures outstanding (excluding interest payable during the various debenture terms). Each series of convertible debentures are convertible to Trust Units based on an established conversion price. All remaining obligations related to convertible debentures can be settled through the payment of cash or issuance of Trust Units at Advantage's option. (2) Bank indebtedness of $587.4 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, 2008 ------------------------------------------------------------------------- Bank indebtedness (long-term) $ 587,404 Working capital deficit(1) 146,397 ------------------------------------------------------------------------- Net debt $ 733,801 ------------------------------------------------------------------------- Trust Units outstanding (000) 142,825 Trust Units closing market price ($/Trust Unit) $ 5.12 ------------------------------------------------------------------------- Market value $ 731,263 ------------------------------------------------------------------------- Convertible debentures maturity value (long-term) $ 132,221 Capital lease obligation (long term) 3,906 ------------------------------------------------------------------------- Total capitalization $1,601,191 ------------------------------------------------------------------------- (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. Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Fund is composed of working capital (excluding derivative assets and liabilities), bank indebtedness, convertible debentures, capital lease obligations and Unitholders' equity. Advantage may manage its capital structure by issuing new Trust Units, obtaining additional financing either through bank indebtedness or convertible debenture issuances, refinancing current debt, issuing other financial or equity-based instruments, adjusting or discontinuing the amount of monthly distributions, suspending or renewing its distribution reinvestment plan, adjusting capital spending, or disposing of assets. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis. In late 2008, a financial crisis materialized which has now turned into a full global recession. This situation has significantly impacted the ability to raise capital. Despite this situation, the Fund continues to generate funds from operations sufficient to fund our operations and a reduced capital program. Management of the Fund's capital structure is facilitated through its financial and operational forecasting processes. The forecast of the Fund's future cash flows is based on estimates of production, commodity prices, forecast capital and operating expenditures, and other investing and financing activities. The forecast is regularly updated based on new commodity prices and other changes, which the Fund views as critical in the current environment. Selected forecast information is frequently provided to the Board of Directors. This continual financial assessment process further enables the Fund to mitigate risks. The Fund continues to satisfy all liabilities and commitments as they come due. We have an established $710 million credit facility agreement with a syndicate of financial institutions; the balance of which utilized at December 31, 2008 was $587 million. This facility will be subject for renewal again in June 2009. The Fund additionally has several convertible debentures that will mature in 2009, whereby we have the option to settle such obligations by cash or though the issuance of Trust Units. Management has budgeted for a capital program of $100 to $130 million for fiscal 2009, as it is important to bring on additional production to offset natural reserve declines and to grow the Fund. Management has significantly reduced the capital program from 2008 and will continually monitor our capital expenditures and make adjustments as needed in order to remain self-sufficient within our funds from operations through the foreseeable future. The current economic situation has also placed additional pressure on commodity prices. Crude oil has dropped from a historic high to approximately US$47/bbl. The impact from the decrease in WTI will be somewhat mitigated for Advantage due to the strengthening US dollar relative to the Canadian dollar. Natural gas prices that had been improving early in 2008, have now started to decline due to the ailing economy as well as increased inventory levels from strong injections and mild weather. Natural gas has dropped to approximately CAD$3.80/GJ. The net effect for the Fund from prolonged weak commodity prices would be reductions in operating netbacks and funds from operations. Management has partially mitigated this risk through our commodity hedging program but the lower commodity price environment has still had a significant negative impact. In order to strengthen our financial position and balance our cash flows, the monthly distribution has been discontinued to repay debt and focus capital spending on our Montney natural gas resource play. To summarize, we have implemented a strategy to maximize self sufficiency such that funds from operations will satisfy our capital program, reduce debt, and meet other expenditure requirements. We do not anticipate any problems satisfying obligations as they become due. A successful hedging program was also executed to help protect our funds from operations. As a result, we feel that Advantage has implemented adequate strategies to protect our business as much as possible in this environment. However, as with all companies, we are still exposed to risks as a result of the current economic situation and the potential duration. We continue to closely monitor the possible impact on our business and strategy, and will make adjustments as necessary with prudent management. 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, 2008, the Fund had 142.8 million Trust Units outstanding. During the year ended December 31, 2008, 4,414,830 Trust Units were issued as a result of the Premium Distribution(TM), Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan"), generating $39.9 million reinvested in the Fund and representing an approximate 20% participation rate (for the year ended December 31, 2007, 4,028,252 Trust Units were issued under the Plan, generating $46.7 million reinvested in the Fund and representing an approximate 18% participation rate). As at March 18, 2009, Advantage had 145.2 million Trust Units issued and outstanding. At December 31, 2008, the Fund had $219.2 million convertible debentures outstanding that were immediately convertible to 9.5 million Trust Units based on the applicable conversion prices (December 31, 2007 - $224.6 million outstanding and convertible to 9.8 million Trust Units). During the year ended December 31, 2008, $25,000 debentures were converted resulting in the issuance of 1,001 Trust Units and the 9.00% debentures matured on August 1, 2008, resulting in a cash payment of $5,392,000 to the debenture holders. As at March 18, 2009, the Fund had $214.3 million convertible debentures outstanding, after the remaining $4.9 million 8.25% debentures matured on February 1, 2009 and were settled through the issuance of 946,887 Trust Units. We have $29.8 million of 8.75% debentures that will mature on June 30, 2009 and $52.3 million of 7.50% debentures that mature on October 1, 2009. These obligations can be settled through the payment of cash or issuance of Trust Units at Advantage's option. Advantage has a Trust Units Rights Incentive Plan for external directors as approved by the Unitholders of the Fund. A total of 500,000 Trust Units were 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 2008, all remaining 150,000 outstanding rights were exercised at $8.60 per right for total cash proceeds of $1,290,000. No Trust Unit Rights were outstanding as of December 31, 2008. As a result of the 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 a result of the "normal growth" guidelines, the Fund is permitted to issue approximately $2.3 billion of new equity from January 1, 2009 to January 1, 2011, which we believe is adequate for any growth we expect to incur. On January 20, 2009, the Fund adopted a Unitholder Rights Agreement (the "Agreement") for which Unitholder approval will be sought at the Fund's next annual meeting of Unitholders. Under the terms of the Agreement, Unitholders will be granted one right per unit. Each right entitles the holder to purchase a Trust Unit from treasury at a specified exercise price in the event of an unsolicited take-over bid for the Fund. The purpose of the Agreement is to allow Unitholders and the Board adequate time to consider and evaluate any unsolicited bid made for the Fund, to provide the Board with adequate time to identify, develop and negotiate value-enhancing alternatives, if considered appropriate, to any such unsolicited bid, to encourage the fair treatment of Unitholders in connection with any take-over bid for the Fund and to ensure that any proposed transaction is in the best interests of the Unitholders of the Fund. The Agreement is similar to other rights plans adopted by many Canadian income trusts and corporations. The Rights Plan is not triggered if an offer to acquire Fund Trust Units is made as a "permited bid" and thereby allows sufficient time for the Board and Unitholders to consider and react to the offer. Bank Indebtedness, Credit Facility and Other Obligations At December 31, 2008, Advantage had bank indebtedness outstanding of $587.4 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 collateralized 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. As well, the borrowing base for the Fund's credit facilities is determined through utilizing our regular reserve estimates. The banking syndicate thoroughly evaluates the reserve estimates based upon their own commodity price expectations to determine the amount of the borrowing base. Revision or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing base of the Fund. In June 2008, the Fund renewed its credit facilities for a further year with the next annual review scheduled to occur in June 2009. There can be no assurances that the $710 million credit facility will be renewed at the current borrowing base level given the present commodity price environment. On March 18, 2009, we announced our intention to dispose of certain assets. The net proceeds from these sales or other oil and natural gas property sales will initially be used to reduce our outstanding bank debt to improve Advantage's financial flexibility. Advantage had a working capital deficiency of $146.4 million as at December 31, 2008. 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. 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. 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. The increase in our working capital deficiency at December 31, 2008 is due to the additional inclusion of $87 million in principal amount of convertible debentures that mature during 2009 and are classified as a current liability. The $4.9 million principal amount 8.25% debentures matured on February 1, 2009 and were settled through the issuance of 946,887 Trust Units. We have $29.8 million of 8.75% debentures that will mature on June 30, 2009 and $52.3 million of 7.50% debentures that mature on October 1, 2009. These obligations can be settled through the payment of cash or issuance of Trust Units at Advantage's option. Advantage has capital lease obligations on various pieces of equipment used in its operations. The total amount of principal obligation outstanding at December 31, 2008 is $5.7 million, bearing interest at effective rates ranging from 5.5% to 6.7%, and is collateralized by the related equipment. The leases expire at dates ranging from December 2009 to August 2010. Capital Expenditures Three months ended Year ended December 31 December 31 ($000) 2008 2007 2008 2007 ------------------------------------------------------------------------- Land and seismic $ 13,039 $ 64 $ 22,532 $ 3,270 Drilling, completions and workovers 49,833 30,020 140,019 94,786 Well equipping and facilities 36,242 9,971 92,016 48,296 Other 198 878 1,024 2,373 ------------------------------------------------------------------------- $ 99,312 $ 40,933 $ 255,591 $ 148,725 Acquisition of Sound Energy Trust - (67) - 22,307 Property acquisitions - 3,200 7,621 16,051 Property dispositions (850) (610) (941) (1,037) ------------------------------------------------------------------------- Total capital expenditures $ 98,462 $ 43,456 $ 262,271 $ 186,046 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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. 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, 2008, the Fund spent a net $99.3 million. Total capital spending in the quarter included $66.4 million at Glacier, $9.4 million at Nevis, $5.8 million at Willesden Green, and $1.6 million at Chip Lake. For the year ended December 31, 2008, the Fund spent a net $255.6 million and drilled a total of 86.8 net (124 gross) wells at a 99% success rate. Total capital spending for the year included $101.7 million at Glacier, $49.6 million at Nevis, $17.2 million at Martin Creek, $15.1 million at Willesden, $9.4 million at Sousa, and $8.1 million at Chip Lake. During 2008, we commenced a significant development drilling program on our Montney natural gas resource play in Glacier, Alberta. Our investment at Glacier considerably increased reserves and confirmed horizontal well rates of 2.5 to 7.5 mmcf/d (417 to 1,250 boe/d). At Nevis, continued light oil drilling in the Wabamun formation extended the field and resulted in numerous wells with initial production exceeding 200 boe/day. A 35 gross (27 net) well Horseshoe Canyon coal bed methane drilling program in 2008 also confirmed several more phases of future drilling. At Nevis, a total of 47 gross (38.8 net) wells were drilled at a 100% success rate and added 2,980 boe/day of initial production. At Martin Creek, our successful 10 well gross (8 net) drilling program in early 2008 added 1,490 boe/day of initial production. At Willesden Green, a new light oil pool was discovered with the drilling of 2 gross (2 net) wells with initial combined production of 800 boe/day. In addition, 3 gross (3 net) wells were successfully drilled for liquids rich natural gas production from the Rock Creek formation. At Northville, Brazeau and Youngstown, 6 gross (4.3 net) wells were successfully drilled adding additional reserves and defined additional drilling locations. Property acquisitions year to date include a $7.6 million property acquisition closed in the third quarter which increased our working interest ownership and drilling inventory in the Horseshoe Canyon coal bed methane lands at Nevis. On December 18, 2008, the Board approved budgeted capital expenditures for 2009 in the range of $100 to $130 million. This is down from 2008 as we feel a conservative approach is appropriate in the current economic climate, where commodity prices are depressed and available financing is limited. The capital spending will be primarily directed towards drilling, infrastructure and strategic investments in our Montney natural gas resource play at Glacier in Northwest Alberta. We will continue to evaluate and adjust our 2009 capital program as the year progresses. Sources and Uses of Funds The following table summarizes the various funding requirements during the year ended December 31, 2008 and 2007 and the sources of funding to meet those requirements: Year ended December 31 ($000) 2008 2007 ------------------------------------------------------------------------- Sources of funds Funds from operations $ 361,087 $ 271,143 Increase in bank indebtedness 39,978 28,893 Decrease in working capital 38,070 - Units issued, net of costs 1,248 104,215 Property dispositions 941 1,037 ------------------------------------------------------------------------- $ 441,324 $ 405,288 ------------------------------------------------------------------------- Uses of funds Expenditures on property and equipment $ 255,591 $ 148,725 Distributions to Unitholders 161,924 170,915 Expenditures on asset retirement 9,259 6,951 Property acquisitions 7,621 16,051 Convertible debenture repayment 5,392 - Reduction of capital lease obligations 1,537 3,184 Acquisition of Sound Energy Trust - 22,307 Debentures redeemed - 19,406 Increase in working capital - 17,749 ------------------------------------------------------------------------- $ 441,324 $ 405,288 ------------------------------------------------------------------------- The Fund generated higher funds from operations during 2008 compared to 2007 due to higher production levels and a stronger average commodity price environment that prevailed through the first three quarters of the year. As a result, the Fund was able to adequately finance its capital expenditures and distributions to Unitholders. However, given the current economy and its effects on commodity prices, our bank indebtedness increased during the fourth quarter as a source of funds. We have been proactive in balancing our cash flows and reduced our distribution in December 2008 followed by a further reduction in January 2009 as commodity prices continued to erode. On March 18, 2009, we announced that our monthly distribution will be discontinued and future cash flow redirect to repay debt and focus capital on our Montney natural gas resource play. We will be closely monitoring our future sources and uses of funds. Annual Financial Information The following is a summary of selected financial information of the Fund for the years indicated. Year ended Year ended Year ended Dec. 31, Dec. 31, Dec. 31, 2008 2007 2006 ------------------------------------------------------------------------- Total revenue (before royalties) ($000) $ 741,962 $ 557,358 $ 419,727 Net income (loss) ($000) $ (20,577) $ (7,535) $ 49,814 per Trust Unit - Basic $ (0.15) $ (0.06) $ 0.62 - Diluted $ (0.15) $ (0.06) $ 0.61 Total assets ($000) $2,305,433 $2,422,280 $1,981,587 Long term financial liabilities ($000)(1) $ 721,198 $ 768,060 $ 581,698 Distributions declared per Trust Unit $ 1.40 $ 1.77 $ 2.66 (1) Long term financial liabilities exclude asset retirement obligations and future income taxes. Quarterly Performance 2008 ($000, except as otherwise indicated) Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Daily production Natural gas (mcf/d) 120,694 122,627 123,104 125,113 Crude oil and NGLs (bbls/d) 11,413 11,980 11,498 12,281 Total (boe/d) 31,529 32,418 32,015 33,133 Average prices Natural gas ($/mcf) Excluding hedging $ 7.15 $ 8.65 $ 10.33 $ 7.90 Including hedging $ 7.61 $ 7.55 $ 9.18 $ 8.23 AECO monthly index $ 6.79 $ 9.27 $ 9.35 $ 7.13 Crude oil and NGLs ($/bbl) Excluding hedging $ 53.65 $ 107.96 $ 110.15 $ 85.99 Including hedging $ 61.67 $ 100.02 $ 101.34 $ 84.83 WTI ($US/bbl) $ 58.75 $ 118.13 $ 124.00 $ 97.96 Total revenues (before royalties) $ 149,205 $ 195,384 $ 208,868 $ 188,505 Net income (loss) $ (95,477) $ 113,391 $ (14,369) $ (24,122) per Trust Unit - basic $ (0.67) $ 0.81 $ (0.10) $ (0.18) - diluted $ (0.67) $ 0.79 $ (0.10) $ (0.18) Funds from operations $ 69,370 $ 93,345 $ 103,754 $ 94,618 Distributions declared $ 45,514 $ 50,743 $ 50,364 $ 50,021 2007 ($000, except as otherwise indicated) Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Daily production Natural gas (mcf/d) 128,556 115,991 108,978 114,324 Crude oil and NGLs (bbls/d) 12,895 10,014 8,952 9,958 Total (boe/d) 34,321 29,346 27,115 29,012 Average prices Natural gas ($/mcf) Excluding hedging $ 6.23 $ 5.62 $ 7.54 $ 7.61 Including hedging $ 6.97 $ 6.35 $ 7.52 $ 8.06 AECO monthly index $ 6.00 $ 5.62 $ 7.37 $ 7.46 Crude oil and NGLs ($/bbl) Excluding hedging $ 73.40 $ 69.03 $ 61.84 $ 56.84 Including hedging $ 70.40 $ 68.51 $ 61.93 $ 58.64 WTI ($US/bbl) $ 90.63 $ 75.33 $ 65.02 $ 58.12 Total revenues (before royalties) $ 165,951 $ 130,830 $ 125,075 $ 135,502 Net income (loss) $ 13,795 $ (26,202) $ 4,531 $ 341 per Trust Unit - basic $ 0.10 $ (0.22) $ 0.04 $ 0.00 - diluted $ 0.10 $ (0.22) $ 0.04 $ 0.00 Funds from operations $ 80,519 $ 62,345 $ 62,634 $ 65,645 Distributions declared $ 57,875 $ 55,017 $ 52,096 $ 50,206 The table above highlights the Fund's performance for the fourth quarter of 2008 and also for the preceding seven quarters. Production during the 2006/2007 winter was steady until we experienced a decrease in the second quarter of 2007 due to several facility turnarounds at that time. The Sound acquisition closed on September 5, 2007, and significantly increased production for the third and fourth quarters of 2007. Production has gradually decreased through the first half of 2008 due to natural declines, wet and cold weather delays, and facility turnarounds. Production increased modestly in the third quarter of 2008 as new wells were brought on production and most facility turnarounds were completed. During the fourth quarter, production again decreased as we experienced freezing conditions from early cold weather as well as an extended third party facility outage. Financial results, particularly revenues and funds from operations, have increased through to the second quarter of 2008, as both commodity prices and production steadily increased over that timeframe. However, revenues and funds from operations slightly declined in the third quarter of 2008, as commodity prices began to decline in response to the financial crisis that materialized in the fall of 2008. This trend worsened in the fourth quarter, as a full global recession set in, and commodity prices continued on a downward trend. We experienced a net loss in the third quarter of 2007 due to a significant drop in natural gas prices realized at that time, amortization of the management internalization consideration and increased depletion and depreciation expense. Net income increased in the fourth quarter of 2007 due to the full integration of the Sound acquisition and moderately improved commodity prices. Net losses were realized in the first and second quarters of 2008, primarily as a result of significant unrealized losses on commodity derivative contracts for future periods. Commodity price declines in the third quarter of 2008 gave rise to significant unrealized gains on these same derivative contracts, and in turn the Fund reported record high net income. We recognized a considerable net loss in the fourth quarter of 2008, a combined result of falling commodity prices and an impairment of our entire goodwill. 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 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. In accordance with GAAP, derivative assets and liabilities are recorded at their fair values at the reporting date, with unrealized gains and losses recognized directly into net income and comprehensive income in the same period. The fair value of derivatives outstanding is an estimate based on pricing models, estimates, assumptions and market data available at that time. As such, the unrealized amounts are not cash and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. International Financial Reporting Standards ("IFRS") In February 2008, the Accounting Standards Board of the Canadian Institute of Chartered Accountants confirmed that publicly accountable entities will be required to adopt IFRS effective January 1, 2011, including preparation of comparative financial information. Management has engaged its key personnel responsible for financial reporting and developed an overall plan to address IFRS implementation. The initial stage of the plan involved staff training and ongoing education. Key personnel received professional education on IFRS accounting principles and standards, both in general and for the oil and gas industry in particular. Review of changes to IFRS has been incorporated into existing processes of internal control over financial reporting. A preliminary project plan for IFRS implementation has been drafted and will be subject to ongoing revision as there are developments. As well, appropriate operating personnel have been engaged, as necessary, to determine how to implement the requirements of IFRS into the Fund's manual and information systems that collect and process financial data. We expect to have continual discussion with our external auditors throughout the process regarding IFRS and implementation. The most significant change identified will be accounting for property, plant and equipment. The Fund, like many Canadian oil and gas reporting issuers, applies the "full cost" concept in accounting for its oil and gas assets. Under full cost, capital expenditures are maintained in a single cost centre for each country, and the cost centre is subject to a single depletion calculation and impairment test. IFRS will require the Fund to make a much more detailed assessment of its oil and gas property, plant and equipment. For depletion and depreciation, the Fund must identify asset components, and determine an appropriate depreciation or depletion method for each component. With regards to impairment calculation purposes, we must be identify "Cash Generating Units", which are defined as the smallest group of assets that produces independent cash flows. An impairment test must be performed individually for all cash generating units. The recognition of impairments in a prior year can be reversed subsequently depending on such calculations. It is also important to note that the International Accounting Standards Board ("IASB") is currently undertaking an extractive industries project, to develop accounting standards specifically for businesses like that of the Fund. However, the project will not be complete prior to IFRS adoption in Canada. We have also identified a number of other areas whereby differences between Canadian GAAP and IFRS are likely to exist for Advantage. However, currently we are concentrating on the accounting for property, plant and equipment and will evaluate these other areas in due course and develop more detailed plans to address the identified issues. 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 President 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. Evaluation of Disclosure Controls and Procedures The Fund has established a Disclosure Committee consisting of the executive members with the responsibility of overseeing the Fund's disclosure practices and designing disclosure controls and procedures ("DCP"), as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, to provide reasonable assurance that information required to be disclosed by the Fund in its annual filings, interim filings or other reports filed or submitted by the Fund under applicable securities legislation is recorded, processed, summarized and reported within the time periods specified in applicable securities legislation and that all material information relating to the Fund is made known to them by others, particularly during the period in which the Fund's annual and interim filings are being prepared. 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 ("ICFR"), as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. Management of Advantage, including our Chief Executive Officer and President and Chief Financial Officer, has evaluated the effectiveness of the design and operation of the disclosure controls and procedures as of December 31, 2008. 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 President 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. Management's Report on Internal Controls over Financial Reporting The Fund is responsible for establishing and maintaining adequate internal control over financial reporting. The Fund's internal control over financial reporting is a process designed, under the supervision and with the participation of executive and financial officers of the Fund, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Fund's financial statements for external reporting purposes in accordance with GAAP. The Fund's internal control over financial reporting includes policies and procedures that: 1. pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of the Fund; 2. provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP; and 3. provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Fund's assets that could have a material effect on the financial statements. The Fund's internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, 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 deterioration in the degree of compliance with the Fund's policies and procedures. The Fund's management assessed the design and effectiveness of the internal control over financial reporting as of December 31, 2008, based on the framework established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the Fund maintained effective internal control over financial reporting as of December 31, 2008. During the year ended December 31, 2008, there has been no change in the Fund's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Fund's internal control over financial reporting. 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 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 eleven members, eight of whom are unrelated to the Fund. The Independent Reserve Evaluation Committee has four members, the Audit Committee has five members, and the Human Resources, Compensation and Corporate Governance Committee has four members. All members of the various committees 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 http://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 2009 budget, as approved by the Board of Directors, is tailored to the current economic climate. Our natural gas resource play at Montney in Glacier, Northwest Alberta will be the largest area of focus. We reiterate that these are extremely uncertain times. Although the 2009 budget incorporates flexibility in its current form, management and the Board will review the budget continually, and adapt when necessary. Advantage's 2009 capital expenditures budget is estimated to be approximately $100 to $130 million. Capital spending is estimated to be allocated 46% to Montney, and 54% to other core areas. Given the low commodity price environment and increasing concerns with the economy, Advantage will target 2009 capital expenditures at the lower end of our guidance range. On March 18, 2009, we announced the intention to dispose of properties producing up to 11,300 boe/d of light oil and natural gas properties located in Northeast British Columbia, West Central Alberta and Northern Alberta. The net proceeds from these sales or other oil and natural gas property sales will initially be used to reduce outstanding bank debt to improve Advantage's financial flexibility. Proposals are anticipated by mid May 2009 and the selected assets will be available in four distinct packages varying in size from approximately 1,600 to 5,400 boe/d of production. Assuming asset sales of approximately 10,000 to 11,300 boe/d of production are completed, we expect production of approximately 20,000 to 22,000 boe/d from a focused asset base (60% natural gas, 40% oil and natural gas liquids). Industry supply, servicing and maintenance costs increased through the first three quarters of 2008 driven primarily from higher crude oil and natural gas prices. Also, there were significant increases from electrical power costs, processing fees, steel and chemicals. We expect to see some easing of operating costs as the lower commodity price environment is expected to remain for a sustained period. Per unit operating costs on an annual basis are expected to range between the $13.95 to $14.45/boe in 2009; however, this will be impacted by the magnitude of our asset disposition program. Advantage's funds from operations in 2009 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 2009 and 2010 to stabilize cash flows and ensure that the Fund's capital program is fully funded. Approximately 56% of our natural gas production, net of royalties, is now hedged for the 2009 calendar year at an average fixed price of $8.09/mcf. Advantage has also hedged 46% of its 2009 crude oil production, net of royalties, at an average floor price of $69.38/bbl. For 2010, we have hedged 48% of our natural gas production, net of royalties, at an average fixed price of $7.46/mcf and 26% of our crude oil production, net of royalties, at an average fixed price of $67.83/bbl. Advantage will 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. Our total drilling inventory in our Glacier Montney natural gas resource play has grown to over 440 confirmed drilling locations and we have significant additional conventional drilling locations. Looking forward, Advantage's high quality assets combined with a significant unconventional and conventional inventory, strong hedging program and excellent tax pools provides many options for the Fund to maximize 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 2009 excluding any impact from our asset disposition program. Annual Funds from Annual Operations Funds from per Operations Trust Unit ($000) ($/Trust Unit) ------------------------------------------------------------------------- Natural gas: AECO monthly price change of $1.00/mcf $ 16,900 $ 0.11 Production change of 6.0 mmcf/d $ 9,800 $ 0.06 Crude oil and NGLs: WTI price change of US$10.00/bbl $ 22,300 $ 0.14 Production change of 1,000 bbls/d $ 11,900 $ 0.07 $US/$Canadian exchange rate change of $0.01 $ 4,800 $ 0.03 Interest rate change of 1% $ 6,400 $ 0.04 Additional Information Additional information relating to Advantage can be found on SEDAR at http://www.sedar.com/ and the Fund's website at http://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. March 18, 2009 CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets December 31, December 31, (thousands of dollars) 2008 2007 ------------------------------------------------------------------------- Assets Current assets Accounts receivable $ 84,689 $ 95,474 Prepaid expenses and deposits 14,258 21,988 Derivative asset (note 13) 41,472 7,027 ------------------------------------------------------------------------- 140,419 124,489 Derivative asset (note 13) 1,148 174 Fixed assets (note 4) 2,163,866 2,177,346 Goodwill (note 5) - 120,271 ------------------------------------------------------------------------- $ 2,305,433 $ 2,422,280 ------------------------------------------------------------------------- Liabilities Current liabilities Accounts payable and accrued liabilities $ 146,046 $ 122,087 Distributions payable to Unitholders 11,426 16,592 Current portion of capital lease obligations (note 6) 1,747 1,537 Current portion of convertible debentures (note 7) 86,125 5,333 Derivative liability (note 13) 611 2,242 Future income taxes (note 10) 11,939 1,430 ------------------------------------------------------------------------- 257,894 149,221 Derivative liability (note 13) 1,039 2,778 Capital lease obligations (note 6) 3,906 5,653 Bank indebtedness (note 8) 587,404 547,426 Convertible debentures (note 7) 128,849 212,203 Asset retirement obligations (note 9) 73,852 60,835 Future income taxes (note 10) 43,976 65,297 ------------------------------------------------------------------------- 1,096,920 1,043,413 ------------------------------------------------------------------------- Unitholders' Equity Unitholders' capital (note 11) 2,075,877 2,027,065 Convertible debentures equity component (note 7) 9,403 9,632 Contributed surplus (note 11) 287 2,005 Accumulated deficit (note 12) (877,054) (659,835) ------------------------------------------------------------------------- 1,208,513 1,378,867 ------------------------------------------------------------------------- $ 2,305,433 $ 2,422,280 ------------------------------------------------------------------------- Commitments (note 16) Subsequent event (note 17) see accompanying Notes to Consolidated Financial Statements Consolidated Statements of Loss, Comprehensive Loss and Accumulated Deficit Year ended Year ended (thousands of dollars, except December 31, December 31, for per Trust Unit amounts) 2008 2007 ------------------------------------------------------------------------- Revenue Petroleum and natural gas $ 769,401 $ 538,764 Realized gain (loss) on derivatives (note 13) (27,439) 18,594 Unrealized gain (loss) on derivatives (note 13) 38,789 (11,049) Royalties (146,349) (98,614) ------------------------------------------------------------------------- 634,402 447,695 ------------------------------------------------------------------------- Expenses Operating 164,091 127,309 General and administrative 22,493 21,449 Management internalization (note 14) 6,964 15,708 Interest 27,893 24,351 Interest and accretion on convertible debentures 19,482 17,436 Depletion, depreciation and accretion 302,104 272,175 Impairment of goodwill (note 5) 120,271 - ------------------------------------------------------------------------- 663,298 478,428 ------------------------------------------------------------------------- Loss before taxes (28,896) (30,733) Future income tax reduction (note 10) (10,812) (24,642) Income and capital taxes (note 10) 2,493 1,444 ------------------------------------------------------------------------- (8,319) (23,198) ------------------------------------------------------------------------- Net loss and comprehensive loss (20,577) (7,535) Accumulated deficit, beginning of year (659,835) (437,106) Distributions declared (196,642) (215,194) ------------------------------------------------------------------------- Accumulated deficit, end of year $ (877,054) $ (659,835) ------------------------------------------------------------------------- Net loss per Trust Unit (note 11) Basic $ (0.15) $ (0.06) Diluted $ (0.15) $ (0.06) ------------------------------------------------------------------------- see accompanying Notes to Consolidated Financial Statements Consolidated Statements of Cash Flows Year ended Year ended December 31, December 31, (thousands of dollars) 2008 2007 ------------------------------------------------------------------------- Operating Activities Net loss $ (20,577) $ (7,535) Add (deduct) items not requiring cash: Unrealized loss (gain) on derivatives (38,789) 11,049 Unit-based compensation (929) 929 Management internalization 6,964 15,708 Non-cash interest expense - 890 Accretion on convertible debentures 2,855 2,569 Depletion, depreciation and accretion 302,104 272,175 Impairment of goodwill 120,271 - Future income tax recovery (10,812) (24,642) Expenditures on asset retirement (9,259) (6,951) Changes in non-cash working capital 22,922 (15,060) ------------------------------------------------------------------------- Cash provided by operating activities 374,750 249,132 ------------------------------------------------------------------------- Financing Activities Units issued, net of costs (note 11) 1,248 104,215 Increase in bank indebtedness 39,978 28,893 Convertible debenture repayment (note 7) (5,392) (19,406) Reduction of capital lease obligations (1,537) (3,184) Distributions to Unitholders (161,924) (170,915) ------------------------------------------------------------------------- Cash used in financing activities (127,627) (60,397) ------------------------------------------------------------------------- Investing Activities Expenditures on property and equipment (255,591) (148,725) Property acquisitions (7,621) (16,051) Property dispositions 941 1,037 Acquisition of Sound Energy Trust (note 3) - (22,307) Changes in non-cash working capital 15,148 (2,689) ------------------------------------------------------------------------- Cash used in investing activities (247,123) (188,735) ------------------------------------------------------------------------- Net change in cash - - Cash, beginning of year - - ------------------------------------------------------------------------- Cash, end of year $ - $ - ------------------------------------------------------------------------- Supplementary Cash Flow Information Interest paid $ 40,215 $ 42,017 Taxes paid $ 1,957 $ 2,062 see accompanying Notes to Consolidated Financial Statements NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2008 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 acquisitions 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. On March 18, 2009, Advantage announced its intention to convert to a growth oriented corporation and has discontinued the payment of distributions to focus on debt repayment and developing the Montney natural gas resource play (note 17). 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. (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. Under Canadian GAAP, 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. The Fund records leasehold improvements at cost and provides depreciation on the straight- line method over the term of the lease. (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. (d) Distributions Distributions declared are calculated on an accrual basis. (e) Financial instruments The Fund's financial instruments consist of financial assets, financial liabilities, and non-financial derivatives. All financial instruments are initially 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. 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 are classified as such by the Fund. As the Fund frequently uses 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. 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 loss, comprehensive loss 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 cash provided by operating activities as a result of their recognition. The Fund also evaluates whether any host contracts contain embedded derivatives, and records them separately from the host contract when their economic characteristics and risk 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 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. Such costs incurred on held for trading financial instruments are 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. (f) 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 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. (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 future income taxes. Under this method future income tax assets and liabilities are determined based on differences between the carrying value of an asset or liability and its tax basis using substantially enacted tax rates and laws expected to apply when the differences reverse. The effect a change in income tax rates has on future tax assets and liabilities is recognized in net income in the period in which the change is substantively 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 14), a unit-based compensation plan for external directors of the Fund, and a Restricted Trust Unit Plan (note 11). 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. If the Trust Unit return for a year is positive, an RTU grant will be calculated based on the return and market capitalization. If the Trust Unit return for a year is negative, but the return is still within the top two-thirds of the approved peer group performance, the Board of Directors may choose a discretionary RTU grant. 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 Trust Unit grant 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. (l) Per Trust Unit amounts Net loss per Trust Unit is calculated using the weighted average number of Trust Units outstanding during the year. Diluted net loss per Trust Unit is calculated using the "if-converted" method to determine the dilutive effect of convertible debentures and the "treasury stock" method for trust unit rights granted to directors, management internalization escrowed Trust Units and Restricted Trust Units. (m) Measurement uncertainty The amounts recorded for depletion and depreciation of fixed assets, 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) Capital disclosures Effective January 1, 2008, the Fund adopted CICA Handbook Section 1535, Capital Disclosures. This Section establishes standards for disclosing information about an entity's capital and how it is managed to enable users of financial statements to evaluate the entity's objectives, policies and procedures for managing capital. The adoption of this Section requires that information on capital management be included in the notes to the consolidated financial statements (see note 15). This new standard does not have any effect on the Fund's financial position or results of operations. (o) Recent accounting pronouncements issued but not implemented (i) Goodwill and intangible assets In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets, replacing Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The new Section will become effective January 1, 2009. Management has evaluated the new Section and there will be no impact for the financial statements of the Fund. (ii) International Financial Reporting Standards ("IFRS") In February 2008, the CICA Accounting Standards Board confirmed that IFRS will replace Canadian GAAP effective January 1, 2011 for publicly accountable enterprises. Management is currently evaluating the effects of all current and pending pronouncements of the International Accounting Standards Board on the financial statements of the Fund, and has developed a plan for implementation. (p) Comparative figures Certain comparative figures have been reclassified to conform to the current year's presentation. 3. Sound Energy Trust Acquisition 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 elected to receive either 0.30 Advantage Trust Units for each Sound Trust Unit or $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 was 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 Consideration: liabilities assumed: Fixed assets $ 514,060 16,977,184 Trust Accounts receivable 27,656 Units issued $ 228,852 Prepaid expenses and Cash 21,403 deposits 3,873 Acquisition costs Derivative asset, net 2,797 incurred 904 Bank indebtedness (107,959) ----------- Convertible debentures (101,553) $ 251,159 Accounts payable and ----------- accrued liabilities (40,023) Future income taxes (29,430) Asset retirement obligations (16,695) Capital lease obligations (1,567) ----------- $ 251,159 ----------- 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 in 2008 due to the realization of estimates. As a result, fixed assets increased $4.4 million, accounts receivable increased $0.2 million, and accounts payable and accrued liabilities increased $4.6 million. 4. Fixed Assets Accumulated Depletion and Net Book December 31, 2008 Cost Depreciation Value --------------------------------------------------------------------- Petroleum and natural gas properties $ 3,299,657 $ 1,140,710 $ 2,158,947 Furniture and equipment 11,572 6,653 4,919 --------------------------------------------------------------------- $ 3,311,229 $ 1,147,363 $ 2,163,866 --------------------------------------------------------------------- Accumulated Depletion and Net Book December 31, 2007 Cost 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 --------------------------------------------------------------------- During the year ended December 31, 2008, Advantage capitalized general and administrative expenditures directly related to exploration and development activities of $11,127,000 (2007 - $9,653,000). Costs of $68,267,000 (2007 - $60,238,000) for unproved properties have been excluded from the calculation of depletion expense, and future development costs of $378,242,000 (2007 - $190,146,000) have been included in costs subject to depletion. The Fund performed a ceiling test calculation at December 31, 2008 to assess the recoverable value of fixed assets. Based on the calculation, the carrying amounts are recoverable as compared to the sum of the undiscounted net cash flows expected from the production of proved reserves based on the following benchmark prices: WTI Crude Oil Exchange Rate AECO Gas Year ($US/bbl) ($US/$Cdn) ($Cdn/mmbtu) --------------------------------------------------------------------- 2009 $ 53.73 $ 0.80 $ 6.82 2010 $ 63.41 $ 0.85 $ 7.56 2011 $ 69.53 $ 0.85 $ 7.84 2012 $ 79.59 $ 0.90 $ 8.38 2013 $ 92.01 $ 0.95 $ 9.20 2014 $ 93.85 $ 0.95 $ 9.41 --------------------------------------------------------------------- Approximate escalation rate after 2014 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. Goodwill The Fund frequently assesses goodwill impairment which is effectively a comparison of the fair value of the Fund to the values assigned to the identifiable assets and liabilities. The fair value of the Fund is typically determined by reference to the market capitalization adjusted for a number of potential valuation factors. The values of the identifiable assets and liabilities include the current assessed value of our reserves and other assets and liabilities. Near the end of 2008, Advantage and the entire oil and gas industry, experienced a substantial decline in market capitalization as a result of the worldwide recession, resulting soft commodity prices, and general negative market reaction. As a result, the entire balance of goodwill was determined to be impaired at December 31, 2008, as there is no market perception of goodwill. Year ended Year ended December 31, December 31, 2008 2007 --------------------------------------------------------------------- Balance, beginning of year $ 120,271 $ 120,271 Impairment (120,271) - --------------------------------------------------------------------- Balance, end of year $ - $ 120,271 --------------------------------------------------------------------- 6. Capital Lease Obligations The Fund has capital leases on a variety of fixed assets. Future minimum lease payments at December 31, 2008 consist of the following: 2009 $ 2,040 2010 2,200 2011 1,925 ---------------------------------------------- 6,165 Less amounts representing interest (512) ---------------------------------------------- 5,653 Current portion (1,747) ---------------------------------------------- $ 3,906 ---------------------------------------------- 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, depreciation and accretion expense. 7. 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, July 8, Dec 2, June 10, 2002 2003 2003 2004 Maturity date Matured Matured Feb. 1, June 30, 2009 2009 Conversion price Matured Matured $ 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, May 18, Sept 15, Nov 13, 2004 2005 2004 2006 Maturity date Oct. 1, June 30, Dec. 1, Dec. 31, 2009 2010 2011 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 --------------------------------------------------------------------- 8.25% After February 1, 2008 and before February 1, 2009 $1,025 --------------------------------------------------------------------- 8.75% After June 30, 2008 and before June 30, 2009 $1,025 --------------------------------------------------------------------- 7.50% 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, 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 balance of debentures outstanding at December 31, 2008 and changes in the liability and equity components during the years ended December 31, 2008 and 2007 are as follows: 10.00% 9.00% 8.25% 8.75% ----------------------------------------------------------- Trading symbol AVN.DB AVN.DBA AVN.DBB AVN.DBF Debentures outstanding $ - $ - $ 4,867 $ 29,839 ----------------------------------------------------------- Liability component: Balance at December 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 December 31, 2007 $ - $ 5,333 $ 4,767 $ 29,382 Accretion of discount - 59 92 305 Converted to Trust Units - - - - Matured - (5,392) - - ----------------------------------------------------------- Balance at December 31, 2008 $ - $ - $ 4,859 $ 29,687 ----------------------------------------------------------- Equity component: Balance at December 31, 2006 $ 59 $ 229 $ 248 $ - Assumed on Sound acquisition - - - 11,408 Converted to Trust Units - - - (10,556) Expired (59) - - - ----------------------------------------------------------- Balance at December 31, 2007 $ - $ 229 $ 248 $ 852 Converted to Trust Units - - - - Expired - (229) - - ----------------------------------------------------------- Balance at December 31, 2008 $ - $ - $ 248 $ 852 ----------------------------------------------------------- 7.50% 6.50% 7.75% 8.00% Total --------------------------------------------------------------------- Trading symbol AVN.DBC AVN.DBE AVN.DBD AVN.DBG Debentures outstanding $ 52,268 $ 69,927 $ 46,766 $ 15,528 $219,195 --------------------------------------------------------------------- Liability component: Balance at December 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 December 31, 2007 $ 50,671 $ 68,092 $ 44,360 $ 14,931 $217,536 Accretion of discount 908 740 604 147 2,855 Converted to Trust Units - (25) - - (25) Matured - - - - (5,392) --------------------------------------------------------------------- Balance at December 31, 2008 $ 51,579 $ 68,807 $ 44,964 $ 15,078 $214,974 --------------------------------------------------------------------- Equity component: Balance at December 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 December 31, 2007 $ 2,248 $ 2,971 $ 2,286 $ 798 $ 9,632 Converted to Trust Units - - - - - Expired - - - - (229) --------------------------------------------------------------------- Balance at December 31, 2008 $ 2,248 $ 2,971 $ 2,286 $ 798 $ 9,403 --------------------------------------------------------------------- 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, 2008, $25,000 debentures (2007 - $24,000) were converted resulting in the issuance of 1,001 Trust Units (2007 - 1,386 Trust Units). The principal amount of 9.00% convertible debentures matured on August 1, 2008 and the Fund settled the obligation by payment of $5.4 million in cash. 8. 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 1.50% depending on the Fund's debt to cash flow ratio. The credit facilities are collateralized 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 2009. 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 principal payable at the end of such two year 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. The credit facilities also prohibit the Fund from entering into any derivative contract where the term of such contract exceeds two years or the aggregate of such contracts hedge greater than 60% of the Fund's estimated oil and gas production. 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, 2008, the effective interest rate on the outstanding amounts under the facility was approximately 5.0% (2007 - 5.7%). 9. 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 $249.9 million which will be incurred between 2009 and 2058. 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, December 31, 2008 2007 --------------------------------------------------------------------- Balance, beginning of year $ 60,835 $ 34,324 Accretion expense 4,186 2,795 Assumed in Sound acquisition - 16,695 Liabilities incurred 1,526 1,640 Change in estimates 16,564 12,332 Liabilities settled (9,259) (6,951) --------------------------------------------------------------------- Balance, end of year $ 73,852 $ 60,835 --------------------------------------------------------------------- 10. 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, December 31, 2008 2007 --------------------------------------------------------------------- Loss before taxes $ (28,896) $ (30,733) --------------------------------------------------------------------- Canadian combined federal and provincial income tax rates 29.79% 32.57% Expected income tax recovery at statutory rates (8,608) (10,011) Increase (decrease) in income taxes resulting from: Amounts included in trust income (58,587) (70,097) Change in enacted tax rates - 550 Management internalization 1,798 5,507 Specified Investment Flow-Through - 42,862 Impairment of goodwill 35,833 - Difference between current and expected rates 18,376 11,297 Other 376 (4,750) --------------------------------------------------------------------- Future income tax reduction (10,812) (24,642) Income and capital taxes 2,493 1,444 --------------------------------------------------------------------- $ (8,319) $ (23,198) --------------------------------------------------------------------- The components of the future income tax liability are as follows: December 31, December 31, 2008 2007 --------------------------------------------------------------------- Fixed assets in excess of tax basis $ 9,463 $ 29,240 Asset retirement obligations (21,475) (16,330) Non-capital tax loss carry forward (21,541) (20,369) Trust assets in excess of tax basis 84,017 82,642 Net derivative assets 11,970 651 Other (6,519) (9,107) --------------------------------------------------------------------- Future income tax liability $ 55,915 $ 66,727 --------------------------------------------------------------------- Current future income tax liability $ 11,939 $ 1,430 Long-term future income tax liability 43,976 65,297 --------------------------------------------------------------------- $ 55,915 $ 66,727 --------------------------------------------------------------------- AOG has a non-capital loss carry forward of approximately $75 million of which $18 million expires in 2011, $11 million in 2012 and $46 million after 2020. 11. Unitholders' Equity (a) Unitholders' capital (i) Authorized Unlimited number of voting Trust Units (ii) Issued Number of Units Amount --------------------------------------------------------------------- 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 7) 3,131,998 37,209 Management internalization forfeitures (24,909) (503) --------------------------------------------------------------------- Balance at December 31, 2007 138,269,374 2,036,121 Distribution reinvestment plan 4,414,830 39,884 Issued for cash, net of costs - (42) Issued on conversion of debentures 1,001 25 Issued on exercise of Trust Unit rights 150,000 1,981 Management internalization forfeitures (10,351) (209) --------------------------------------------------------------------- 142,824,854 $ 2,077,760 --------------------------------------------------------------------- Management internalization escrowed Trust Units (1,883) --------------------------------------------------------------------- Balance at December 31, 2008 $ 2,075,877 --------------------------------------------------------------------- On June 23, 2006, 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. For the year ended December 31, 2008, a total of 10,351 Trust Units issued for the management internalization were forfeited (2007 - 24,909 Trust Units) and $7.0 million has been recognized as management internalization expense (2007 - $15.7 million). As at December 31, 2008, 564,612 Trust Units remain held in escrow (December 31, 2007 - 1,193,622 Trust Units). On July 24, 2006, Advantage announced that it adopted a Premium Distribution(TM), Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan"). 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, 2008, 4,414,830 Trust Units (2007 - 4,028,252 Trust Units) were issued under the Plan, generating $39.9 million (2007 - $46.7 million) reinvested in the Fund. 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, December 31, 2008 2007 --------------------------------------------------------------------- Balance, beginning of year $ 2,005 $ 863 Unit-based compensation (1,256) 1,255 Expiration of convertible debentures equity component 229 59 Exercise of Trust Unit Rights (691) (172) --------------------------------------------------------------------- Balance, end of year $ 287 $ 2,005 --------------------------------------------------------------------- (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 were reserved for issuance under the plan with an aggregate of 400,000 rights granted since inception. At December 31, 2007, 150,000 rights remained outstanding under the plan, all of which were exercised at $8.60 per right in 2008 for total cash proceeds of $1,290,000. Contributed surplus of $691,000 in respect of these rights has been transferred to Unitholders' capital. No Trust Unit Rights are outstanding as of December 31, 2008. Number Price --------------------------------------------------------------------- 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 Exercised (150,000) - Reduction of exercise price - (0.60) --------------------------------------------------------------------- Balance at December 31, 2008 - $ 8.60 --------------------------------------------------------------------- (d) Unit-based compensation Advantage's current employee compensation includes a Restricted Trust Unit Plan, as approved by the Unitholders on June 23, 2006. The purpose of the long-term compensation plan 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. Although Advantage experienced a negative return for the 2008 year, the approved peer group also experienced likewise negative returns. As a result, Advantage's 2008 annual return was within the top two- thirds of the approved peer group and the Board of Directors granted Restricted Trust Units at their discretion. The RTU was deemed to be granted at January 15, 2009 and was valued at $3.8 million to be issued in Trust Units at $5.49 per Trust Unit. No compensation expense was included in general and administration expense for the year ended December 31, 2008 as the RTU was granted after year-end. A total of 171,093 Trust Units were issued to employees in early 2009 in satisfaction of the first third of the grant that vested immediately. The remaining two-thirds of the RTU grant will vest evenly on the following two yearly anniversary dates. Since implementing the Plan in 2006, the grant thresholds have not been previously met, and there have been no RTU grants made during prior years and no related compensation expense has been recognized. (e) Net loss per Trust Unit The calculations of basic and diluted net loss per Trust Unit are derived from both loss available to Unitholders and weighted average Trust Units outstanding calculated as follows: Year ended Year ended December 31, December 31, 2008 2007 --------------------------------------------------------------------- Loss available to Unitholders Basic and diluted $ (20,577) $ (7,535) --------------------------------------------------------------------- Weighted average Trust Units outstanding Basic and diluted 139,483,151 119,604,019 --------------------------------------------------------------------- The calculation of diluted net loss 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 loss per Trust Unit calculation for the year ended December 31, 2008 were 9,713,840 (2007 - 9,083,663 Trust Units). As at December 31, 2008, the total convertible debentures outstanding were immediately convertible to 9,529,075 Trust Units (2007 - 9,847,253 Trust Units). All of the Trust Unit Rights and Management Internalization escrowed Trust Units have been excluded from the calculations of diluted net loss per Trust Unit for the years ended December 31, 2008, and 2007 as the impacts would be anti-dilutive. Total weighted average Trust Units issuable in exchange for the Trust Unit Rights and Management Internalization escrowed Trust Units and excluded from the diluted net loss per Trust Unit calculation for the year ended December 31, 2008 were 8,795 and 576,827, respectively (year ended December 31, 2007 - 42,918 and 582,861 Trust Units, respectively). 12. Accumulated Deficit Accumulated deficit consists of accumulated income and accumulated distributions for the Fund since inception as follows: December 31, December 31, 2008 2007 --------------------------------------------------------------------- Accumulated Income $ 199,411 $ 219,988 Accumulated Distributions (1,076,465) (879,823) --------------------------------------------------------------------- Accumulated Deficit $ (877,054) $ (659,835) --------------------------------------------------------------------- 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, management internalization expense and other asset impairments. For the year ended December 31, 2008 the Fund declared $196.6 million in distributions representing $1.40 per distributable Trust Unit (2007 - $215.2 million in distributions representing $1.77 per distributable Trust Unit). 13. 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, 2008, 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 7) resulting in fair values that will vary over time as market conditions change. As at December 31, 2008, the estimated fair value of the total outstanding convertible debenture obligation was $191.2 million (December 31, 2007 - $215.4 million). The fair value of convertible debentures was determined based on the current public trading activity of such debentures. 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 internally and 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. 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 only enters into derivative contracts with major national banks and international energy firms to further mitigate associated 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. As at December 31, 2008, $14.2 million or 17% of accounts receivable are outstanding for 90 days or more. The Fund believes that the entire balance is collectible, and in some instances we have the ability to mitigate risk through withholding production or offsetting payables with the same parties. Accordingly, management has not provided for an allowance for doubtful accounts at December 31, 2008. 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. Although the credit facility is a source of liquidity risk, the facility also 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 principal payable at the end of such two year 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 2009 to 2011 (note 7). 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. The timing of cash outflows relating to financial liabilities are as follows: One to Four Less than three to five one year years years Thereafter Total --------------------------------------------------------------------- Accounts payable and accrued liabilities $ 146,046 $ - $ - $ - $ 146,046 Distributions payable to Unitholders 11,426 - - - 11,426 Derivative liabilities 611 1,039 - - 1,650 Bank indebtedness - principal - 587,404 - - 587,404 Bank indebtedness - interest 25,242 37,863 - - 63,105 Convertible debentures - principal 86,974 132,221 - - 219,195 Convertible debentures - interest 14,838 12,005 - - 26,843 --------------------------------------------------------------------- $ 285,137 $ 770,532 $ - $ - $1,055,669 --------------------------------------------------------------------- The Fund's bank indebtedness does not have specific maturity dates. It is governed by a credit facility agreement with a syndicate of financial institutions (note 8). Under the terms of the agreement, the facility is reviewed annually, with the next review scheduled in June 2009. The facility is revolving, and is extendible at each annual review for a further 364 day period at the option of the syndicate. If not extended, the credit facility is converted at that time into a two year term facility, with the principal payable at the end of such two year term. Management fully expects that the facility will be extended at each annual review. 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% increase in interest rate for the year ended December 31, 2008 could have increased net loss by approximately $4.2 million for that period (year ended December 31, 2007 - $3.0 million). 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, 2008 could impact net loss by approximately $12.8 million for the year ended December 31, 2008. 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, 2008 could impact net loss by $2.8 million for the year ended December 31, 2008. A similar change in the currency rate assumption underlying the derivatives fair value does not have a material impact on net income. As at December 31, 2008 the Fund had the following derivatives in place: Description of Derivative Term Volume Average Price ------------------------------------------------------------------------- Natural gas - AECO Fixed price April 2008 to 14,217 mcf/d Cdn$7.10/mcf March 2009 Fixed price April 2008 to 14,217 mcf/d Cdn$7.06/mcf March 2009 Fixed price November 2008 14,217 mcf/d Cdn$7.77/mcf to March 2009 Fixed price November 2008 4,739 mcf/d Cdn$8.10/mcf to March 2009 Fixed price November 2008 14,217 mcf/d Cdn $9.45/mcf to March 2009 Fixed price April 2009 to 9,478 mcf/d Cdn $8.66/mcf December 2009 Fixed price April 2009 to 9,478 mcf/d Cdn $8.67/mcf December 2009 Fixed price April 2009 to 9,478 mcf/d Cdn $8.94/mcf December 2009 Fixed price April 2009 to 14,217 mcf/d Cdn $7.59/mcf March 2010 Fixed price April 2009 to 14,217 mcf/d Cdn $7.56/mcf March 2010 Fixed price January 2010 14,217 mcf/d Cdn $8.23/mcf to June 2010 Crude oil - WTI Fixed price February 2008 2,000 bbls/d Cdn$90.93/bbl to January 2009 Collar February 2008 2,000 bbls/d Sold put Cdn$70.00/bbl to Purchase call Cdn$105.00/bbl January 2009 Cost Cdn$1.52/bbl Fixed price April 2008 to 2,500 bbl/d Cdn $97.15/bbl March 2009 Collar April 2009 to 2,000 bbl/d Bought put Cdn $62.00/bbl December 2009 Sold call Cdn $76.00/bbl As at December 31, 2008, the fair value of the derivatives outstanding resulted in an asset of approximately $42,620,000 (December 31, 2007 - $7,201,000) and a liability of approximately $1,650,000 (December 31, 2007 - $5,020,000). For the year ended December 31, 2008, $38,789,000 was recognized in net loss as an unrealized derivative gain (December 31, 2007 - $11,049,000 unrealized derivative loss) and $27,439,000 was recognized in net loss as a realized derivative loss (December 31, 2007 - $18,594,000 realized derivative gain). 14. Management Internalization Concurrent with the acquisition of Ketch Resources Trust in 2006, 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, 2008, a total of 10,351 Trust Units issued for the management internalization were forfeited (2007 - 24,909 Trust Units) and $7.0 million has been recognized as management internalization expense (2007 - $15.7 million). As at December 31, 2008, 564,612 Trust Units remain held in escrow (December 31, 2007 - 1,193,622 Trust Units). 15. Capital Management The Fund manages its capital with the following objectives: - To ensure sufficient financial flexibility to achieve the ongoing business objectives including replacement of production, funding of future growth opportunities, and pursuit of accretive acquisitions; and - To maximize Unitholder return through enhancing the Trust Unit value. Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Fund is composed of working capital (excluding derivative assets and liabilities), bank indebtedness, convertible debentures, capital lease obligations and Unitholders' equity. Advantage may manage its capital structure by issuing new Trust Units, obtaining additional financing either through bank indebtedness or convertible debenture issuances, refinancing current debt, issuing other financial or equity-based instruments, adjusting or discontinuing the amount of monthly distributions, suspending or renewing its distribution reinvestment plan, adjusting capital spending, or disposing of non-core assets. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis. Advantage's capital structure as at December 31, 2008 is as follows: December 31, 2008 --------------------------------------------------------------------- Bank indebtedness (long-term) $ 587,404 Working capital deficit(1) 146,397 --------------------------------------------------------------------- Net debt 733,801 Trust Units outstanding market value 731,263 Convertible debentures maturity value (long-term) 132,221 Capital lease obligations (long-term) 3,906 --------------------------------------------------------------------- Total $ 1,601,191 --------------------------------------------------------------------- (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. The Fund's bank indebtedness is governed by a $710 million credit facility agreement (note 8) that contains 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. The Fund is in compliance with all credit facility covenants. As well, the borrowing base for the Fund's credit facilities is determined through utilizing Advantage's regular reserve estimates. The banking syndicate thoroughly evaluates the reserve estimates based upon their own commodity price expectations to determine the amount of the borrowing base. Revision or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing base of the Fund. Advantage's issuance of convertible debentures is limited by its Trust Indenture which currently restricts the issuance of additional convertible debentures to 25% of market capitalization subsequent to issuance. Advantage's Trust Indenture also provides for the issuance of an unlimited number of Trust Units. However, through tax legislation, an income trust is restricted to doubling 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. 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. As a result of the "normal growth" guidelines, the Fund is permitted to issue approximately $2.3 billion of new equity from January 1, 2009 to January 1, 2011, which we believe is adequate for any growth we expect to incur. If an income trust exceeds the established limits on the issuance of new trust units and convertible debt that constitute normal growth, the income trust will be immediately subject to the Specified Investment Flow-Through Entity tax legislation whereby the taxable portion of distributions paid will be subject to tax at the trust level. Management of the Fund's capital structure is facilitated through its financial and operational forecasting processes. The forecast of the Fund's future cash flows is based on estimates of production, commodity prices, forecast capital and operating expenditures, and other investing and financing activities. The forecast is regularly updated based on new commodity prices and other changes, which the Fund views as critical in the current environment. Selected forecast information is frequently provided to the Board of Directors. The Fund's capital management objectives, policies and processes have remained unchanged during the year ended December 31, 2008. 16. Commitments Advantage has several lease commitments relating to office buildings. The estimated annual minimum operating lease rental payments for buildings are as follows: 2009 $ 3,862 2010 3,878 2011 1,471 2012 1,072 --------------------------------------------------------------------- $ 10,283 --------------------------------------------------------------------- 17. Subsequent event On March 18, 2009, Advantage announced that our Board of Directors had approved conversion to a growth oriented corporation and a strategic asset disposition program to increase financial flexibility. The corporate conversion will be subject to approval by at least two-thirds of the Fund's Unitholders as well as customary court and regulatory approvals, anticipated to be completed on or about June 30, 2009. The conversion will enable Advantage to pursue a business plan that is focused on the development and growth of the Montney natural gas resource play at Glacier. The Fund has engaged an advisory firm to assist in the disposal of light oil and natural gas properties located in Northeast British Columbia, West Central Alberta and Northern Alberta with proposals anticipated by mid May 2009. As another step to increase Advantage's financial flexibility and to focus on development and growth at Glacier, Advantage announced it will discontinue payment of cash distributions with the final cash distribution paid on March 16, 2009 to Unitholders of record as of February 27, 2009. Going forward, Advantage does not anticipate paying distributions or dividends in the immediate future and will instead direct cash flow to capital expenditures and debt repayment. 18. 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 ("US GAAP"). 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 Restricted Trust Unit Plan and Trust Units held in escrow subject to service requirement provisions. 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. (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 Loss. 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 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. (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 impairment losses of $49.5 million in 2001 ($28.3 million net of tax), $535.4 million in 2006 ($477.8 million net of tax), and $1,047.5 million in 2008 ($770.8 million net of tax). Impairment losses decrease 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, 2008 and 2007. The differences between Canadian GAAP and US GAAP relate to future income tax impact on GAAP differences for fixed assets. Under Canadian GAAP as at December 31, 2008, the Fund's carrying value of its net assets exceeded its tax bases and resulted in a future income tax liability. Adjustments under US GAAP result in a large future income tax recovery and a future income tax asset, as the ceiling test write down significantly lowered the Fund's fixed assets carrying value under US GAAP. 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 2007 and 2008 is entirely at the provincial level. (f) Goodwill Under Canadian and US GAAP, the Fund is required to test the carrying amount of goodwill at each balance sheet reporting date and the methodologies are substantially the same. However, the carrying value of the reporting unit (the Fund) under US GAAP is much lower due to the impairments to property, plant and equipment required under US GAAP (note 18(d)). As the fair value of the reporting unit (the Fund) is in excess of its carrying values as determined under US GAAP, there is no impairment of goodwill for US GAAP reporting purposes. (g) 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 value increases net income available to Unitholders. For the years ended December 31, 2008 and 2007, net income available to Unitholders was increased by $476.2 million and $390.3 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 unitholders' equity, the Fund's only significant equity account: Year ended Year ended Unitholders' Equity December 31, December 31, (thousands of Canadian dollars) 2008 2007 --------------------------------------------------------------------- Balance, beginning of year $ (176,393) $ (402,158) Net income (loss) and comprehensive income (loss) (555,148) 50,610 Distributions declared (196,642) (215,194) Change in redemption value of temporary equity 476,237 390,349 --------------------------------------------------------------------- Balance, end of year $ (451,946) $ (176,393) --------------------------------------------------------------------- (h) 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: December 31, December 31, (thousands of Canadian dollars) 2008 2007 --------------------------------------------------------------------- Accounts receivable Trade receivables $ 84,592 $ 94,959 Other receivables 97 515 --------------------------------------------------------------------- Total accounts receivable $ 84,689 $ 95,474 --------------------------------------------------------------------- December 31, December 31, (thousands of Canadian dollars) 2008 2007 --------------------------------------------------------------------- Accounts payable and accrued liabilities Accounts payable $ 80,016 $ 72,691 Accrued liabilities 66,030 48,994 Other payables - 402 --------------------------------------------------------------------- Total accounts payable and accrued liabilities $ 146,046 $ 122,087 --------------------------------------------------------------------- (i) 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. (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 $ 484,630 16,977,184 Trust Future income tax Units issued $ 228,852 asset 29,430 Cash 21,403 Accounts receivable 27,656 Acquisition costs Prepaid expenses incurred 904 and deposits 3,873 ------------ Derivative asset, net 2,797 $ 251,159 Bank indebtedness (107,959) ------------ Convertible debentures (101,553) Accounts payable and accrued liabilities (40,023) Future income tax liability (29,430) Asset retirement obligations (16,695) Capital lease obligations (1,567) ------------ $ 251,159 ------------ (k) US Accounting Pronouncements 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 date for this standard was originally as of the beginning of the first interim or annual reporting period that begins after November 15, 2007. However, the FASB postponed this implementation date by one year for non-financial assets and liabilities by the issuance of Staff Position 157-2. Accordingly, the Fund has implemented FAS 157 for all financial assets and liabilities only. The implementation did not result in any changes to the fair values of financial assets and liabilities of the Fund. (l) Recent US Accounting Pronouncements Issued But Not Implemented 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. As the standard is applied prospectively, the Fund will assess the impact on any future business combinations. FASB Staff Position 157-2: This Staff Position delays the implementation of the requirements of SFAS 157 with respect to non-financial assets and liabilities, until the first interim or annual reporting period that begins after November 15, 2008. The Fund has not yet assessed the full impact, if any, of this standard on the consolidated financial statements. SFAS 162, Hierarchy of GAAP: This Statement establishes a hierarchy among the existing types of accounting pronouncements in the United States. The implementation date for this standard is as of the beginning of the first interim or annual reporting period that begins after November 15, 2008. The Fund has assessed the impact of this Statement and does not anticipate any significant impact on the consolidated financial statements. FASB Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement): If an entity issues convertible debt within the scope of the Staff Position, it is required to separate the instrument into a liability-classified component and an equity-classified component. The implementation date for this standard was originally as of the beginning of the first interim or annual reporting period that begins after December 15, 2008. The Fund has assessed the impact of this Staff Position and does not anticipate any significant impact on the consolidated financial statements. The application of US GAAP would have the following effect on net loss as reported: Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) Year ended Year ended (thousands of Canadian dollars, except December 31, December 31, for per Trust Unit amounts) 2008 2007 --------------------------------------------------------------------- Net loss - Canadian GAAP, as reported $ (20,577) $ (7,535) US GAAP Adjustments: General and administrative - note 18 (a) (904) 606 Management internalization - note 18 (a) 2,946 7,450 Interest and accretion on convertible debentures - note 18 (b) 2,051 1,741 Depletion, depreciation and accretion - notes 18 (c) and (d) (983,222) 72,990 Impairment of goodwill - note 18 (f) 120,271 - Future income tax reduction - note 18 (e) 324,287 (24,642) --------------------------------------------------------------------- Net income (loss) and comprehensive income (loss) - US GAAP $ (555,148) $ 50,610 --------------------------------------------------------------------- The application of US GAAP would have the following effect on the balance sheets as reported: Consolidated December 31, 2008 December 31, 2007 Balance Sheets ----------------- ----------------- (thousands of Canadian US Canadian US Canadian dollars) GAAP GAAP GAAP GAAP --------------------------------------------------------------------- Assets Deferred charge - note 18 (b) $ - $ 1,181 $ - $ 1,984 Fixed assets, net - notes 18 (c) and (d) 2,163,866 676,611 2,177,346 1,673,251 Future income taxes - note 18 (e) - 347,038 - - Goodwill - note 18 (f) - 120,271 120,271 120,271 Liabilities and Unitholders' Equity Current portion of convertible debentures 86,125 87,272 5,333 5,392 - note 18 (b) Current portion of future income taxes - note 18 (e) 11,939 11,939 1,430 - Trust Unit liability - note 18 (a) - 2,414 - 7,515 Convertible debentures - note 18 (b) 128,849 132,377 212,203 219,674 Future income taxes - note 18 (e) 43,976 - 65,297 - Temporary equity - note 18 (g) - 678,581 - 1,104,831 Unitholders' equity - notes 18 (a), (b) and (g) 1,208,513 (451,946) 1,378,867 (176,393) Advisory The information in this release 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 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; and obtaining required approvals of regulatory authorities. Advantage's actual results, 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. DATASOURCE: Advantage Energy Income Fund CONTACT: Investor Relations, Toll free: 1-866-393-0393, ADVANTAGE ENERGY INCOME FUND, 700, 400 - 3rd Avenue SW, Calgary, Alberta, T2P 4H2, Phone: (403) 718-8000, Fax: (403) 718-8300, Web Site: http://www.advantageincome.com/, E-mail:

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