Advantage Announces 1st Quarter Results, Conference Call & Webcast on May 14, 2007

CALGARY, May 11 /PRNewswire-FirstCall/ -- Advantage Energy Income Fund (TSX: AVN.UN) ("Advantage" or the "Fund") is pleased to announce its unaudited operating and financial results for the first quarter ended March 31, 2007.

A conference call will be held on Monday May 14, 2007 at 9:00 a.m. MST (11:00 a.m. EST). The conference call can be accessed toll-free at 1-866-585-6398. A replay of the call will be available from approximately 2:00 p.m. EST on May 14, 2007 until approximately midnight, May 21, 2007 and can be accessed by dialing toll free 1-866-245-6755. The passcode required for playback is 587317. A live web cast of the conference call will be accessible via the Internet on Advantage's website at http://www.advantageincome.com/.

Three months Three months ended ended March 31, 2007 March 31, 2006 ------------------------------------------------------------------------- Financial ($000) Revenue before royalties $ 135,502 $ 86,901 per Trust Unit(1) $ 1.25 $ 1.48 per boe $ 51.90 $ 54.49 Funds from operations $ 65,645 $ 46,630 per Trust Unit(2) $ 0.59 $ 0.79 per boe $ 25.14 $ 29.24 Net income $ 341 $ 15,964 per Trust Unit(1) $ 0.00 $ 0.27 Distributions $ 50,206 $ 44,459 per Trust Unit(2) $ 0.45 $ 0.75 Payout ratio (%) 76% 95% Expenditures on property and equipment $ 49,696 $ 20,989 Working capital deficit(3) $ 31,896 $ 18,644 Bank indebtedness $ 354,443 $ 278,777 Convertible debentures (face value) $ 180,730 $ 113,531 Operating Daily Production Natural gas (mcf/d) 114,324 65,768 Crude oil and NGLs (bbls/d) 9,958 6,760 Total boe/d at 6:1 29,012 17,721 Average prices (including hedging) Natural gas ($/mcf) $ 8.06 $ 8.69 Crude oil and NGLs ($/bbl) $ 58.64 $ 58.26 Supplemental (000) Trust Units outstanding at end of period 115,050 59,468 Trust Units issuable Convertible Debentures 8,334 5,699 Exchangeable Shares - 99 Trust Units Rights Incentive Plan 188 310 Trust Units outstanding and issuable at end of period 123,572 65,576 Basic weighted average Trust Units 108,332 58,874 (1) based on basic weighted average Trust Units outstanding (2) based on number of Trust Units outstanding at each cash distribution record date (3) working capital deficit excludes derivative assets and liabilities Message to Unitholders Highlights of the first quarter include: - Production volumes in Q1 of 2007 increased 64% to 29,012 boe/d compared to 17,721 boe/d in Q1 of 2006. Natural gas production for Q1 of 2007 was 114.3 mmcf/d, compared to 65.8 mmcf/d reported in the same period of 2006. Crude oil and natural gas liquids production averaged 9,958 bbls/d compared to 6,760 bbls/d in Q1 of 2006. Production volumes in the first quarter are higher due to continued success in our drilling program and from the Ketch acquisition, which closed June 23, 2006. First quarter production volumes were impacted by cold weather issues that created operational downtime at Fontas and Martin Creek. - Q1 2007 payout ratio decreased to 76% compared to 95% for the same period in 2006, and 94% in Q4 2006. The decreased payout ratio from Q4 2006 resulted from distribution adjustments and better realized gas pricing due to our hedging program. - The Fund declared three distributions during the quarter totaling $0.45 per Trust Unit ($0.15 per unit per month). Since inception, the Fund has distributed $714.8 million or $14.94 per Trust Unit. - Funds from operations for the first quarter of 2007 was $65.6 million or $0.59 per Trust Unit compared to $46.6 million or $0.79 per Trust Unit for the same period of 2006. - Advantage has successfully de-leveraged the balance sheet by reducing debt from 1.64 times bank debt to cash flow from Q4 of 2006 to 1.35 times bank debt to cash flow in Q1 2007. This has positioned the Fund for future opportunities. - A highly successful capital program during the first quarter resulted in the drilling of 39 gross (24.1 net) wells at a 97% success rate. Capital expenditures totaled a net $49 million for E&D activity which was less than expected due to the deferral of some projects as a result of early spring break-up. Activity was primarily focused on Martin Creek and Nevis. During the first quarter 13 gas wells (of a 17 well winter program) were drilled at Martin Creek, 6 gas wells were drilled at Chigwell and 3 oil wells were drilled at Nevis. As well, 2 oil wells and 1 gas well were drilled at Willesden Green. Other capital spending related to a variety of wells, with smaller working interests, and facilities necessary to support our 2007 activity. - A complimentary asset acquisition of $12.9 million was also completed at Nevis where the Fund has been very active and successful. The acquisition included 175 boe/d and 6.75 sections of undeveloped land with immediate drilling opportunities. - Operating costs were higher in the first quarter driven by significant one-time costs associated with the freeze up of facilities at Fontas, a prior period adjustment and a general increase in the cost of production services. Hedging Position - Advantage has layered in a number of hedges on both natural gas and oil which will provide floor protection through summer 2007 and winter 2007/2008 for natural gas. The Fund will continue to be active in hedging to protect cash flow. - The Fund currently has approximately 54% of natural gas production, net of royalties, hedged for summer at an average floor price of $7.08/mcf and an average ceiling of $8.09/mcf. In addition, 14% of crude oil production, net of royalties, has been hedged for the same period at an average floor of US$65.00/bbl and a ceiling of US$90.00/bbl. Looking Forward - The merger of Advantage and Ketch has created a very high quality long life asset base with over 500 high quality drilling locations (greater than 4 year inventory) allowing increased flexibility for capital allocation and upgrading. - Production during the summer will be impacted by spring break-up and major 3rd party plant turnarounds which are expected to occur. Per unit operating costs are expected to remain in the higher end of our guidance during spring and summer months when planned facilities outages take place. In addition, we expect the payout ratio to be higher during that period due to softer gas prices which are partly offset by our hedging program, and lower production rates due to 3rd party plant maintenance. - Advantage reiterates annual guidance of 27,500 to 29,500 boe/d of production with capital expenditures of $125 to $145 million. Annual operating costs are expected to remain around the higher end of our guidance of $9.50 to $10.50/boe driven by continued higher power costs and cost pressures. We believe some relief in production services will occur later this year as decreased drilling in western Canada will reduce the cost of production services and supplies. - Advantage has exceptional tax pool coverage which will help reduce the amount of tax leakage to Unitholders for several years after 2011. As at December 31, 2006 the Fund had approximately $1.2 billion in tax pools and deductions available, one of the highest in the sector. MANAGEMENT'S DISCUSSION & ANALYSIS

The following Management's Discussion and Analysis ("MD&A"), dated as of May 11, 2007, provides a detailed explanation of the financial and operating results of Advantage Energy Income Fund ("Advantage", the "Fund", "us", "we" or "our") for the three months ended March 31, 2007 and should be read in conjunction with the consolidated financial statements contained within this interim report and the audited financial statements and MD&A for the year ended December 31, 2006. 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 cubit 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 and per Trust Unit, cash netbacks, and payout ratio. 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. Both cash netbacks and payout ratio are dependent on the determination of funds from operations. Cash netbacks include the primary cash revenues and expenses on a per boe basis that comprise funds from operations. Payout ratio represents the distributions declared for the period as a percentage of funds from operations. Funds from operations reconciled to cash provided by operating activities is as follows:

Three months ended March 31 ($000) 2007 2006 % change ------------------------------------------------------------------------- Cash provided by operating activities $ 50,520 $ 39,880 27% Expenditures on asset retirement 4,009 1,033 288% Changes in non-cash working capital 11,116 5,717 94% ------------------------------------------------------------------------- Funds from operations $ 65,645 $ 46,630 41% ------------------------------------------------------------------------- Forward-Looking Information

The information in this report contains certain forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar expressions. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Advantage's control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; obtaining required approvals of regulatory authorities and other risk factors set forth in Advantage's Annual Information Form which is available at http://www.advantageincome.com/ or http://www.sedar.com/. 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.

Overview Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Cash provided by operating activities ($000) $ 50,520 $ 39,880 27% Funds from operations ($000) $ 65,645 $ 46,630 41% per Trust Unit(1) $ 0.59 $ 0.79 (25)% Net income ($000) $ 341 $ 15,964 (98)% per Trust Unit - Basic $ 0.00 $ 0.27 (100)% - Diluted $ 0.00 $ 0.27 (100)% (1) Based on Trust Units outstanding at each distribution record date.

Cash provided by operating activities increased 27%, funds from operations increased 41%, and funds from operations per Trust Unit decreased 25% for the three months ended March 31, 2007, as compared to the same period of 2006. The increase in cash provided by operating activities and funds from operations has been primarily due to the merger with Ketch Resources Trust ("Ketch") that closed on June 23, 2006. The financial and operating results from the acquired Ketch properties are included in all 2007 figures but are not included in the three month period ended March 31, 2006, thereby explaining most variances. However, both funds from operations and funds from operations per Trust Unit have been negatively impacted by lower natural gas prices throughout the first three months of 2007. Natural gas prices, excluding hedging, were $7.61/mcf in the first quarter of 2007, a decrease of 12% compared to $8.69/mcf in the first quarter of 2006. Weaker natural gas prices have been partially offset by a successful hedging program that was implemented in November 2006. Net income decreased 98% in 2007, and net income per basic Trust Unit decreased 100% for the three months ended March 31, 2007, as compared to 2006. The lower net income has been primarily due to the lower natural gas prices realized during the period, amortization of the management internalization consideration, and increased depletion and depreciation expense. The primary factor that causes significant variability of Advantage's cash provided by operating activities, funds from operations and net income is 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 March 31 2007 2006 % change ------------------------------------------------------------------------- Distributions declared ($000) $ 50,206 $ 44,459 13% per Trust Unit(1) $ 0.45 $ 0.75 (40)% Payout ratio (%) 76% 95% (19)% (1) Based on Trust Units outstanding at each distribution record date.

Total distributions increased 13% in the first quarter of 2007 when compared to the same period in 2006. The higher total distributions reflect the increased Trust Units outstanding from the continued growth and development of the Fund, particularly due to the Ketch acquisition. As a result of natural gas prices that have been very weak during the 2006/2007 winter season, we reduced the distribution level during this period to more appropriately reflect the current commodity price environment. Distributions per Trust Unit were $0.45 for the three months ended March 31, 2007, representing a decrease of 40% from the $0.75 in 2006. This positively impacted the payout ratio in the first three months of 2007 which was 76%, a decrease of 19% when compared to the same period in 2006. The monthly distribution is currently $0.15 per Trust Unit. To mitigate the persisting risk associated with lower natural gas prices and the resulting negative impact on distributions, the Fund implemented a hedging program in 2006 with 54% of natural gas hedged for April to October 2007. See "Commodity Price Risk" section for a more detailed discussion of our price risk management. We believe the Fund has taken the necessary action and is now well-positioned with the objective of providing long-term distribution sustainability to Unitholders.

Distributions are determined by Management and the Board of Directors. We closely monitor our distribution policy considering forecasted cash flows, optimal debt levels, capital spending activity, taxability to Unitholders, working capital requirements, and other potential cash expenditures. Distributions are announced monthly and are based on the cash available after retaining a portion to meet such spending requirements. The level of distributions are primarily determined by cash flows received from the production of oil and natural gas from existing Canadian resource properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. If the oil and natural gas reserves associated with the Canadian resource properties are not supplemented through additional development or the acquisition of additional oil and natural gas properties, our distributions will decline over time in a manner consistent with declining production from typical oil and natural gas reserves. Therefore, distributions are highly dependent upon our success in exploiting the current reserve base and acquiring additional reserves. Furthermore, monthly distributions we pay to Unitholders are highly dependent upon the prices received for such oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond our control. Declines in oil or natural gas prices will have an adverse effect upon our operations, financial condition, reserves and ultimately on our ability to pay distributions to Unitholders. The Fund attempts to mitigate the volatility in commodity prices through our hedging program. It is our long-term objective to provide stable and sustainable distributions to the Unitholders, while continuing to grow the Fund. However, given that funds from operations can vary significantly from month-to-month due to these factors, the Fund may utilize various financing alternatives as an interim measure to maintain stable distributions.

Revenue Three months ended March 31 ($000) 2007 2006 % change ------------------------------------------------------------------------- Natural gas excluding hedging $ 78,333 $ 51,458 52% Realized hedging gains 4,620 - - ------------------------------------------------------------------------- Natural gas including hedging $ 82,953 $ 51,458 61% ------------------------------------------------------------------------- Crude oil and NGLs excluding hedging $ 50,939 $ 35,443 44% Realized hedging gains 1,610 - - ------------------------------------------------------------------------- Crude oil and NGLs including hedging $ 52,549 $ 35,443 48% ------------------------------------------------------------------------- Total revenue $ 135,502 $ 86,901 56% -------------------------------------------------------------------------

Natural gas revenues, excluding hedging, have increased 52% for the three months ended March 31, 2007, compared to 2006. Crude oil and NGL revenues, excluding hedging, have increased by 44% for the three months ended March 31, 2007. Revenues have increased due to additional production from the Ketch merger but have been partially offset by lower commodity prices. Due to the Fund's hedge positions that were in place for the first quarter of 2007, natural gas revenues, including hedging, have increased 61% and crude oil and NGL revenues, including hedging, increased 48%.

Production Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Natural gas (mcf/d) 114,324 65,768 74% Crude oil (bbls/d) 7,557 5,615 35% NGLs (bbls/d) 2,401 1,145 110% ------------------------------------------------------------------------- Total (boe/d) 29,012 17,721 64% ------------------------------------------------------------------------- Natural gas (%) 66% 62% Crude oil (%) 26% 32% NGLs (%) 8% 6%

The Fund's total daily production averaged 29,012 boe/d for the first quarter of 2007, an increase of 64% compared with the same period of 2006. Natural gas production increased 74%, crude oil production increased 35%, and NGLs production increased 110%. The increase in production during the quarter has been primarily attributed to the Ketch acquisition, which closed June 23, 2006.

Our successful fourth quarter 2006 drilling program and further additions in the first quarter of 2007 from Nevis, Chigwell, and Willesden Green, as well as other areas in Southern Alberta and Saskatchewan have moderately offset declines. Additions from Martin Creek were minimal in the first quarter as most of the new production came on during the latter part of March. In addition, our flattening production platform, resulting from our continued focus on long life assets, is contributing to a stable operating foundation. Production outages were slightly higher than expected especially in our northern properties of Fontas and Martin Creek where cold weather issues created operational downtime.

For the remainder of the year, we expect major third party plant turnarounds during the second and third quarter, which will impact our production levels.

Commodity Prices and Marketing Natural Gas Three months ended March 31 ($/mcf) 2007 2006 % change ------------------------------------------------------------------------- Realized natural gas prices Excluding hedging $ 7.61 $ 8.69 (12)% Including hedging $ 8.06 $ 8.69 (7)% AECO monthly index $ 7.46 $ 9.31 (20)%

Realized natural gas prices, excluding hedging, decreased 12% for the three months ended March 31, 2007, as compared to the same period of 2006. The price of natural gas is primarily based on supply and demand fundamentals in the North American marketplace. Natural gas prices experienced sustained weakness throughout 2006 due to relatively uneventful weather resulting in natural gas inventories that swelled to historic levels. The 2006/2007 winter has generally been mild, with inventory levels remaining higher than average, causing continued downward pressure on commodity prices. However, February 2007 brought sustained colder weather and inventory levels decreased below 2006 levels but are still ample compared to demand. The withdrawals from inventories resulted in a modest rebound in natural gas prices but overall the prices still remain low. We continue to believe that the long-term pricing fundamentals for natural gas remain strong. These fundamentals include (i) the continued strength of crude oil prices, which has eliminated the economic advantage of fuel switching away from natural gas, (ii) long-term tightness in supply that has resulted from persistent demand and the decline in North American natural gas production levels and (iii) ongoing weather related factors such as hot summers, cold winters and annual hurricane season in the Gulf of Mexico, all of which have an impact on the delicate supply/demand balance that exists.

Crude Oil and NGLs Three months ended March 31 ($/bbl) 2007 2006 % change ------------------------------------------------------------------------- Realized crude oil prices Excluding hedging $ 59.03 $ 59.42 (1)% Including hedging $ 61.40 $ 59.42 3% Realized NGLs prices Excluding hedging $ 49.93 $ 52.57 (5)% Realized crude oil and NGLs prices Excluding hedging $ 56.84 $ 58.26 (2)% Including hedging $ 58.64 $ 58.26 1% WTI ($US/bbl) $ 58.12 $ 63.88 (9)% $US/$Canadian exchange rate $ 0.85 $ 0.87 (2)%

Realized crude oil and NGLs prices, excluding hedging, decreased 2% for the three months ended March 31, 2007, as compared to the same period of 2006. Advantage's crude oil prices are based on the benchmark pricing of West Texas Intermediate Crude ("WTI") adjusted for quality, transportation costs and $US/$Canadian exchange rates. Advantage's realized crude oil price has not changed to the same extent as WTI due to the change in foreign exchange rates and the narrowing of Canadian crude oil differentials relative to WTI. The price of WTI fluctuates based on worldwide supply and demand fundamentals. There has been significant price volatility experienced over the last several years whereby WTI has reached historic high levels. For the three months ended March 31, 2007, WTI averaged $US 58.12/bbl, a decrease of 9%, compared to 2006. Many developments have resulted in the current price levels, including significant geopolitical issues. Early in 2006, prices were strong due to concerns regarding the lack of North American refining capacity, and the continued strength of global demand. The mild 2005/2006 winter and the surge in crude imports to North America resulted in significantly higher inventories that prompted the relative price decrease during the end of 2006. Prices have strengthened once again in the first quarter of 2007 due to continued civil unrest in the Middle East and production restrictions by the OPEC cartel. With the current strengthening in price levels, it is notable that demand has remained resilient. We believe that the pricing fundamentals for crude oil remain strong with many factors affecting the continued strength including (i) supply management and supply restrictions by the OPEC cartel, (ii) ongoing civil unrest in Venezuela, Nigeria, and the Middle East, (iii) strong world wide demand, particularly in China, India and the United States and (iv) North American refinery capacity constraints.

Commodity Price Risk

The Fund's operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by economic and, in the case of oil prices, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions impact prices. Any movement in oil and natural gas prices could have an effect on the Fund's financial condition and therefore on the distributions to holders of Advantage Trust Units. As current and future practice, Advantage has established a financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivatives. These commodity risk management activities could expose Advantage to losses or gains. To the extent that Advantage engages in risk management activities related to commodity prices, it will be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities.

Currently, the Fund has the following derivatives in place: Description of Derivative Term Volume Average Price ------------------------------------------------------------------------- Natural gas - AECO Fixed price April 2007 9,478 mcf/d Cdn$7.16/mcf to October 2007 Fixed price April 2007 9,478 mcf/d Cdn$7.55/mcf to October 2007 Fixed price November 2007 7,109 mcf/d Cdn$9.54/mcf to March 2008 Collar November 2007 9,478 mcf/d Floor Cdn$8.44/mcf to March 2008 Ceiling Cdn$10.29/mcf Collar November 2007 7,109 mcf/d Floor Cdn$8.70/mcf to March 2008 Ceiling Cdn$10.71/mcf Crude oil - WTI Collar October 2006 to 1,000 bbls/d Floor US$65.00/bbl September 2007 Ceiling US$90.00/bbl

As at March 31, 2007 the fair value of the derivatives outstanding was an asset of approximately $1,638,000 and a liability of $3,234,000. For the three months ended March 31, 2007, $12,029,000 was recognized in income as an unrealized derivative loss due to a decrease in the fair value from December 31, 2006 and $6,230,000 was recognized in income as a realized derivative gain, which partially alleviated lower revenue from reduced commodity prices. The valuation of the derivatives is the estimated fair value to settle the contracts as at March 31, 2007 and is based on pricing models, estimates, assumptions and market data available at that time. The actual gain or loss realized on cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. The Fund does not apply hedge accounting and current accounting standards require changes in the fair value to be included in the consolidated statement of income and comprehensive income as an unrealized derivative gain or loss with a corresponding derivative asset or liability recorded on the balance sheet.

In addition, the Fund has the following physical natural gas contracts in place with gains and losses recognized in earnings as the contracts settle:

Description of Physical Contract Term Volume Average Price ------------------------------------------------------------------------- Natural gas - AECO Collar April 2007 4,739 mcf/d Floor Cdn$7.12/mcf to October 2007 Ceiling Cdn$8.67/mcf Collar April 2007 4,739 mcf/d Floor Cdn$6.86/mcf to October 2007 Ceiling Cdn$9.13/mcf Collar April 2007 9,478 mcf/d Floor Cdn$7.39/mcf to October 2007 Ceiling Cdn$9.63/mcf Collar April 2007 9,478 mcf/d Floor Cdn$6.33/mcf to October 2007 Ceiling Cdn$7.20/mcf

Currently, the Fund has fixed the commodity price on anticipated production as follows:

Approximate Production Hedged, Commodity Net of Royalties Minimum Price Maximum Price ------------------------------------------------------------------------- Natural gas - AECO Summer 2007 54% Cdn$7.08/mcf Cdn$8.09/mcf Winter 2007/2008 28% Cdn$8.85/mcf Cdn$10.19/mcf Crude Oil - WTI Summer 2007 14% US$65.00/bbl US$90.00/bbl Royalties Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Royalties, net of Alberta Royalty Credit ($000) $ 26,165 $ 16,340 60% per boe $ 10.02 $ 10.25 (2)% As a percentage of revenue, excluding hedging 20.2% 18.8% 1.4%

Advantage pays royalties to the owners of mineral rights from which we have leases. The Fund currently has mineral leases with provincial governments, individuals and other companies. Royalties for 2006 are shown net of Alberta Royalty Credit, which was a royalty rebate provided by the Alberta government to certain producers and is proposed to be eliminated effective January 1, 2007. Royalties have increased in total due to the increase in revenue from higher production and have decreased on a per boe basis due to reduced natural gas prices. Royalties as a percentage of revenue, excluding hedging, have increased slightly from the 2006 period due to the inclusion of slightly higher royalty rate properties from the Ketch acquisition and the payment of prior year royalty adjustments. We expect the royalty rate to remain comparable for 2007.

Operating Costs Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Operating costs ($000) $ 30,270 $ 15,066 101% per boe $ 11.59 $ 9.45 23%

Total operating costs increased 101% for the three months ended March 31, 2007 as compared to 2006 mainly due to the Ketch acquisition. Operating costs per boe increased 23% for the three months ended March 31, 2007, mainly due to increased service and supply costs as the industry experienced an overall labour cost increase, a prior period adjustment and several one-time events. Cold weather in February 2007 caused the freeze-up of facilities in Fontas and Martin Creek that required additional maintenance and repair work. In addition, increased power and trucking costs due to crude oil pipeline restrictions in Southeast Saskatchewan have continued into the first quarter of 2007. Lastly, upward pressure is normally placed on operating costs during the winter months due to a peak in winter activity and field work. We will be opportunistic and proactive in pursuing alternatives that will improve our operating cost structure. A significant operating cost that Advantage has been successful in stabilizing is electricity associated with field operations. The Fund has been active in preserving the price of power by hedging 3.5 MW at $56.68/MWh for 2007 and 3.0 MW at $54.00/MWh for 2008, which represents a substantial portion of our power usage. We expect that operating costs per boe will be in the upper end of our guidance range of $9.50 to $10.50 for the 2007 year.

General and Administrative Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- General and administrative expense ($000) $ 4,716 $ 1,966 140% per boe $ 1.81 $ 1.23 47%

General and administrative ("G&A") expense has increased 140% for the three months ended March 31, 2007, as compared to 2006. G&A per boe increased 47% for the three months when compared to the same period of 2006. G&A expense has increased overall and per boe primarily due to an increase in staff levels that have resulted from the Ketch acquisition and growth of the Fund. Additionally, the Ketch acquisition was conditional on Advantage internalizing the external management contract structure and eliminating all related fees for a more typical employee compensation arrangement. The new employee compensation plan has resulted in higher G&A expense that is offset by the elimination of future management fees and performance incentive. Prior to elimination of the management contract, the quarterly management fee and annual performance incentive were not included within G&A.

Management Fee, Performance Incentive, and Management Internalization Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Management fee ($000) $ - $ 832 (100)% per boe $ - $ 0.52 (100)% Performance incentive ($000) $ - $ 2,680 (100)% Management internalization ($000) $ 5,369 $ - -

Prior to the Ketch merger, the Manager received both a management fee and a performance incentive fee as compensation pursuant to the Management Agreement approved by the Board of Directors. As a condition of the merger with Ketch, the Fund and the Manager reached an agreement to internalize the management contract arrangement. As part of the agreement, Advantage agreed to purchase all of the outstanding shares of the Manager pursuant to the terms of the Arrangement, thereby eliminating the management fee and performance incentive effective April 1, 2006. The Trust Unit consideration issued in exchange for the outstanding shares of the Manager was placed in escrow for a 3-year period and is being deferred and amortized into income as management internalization expense over the specific vesting periods during which employee services are provided.

Interest Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Interest expense ($000) $ 5,187 $ 3,193 62% per boe $ 1.99 $ 2.00 (1)% Average effective interest rate 5.4% 4.9% 0.5% Bank indebtedness at March 31 ($000) $ 354,443 $ 278,777 27%

Interest expense has increased 62% for the three months ended March 31, 2007, as compared to 2006. Interest expense per boe has remained stable for the three months ended March 31, 2007. The increase in interest expense is primarily attributable to a higher average debt level associated with the growth of the Fund, an increase in the average effective interest rates, and the merger with Ketch, which included the assumption of Ketch's additional bank indebtedness. The increased debt has been used in financing continued development activities and pursuit of expansion opportunities. We monitor the debt level to ensure an optimal mix of financing and cost of capital that will provide a maximum return to Unitholders. Our current credit facilities have been a favorable financing alternative with an effective interest rate of only 5.4% for the three months ended March 31, 2007. The Fund's interest rates are primarily based on short term Bankers Acceptance rates plus a stamping fee.

Interest and Accretion on Convertible Debentures Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Interest on convertible debentures ($000) $ 3,238 $ 2,345 38% per boe $ 1.24 $ 1.47 (16)% Accretion on convertible debentures ($000) $ 599 $ 461 30% per boe $ 0.23 $ 0.29 (21)% Convertible debentures maturity value at March 31 ($000) $ 180,730 $ 113,531 59%

Interest on convertible debentures has increased 38% and accretion on convertible debentures has increased 30% for the three months ended March 31, 2007 as compared to the same period of 2006. The increases in total interest and accretion for the quarter as well as the increased convertible debentures maturity value are due to Advantage assuming Ketch's 6.50% convertible debentures in the merger. The increased interest and accretion from the additional debentures has been partially offset for the quarter due to the exchange of convertible debentures to Trust Units during 2006 that pay distributions rather than interest. During the three months ended March 31, 2007, there were no convertible debenture conversions.

Cash Netbacks Three months ended Three months ended March 31, 2007 March 31, 2006 $000 per boe $000 per boe ------------------------------------------------------------------------- Revenue $ 129,272 $ 49.51 $ 86,901 $ 54.49 Realized gain on derivatives 6,230 2.39 - - Royalties (26,165) (10.02) (16,340) (10.25) Operating costs (30,270) (11.59) (15,066) (9.45) ------------------------------------------------------------------------- Operating $ 79,067 $ 30.29 $ 55,495 $ 34.79 General and administrative (4,716) (1.81) (1,966) (1.23) Management fee - - (832) (0.52) Interest (5,187) (1.99) (3,193) (2.00) Interest on convertible debentures (3,238) (1.24) (2,345) (1.47) Taxes (281) (0.11) (529) (0.33) ------------------------------------------------------------------------- Funds from operations $ 65,645 $ 25.14 $ 46,630 $ 29.24 -------------------------------------------------------------------------

Funds from operations of Advantage for the quarter ended March 31, 2007 increased to $65.6 million from $46.6 million in the prior year. However, the cash netback per boe for March 31, 2007 was $25.14, 14% lower than the $29.24 realized during the same period of 2006. The lower cash netback per boe is primarily due to lower revenues per boe resulting from softer natural gas prices as well as higher operating costs. Operating costs per boe for the three months ended March 31, 2007 were $11.59, an increase of 23% from the $9.45 experienced in 2006. Operating costs have steadily increased over the past year due to significantly higher field costs associated with supplies and services that has resulted from the high level of industry activity and an overall industry labour cost increase.

Depletion, Depreciation and Accretion Three months ended March 31 2007 2006 % change ------------------------------------------------------------------------- Depletion, depreciation & accretion ($000) $ 63,918 $ 30,023 113% per boe $ 24.48 $ 18.82 30%

Depletion and depreciation of property and equipment is provided on the "unit-of-production" method based on total proved reserves. The depletion, depreciation and accretion ("DD&A") provision has increased 113% for the three months ended March 31, 2007 due to the 64% increase of daily production volumes mainly from the Ketch acquisition. The DD&A per boe has increased by 30% for the three months ended March 31, 2007 compared to the prior year. The higher DD&A per boe was due to a higher valuation for the Ketch reserves than accumulated from prior acquisitions and development activities.

Taxes

Current taxes paid or payable for the quarter ended March 31, 2007 amounted to $0.3 million, compared to $0.5 million expensed for the same period of 2006. 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 operating company's assets and liabilities. For the three months ended March 31, 2007, the Fund recognized an income tax reduction of $16.6 million compared to a reduction of $2.5 million for 2006.

Under the Fund's current structure, payments are made between the operating company and the Fund transferring income tax obligations to the Unitholders. Therefore, based on the current structure and existing legislation, no cash income taxes are to be paid by the operating company or the Fund, and as such, the future income tax liability recorded on the balance sheet will be recovered through earnings over time. As at March 31, 2007, the operating company had a future income tax liability balance of $45.3 million, compared to $61.9 million at December 31, 2006. Canadian generally accepted accounting principles require that a future income tax liability be recorded when the book value of assets exceeds the balance of tax pools.

On October 31, 2006, the Federal Government proposed changes to Canada's tax system that include altering the tax treatment of income trusts. The government proposed 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 in addition to personal tax as if they were dividends from a taxable Canadian corporation. The changes are proposed to take effect in 2011 for existing publicly-traded trusts. If enacted, the proposal could affect the Fund in several ways, and Advantage is currently assessing several options for the future. The Fund may allocate a portion of cash flows to additional tax on distributions, resulting in less cash flow available for distribution or the Fund may determine strategic alternatives such as increasing cash flow allocated to capital spending, conversion to a corporation, or paying a higher percentage of distributions on a return of capital basis, all of which could result in a decrease or elimination of distributions.

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 2007 2008 2009 2010 2011 ------------------------------------------------------------------------- Building leases $ 4.8 $ 1.6 $ 1.4 $ 0.8 $ 0.8 $ 0.2 Capital leases 2.5 2.2 0.3 - - - Pipeline/transportation 5.5 2.9 2.0 0.5 0.1 - Convertible debentures(1) 180.7 1.4 5.4 57.1 70.0 46.8 ------------------------------------------------------------------------- Total contractual obligations $193.5 $ 8.1 $ 9.1 $ 58.4 $ 70.9 $ 47.0 ------------------------------------------------------------------------- (1) As at March 31, 2007, Advantage had $180.7 million convertible debentures outstanding. Each series of convertible debentures are convertible to Trust Units based on an established conversion price. The Fund expects that the obligations related to convertible debentures will be settled either directly or indirectly through the issuance of Trust Units. (2) Bank indebtedness of $354.4 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) March 31, 2007 ------------------------------------------------------------------------- Bank indebtedness (long-term) $ 354,443 Working capital deficit(1) 31,896 ------------------------------------------------------------------------- Net debt $ 386,339 ------------------------------------------------------------------------- Trust Units outstanding (000) 115,050 Trust Unit closing market price ($/Trust Unit) $ 11.84 ------------------------------------------------------------------------- Market value $ 1,362,192 ------------------------------------------------------------------------- Convertible debentures maturity value (long-term) $ 179,245 ------------------------------------------------------------------------- Total capitalization $ 1,927,776 ------------------------------------------------------------------------- (1) Working capital deficit includes accounts receivable, prepaid expenses and deposits, accounts payable and accrued liabilities, distributions payable, and the current portion of capital lease obligations and convertible debentures. Unitholders' Equity and Convertible Debentures

Advantage has utilized a combination of Trust Units, convertible debentures and bank debt to finance acquisitions and development activities.

As at March 31, 2007, the Fund had 115.0 million Trust Units outstanding. On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus an additional 800,000 Trust Units upon exercise of the Underwriters' over-allotment option on March 7, 2007, at $12.80 per Trust Unit for approximate net proceeds of $104.1 million (net of Underwriters' fees and other issue costs of $6.0 million). The net proceeds of the offering were used to pay down bank indebtedness and to subsequently fund capital and general corporate expenditures. As at May 11, 2007, Advantage had 115.4 million Trust Units issued and outstanding.

On July 24, 2006, Advantage adopted a Premium Distribution(TM), Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan"). For Unitholders that elect to participate in the Plan, Advantage will settle the monthly distribution obligation through 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 three months ended March 31, 2007, 1,069,989 Trust Units were issued as a result of the Plan, generating $12.4 million reinvested in the Fund and representing an approximate 23% participation rate.

As at March 31, 2007, the Fund had $180.7 million convertible debentures outstanding that were convertible to 8.3 million Trust Units based on the applicable conversion prices. During the three months ended March 31, 2007, no convertible debentures were exchanged and as at May 11, 2007, the convertible debentures outstanding have not changed from December 31, 2006.

Bank Indebtedness, Credit Facility and Other Obligations

At March 31, 2007, Advantage had bank indebtedness outstanding of $354.4 million, after executing the highest quarter of capital spending expected in 2007. The Fund has a $600 million credit facility agreement consisting of a $580 million extendible revolving loan facility and a $20 million operating loan facility. The current credit facilities are secured by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement from the Fund covering all assets and cash flows.

At March 31, 2007, Advantage had a working capital deficiency of $31.9 million. Our working capital includes items expected for normal operations such as trade receivables, prepaids, deposits, trade payables and accruals as well as the current portion of capital lease obligations and convertible debentures. Working capital varies primarily due to the timing of such items, the current level of business activity including our capital program, commodity price volatility, and seasonal fluctuations. Advantage has no unusual working capital requirements. We do not anticipate any problems in meeting future obligations as they become due given the strength of our funds from operations. It is also important to note that working capital is effectively integrated with Advantage's operating credit facility, which assists with the timing of cash flows as required.

Advantage generally does not make use of capital leases to finance development expenditures. However, Advantage currently has two capital leases outstanding at March 31, 2007 for $2.5 million that were both assumed from corporate acquisitions.

Capital Expenditures Three months ended March 31 ($000) 2007 2006 ------------------------------------------------------------------------- Land and seismic $ 2,340 $ 2,228 Drilling, completions and workovers 27,135 14,007 Well equipping and facilities 20,110 4,288 Other 111 466 ------------------------------------------------------------------------- $ 49,696 $ 20,989 Property acquisitions 12,851 - Property dispositions (427) - ------------------------------------------------------------------------- Total capital expenditures $ 62,120 $ 20,989 -------------------------------------------------------------------------

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 preserve a balance of year round access. We focus on areas where past activity has yielded long-life reserves with high cash netbacks. With the integration of the Ketch assets, Advantage is very well positioned to selectively exploit the highest value-generating drilling opportunities given the size, strength and diversity of our asset base. As a result, the Fund has a high level of flexibility to distribute its capital program and ensure a risk-balanced platform of projects. Our preference is to operate a high percentage of our properties such that we can maintain control of capital expenditures, operations and cash flows.

For the three month period ended March 31, 2007, the Fund had a very active capital program and spent a net $62.1 million. Approximately $27.1 million was expended on drilling and completion operations where the Fund drilled a total of 24.1 net (39 gross) wells at a 97% success rate. During the quarter we drilled 9.9 net (13 gross) gas wells at Martin Creek, 2.3 net (6 gross) gas wells at Chigwell, one 100% working interest gas well at both Boundary Lake and Westerose, three 100% working interest oil wells at Nevis, two 100% working interest oil wells and 0.2 net (1 gross) gas well at Willesden Green, and one 100% working interest oil well at Pinto as well as several wells at other minor properties. Total capital spending in the quarter included $21.7 million at Martin Creek, $7.3 million at Nevis, $4.9 million at Willesden Green, $3.1 million at Brazeau, and $2.4 million in SE Saskatchewan. The $12.9 million property acquisition was for producing properties and undeveloped land at the Fund's core area, Nevis.

The following table summarizes the various funding requirements during the three months ended March 31, 2007 and the sources of funding to meet those requirements.

Sources and Uses of Funds Three months ended March 31, ($000) 2007 ------------------------------------------------------------------------- Sources of funds Units issued, net of costs $ 116,481 Funds from operations 65,645 Property dispositions 427 ------------------------------------------------------------------------- $ 182,553 ------------------------------------------------------------------------- Uses of funds Decrease in bank indebtedness $ 56,131 Distributions to Unitholders 51,919 Expenditures on property and equipment 49,696 Property acquisitions 12,851 Increase in working capital 7,596 Expenditures on asset retirement 4,009 Reduction of capital lease obligations 351 ------------------------------------------------------------------------- $ 182,553 ------------------------------------------------------------------------- Quarterly Performance 2007 2006 ($000, except as otherwise indicated) Q1 Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Daily production Natural gas (mcf/d) 114,324 117,134 122,227 70,293 65,768 Crude oil and NGLs (bbls/d) 9,958 9,570 9,330 6,593 6,760 Total (boe/d) 29,012 29,092 29,701 18,309 17,721 Average prices Natural gas ($/mcf) Excluding hedging $ 7.61 $ 6.90 $ 5.89 $ 6.18 $ 8.69 Including hedging $ 8.06 $ 7.27 $ 5.90 $ 6.18 $ 8.69 AECO monthly $ 7.46 $ 6.36 $ 6.03 $ 6.28 $ 9.31 Crude oil and NGLs ($/bbl) Excluding hedging $ 56.84 $ 54.58 $ 67.77 $ 68.69 $ 58.26 Including hedging $ 58.64 $ 55.86 $ 67.77 $ 68.69 $ 58.26 WTI (US$/bbl) $ 58.12 $ 60.21 $ 70.55 $ 70.75 $ 63.88 Total revenues (before royalties) $135,502 $127,539 $124,521 $ 80,766 $ 86,901 Net income $ 341 $ 8,736 $ 1,209 $ 23,905 $ 15,964 per Trust Unit - basic $ 0.00 $ 0.08 $ 0.01 $ 0.38 $ 0.27 - diluted $ 0.00 $ 0.08 $ 0.01 $ 0.38 $ 0.27 Funds from operations $ 65,645 $ 62,737 $ 63,110 $ 42,281 $ 46,630 Distributions declared $ 50,206 $ 58,791 $ 60,498 $ 53,498 $ 44,459 Payout ratio (%) 76% 94% 96% 127% 95% 2005 ($000, except as otherwise indicated) Q4 Q3 Q2 ----------------------------------------------------- Daily production Natural gas (mcf/d) 72,587 75,994 79,492 Crude oil and NGLs (bbls/d) 7,106 7,340 6,772 Total (boe/d) 19,204 20,006 20,021 Average prices Natural gas ($/mcf) Excluding hedging $ 11.68 $ 8.25 $ 7.27 Including hedging $ 10.67 $ 7.79 $ 7.30 AECO monthly $ 11.68 $ 8.15 $ 7.38 Crude oil and NGLs ($/bbl) Excluding hedging $ 60.14 $ 66.00 $ 56.57 Including hedging $ 59.53 $ 61.10 $ 56.24 WTI (US$/bbl) $ 60.04 $ 63.17 $ 53.13 Total revenues (before royalties) $110,172 $ 95,715 $ 87,476 Net income $ 25,846 $ 18,674 $ 26,537 per Trust Unit - basic $ 0.45 $ 0.33 $ 0.46 - diluted $ 0.45 $ 0.32 $ 0.46 Funds from operations $ 60,906 $ 55,575 $ 49,705 Distributions declared $ 43,265 $ 43,069 $ 44,693 Payout ratio (%) 71% 77% 90%

The table above highlights the Fund's performance for the first quarter of 2007 and also for the preceding seven quarters. During 2005, production continued to experience normal declines until a more significant decrease occurred in the first quarter of 2006 due to a one-time adjustment for several payout wells, restricted production on wells in Chip Lake and Nevis, and some minor non-core property dispositions that occurred in 2005. Production increased in the second quarter of 2006 with the addition of eight days of production from the Ketch properties and further increased in the third quarter of 2006 as the acquisition was fully integrated with Advantage. Advantage's revenues and funds from operations increased beginning in the third quarter of 2006 primarily due to the production from the merger with Ketch, offset by lower natural gas prices. Net income has been lower during the last three quarters due to reduced natural gas prices realized during the periods, amortization of the management internalization consideration, and increased depletion and depreciation expense due to the Ketch merger. During 2006, the payout ratio was higher relative to prior quarters as a result of considerably weak natural gas prices relative to the distribution level. Additionally, the timing of the Ketch merger significantly increased the payout ratio for the second quarter of 2006 as the arrangement closed prior to the June record date resulting in the payment of a full month distribution to Ketch Unitholders whereas funds from operations for June only included eight days of cash flows from the Ketch properties. The payout ratio in the first quarter of 2007 decreased as we reduced the distribution level to reflect current commodity prices.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires Management to make certain judgments and estimates. Changes in these judgments and estimates could have a material impact on the Fund's financial results and financial condition. Management relies on the estimate of reserves as prepared by the Fund's independent qualified reserves evaluator. The process of estimating reserves is critical to several accounting estimates. The process of estimating reserves is complex and requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development and production activities becomes available and as economic conditions impact crude oil and natural gas prices, operating costs, royalty burden changes, and future development costs. Reserve estimates impact net income through depletion and depreciation of property and equipment, the provision for asset retirement costs and related accretion expense, and impairment calculations for property and equipment 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.

Controls and Procedures

The Fund has established procedures and internal control systems to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Management of the Fund is committed to providing timely, accurate and balanced disclosure of all material information about the Fund. Disclosure controls and procedures are in place to ensure all ongoing reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and Vice-President Finance and Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regular filings, fairly present in all material respects the financial condition, results of operations, and cash flows as of the dates and for the periods presented in the filings. The certifications further acknowledge that the filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the filings. During the first quarter of 2007, there were no significant changes that would materially affect, or are reasonably likely to materially affect, the internal controls over financial reporting.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation. Further, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Outlook

The Fund has established a 2007 Budget, as approved by the Board of Directors, that retains a high degree of activity and will focus on drilling in many of our key properties where a high level of success was realized through 2006. Capital will also be directed to accommodate facility expansions and further develop enhanced recovery schemes as necessary. New drill bit additions are expected to be more effective in replacing production as corporate declines have continued to subside through the first quarter of 2007. Advantage's production now contains very little flush production from high impact wells and concentrated drilling programs (from 2004 and 2005 activities) creating a balanced and predictable platform. During the second and third quarters of 2007, we expect two major third party plant turnarounds to occur which will significantly affect our Lookout Butte and Westerose properties. These two turnarounds combined with well payouts are expected to result in an impact of approximately 400 boe/d to the 2007 annual average production. Overall, we expect production in 2007 to average between 27,500 to 29,500 boe/d.

Advantage's 2007 capital expenditures budget of $120 to $145 million includes the drilling, completion and tie-in of 107 gross wells (64 net) weighted approximately 50% toward light oil and 50% to natural gas. In Northeast B.C., a 17 well (14 net) natural gas drilling program was substantially completed in the first quarter of 2007 at Martin Creek. This program exploited the northern portions of the Field where a successful drilling program was conducted in 2006 which extended pool boundaries. Results confirm a very successful program with tested well deliverability in excess of facilities capacity and budget assumptions. Combined with Advantage's already commanding position of facilities infrastructure and operatorship, we estimate three to four years of drilling inventory in this property. At Sunset, in Northern Alberta, four wells are planned to follow-up the successful 2006 development drilling program and capital will also be required to expand water flood facilities in this light oil pool. In Central Alberta, a 12 well (12 net) program is planned at Nevis for 40 degree light oil where horizontal drilling in 2006 showed excellent results. A net 15 sections of land were added through deals with industry third parties in 2006 bringing the total land under control to 37.5 net sections in this property. A second development drilling program in the western portion of the Nevis property is underway and facilities will be constructed to accommodate production additions. Additional gas opportunities will be pursued in the Central Alberta areas targeting down spacing and follow-up to successes. Initial drilling results on the west side of Nevis are comparable to wells previously drilled to date. In Southern Alberta and S.E. Saskatchewan, 13 wells (10 net) will be drilled for oil targets in 2007.

Operating costs are forecasted to be closer to the upper end of our guidance range of $9.50 to $10.50/boe range as higher gas prices indicated by the current strip price through the summer of 2007 suggest higher power costs than what was realized in 2006. In addition, higher property taxes, surface rentals and additional trucking costs due to continued pipeline restrictions in Southeast Saskatchewan are expected to occur in 2007. Advantage is undertaking several operating cost reduction initiatives through 2007 to help offset these increases.

Advantage's funds from operations in 2007 will continue to be impacted by the volatility of crude oil and natural gas prices and the $US/$Canadian exchange rate. Advantage will continue to follow its strategy of acquiring properties that provide low risk development opportunities and enhance long term cash flow. Advantage will also continue to focus on low cost production and reserve additions through low to medium risk development drilling opportunities that have arisen as a result of the acquisitions completed in prior years and from the significant inventory of drilling opportunities that has resulted from the Ketch merger. The synergy of larger size and the complementary winter/summer drilling programs with the Ketch merger is providing benefits in terms of securing services, flexibility and quality of our capital program.

Looking forward, Advantage's high quality assets, three year drilling inventory, hedging program and excellent tax pools provides many options for the Fund and we are committed to maximizing value generation for our Unitholders.

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.

May 11, 2007 CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets March 31, December 31, (thousands of dollars) 2007 2006 ------------------------------------------------------------------------- (unaudited) Assets Current assets Accounts receivable $ 81,580 $ 79,537 Prepaid expenses and deposits 16,555 16,878 Derivative asset (note 8) 1,093 9,840 ------------------------------------------------------------------------- 99,228 106,255 Deposit on property acquisition - 1,410 Derivative asset (note 8) 545 593 Fixed assets (note 2) 1,756,251 1,753,058 Goodwill 120,271 120,271 ------------------------------------------------------------------------- $ 1,976,295 $ 1,981,587 ------------------------------------------------------------------------- Liabilities Current liabilities Accounts payable and accrued liabilities $ 108,823 $ 116,109 Distributions payable to Unitholders 17,257 18,970 Current portion of capital lease obligations (note 3) 2,481 2,527 Current portion of convertible debentures (note 5) 1,470 1,464 Derivative liability (note 8) 3,234 - ------------------------------------------------------------------------- 133,265 139,070 Capital lease obligations (note 3) - 305 Bank indebtedness (note 4) 354,443 410,574 Convertible debentures (note 5) 171,412 170,819 Asset retirement obligations 35,306 34,324 Future income taxes 45,328 61,939 ------------------------------------------------------------------------- 739,754 817,031 ------------------------------------------------------------------------- Unitholders' Equity Unitholders' capital (note 6) 1,714,608 1,592,758 Convertible debentures equity component (note 5) 8,041 8,041 Contributed surplus (note 6) 863 863 Accumulated deficit (note 7) (486,971) (437,106) ------------------------------------------------------------------------- 1,236,541 1,164,556 ------------------------------------------------------------------------- $ 1,976,295 $ 1,981,587 ------------------------------------------------------------------------- Commitments (note 9) See accompanying Notes to Consolidated Financial Statements Consolidated Statements of Income, Comprehensive Income and Accumulated Deficit Three months Three months ended ended (thousands of dollars, except for per March 31, March 31, Trust Unit amounts) (unaudited) 2007 2006 ------------------------------------------------------------------------- Revenue Petroleum and natural gas $ 129,272 $ 86,901 Realized gain on derivatives (note 8) 6,230 - Unrealized loss on derivatives (note 8) (12,029) - Royalties, net of Alberta Royalty Credit (26,165) (16,340) ------------------------------------------------------------------------- 97,308 70,561 ------------------------------------------------------------------------- Expenses Operating 30,270 15,066 General and administrative 4,716 1,966 Management fee - 832 Performance incentive - 2,680 Management internalization (note 6) 5,369 - Interest 5,187 3,193 Interest and accretion on convertible debentures 3,837 2,806 Depletion, depreciation and accretion 63,918 30,023 ------------------------------------------------------------------------- 113,297 56,566 ------------------------------------------------------------------------- Income (loss) before taxes and non-controlling interest (15,989) 13,995 Future income tax reduction (16,611) (2,527) Income and capital taxes 281 529 ------------------------------------------------------------------------- (16,330) (1,998) ------------------------------------------------------------------------- Net income before non-controlling interest 341 15,993 Non-controlling interest - 29 ------------------------------------------------------------------------- Net income and comprehensive income 341 15,964 Accumulated deficit, beginning of period (437,106) (269,674) Distributions declared (50,206) (44,459) ------------------------------------------------------------------------- Accumulated deficit, end of period $ (486,971) $ (298,169) ------------------------------------------------------------------------- Net income per Trust Unit (note 6) Basic $ 0.00 $ 0.27 Diluted $ 0.00 $ 0.27 ------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements Consolidated Statements of Cash Flows Three months Three months ended ended March 31, March 31, (thousands of dollars) (unaudited) 2007 2006 ------------------------------------------------------------------------- Operating Activities Net income $ 341 $ 15,964 Add (deduct) items not requiring cash: Unrealized loss on derivatives 12,029 - Performance incentive - 2,680 Management internalization 5,369 - Accretion on convertible debentures 599 461 Depletion, depreciation and accretion 63,918 30,023 Future income taxes (16,611) (2,527) Non-controlling interest - 29 Expenditures on asset retirement (4,009) (1,033) Changes in non-cash working capital (11,116) (5,717) ------------------------------------------------------------------------- Cash provided by operating activities 50,520 39,880 ------------------------------------------------------------------------- Financing Activities Units issued, net of costs (note 6) 116,481 - Increase (decrease) in bank indebtedness (56,131) 26,301 Reduction of capital lease obligations (351) (88) Distributions to Unitholders (51,919) (44,054) ------------------------------------------------------------------------- Cash provided by (used in) financing activities 8,080 (17,841) ------------------------------------------------------------------------- Investing Activities Expenditures on property and equipment (49,696) (20,989) Property acquisitions (12,851) - Property dispositions 427 - Changes in non-cash working capital 3,520 (1,050) ------------------------------------------------------------------------- Cash used in investing activities (58,600) (22,039) ------------------------------------------------------------------------- Net change in cash - - Cash, beginning of period - - ------------------------------------------------------------------------- Cash, end of period $ - $ - ------------------------------------------------------------------------- Supplementary Cash Flow Information Interest paid $ 7,005 $ 6,643 Taxes paid $ 361 $ 529 See accompanying Notes to Consolidated Financial Statements NOTES TO CONSOLIDATED FINANCIAL STATEMENTS March 31, 2007 (unaudited) All tabular amounts in thousands except for Trust Units and per Trust Unit amounts The interim consolidated financial statements of Advantage Energy Income Fund ("Advantage" or the "Fund") have been prepared by management in accordance with Canadian generally accepted accounting principles using the same accounting policies as those set out in note 2 to the consolidated financial statements for the year ended December 31, 2006, except as described below. The interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements of Advantage for the year ended December 31, 2006 as set out in Advantage's Annual Report. 1. Changes in Accounting Policies (a) Financial Instruments Effective January 1, 2007, the Fund adopted CICA Handbook sections 3855 "Financial Instruments - Recognition and Measurement", 3862 "Financial Instruments - Disclosures", 3863 "Financial Instruments - Presentation", and 3865 "Hedges". Section 3855 "Financial Instruments - Recognition and Measurement" establishes criteria for recognizing and measuring financial instruments including financial assets, financial liabilities and non-financial derivatives. Under this standard, all financial instruments must initially be recognized at fair value on the balance sheet. Measurement of financial instruments subsequent to the initial recognition, as well as resulting gains and losses, are recorded based on how each financial instrument was initially classified. The Fund has classified each identified financial instrument into the following categories: held for trading, loans and receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Held for trading financial instruments are measured at fair value with gains and losses recognized in earnings immediately. Available for sale financial assets are measured at fair value with gains and losses, other than impairment losses, recognized in other comprehensive income and transferred to earnings when the asset is derecognized. Loans and receivables, held to maturity investments and other financial liabilities are recognized at amortized cost using the effective interest method and impairment losses are recorded in earnings when incurred. Upon adoption and with all new financial instruments, an election is available that allows entities to classify any financial instrument as held for trading. Only those financial assets and liabilities that must be classified as held for trading by the standard have been classified as such by the Fund. As the Fund frequently utilizes non- financial derivative instruments to manage market risk associated with volatile commodity prices, such instruments must be classified as held for trading and recorded on the balance sheet at fair value as derivative assets and liabilities. Section 3865 "Hedges" provides an alternative to recognizing gains and losses on derivatives in earnings if the instrument is designated as part of a hedging relationship and meets the necessary criteria. Under the alternative hedge accounting treatment, gains and losses on derivatives classified as effective hedges are included in other comprehensive income until the time at which the hedged item is realized. The Fund does not utilize derivative instruments for speculative purposes but has elected not to apply hedge accounting. Therefore, gains and losses on these instruments are recorded as unrealized gains and losses on derivatives in the consolidated statement of income, comprehensive income and accumulated deficit in the period they occur and as realized gains and losses on derivatives when the contracts are settled. Since unrealized gains and losses on derivatives are non-cash items, there is no impact on the statement of cash flows as a result of their recognition. In some instances, derivative financial instruments can be embedded within other contracts. Embedded derivatives within a host contract must be recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative, and the combined contract is not classified as held for trading or designated at fair value. The Fund selected January 1, 2003, as its accounting transition date for any potential embedded derivatives and has not identified any embedded derivatives that would require separation from the host contract and fair value accounting. Transaction costs are frequently attributed to the acquisition or issue of a financial asset or liability. Section 3855 requires that such transaction costs incurred on held for trading financial instruments be expensed immediately. For other financial instruments, an entity can adopt an accounting policy of either expensing transaction costs as they occur or adding such transaction costs to the fair value of the financial instrument. The Fund has chosen a policy of adding transaction costs to the fair value initially recognized for financial assets and liabilities that are not classified as held for trading. The Fund has adopted the new standards prospectively as required which allows amendments to the carrying values of financial instruments, effective as of the adoption date, to be recognized as an adjustment to the beginning balance of accumulated deficit. As the new standards have not resulted in any significant changes to the recognition and measurement of the Fund's financial instruments, no adjustment to accumulated deficit was required. The new standards also require several additional disclosures in the notes to the financial statements. Among the disclosures required, the Fund must disclose the exposure to various risks associated with financial instruments and the policies that exist to manage these risks. (b) Comprehensive Income Effective January 1, 2007, the Fund adopted CICA Handbook section 1530 "Comprehensive Income". The Fund has adopted this section retroactively and there were no changes to prior periods. Comprehensive income consists of net income and other comprehensive income ("OCI") with amounts included in OCI shown net of tax. Accumulated other comprehensive income is a new equity category comprised of the cumulative amounts of OCI. To date, the Fund does not have any adjustments in OCI and therefore comprehensive income is currently equal to net income. (c) Accounting Changes Effective January 1, 2007, the Fund adopted the revised recommendations of CICA section 1506 "Accounting Changes". The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including the changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007. (d) Recent Accounting Pronouncements Issued But Not Implemented The CICA has issued section 1535 "Capital Disclosures", which will be effective January 1, 2008 for the Fund. Section 1535 will require the Fund to provide additional disclosures relating to capital and how it is managed. It is not anticipated that the adoption of section 1535 will impact the amounts reported in the Fund's financial statements as they primarily relate to disclosure. 2. Fixed Assets Accumulated Depletion and Net Book March 31, 2007 Cost Depreciation Value --------------------------------------------------------------------- Petroleum and natural gas properties $ 2,391,363 $ 639,774 $ 1,751,589 Furniture and equipment 8,286 3,624 4,662 --------------------------------------------------------------------- $ 2,399,649 $ 643,398 $ 1,756,251 --------------------------------------------------------------------- Accumulated Depletion and Net Book December 31, 2006 Cost Depreciation Value --------------------------------------------------------------------- Petroleum and natural gas properties $ 2,324,948 $ 576,707 $ 1,748,241 Furniture and equipment 8,175 3,358 4,817 --------------------------------------------------------------------- $ 2,333,123 $ 580,065 $ 1,753,058 --------------------------------------------------------------------- During the three months ended March 31, 2007, Advantage capitalized general and administrative expenditures directly related to exploration and development activities of $1,969,000 (March 31, 2006 - $838,000). 3. Capital Lease Obligations The Fund has capital leases on a variety of property and equipment. Future minimum lease payments at March 31, 2007 consist of the following: 2007 $ 2,207 2008 308 ------------------------------------------------- 2,515 Less amounts representing interest (34) ------------------------------------------------- Current portion $ 2,481 ------------------------------------------------- 4. Bank Indebtedness Advantage has a credit facility agreement with a syndicate of financial institutions which provides for a $580 million extendible revolving loan facility and a $20 million operating loan facility. The loan's interest rate is based on either prime, US base rate, LIBOR or bankers' acceptance rates, at the Fund's option, subject to certain basis point or stamping fee adjustments ranging from 0.00% to 1.25% depending on the Fund's debt to cash flow ratio. The credit facilities are secured by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement from the Fund covering all assets and cash flows. The credit facilities are subject to review on an annual basis with the next review to occur in June 2007. Various borrowing options are available under the credit facilities, including prime rate-based advances, US base rate advances, US dollar LIBOR advances and bankers' acceptances loans. The credit facilities constitute a revolving facility for a 364 day term which is extendible annually for a further 364 day revolving period at the option of the syndicate. If not extended, the revolving credit facility is converted to a two year term facility with the first payment due one year and one day after commencement of the term. The credit facilities contain standard commercial covenants for facilities of this nature. The only financial covenant is a requirement for AOG to maintain a minimum cash flow to interest expense ratio of 3.5:1, determined on a rolling four quarter basis. Breach of any covenant will result in an event of default in which case AOG has 20 days to remedy such default. If the default is not remedied or waived, and if required by the majority of lenders, the administrative agent of the lenders has the option to declare all obligations of AOG under the credit facilities to be immediately due and payable without further demand, presentation, protest, or notice of any kind. Distributions by AOG to the Fund (and effectively by the Fund to Unitholders) are subordinated to the repayment of any amounts owing under the credit facilities. Distributions to Unitholders are not permitted if the Fund is in default of such credit facilities or if the amount of the Fund's outstanding indebtedness under such facilities exceeds the then existing current borrowing base. Interest payments under the debentures are also subordinated to indebtedness under the credit facilities and payments under the debentures are similarly restricted. For the three months ended March 31, 2007, the effective interest rate on the outstanding amounts under the facility was approximately 5.4% (March 31, 2006 - 4.9%). 5. 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% 7.75% --------------------------------------------------------------------- Issue date Oct. 18, July 8, Dec. 2, Sep. 15, 2002 2003 2003 2004 Maturity date Nov. 1, Aug. 1, Feb. 1, Dec. 1, 2007 2008 2009 2011 Conversion price $ 13.30 $ 17.00 $ 16.50 $ 21.00 Liability component $ 52,722 $ 28,662 $ 56,802 $ 47,444 Equity component 2,278 1,338 3,198 2,556 ---------------------------------------------------------------------

Gross proceeds 55,000 30,000 60,000 50,000