Clean Power Income Fund Announces 2005 Fourth Quarter and Year-end Results

Toronto, Ontario, Canada March 20, 2006 - Continued steady performance from windpower, waterpower and biomass - Operational turnaround continues at GRS - Significant progress on Erie Shores wind project Clean Power Income Fund (CLE.UN:TSX) today announced its financial results for the fourth quarter and the year ended December 31, 2005. Revenue generated from Clean Power’s continuing operations (water power and biomass facilities in Canada and windpower facilities in the U.S.) totalled $9.4 million for the fourth quarter of 2005, representing a 12 percent increase over the $8.4 million earned for the same period in 2004. On a year-over-year basis, revenue from continuing operations was $31.2 million, up from $30.4 million for 2004. Stable performance of the Fund’s core assets in 2005 supported progressive improvement in the performance of Gas Recovery Systems, LLC (“GRS”). The Fund’s investment in GRS through its operating subsidiary, Clean Power Operating Trust (“CPOT”), is now classified for accounting purposes as “discontinued operations” to reflect the ongoing work of the Special Committee of the Board of Trustees of CPOT on unitholder value enhancement opportunities with respect to the disposition of GRS, as announced on March 16, 2005. For the fourth quarter, the Fund recorded a loss on the discontinued operations (GRS) of $0.2 million, compared with a $3.9 million loss for the same period in 2004. Year over year, the additional expenses and downtime required to produce GRS’s operational turnaround resulted in a net loss of $5.7 million for 2005, compared with net income from GRS operations of $4.1 million for the prior year. For the fourth quarter, Clean Power Income Fund generated cash available for distribution of $4.1 million from continuing operations (2004 – $3.2 million) and $1.8 million from discontinued operations (2004 – $4.2 million). As a result of the adoption of Variable Interest Entity (“VIE”) accounting on January 1, 2005, total cash available for distribution for 2005 of $18.1 million or $0.511 per unit includes the cash from operations of GRS (regardless of whether such cash was paid to CPOT or retained by GRS), net of GRS non-expansion capital expenditures, whereas 2004 results ($28.8 million or $0.815 per unit) have not been restated and are based on interest earned by CPOT on the GRS loans. For comparison on a fully consolidated (VIE) basis, cash available for distribution for the fourth quarter of 2005 from all operations was 36 percent higher than in the first quarter of 2005, strengthening the Fund’s payout ratio from 140% for the first quarter to 103% for the fourth quarter, as follows: Distributions to unitholders in 2005 totalled $24.8 million or $0.70 per unit, and were supported by a release from the Reserve Account (net of investment income) of $1.4 million, compared with $1.7 million in 2004. As at December 31, 2005, the balance in the Reserve Account was $8.8 million and the Fund had $4.8 million in cash and cash equivalents, an increase of $0.5 million over 2004. Total long-term debt of $223.0 million or 45 percent of assets includes both the $168.3 million in project debt and long-term project financing for the Erie Shores Wind Farm in 2005, and $55.0 million in convertible debentures issued in 2004. The current portion of long-term debt was $1.2 million as of the 2005 year-end (2004 – $2.8 million). “2005 was a recovery year for Clean Power Income Fund,” stated Stephen Probyn, President and Chief Executive Officer of Clean Power Inc., Manager of the Fund. “As we indicated in our 2004 Annual Report, our first priorities were to address the performance issues at GRS and to proceed with the construction and operation of Clean Power’s newest acquisition, the 99MW Erie Shores Wind Farm. We have succeeded in both endeavours. At GRS, which is one of the largest companies in its sector of the U.S. power industry, we are pleased with the progress on operational efficiencies and market opportunities made to date. At Erie Shores, we now have more than half of the project’s 66 wind turbines installed, more turbines going up day-by-day and, at the same time, the commissioning process is well underway to start selling ‘clean power’ into the Ontario grid.” OPERATING RESULTS (in thousands of Canadian dollars except per Trust Unit Amounts) Three months ended Year ended December 31 December 31 2005 2004 2005 2004 Revenues 9,415 8,447 31,184 30,441 Expenses (5,006) (5,554) (20,593) (20,260) Operating income 4,409 2,893 10,591 10,181 Interest expense (1,825) (1,762) (7,396) (5,935) Foreign exchange (loss) gain (830) 1,172 (1,070) (710) Future income tax recovery (expense) 280 164 481 Minority interest (expense) recovery (20) 17 26 (102) Net income from continuing operations 1,734 2,600 2,315 3,915 Net income (loss) from discontinued operations (167) (3,925) (5,734) 4,097 Total net income 1,567 (1,325) (3,419) 8,012 Per Trust Unit – basic and diluted 0.044 (0.037) (0.097) 0.227 Continuing Operations Operating cash flow after changes in working capital 3,574 726 9,668 13,848 Changes in working capital 778 2,301 1,292 (2,163) Cash flow from investments(1) (162) 152 976 1,184 Minority interest (expense) recovery (20) (17) 26 (102) Non-expansion capital expenditures (24) (11) (216) (82) Cash available for distribution from continuing operations 4,146 3,151 11,746 12,685 Discontinued Operations(2) Operating cash flow after changes in working capital 2,802 3,976 15,296 16,467 Changes in working capital 972 250 (1,820) (313) Non-expansion capital expenditures (1,947) (7,130) Cash available for distribution from discontinued operations 1,827 4,226 6,346 16,154 Total cash available for distribution(3) 5,973 7,377 18,092 28,839 Per Trust Unit – basic and diluted 0.169 0.209 0.511 0.815 Cash Distributions declared 6,190 7,340 24,758 32,127 Per Trust Unit – basic and diluted 0.175 0.207 0.700 0.908 Distributions supported by reserves or other non-operational cash(4) 217 6,666 3,288 Weighted average number of Trust Units outstanding – basic and diluted 35,368,597 35,368,597 35,368,597 35,368,597 (1) Consists of waterpower levelization payments and biomass principal repayments. (2) For 2005, the cash available for distribution from discontinued operations represents the cash flows from operations of GRS (regardless of whether such cash was paid to CPOT or retained by GRS), plus (minus) the net increase (decrease) in GRS’ working capital, less GRS’ non-expansion capital expenditures. Because the Fund has not restated its 2004 financial results for the adoption of AcG-15, the Fund has not recalculated cash available for distribution from discontinued operations to reflect the revised formula. Accordingly, the cash available for distribution from discontinued operations for 2004 represents interest income earned by the Fund on its loans to GRS plus (minus) an adjustment for changes in the working capital balances between the Fund and GRS. (3) “Cash available for distribution” is a measure of the Fund’s ability to make distributions to unitholders based on operating results; however, it is not defined under GAAP and it should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP as an indicator of the Fund’s performance or liquidity. Cash available for distribution is defined as: operating cash flow after changes in working capital, plus (minus) increase (decrease) in working capital, plus cash flow from investments, less minority interest expense, less non-expansion capital expenditure. (4) “Distributions supported by reserves or other non-operational cash” is a measure of the Fund’s ability to make distributions to unitholders based on operating results; however it is not defined under GAAP and should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP as an indicator of the Fund’s performance or liquidity. Distributions supported by reserves or other non-operational cash is defined as: cash distributions declared less cash available for distribution. This amount does not include cash to finance working capital. BUSINESS DEVELOPMENT ACTIVITIES On June 29, 2005, the Fund acquired AIM PowerGen Corporation’s (“AIM”) interest in the Erie Shores Wind Farm Limited Partnership, the owner of the 99 MW windpower project near the shores of Lake Erie, for nominal consideration and additional potential payments. Also on June 29, 2005, the construction and long-term project financing was completed. Construction of the project was initiated in the summer of 2005. Despite the unusual weather conditions in southern Ontario, on March 7, 2006 the Fund announced that the project had been energized and that 27, or approximately 40% of the total 66 turbines had been erected. The commercial operation date, which occurs at the completion of performance testing for all 66 turbines is expected to occur in the second quarter of 2006. During 2005, the Fund acquired, from AIM, a right of first refusal respecting a proposed 50 MW expansion of the Erie Shores Wind Farm. During the first quarter of 2005, GRS undertook an extensive refurbishment and expansion of the Arbor Hills facility, which was completed in January 2006. In the third quarter, an expansion at the Vienna Junction facility was initiated to increase direct gas sales output. This expansion was completed in January 2006. On November 15, 2004, the Fund announced its intention to participate in a 50% interest in a 20 MW windpower generating facility in Grand Manaan, New Brunswick. In November 2005, the Fund withdrew its interest in proceeding with the project and was repaid, in full, principal and accrued interest on a $400,000 secured senior promissory note provided to the owner of the project for development costs. PROPOSED TRANSACTION On August 29, 2005, a Special Committee of the CPOT Board of Trustees was formed to investigate unitholder value enhancement opportunities. The Special Committee has retained professional advisors, including Scotia Capital Inc. as overall financial advisors, to assist it. The Special Committee is comprised of two Independent Trustees, Mr. John C. Fox and Mr. Donald M. McCutchan, and one Manager Trustee, Mr. H. Allen Jackson. Initially, the Special Committee is concentrating on unitholder value enhancement opportunities with respect to the Fund’s investment in GRS. On March 16, 2006, the Fund announced a competitive process had been undertaken to dispose of the Fund’s investment in GRS and the Special Committee anticipates receiving definitive proposals shortly. Reflecting this, GRS operations and cash flow which have been consolidated with those of the Fund under VIE accounting recommendations, starting with the first quarter of 2005, are now shown under “Discontinued Operations” in the audited consolidated financial statements of the Fund for the 2005 fiscal year. The Special Committee has concluded that a disposition of the Fund’s investment in GRS is probable and expected to occur during fiscal 2006. The disposition of this investment is expected to reduce the Fund’s exposure to fluctuations in the value of the Canadian dollar relative to the U.S. dollar and to decrease variability in cash flow resulting from higher maintenance expenditures at GRS relative to the Fund’s other investments. SUMMARY OF FOURTH QUARTER RESULTS For the three months ended December 31, 2005, the Fund generated Cash Available for Distributions of $6.0 million and cash distributions declared were $6.2 million, which represents a payout ratio of 103%. Fund revenues during the fourth quarter were $9.4 million, an increase of $1.0 million over the same period in 2004. The increase resulted from improved water flows and production at the Wawatay facility, agreement on a replacement escalator and the resulting “catchup” under the Hluey Lakes PPA and higher average Alberta Power Pool prices. Of the approximately $0.4 million “catchup” at Hluey Lakes, $0.1 million relates to 2005 and approximately $25,000 relates to the fourth quarter. Operating expenses of $5.0 million in the fourth quarter of 2005 were $0.55 million lower than operating expenses during the same period in 2004. However, a receipt of $0.4 million relating to water rentals and property taxes paid at the Wawatay and Dryden facilities for prior years was netted against expenses. Without this repayment, operating expenses would have decreased by $0.15 million due to maintenance cost reductions at Whitecourt. Operating income for the three months ended December 31, 2005 of $4.4 million increased by approximately $1.5 million over the same period in 2004. Accounting for the one-time payments discussed above, this increase would have been $0.7 million. The net income from continuing operations for the 2005 fourth quarter was $1.7 million and included a $0.8 million foreign exchange loss on the Fund’s U.S. Wind Loan, as compared to a net income of $2.6 million for the fourth quarter of 2004. The decrease of $0.9 million is a result of the improvements in operating income being offset by a swing of $2.0 million in foreign exchange gain (loss). Operating cash flow after changes in working capital for the 2005 fourth quarter was $3.5 million compared to $0.7 million for the same period in 2004. OPERATING RESULTS The Fund generated operating cash flow after changes in working capital from continuing operations for the year ended December 31, 2005 of $9.7 million ($0.273 per Trust Unit), a decrease of $4.2 million from $13.8 million ($0.392 per Trust Unit) in 2004. The decrease in 2005 from 2004 was primarily due to a $3.5 million increase in working capital. This change in working capital resulted from the $1.0 million prepayment, in December, of interest on Bankers’ Acceptances outstanding in the bank credit facility, with other contributors being deferral of expenditures related to the Special Committee activities and a general increase in most current assets of the Fund. With the exception of the Erie Shores Wind Farm which was not yet operational in 2005, all of the Fund’s continuing operations generated cash flow near or in excess of expectations. Performance of the individual investments is discussed later in this report. Performance of the discontinued operations is discussed separately below under “Landfill Gas Operating Results”. Revenues from continuing operations increased to $31.2 million for the year ended December 31, 2005, compared to $30.4 million for the fiscal year 2004. The increase of $0.8 is due to the impact of increased power sales at Whitecourt and to increased returns earned on the Reserve Account. Revenues from the U.S. Wind Loan, the waterpower facilities and Chapais were consistent with 2004. Total expenses increased slightly from $20.3 million in 2004 to $20.6 million in 2005. The Fund’s administrative costs increased by $0.2 million from 2004 primarily due to very rapid evolution of regulatory change and corporate governance requirements for public companies. Interest expense on long-term debt for 2005 increased by $1.5 million, from $4.4 million in 2004 to $5.9 million in 2005 due to interest on the convertible debentures being included for a full year in 2005 and only six months in 2004. A foreign exchange loss of $1.1 million was recorded for the year ended December 31, 2005, compared to a foreign exchange loss of $0.7 million for the same period in 2004. These accounting translation losses were due to the revaluation of loans associated with the Fund’s U.S. dollar-denominated investments in windpower. They were caused by a strengthening Canadian dollar against the U.S. dollar and had no effect on the Fund’s cash flows for the period. The net income from continuing operations for the year ended December 31, 2005 was $2.3 million ($0.065 per Trust Unit), compared to $3.9 million ($0.111 per Trust Unit) in 2004. During the year, minority interest expense (recovery) incurred on the Exchangeable Class B Shares was virtually nil (2004 – expense of $0.1 million). For 2005, total Cash Available for Distributions was $18,092 (see calculation on previous page). This consists of Cash Available for Distributions from continuing operations of $11,746 ($0.332 per Trust Unit) and Cash Available for Distributions from discontinued operations of $6,346 ($0.179 per Trust Unit). The total Cash Available for Distributions in 2005 was $6,666 ($0.188 per Trust Unit) less than the $24,758 ($0.700 per Trust Unit) in distributions declared to unitholders. The difference is due to: - a planned drawdown of $1.1 million from the Reserve Account, net of Reserve Account investment income; - cash flow available for distribution from discontinued operations was $3.9 million below expectations; - a planned incremental borrowing of $1.3 million on the working capital facility; and - other items totaling $0.4 million. It is important to note that the above cash flow available for distribution amounts include the full consolidation of GRS for 2005, whereas cash flow available for distribution for 2004 was based on interest earned on the GRS loans. The Reserve Account was established when the Fund began operations on November 14, 2001 and will be utilized for working capital and distribution support on an as-needed bases. A drawdown of approximately $1.1 million from the Reserve Account was planned for 2005 to cover an expected shortfall in operating cash flow. The actual Reserve Account drawdown (net of investment income) was $1.4 million (2004 – $1.7 million). In addition, $5.3 million from the Fund’s non-Reserve Account cash accounts and credit facilities were utilized to support distributions and the increase in working capital. CONTINUING OPERATIONS Wind Operating Results Erie Shores Wind Farm On June 29, 2005, the Fund announced the acquisition of Aim PowerGen Corporation’s interest in the Erie Shores Wind Farm Limited Partnership for nominal consideration and additional potential payments. On the same date the Fund also announced the completion of its construction and long-term non-recourse project financing of the $186 million Erie Shores Wind Farm, consisting of the following three parts: - $120 million non-recourse project financing arranged and led by SunLife Financial; - $56 million equity bridge loan from CPOT’s acquisition facility provided by Scotia Capital and National Bank; and - $10 million equity bridge loan from SunLife Financial. On July 22, 2005, the start of construction on the 29 km site near the north shore of Lake Erie was formally recognized at a “ground breaking” ceremony attended by then Ontario Minister of Energy, Dwight Duncan. By December 7, 2005, all foundation work for each of the 66 wind towers was completed. On March 7, 2006, the Fund announced that the project had been “energized”, allowing for the commencement of the commissioning process, and that 27 of the 66 turbines had been erected. Operations GE Energy, one of the world’s foremost suppliers of power generation and energy delivery technology, is engaged as both the turbine supplier and the service and maintenance provider for the Erie Shores Wind Farm. GE will deliver the project’s 66 GE 1.5 MW SLE turbines under a fixed-price turbine supply agreement. This agreement with GE also provides a 4-year revenue reimbursement warranty and a performance guarantee at 97 percent availability. Under the fixed-price service & maintenance agreement, General Electric Canada will provide operating and management services to the Erie Shores facility for its first four years. U.S. Wind Loan Receivable In 2005, the Fund received its revenue in this segment solely in the form of loan interest payments from its debt investment in the six wind facilities in the United States. For the year ended December 31, 2005, the Fund received all scheduled U.S. Wind Loan interest payments. Interest income of $2.5 million is $0.2 million lower than 2004 due to the continued strengthening of the Canadian dollar relative to the U.S. dollar during 2005. The Fund has entered into put and call options so that this decrease in revenue had no impact on the operating cash flows of the Fund. For 2005, total production volumes were 274,464 MWh or 84% of the expected long-term average. This is due to the higher wind speeds and availability at Peetz being offset largely by lower wind speeds and availability at Texas Big Spring. The lower availability was caused by the ongoing gearbox and generator repairs that began in 2004. The owner continues to work with the turbine manufacturer to remedy the problems under warranty. Operating performance has a significant influence on the ability of the wind projects to service their debt obligations, but it is not the only contributing factor. The subordinated loan structure associated with the Fund’s wind investment protects the Fund from some variation in production, as does a US $1 million debt service reserve that was not utilized in either 2005 or 2004. Additional protection is afforded by insurance and equipment manufacturer warranties for availability, parts and labour as well as revenue reimbursement. As a result, the impact of any warranty expirations should not affect the Fund’s interest payments. Remaining manufacturer and operator warranties for parts and labour expired in December 2005 at Peetz Table (parts only). The remaining revenue loss warranties will expire in December 2006 at Peetz Table. For Foote Creek IV, all manufacturer, operator and revenue loss warranties are in effect until September 2015. U.S. Windpower Production (MWh) Facility Location 2005 Long-term average 2005 % of long-term average 2004 Foote Creek II Wyoming 5,475 6,600 83 5,562 Foote Creek III Wyoming 71,087 79,700 89 71,827 Foote Creek IV Wyoming 54,666 62,400 88 53,135 Peetz Table Colorado 76,245 72,700 105 78,166 Big Spring Texas 61,141 100,200 61 85,546 Chandler Minnesota 5,850 6,900 85 6,268 Total 274,464 328,500 84 298,504 U.S. Windpower Operations - (in thousands of Canadian dollars) 2005 2004 Interest earned on wind investments $ 2,503 $ 2,671 Waterpower Operating Results The Fund derives its revenue in this segment in the form of cash flow generated by operations of the four waterpower facilities where the Fund has 100% equity interest. The waterpower facilities operated at an average availability of 99% for the year ended December 31, 2005 which is consistent with the availability achieved in the corresponding period in 2004. Aggregate production in 2005 was 165,713 MWh or approximately 94% of the long-term average and 9% below 2004. All the facilities were below the long-term average for 2005 and the production levels of 2004, except for Dryden, due to low precipitation at Sechelt in the months of February, August and September; a 1 in 75 year drought at Wawatay during the second and third quarters; and unusually warm weather at the Hluey Lakes facility during the fourth quarter. Dryden was able to maintain its production levels for the 12 months of 2005 due to the optimization of the reservoirs available, which were at full capacity in the spring of 2005. For the year of 2005, revenues were $12.4 million, only $0.1 million lower than in 2004 due to decreased production at the Wawatay and Sechelt facilities, largely offset by increased power purchase agreement pricing at Sechelt and a “catchup” of approximately $0.4 million, recorded in the fourth quarter, resulting from the agreement with BC Hydro on a replacement escalator in the Hluey Lakes PPA. Of the “catchup” amount, approximately $0.1 million relates to 2005 and the remainder to the prior years. Operating expenses for the period were $0.4 million lower than for 2004. However, the Fund received a repayment of water rentals and property taxes relating to the Wawatay and Dryden facilities for prior years, up to 2003, of $0.4 million that was netted against the expenses. Therefore, on a gross basis, operating expenses were consistent with 2004 and there were no material unscheduled outages. Waterpower Production (MWh) Facility Location 2005 Long-term average 2005 % of long-term average 2004 Sechelt British Columbia 85,359 90,300 95 91,439 Wawatay Ontario 49,852 59,013 84 65,149 Dryden (3 plants) Ontario 24,198 20,568 118 18,519 Hluey Lakes British Columbia 6,304 6,714 94 6,438 Total 165,713 176,595 94 181,545 Waterpower Operations (in thousands of Canadian dollars) 2005 2004 Power sales $ 12,443 $ 12,525 Depreciation and amortization 3,129 3,250 Operating income 6,961 6,486 Interest on levelization amounts(1) 1,529 1,507 Biomass Operating Results The Fund derives revenue from this segment in the form of cash flow generated by the operations of two biomass facilities where the Fund has the following interests: a 100% equity interest in the Whitecourt facility in Alberta and a debt and 31.3% equity interest in the Chapais facility in Québec. In 2005, the Whitecourt facility and the Chapais facility operated at an average availability of 96% and 93%, respectively. For the year ended December 31, 2005, Whitecourt production of 202,565 MWh represented 101% of the long-term average and a marginal improvement over 2004. Whitecourt’s revenue for 2005 exceeded 2004′s revenue by $0.64 million, due to higher production and a higher average Power Pool price. Approximately 3.3 MW of Whitecourt’s 28 MW capacity is not contracted and is sold at the Alberta Power Pool spot price. The actual average Power Pool price for 2005 was $70 per MWh, compared to $55 per MWh for 2004. Operations and maintenance costs for 2005 were approximately $0.149 million higher than in 2004 due mainly to higher labour costs and maintenance expenses for the fuel reclaim. Operating income for the year ended December 31, 2005 was $4.2 million compared to $3.9 million for 2004. For the year ended December 31, 2005, Chapais production of 219,994 MWh marginally exceeded forecast expectations. The Chapais power contract with Hydro Québec is structured to produce approximately 50% of Chapais’ annual revenue in the four-month period December to March. The contract also has an annual maximum production target of 218,912 MWh, beyond which power pricing is reduced to a level that does not justify operating. As a result, Chapais operates at full production capacity for the four-month winter period and will balance production throughout the remaining period to achieve, but not materially exceed, the maximum production target. Chapais’ cash payments to the Fund are structured to deliver almost equal monthly payments. For the year ended December 31, 2005, Chapais’ operating costs were higher than 2004, primarily as a result of increased fuel costs related to recent Québec legislation limiting non-native tree-cutting rights. The facility has secured additional long-term fuel supply contracts which have increased the average price of fuel. This has resulted in the temporary suspension through to 2007, of $0.09 million in semi-annual interest payments scheduled to have been paid in July 2005, January 2006 and July 2006. The operator is assessing opportunities to recover expenses to offset the fuel cost increase. Interest and other investment income was $1.2 million for 2005 and principal repayments were $0.5 million, compared to $1.3 million and $0.5 million, respectively, for 2004. Production (MWh) Facility Location 2005 Long-term average 2005 % of long-term average 2004 Whitecourt Alberta 202,565 200,000 101 199,307 Chapais Québec 219,994 219,000 100 221,096 Total 422,559 419,000 101 420,403 Whitecourt Biomass Facility, Alberta Operations (in thousands of Canadian dollars) 2005 2004 Power sales $ 13,928 $ 13,283 Depreciation and amortization 2,807 2,837 Operating Income 4,193 3,915 Chapais Biomass Facility, Quebec (in thousands of Canadian dollars) 2005 2004 Interest and other investment income $ 1,190 $ 1,309 DISCONTINUED OPERATIONS – LANDFILL GAS OPERATING RESULTS The Fund’s investment in GRS is in the form of loans with monthly fixed interest payments that commenced January 31, 2003. The GRS investment is structured to provide the Fund with nearly 100% of GRS cash flow, with the exception of some expenses. For the year ended December 31, 2005, the Fund received payments of US $10.9 million (2004 – US $11.0 million), representing 100% of the aggregate scheduled monthly interest payments from its two GRS-related loans. Starting in the first quarter of 2005, changes to Canadian Generally Accepted Accounting Principles (“GAAP”) required the consolidation of GRS and its parent companies, PEET U.S. Holdings, Inc. (“PEET U.S.”) and PEET Canadian Holdings Inc. (“PEET Canadian”), with the Fund for reporting purposes. Furthermore, in the fourth quarter of 2005 the Fund announced that the Special Committee had been established to investigate unitholder value enhancement opportunities, initially concentrating on the Fund’s investment in GRS. As part of its evaluation, the Special Committee included the disposition of the GRS investment as a viable option. For reporting purposes, GRS operations and cash flow, consolidated with those of the Fund, will be presented in the Fund’s audited consolidated financial statements as “discontinued operations” while the Special Committee further investigates the potential of the disposition of the Fund’s GRS investment. The Fund’s cash flow from GRS continues to be received in the form of interest payments. GRS Operations GRS operates 29 facilities in the United States, of which 26 generate revenue from the sale of electrical power into the local grid. Revenue of the other three GRS plants is derived from the direct sale to industrial users of treated LFG (medium BTU gas, approximately 45% to 55% natural gas) through bilateral or single-source pipeline from the landfill to the host user. For 2005, GRS’s sales of electricity represented approximately 93% of gross margin (2004 – 94%); the remainder represented the direct sale of medium BTU gas. The three largest budgeted contributors to gross margin, generated 51% of GRS electricity gross margin (2004 – 43%): Arbor Hills, Michigan; Mallard Lake, Illinois; and Pine Bend, Minnesota. The next two most significant facilities, Fall River in Massachusetts and Coyote Canyon in southern California, generated 25% (2004 – 18%). Fourteen of 26 landfill sites which source LFG for power generation including Arbor Hills, Mallard Lake and Pine Bend, are open sites that continue to receive additional landfill and therefore the quantity of LFG to be produced from these sites is not fixed. For 2005, LFG sales produced approximately 7% of GRS gross margin (2004 – 6%). Of the three gas sales facilities (Newby Island III, Sacramento and Vienna Junction), Newby Island III represented 131% (2004 – 95%) of all 2005 gas gross margin. The Vienna Junction facility experienced a compressor failure early in 2005. GRS then rented a compressor while the facility was re-powered during 2005. The period of lost sales and the increased operating costs associated with the rental expense resulted in a negative gross margin for Vienna Junction in 2005. The re-powering project was completed in January 2006. Both Newby Island III and Vienna Junction source gas from open landfills. Production (all facilities) (in thousands of MWh) Facility Location 2005 Long-term average 2005 % of long-term average 2004 Arbor Hills, Pine Bend and Mallard Lake Michigan,Minnesota and Illinois 257,690 301,669 85 280,279 Other Facilities 7 U.S. states 375,108 389,219 96 388,742 Total 632,798 690,888 92 669,021 Aggregate annual GRS production levels were approximately 8% (2004 – 15%) below expectations and approximately 5% below 2004 annual production due primarily to mechanical issues at two of GRS’s three largest facilities (Arbor Hills and Pine Bend). Production at the Arbor Hills facility was below expectations as the boiler failure that occurred in late 2004 caused a production slowdown that continued into 2005, with operations stabilizing in the second quarter. Also, the expansion expected to be completed in the fourth quarter of 2005 was not completed until January 2006. Pine Bend’s production for the year was 71% of expected production as the facility experienced a two-month shutdown resulting from two turbine failures in the third quarter. The repairs were completed in early 2006 and the plant is now fully operational. These two facilities accounted for 64% of GRS’s total annual production shortfall. GRS FINANCIAL RESULTS Operating cash flow before changes in working capital was US $11.1 million for 2005, compared to US $14.0 million in 2004, a decrease of US $2.9 million. This decrease is a result of a combination of lower than expected production and lower PPA rates at Pine Bend. Total 2005 revenue was US $43.9 million, down 5% from 2004 for the reasons described above. For 2005 operating costs were consistent at US $28.7 million (2004 – US $28.5 million). Other costs of US $13.5 million decreased by US $0.8 million due to a decrease in depreciation expense of US $1.3 million offset by a US $0.5 million extraordinary expense for accretion on asset retirement obligations, accrued retention bonuses and loss on disposal of assets and inventory. Depreciation decreased in 2005 as a large group of assets became fully depreciated in April 2005. As demonstrated in the following table, in 2005, unlike 2004, operating cash flow and working capital was not capable of funding GRS’s maintenance capital obligations and its dividend payment obligations to PEET U.S. to pay its direct interest obligations to the Fund because of the comprehensive business plan put into place during 2005 by the new management team. As a limited liability company, GRS is a division of PEET U.S. The Fund receives cash from GRS through two loans: a US $78.3 million 11.5% interest-bearing loan from a Fund subsidiary to PEET U.S. paid monthly; and a US $15 million 11.5% interest-bearing loan to PEET Canadian, the parent of PEET U.S., paid quarterly. Should GRS operating cash flow exceed interest obligations, the loan agreements provide for the option of returning cash to the Fund by way of principal repayment. Dividends paid by PEET U.S. from GRS operating cash flow are intended to service the PEET Canadian loan obligations. In 2005, the cash payments of PEET U.S. dividends were supported by an advance from a Fund subsidiary. GRS has received US $7.35 million (2004 – US $6.9 million) in advances from PEET U.S. to finance capital expenditures and working capital. GRS Cash Flow Analysis (in thousands of US dollars) Year ended Year ended December 31, 2005 December 31, 2004 Power/gas sales(1) $ 43,891 $ 46,103 Operating costs (28,681) (28,464) Other(2) (13,536) (14,383) Income before income tax provision 1,674 3,256 Depreciation and accretion 9,448 10,780 Operating cash flow before changes in working capital(*) 11,122 14,036 Dividends paid to PEET US(3) (9,780) (9,480) Illinois Retail Rate Law liability funding(4) (740) (413) Capital Expenditures Non-expansion capital expenditures (5) (6,131) (7,040) Expansion expenditures(6) (2,746) (6,082) Net cash (borrowings) $ (8,275) $ (8,979) Funding from changes in GRS working capital and cash 925 2,036 Borrowings from PEET U.S. 7,350 6,943 (*) Operating cash flow before changes in working capital is a non-GAAP term which management uses to evaluate operating cash flow before working capital timing differences. (1) GRS power/gas sales include $2.2 million (2005 – $0.5 million) in revenue from the sale RECs. (2) Other includes depreciation and amortization, administration expenses, extraordinary items and interest expense. (3) The dividend received by PEET U.S is then substantially paid out as interest expense to a subsidiary of CPOT and as dividends to PEET Canada to support interest payments on its loan to CPOT. (4) Represents the difference between the increased obligation and cash funding of the restricted investment balance. (5) Amounts incurred to prolong the life of an existing asset. (6) Amounts incurred for the 12 months ended December 31, 2005 to finance expansions of existing facilities including Arbor Hills and Vienna Junction. Consolidated Balance Sheets (unaudited) (in thousands of Canadian dollars) As at December 31 2005 2004 ASSETS Current Cash and cash equivalents $ 4,838 $ 4,313 Accounts receivable 3,529 2,101 Other receivables 3,062 364 Accrued interest on loans receivable 854 775 Chapais loan receivable 517 464 Material and supplies inventories 854 750 Prepaid expenses 1,155 371 Current assets of discontinued operations 13,920 313 28,729 9,451 Cash in escrow 23,019 U.S. Wind Loan receivable 21,434 22,168 Chapais loans receivable 14,448 14,965 Western Wind note receivable 400 Other long-term investment 1,540 1,513 Erie Shores construction and project costs 116,640 Reserve Account 8,823 10,196 Capital assets 146,922 152,597 Goodwill 8,885 8,885 Other assets 5,108 5,722 Long-term assets of discontinued operations 115,239 133,607 28,729 9,451 Cash in escrow 23,019 U.S. Wind Loan receivable 21,434 22,168 Chapais loans receivable 14,448 14,965 Western Wind note receivable 400 Other long-term investment 1,540 1,513 Erie Shores construction and project costs 116,640 Reserve Account 8,823 10,196 Capital assets 146,922 152,597 Goodwill 8,885 8,885 Other assets 5,108 5,722 Long-term assets of discontinued operations 115,239 133,607 $ 490,787 $ 359,504 LIABILITIES AND UNITHOLDERS’ EQUITY Current Accounts payable and accrued liabilities $ 14,945 $ 1,891 Distributions payable 2,089 2,089 Interest payable 244 Current portion of long-term debt 1,200 2,790 Current portion of capital lease obligations 68 68 Current Liabilities of discontinued operations 6,527 25,073 6,838 Convertible debentures 55,000 55,000 Long-term debt 168,139 25,000 Levelization amounts 16,277 14,611 Future income tax liability 7,197 7,362 Capital lease obligations 63 119 Minority interest 2,336 3,161 Long-term liabilities of discontinued operations 33,904 307,989 112,091 Trust Units issued 332,849 332,849 Cumulative translation adjustment 1,313 Deficit (151,364) (85,436) Total unitholders’ equity 182,798 247,413 $ 490,787 $ 359,504 Consolidated Statements of Income (Loss) (unaudited) (in thousands of Canadian dollars except per Trust Unit amounts) For the year ended December 31 2005 2004 REVENUES Power sales $ 26,371 $ 25,808 Interest earned on U.S. Wind Loan receivable 2,503 2,671 Other investment income 2,205 1,848 Other income 105 114 31,184 30,441 COSTS AND OPERATING EXPENSES Operating and maintenance 9,547 9,402 Management and administration 4,696 4,481 Depreciation and amortization 6,350 6,377 20,593 20,260 Operating income 10,591 10,181 Interest expense on long-term debt 5,867 4,428 Interest on levelization amounts 1,529 1,507 Foreign exchange loss 1,070 710 Income (loss) for the year before future income tax expense (recovery) and minority interest (recovery) $ 2,125 $ 3,536 Future income tax expense (recovery) (164) (481) Minority interest (recovery) (26) 102 Net income (loss) for the year from continuing operations $ 2,315 $ 3,915 Net income (loss) for the year from Discontinued Operations $ (5,734) $ 4,097 Net income (loss) for the year $ (3,419) $ 8,012 Net income (loss) per Trust Unit – basic and diluted – Continuing Operations $ 0.065 $ 0.111 Net income (loss) per Trust Unit – basic and diluted – Discontinued Operations $ (0.162) $ 0.116 Net income (loss) per Trust Unit – basic and diluted $ (0.097) $ 0.227 Weighted average number of Trust Units outstanding – basic and diluted 35,368,597 35,368,597 Consolidated Statements of Deficit (in thousands of Canadian dollars) For the year ended December 31 2005 2004 Deficit, beginning of year, prior to change in accounting policy (85,436) (61,321) Adjustment to deficit resulting from change in accounting policy (37,750) Deficit, beginning of year, as restated (123,186) (61,321) Net income (loss) for the year (3,419) 8,012 Distributions declared to unitholders (24,759) (32,127) Deficit, end of year $ (151,364) $ (85,436) Consolidated Statements of Cash Flows (unaudited) (in thousands of Canadian dollars) For the year ended December 31 2005 2004 OPERATING ACTIVITIES Net income (loss) from continuing operations $ 2,315 $ 3,915 Add (deduct) items not affecting cash Minority interest (26) 102 Loss on disposal of fixed assets 36 Future income tax recovery (164) (481) Depreciation and amortization 6,350 6,377 Unpaid interest on levelization amounts 1,154 999 Unrealized foreign exchange loss and other 2,099 1,192 Equity income less than (in excess of) distributions received (27) 75 Investment income on Reserve Account (777) (494) 10,960 11,685 (Increase) decrease in operating working capital (1,292) 2,163 Cash provided by operating activities of continuing operations 9,668 13,848 INVESTING ACTIVITIES Additional investment in Reserve Account (7,000) Release from Reserve Account 2,150 2,200 Deposit into cash in escrow (23,019) Receipt of advance (advance) to Western Wind 400 (400) Repayment of other long-term investments 464 503 Investment in Erie Shores construction and project costs (106,746) (362) Purchases and construction of property and equipment (216) (82) Cash used in investing activities of continuing operations (126,967) (5,141) FINANCING ACTIVITIES Net proceeds from issuance of convertible debentures 52,309 Distributions to unitholders (24,759) (32,864) Distributions to minority interest holders (316) (420) Proceeds from long-term debt 141,550 15,105 Deferred financing fees (1,539) Repayment of credit facility (44,725) Proceeds from levelization amounts 512 682 Repayment of capital lease obligations (56) (86) Advances on Net Profits Interest (25) (25) Cash provided by (used in) financing activities of continuing operations 115,367 (10,024) Net increase (decrease) in cash and cash equivalents from continuing operations (1,932) (1,317) Net increase (decrease) in cash and cash equivalents from discontinued operations 2,457 1,196 Cash and cash equivalents, beginning of period 4,313 4,434 Cash and cash equivalents, end of period $ 4,838 $ 4,313 Cash and cash equivalents are comprised of: Cash 4,047 3,639 Short-term investments 791 674 $ 4,838 $ 4,313 Interest paid during the year $ 7,386 $ 4,410 Income taxes paid during the year $ - $ 21 This press release may contain forward-looking information or forward-looking statements within the meaning of applicable securities legislation (“forward-looking statements”). Any statements that express or involve discussions with respect to the Fund’s predictions, expectations, beliefs, plans, projections, objectives, assumptions, potentials, estimates, intentions, future events or performance (often, but not always, using words or phrases such as “believes”, “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, or “intends” or stating that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken or achieved) are not statements of historical fact, but are forward-looking statements. Such forward-looking statements, by their nature, necessarily involve known and unknown risks, assumptions, uncertainties and other factors beyond the Fund’s ability to control or predict, that may cause our actual results, performance or achievements, or developments in our business or in our industry, to differ materially from the anticipated results, performance, achievements or developments expressed or implied by such forward-looking statements. Forward-looking statements may include, but are not limited to: the Fund’s efforts to dispose of its interest in GRS; expectations regarding receiving definitive proposals for dispositions regarding GRS; and how best to proceed with work on unitholder value enhancement opportunities. Investors and others should not place undue reliance on these forward-looking statements as actual results could differ materially from the forward-looking statements in this press release based on risks associated with: the unitholder value enhancement opportunities involving third parties and other factors over which the Fund has no control; the fact that definitive proposals for a disposition of GRS may not be sufficient to complete a disposition of GRS on acceptable terms; and that the Special Committee and the manager of CPOT’s work on how best to proceed with unitholder value enhancement opportunities is successful. The foregoing list of risks is not exhaustive. The forward-looking statements in this press release are based on the material factors and assumptions that the Fund considered reasonable at the time they were prepared, including that a disposition of GRS can be achieved on terms acceptable to the Special Committee, and that the Special Committee and the manager of CPOT can successfully work on how best to proceed with unitholder value enhancement opportunities. It is important to note that: unless otherwise indicated, forward-looking statements in this press release describe our views and expectations as of the date of this press release; we caution readers not to place undue reliance on these statements as our actual results may differ materially from our expectations if known and unknown risks or uncertainties affect our business, or if our estimates or assumptions prove inaccurate, and therefore, we cannot provide any assurance that forward-looking statements will materialize; that while it is anticipated that subsequent events and developments could cause our views and expectations to change, the Fund does not undertake or assume any obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or any other reason; and all forward-looking statements contained in this press release are expressly qualified by this cautionary statement.

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