Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

November 14, 2005 14:02 ET

Canadian Hydro Announces Third Quarter Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 14, 2005) - Canadian Hydro Developers (TSX:KHD), Inc. (the "Company" or "Canadian Hydro") reported cash flow from operations(1) for the third quarter ended September 30, 2005 ("Q3 2005") of $1,220,000 ($0.02 per share, diluted(3)) on generation of 119 million kWh, compared to $3,589,000 ($0.05 per share, diluted(3)) on generation of 124 million kWh for Q3 2004. Net loss was $1,274,000 ($0.02 per share, diluted) for Q3 2005, compared to net earnings of $1,379,000 ($0.02 per share, diluted) for Q3 2004.

Cash flow from operations(1) for the nine months ended September 30, 2005 decreased to $6,600,000 ($0.08 per share, diluted(3)) on generation of 324 million kWh, compared to $7,783,000 ($0.11 per share, diluted(3)) on generation of 302 million kWh for the same period in 2004. Net earnings for the nine months ended September 30, 2005 were $544,000 ($0.01 per share, diluted), compared to $3,051,000 ($0.04 per share, diluted) for the same period in 2004.

Company-wide generation in Q3 2005 was 4% lower than Q3 2004 notwithstanding the addition of 53 MW of generation in 2005. This was due to 19% lower same plant generation resulting from below normal water flows in all provinces where the Company operates, combustor issues encountered with the 25 MW Grande Prairie EcoPower® Centre ("GPEC") since commissioning in June 2005 and very low summer water flows at the 25 MW Upper Mamquam Hydroelectric Plant since commissioning in July 2005. The impact of lower generation was offset partially by higher average spot ("Pool") prices received for electricity on the Company's merchant plants located in Alberta and Ontario (Q3 2005 - $65/MWh; Q3 2004 - $55/MWh). Lower generation, combined with a one-time charge to unwind an interest rate swap on debt that was refinanced at significantly lower interest rates, and higher operating costs due to the combustor issues at GPEC, resulted in lower quarter-over-quarter financial results.

All of Canadian Hydro's renewable energy plants, excluding GPEC, operated well during the nine months ended September 30, 2005, generating close to historic averages. With no one facility accounting for more than 25% of overall expected average long-term generation, the Company's diversified portfolio of renewable energy plants across three proven technologies and three provinces reduces production variability.

For the nine months ended September 30, 2005, these same factors, offset partially by higher water flows in B.C. and Alberta in the first quarter of 2005 and same year-over-year Pool prices received, resulted in 7% higher generation, but lower financial results compared to the same period in the prior year. The year-to-date average Pool price received for electricity on the Company's merchant plants was unchanged from 2004 at $55/MWh. Approximately 85% of the Company's generation was sold under various long-term sales agreements for Q3 2005 and for the nine months ended September 30, 2005 (Q3 2004 - 86%; 2004 - 87%), with the balance being exposed to the Pool.




------------------------------------------------------------------------
3 Months Ended 9 Months Ended
September 30, September 30,
(unaudited) 2005 2004 2005 2004
------------------------------------------------------------------------
Financial Results
(in thousands of dollars
except per share amounts)
Revenue 6,891 7,064 19,107 17,849
EBITDA(2) 3,600 5,196 11,936 12,556
Cash flow from operations(1) 1,220 3,589 6,600 7,783
Per share (diluted)(3) 0.02 0.05 0.08 0.11
Earnings before interest
rate swap unwind costs
and taxes 61 2,430 3,323 5,149
Net earnings (loss) (1,274) 1,379 544 3,051
Per share (diluted) (0.02) 0.02 0.01 0.04

Operating Results
Electricity generation -
MWh (net) 119,137 123,606 323,897 301,937
Average price received
per MWh ($) 58 57 59 59
Electrical generation
under contract (%) 85 86 85 87
------------------------------------------------------------------------
(1) Before changes in non-cash working capital.

(2) EBITDA is provided to assist management and investors in
determining the ability of the Company to generate cash from
operations. EBITDA as presented is defined as cash flow from
operations before changes in non-cash working capital, plus
interest on debt and current tax expense. This measure does not
have any meaning prescribed in Canadian generally accepted
accounting principles ("GAAP") and may not be comparable to similar
measures presented by other companies.

(3) Cash flow from operations(1) per share (diluted) is provided to
assist management and investors in determining the Company's cash
flow from operations(1) on a per share basis and does not have any
meaning prescribed in GAAP and may not be comparable to similar
measures presented by other companies.


Q3 2005 Achievements:

- Achieved commercial operations at the 25 MW Upper Mamquam Hydroelectric
Project on July 23, 2005;

- Progressed well on construction at the 67.5 MW Melancthon I Wind Project (formerly referred to as the "Melancthon Grey Wind Project"), with all 45 turbines erected by October 31, 2005 and with continued plans to be operational in March 2006;

- Readied several hundred megawatts of renewable energy prospects for bids into upcoming calls for power later this year and next;

- Obtained an investment grade credit rating of BBB, with a Stable trend from Dominion Bond Rating Service Ltd.; and

- Closed $220 million in unsecured debt financings.

"With all of our turbines standing and pre-commissioning activities underway at Melancthon I, we are currently on target with plans to be commercially operational in March 2006", said John Keating, Chief Executive Officer. "The addition of this wind plant will result in net installed capacity of 229.5 MW adding to our diversified portfolio of technologies across the provinces in which we operate."

Canadian Hydro is a developer, owner and operator of 17 low-impact renewable power plants with a net capacity of 162 MW, which are all certified or slated for certification under the EcoLogo(M) program. The Company's Melancthon I Wind Project is slated for certification as a low-impact renewable energy facility upon completion.

Canadian Hydro Developers, Inc. is passionate about meeting the goals of investors and the needs of the environment. As industry leaders, Canadian Hydro is focused on building a sustainable future for Canada and with over 15 years experience, Canadian Hydro is the working model for the unlimited development potential of low-impact renewable energy.

Common shares outstanding: 79,543,873

MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")

The following MD&A, dated November 7, 2005, should be read in conjunction with the unaudited interim consolidated financial statements as at and for the 3 and 9 months ended September 30, 2005 and 2004, and should also be read in conjunction with the audited consolidated financial statements and MD&A included in the Annual Report as at and for the year ended December 31, 2004. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). All tabular amounts in the following MD&A are in thousands of Canadian dollars unless otherwise noted. Additional information respecting the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

Forward-Looking Statements

Certain statements contained in this MD&A, constitute forward-looking statements. These statements relate to future events or the Company's future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect, "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes the expectations reflected in those forward looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. These statements speak only as of the date of this MD&A. The Company does not intend, and does not assume any obligation, to update these forward-looking statements.

Revenue

For Q3 2005, revenue decreased 2% to $6,891,000 on generation of 119 million kWh compared to $7,064,000 on generation of 124 million kWh in Q3 2004. The decrease in revenue in the current quarter was due to 4% lower Company-wide generation, notwithstanding increased generation of 53 MW in 2005. This was due to 19% lower same plant generation resulting from below normal water flows in all provinces where the Company operates, combustor issues encountered with the 25 MW Grande Prairie EcoPower® Centre ("GPEC") since commissioning in June 2005 and very low summer water flows at the 25 MW Upper Mamquam Hydroelectric Plant ("Mamquam") since commissioning in July 2005. The impact of lower generation was offset partially by higher average spot ("Pool") prices received for electricity on the Company's merchant plants located in Alberta and Ontario (Q3 2005 - $65/MWh; Q3 2004 - $55/MWh).

For the 9 months ended September 30, 2005, revenue increased 7% to $19,107,000 on generation of 324 million kWh compared to $17,849,000 on generation of 302 million kWh for the same period in 2004. The year-to-date increase in revenue and generation was due to the same factors as Q3 2005, as well as higher water flows in B.C. and Alberta in the first quarter of 2005, offset partially by same year-over-year Pool prices received. The average Pool price received for electricity on the Company's merchant plants was unchanged from 2004 at $55/MWh.

Approximately 85% of the Company's generation was sold pursuant to long-term sales contracts in Q3 2005 and for the 9 months ended September 30, 2005 (Q3 2004 - 86%; 2004 - 87%). The average price received by the Company for electricity from all operations for Q3 2005 was $58/MWh (Q3 2004 - $57/MWh). The average price received by the Company for electricity from all operations for the 9 months ended September 30, 2005 was $59/MWh (2004 - $59/MWh).



Electricity Generation - by Province and Technology

------------------------------------------------------------------------
Electricity Generation for All Plants - MWh(1)
Q3 2005 Q3 2004 Variance 2005 2004 Variance
------------------------------------------------------------------------

British Columbia 54,072 63,280 - 15% 131,937 124,949 + 6%
Alberta 58,079 45,610 + 27% 141,021 122,680 + 15%
Ontario 6,986 14,716 - 53% 50,939 54,308 - 6%
------------------------------------------------------------------------
Totals 119,137 123,606 - 4% 323,897 301,937 + 7%
------------------------------------------------------------------------
Hydroelectric 83,395 104,254 - 20% 229,575 224,344 + 2%
Wind 22,394 19,352 + 16% 79,203 77,306 + 3%
Biomass 13,348 - -% 15,119 - -%
Natural Gas - - -% - 287 -100%
------------------------------------------------------------------------
Totals 119,137 123,606 - 4% 323,897 301,937 + 7%
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
Electricity Generation for Same Plants - MWh(1)
Q3 2005 Q3 2004 Variance 2005 2004 Variance
------------------------------------------------------------------------

Hydroelectric 78,169 104,254 - 25% 217,224 224,344 - 3%
Wind 21,640 19,352 + 12% 76,969 77,306 - 0%
Natural Gas - - -% - 287 -100%
------------------------------------------------------------------------
Totals 99,809 123,606 - 19% 294,193 301,937 - 3%
------------------------------------------------------------------------
------------------------------------------------------------------------

----------------------------------------------
Electricity Generation for New Plants - MWh(1)
Q3 2005 2005
----------------------------------------------

GPEC 13,349 15,119
Upper Mamquam 4,385 4,385
Misema Hydro 841 7,966
Taylor Wind 753 2,234
----------------------------------------------
Total - new 19,328 29,704
----------------------------------------------
----------------------------------------------
(1) Reflecting the Company's net interest.


Operating Expenses

Q3 2005 operating expenses increased 92% to $2,943,000 from $1,532,000 in Q3 2004. For the 9 months ended September 30, 2005, operating expenses increased 55% to $6,524,000 from $4,211,000 for the same period in 2004. Gross margins (revenue less operating expenses; expressed as a percentage of revenue) were lower at 57% in Q3 2005 (Q3 2004 - 78%) and 66% for the 9 months ended September 30, 2005 (2004 - 76%). The increase in operating expenses was due primarily to higher than expected operating costs at GPEC due to issues encountered with the combustors since commissioning in June 2005, the addition of GPEC, Mamquam, the Misema Hydroelectric Plant and the Taylor Wind Plant, which had no comparable operating expenses from these plants in the prior year, and higher sub-lease costs at Ragged Chute, resulting from the new sub-lease agreement that commenced on June 30, 2004.

Interest on Debt, Long-Term Debt and Revolving Construction Lines of Credit

Interest on debt (excluding capitalized interest) in Q3 2005 increased 43% to $2,050,000 compared to $1,438,000 in Q3 2004 and for the 9 months ended September 30, 2005, increased 9% to $4,517,000 from $4,152,000 for the same period in 2004. These increases were due to higher outstanding debt on completed projects.

Capitalized interest associated with construction-in-progress in Q3 2005 was $1,258,000 (Q3 2004 - $154,000) and $2,893,000 for the 9 months ended September 30, 2005 (2004 - $171,000). These increases were due to higher debt on projects under construction in 2005 compared to 2004. During Q3 2005, interest was capitalized on debt related to the Melancthon I Wind Project ("Melancthon I"; formerly referred to as the "Melancthon Grey Wind Project") and Mamquam, compared to interest capitalized on Mamquam and GPEC during Q3 2004. During the nine months ended September 30, 2005, interest was capitalized on debt related to GPEC, Mamquam and Melancthon I, compared to GPEC and Mamquam during the same period in 2004.

The Company significantly restructured its debt in 2005 with the closing of a $120,000,000 unsecured private debt placement financing (the "Debentures"), $100,600,000 in unsecured bank credit facilities (the "Bank Facilities"), and a $35,000,000 (net to the Company's interest) secured joint debt private placement financing of the Pingston Hydroelectric Plant (the "Pingston Debt"). Dominion Bond Rating Service Ltd. provided an investment grade credit rating of BBB with a Stable Trend for the Debentures and A (High) with a Stable Trend for the Pingston Debt. This debt restructuring was the culmination of the Company's capital plan that was established in 2002. The new debt structure is expected to afford the Company the required financial flexibility and appropriate leverage to execute its strategic plan, including financing future growth in developing long-term contracted renewable power generation assets.

The result of this debt restructuring was an increase in long-term debt (including current portion) to $199,703,000 as at September 30, 2005 (September 30, 2004 - $64,300,000), from $66,497,000 as at December 31, 2004. This increase was offset partially by the repayment of the Company's secured bank credit facilities with proceeds from the Debentures and regular repayments on the long-term debt during the year. The proceeds from the Bank Facilities are being used to finance $75,600,000 of capital expenditures associated with Melancthon I and $25,000,000 for general corporate purposes. The proceeds from the Pingston Debt were used primarily for capital expenditures associated with Melancthon I (see Note 6 to the interim consolidated financial statements).

In conjunction with the Company's debt restructuring, an interest rate swap that fixed the interest rate on a portion of its secured bank credit facilities was unwound at a cost of $1,924,200, which was charged to earnings during Q3 2005 (see Note 6 to the interim consolidated financial statements). The interest rate swap was unwound as the Company repaid this debt with proceeds from the Debentures. The long-term savings resulting from the Company's new and significantly lower cost debt structure will more than offset this one-time cost.

At September 30, 2005, the Company had a 60/40 debt/equity ratio (December 31, 2004 - 44/56), closer to the Company's revised target of 65/35. The Company expects to achieve this target upon the completion of construction at Melancthon I.

Amortization Expense

Amortization expense increased 76% to $1,836,000 for Q3 2005 (Q3 2004 - $1,041,000), and 33% to $4,128,000 for the 9 months ended September 30, 2005 (2004 - $3,098,000), due primarily to the addition of the Pingston Expansion Hydroelectric Plant in April 2004, the Taylor Wind Plant in December 2004, the Misema Hydroelectric Plant in January 2005, GPEC in June 2005 and Mamquam in July 2005. The hydroelectric and biomass plants are amortized on a straight-line basis over a 40 year period, and the wind plant is amortized on a straight-line basis over a 15 year period.

Administration Expense

Administration expense increased to $787,000 for Q3 2005 (Q3 2004 - $526,000), and remained consistent at $1,595,000 for the 9 months ended September 30, 2005, compared to $1,598,000 for the same period in the prior year. The increase in Q3 2005 was due to moderately higher salary costs with the addition of four new employees and increased stock compensation expense due to stock options issued to employees during the year. For the nine months ended September 30, 2005, the increase in administration expense resulting from the new employees and higher stock compensation expense, as well as bonuses paid to certain employees, was offset by the Company receiving a cash payment of $750,000, net of associated costs, as a result of a settlement of a lawsuit the Company had with a former insurer and engineering firm associated with a project. Capitalized administration costs associated with construction-in-progress for Q3 2005 were $181,000 (Q3 2004 - $111,000) and $795,000 for the 9 months ended September 30, 2005 (2004 - $415,000). Melancthon I (67.5 MW) and Mamquam (25 MW) were under construction in Q3 2005 compared to four projects, totaling 68.4 MW, under construction in Q3 2004.

Gain on Derivative Financial Instruments

Gain on derivative financial instruments increased to $786,000 in Q3 2005 compared to a loss of $97,000 in Q3 2004. In Q3 2005, the gain was the result of a $349,000 increase in the fair value of one of the Company's contract for differences ("CFD") and $278,000 in cash payments received from another party in connection with the CFD. In addition, in the first and second quarters, one of the Company's contracts did not qualify for hedge accounting. The fair value of the contract on January 1, 2005 was a gain of $444,000. The gain is recognized into income over the period to which the gain relates with $43,000 recognized in Q3 2005. On July 1, 2005, when hedge accounting was re-applied, the fair value of the contract of $116,000, which was originally recorded as a derivative financial instrument liability, was recognized into earnings during the quarter.

For the 9 months ended September 30, 2005, the gain on derivative financial instruments increased to $902,000 from $359,000 for the same period in 2004. The increase was a result of the amortization of the gain of $245,000, a $601,000 increase in the fair value of one of the Company's CFDs, and $614,000 in cash settlements received from two other parties in connection with the CFDs. This gain was offset by a loss of $558,000 recorded for the change in the fair value of the CFD that no longer qualified for hedge accounting during Q1 2005 and Q2 2005.

Taxes

The Company does not anticipate current income taxes, other than in respect of the Cowley Ridge Wind Plant, through its wholly owned subsidiary, for several years. However, the Company is liable for the Federal Tax on Large Corporations ("LCT") and Provincial Capital Taxes in Ontario. The provision for these taxes comprises the current tax provision. The Company's larger capital base in 2005 resulted in higher current taxes compared to the prior year. This was offset partially by a decrease in the LCT rate from 0.2% to 0.175% of capital, less a $50,000,000 capital deduction in 2005. LCT will be phased out by the Federal Government by January 1, 2008.

Cowley Ridge Wind Power Inc. is fully taxable, but is entitled to recover approximately 175% of cash taxes paid annually (limited to 15% of eligible gross revenue) in accordance with the Revenue Rebate Regulation of the Alberta Small Power Research and Development Act. This Regulation will apply until the associated power sale agreements expire in 2013 (9.0 MW) and 2014 (9.9 MW).

Future income tax recovery was $919,000 in Q3 2005 compared to a future income tax expense of $882,000 in Q3 2004. Future income tax expense was $36,000 for the 9 months ended September 30, 2005 (2004 - $1,477,000). The 3 and 9 month decrease was due to lower taxable earnings, combined with tax pools available to the Company to offset current taxes to future periods compared to higher taxable earnings in 2004.

Net Earnings and Cash Flow from Operations before Changes in Non-Cash Working Capital

Net loss was $1,274,000 ($0.02 per share) in Q3 2005 compared to net earnings of $1,379,000 ($0.02 per share) in Q3 2004. The decrease was due primarily to lower revenue, costs to unwind the interest rate swap, and higher operating costs, interest on debt, administrative expenses and amortization; offset partially by a higher gain on derivative financial instrument and lower taxes, as described above. For the 9 months ended September 30, 2005, net earnings were $544,000 ($0.01 per share) compared to $3,051,000 ($0.04 per share) for the same period in 2004. The year-to-date increase was due to the same factors as Q3 2005, combined with higher revenue in the first and second quarters as compared to the prior year, as described above, as well as a gain on the sale of development prospects in the second quarter of 2005 (see below). Similarly, excluding non-cash items and the costs to unwind the interest rate swap, which are financing costs, cash flow from operations operations before changes in non-cash working capital was $1,220,000 for Q3 2005 (Q3 2004 - $3,589,000) and $6,600,000 for the 9 months ended September 30, 2005 (2004 - $7,783,000).

Capital Asset Additions, Prospect Development Costs and Gain on Sale of Development Prospects

Capital asset additions were $43,908,000 in Q3 2005 (Q3 2004 - $15,267,000) and $99,416,000 for the 9 months ended September 30, 2005 (2004 - $33,684,000), resulting in a 54% increase in the net book value of capital assets since December 31, 2004. These investment activities related to construction costs incurred for GPEC, Mamquam and Melancthon I.

Prospect development costs were $742,000 in Q3 2005 (Q3 2004 - $972,000) and $2,061,000 for the 9 months ended September 30, 2005 (2004 - $2,019,000), relating primarily to costs associated with the Dunvegan Hydroelectric Prospect, and new wind and hydroelectric prospects in Ontario and B.C. (see Note 5 to the interim consolidated financial statements). These additions exclude the acquisition of Canadian Renewable Energy Corporation ("CREC"), which was acquired with common shares issued by the Company (see 'Capital Resources and Liquidity' below). Costs associated with Melancthon I were transferred from development costs to construction-in-progress, including prospect development costs acquired (see Note 7(b) to the interim consolidated financial statements), during the first quarter of 2005.

During the second quarter, the Company sold certain wind energy development prospects acquired from the acquisition of CREC on January 21, 2005, for proceeds of $310,000, plus an additional contingent payment should the purchasers be successful in constructing wind generating assets within a certain period of time following the sale. These sales resulted in a gain of $78,000 being recognized for the nine months ended September 30, 2005.

Financial Position

The following chart outlines significant changes in the consolidated balance sheet from December 31, 2004 to September 30, 2005:



-----------------------------------------------------------------------
Increase Explanation
(Decrease)
$
-----------------------------------------------------------------------
Cash (1,434) Decrease due to capital asset
additions, prospect development costs
incurred, long-term debt repayments,
costs incurred to unwind the
interest rate swap and payment of
other liabilities and accounts
payable since year end; offset
partially by proceeds from the debt
restructuring, cash flow from
operations, collection of year end
receivables, and settlement of a
lawsuit in 2005.

Accounts receivable 4,818 Increase in uncollected revenue from
hydroelectric plants as generation
was higher in September 2005 than in
December 2004.

Revenue rebate (183) Decrease due to receipt of the 2004
revenue rebate, offset partially by
the 2005 revenue rebate accrual.

Prepaid expenses 193 Increase due to prepaid property
taxes and short-term financing costs,
offset partially by the amortization
of certain prepaid expenses.

Derivative financial
instrument 601 Fair value change from December 31,
2004 of a CFD that is not considered
a hedge under the CICA accounting
guideline on hedging relationships
and the fair value change from
January 1, 2005 of a CFD that did not
qualify as a hedge for the first and
second quarters of 2005 (see Note 3
to the interim consolidated financial
statements).

Deferred financing
costs 2,154 Increase due to costs incurred on
long-term debt financings that are
amortized over the life of the debt.

Capital assets 119,390 Construction costs on GPEC, Mamquam
and Melancthon I, and the acquisition
of the Misema Hydroelectric Plant
(see Note 7(b) to the interim
consolidated financial statements),
offset partially by amortization.

Prospect development
costs (5,558) Decrease due to the transfer of costs
for Melancthon I into construction-
in-progress and the sale of certain
development prospects; offset
partially by the acquisition of
development prospects (see Note 7(b)
to the interim consolidated financial
statements) and costs related to the
development of new prospects.

Other liabilities (2,290) Decrease due to payments in amounts
owing to a third party (see Note
14(b) to the audited consolidated
financial statements as at and for
the year ended December 31, 2004).

Deferred credit 315 Fair value of a CFD (see Note 3 to
the interim consolidated financial
statements), net of recognition to
net earnings.

Accounts payable and
accrued liabilities 3,845 Project and financing costs accrued
at September 30, 2005, offset
partially by the payment of project
costs accrued at December 31, 2004.
Revolving construction
lines of credit (28,800) Repayment of the revolving
construction lines of credit with
proceeds from the Debentures.

Long-term debt 133,206 Increase resulting from debt
restructuring in 2005, offset
partially by repayment of long-term
debt.

Future income taxes (198) Decrease due to future income taxes
that are expected to be recovered by
the Company in the future based on
the Company's taxable position at
September 30, 2005, the acquisition
of a future tax asset (see Note 7(b)
to the interim consolidated financial
statements) and the tax effect on
share issue costs.

Share capital 13,027 Common share issuances for the
acquisition of Canadian Renewable
Energy Corporation, a private
placement and option exercises (see
Note 7 to the interim consolidated
financial statements).
-----------------------------------------------------------------------


Capital Resources and Liquidity

On January 21, 2005, the Company acquired the shares of CREC in exchange for 4,037,687 common shares of the Company valued at $12,113,000, $47,000 in acquisition costs and 2,250,000 special warrants, which will vest and automatically convert into common shares of the Company upon certain events occurring. CREC was an independent power producer with an operating 3.2 MW hydroelectric plant and several hundred megawatts of wind and hydroelectric development prospects in Ontario. CREC was purchased for its operating plant and to strategically position the Company in Ontario for future long-term contracts for renewable energy that may be awarded by the Ontario government. ARC Financial Corporation, whose CEO is an elected director of CHD and whose private equity fund is a large shareholder of the Company, advise two private equity funds that owned 86.6% of CREC. See Note 7(b) to the interim consolidated financial statements.

On August 23, 2005, the Company issued 85,575 common shares at $4.09 per share to a third party as part of an agreement related to the construction of one of the Company's plants.

The Company issued 88,250 common shares at an average exercise price of $1.50 per share for gross proceeds of $132,000 during Q3 2005 and 736,750 common shares at an average price of $0.80 per share for gross proceeds of $587,000 during the 9 months ended September 30, 2005, due to the exercise of expiring stock options.

The Company's current capital expenditure plans total approximately $126,000,000 for the construction of Melancthon I. At September 30, 2005, $95,495,000 has been spent on this project and is included in capital assets as construction-in-progress (see Note 4 to the interim consolidated financial statements). The remaining $30,505,000 of capital expenditures will be financed through $46,500,000 in undrawn and available credit from the Bank Facilities.

Impact of New Accounting Pronouncements

Effective January 1, 2005, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") accounting guideline for identifying and accounting for variable interest entities ("VIEs"). The Company has determined that it does not have interests in VIEs that require consolidation under this guideline and as a result, there is no impact on the Company's financial statements.

Financial Instruments

In January 2005, the Company entered into various foreign exchange contracts, expiring in 2005, which fix the Company's U.S. dollar payments under a wind turbine purchase contract in Canadian dollars. The remaining aggregate amount of U.S. dollar purchases is $6,423,300, which is fixed at a blended average rate of 1.206 for a remaining aggregate Canadian dollar amount of $7,743,617. These foreign exchange contracts qualify as hedges for accounting purposes. At September 30, 2005, the fair value of the foreign exchange contract was a loss of $280,000 due primarily to the increase in the value of the Canadian dollar from inception of the contracts to September 30, 2005, which was used in determining fair value.

As disclosed in the December 31, 2004 MD&A, the Company entered into an interest rate swap that qualified as a hedge for accounting purposes. In September 2005, upon closing of the Debentures and repayment of the Company's secured bank credit facilities, the interest rate swap was unwound at a cost of $1,924,200, which was charged to earnings during the quarter. The long-term savings resulting from the Company's new and significantly lower cost debt structure will more than offset this one-time cost.

As disclosed in the December 31, 2004 MD&A, the Company has entered into several CFDs that qualified as hedges for accounting purposes. At December 31, 2004, the Company fair valued the CFDs using the forward market prices for electricity for 2005 and 2006 and, due to the illiquidity of the forward market past 2006, using the 2006 forward market price for 2007 onwards, discounted at 5%. Given the ongoing illiquidity of the forward market, in 2005, the Company enhanced its assumptions for fair valuing its CFDs by assuming the actual contract prices contained in the CFDs were the same as the forward prices for periods where no forward market prices exist. Had these assumptions been used at December 31, 2004, the fair value of the Company's CFDs would have resulted in a gain of $1,035,000 compared to a gain of $7,327,000 as disclosed previously. The enhanced assumptions relate to fair value disclosures and have no impact on previously reported earnings. During the first six months of 2005, one of the Company's CFDs no longer qualified for hedge accounting. As a result, a loss of $558,000 was recognized into earnings (see Note 3 to the interim consolidated financial statements). On July 1, 2005, the Contract re-qualified as a hedge and hedge accounting was prospectively applied. At September 30, 2005, the fair value of the CFDs that qualify as hedges would result in a loss of $1,069,000 (see Note 10(b) to the interim consolidated financial statements).



Outstanding Share Data
------------------------------------------------------------------------
As at November 7, 2005
(Unaudited)
------------------------------------------------------------------------
Basic common shares 79,543,873
Convertible securities:
Warrants 2,250,000
Options 4,287,150
------------------------------------------------------------------------
6,537,150
------------------------------------------------------------------------
Diluted common shares 86,081,023
------------------------------------------------------------------------
------------------------------------------------------------------------


Outlook

Construction of Melancthon I is progressing well. As of October 31, 2005, all 45 turbines were erected. Pre-commissioning activities have begun and the Company is on target for achieving commercial operations in March 2006. This plant is expected to generate 194,800 MWh on a full year basis and is expected to positively impact the Company's financial results in 2006 and onwards, beginning in April 2006.

GPEC, which became commercially operational on June 21, 2005, achieved lower than expected generation for Q3 2005 due to issues encountered with the plant's combustors. While the Company believes these issues are now largely resolved, in late October, instrumentation problems led to damage to the plant's two boilers. The instrumentation problem has been addressed and adjustments have been made to ensure this will not occur again. Because of these reasons, the Company expects GPEC to generate approximately 22,000 MWh in Q4 2005, which is lower than previously anticipated.

On July 23, 2005, the Company achieved commercial operations at Mamquam completing the Company's growth target, along with GPEC and the Misema Hydroelectric Plant, of 53 MW for 2005. Mamquam is expected to generate approximately 98,200 MWh of electricity and RECs per year and positively impact the Company's financial results for the fourth quarter of 2005 and onwards. With normal precipitation experienced thus far in Q4 2005 and forecasted for the remainder of the year, the Company expects average generation in Q4 2005 for the Company's B.C. hydroelectric plants.

Reservoir levels in Alberta, where the Company's Alberta hydroelectric plants are located, are currently at normal and above normal levels for this time of year. As a result, hydroelectric generation in Alberta for Q4 2005 is expected to be at average levels.

Ontario had a dry summer during which the Company experienced below average hydroelectric generation in Ontario in Q3 2005. The forecast for the fourth quarter is for normal and below normal precipitation. Because of this, the Company expects average to below average hydroelectric generation in Ontario for Q4 2005.

Pool prices in Q3 2005 ($67/MWh) were higher than those in Q3 2004 ($58/MWh). Year-to-date 2005 pool prices (2005 - $63/MWh) were higher than those in the same period in the prior year (2004 - $55/MWh). Pool prices for the remainder of 2005 are expected to be higher than those in Q3 2005 due to higher natural gas prices. The average Pool price for October 2005 was $122/MWh, compared to $74/MWh for the month of September 2005 and $58/MWh for the month of October 2004.



CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGS
(Unaudited)
(in thousands of dollars except per share amounts)

3 months ended 9 months ended
September 30 September 30
2005 2004 2005 2004
------------------------------------------------------------------------

Revenue
Electric energy sales 6,796 6,979 18,780 17,504
Revenue rebate 95 85 327 345
------------------------------------------------------------------------
6,891 7,064 19,107 17,849
------------------------------------------------------------------------

Expenses
Operating 2,943 1,532 6,524 4,211
Interest on debt (Note 4) 2,050 1,438 4,517 4,152
Amortization 1,836 1,041 4,128 3,098
Administration (Notes 4 and 9) 787 526 1,595 1,598
(Gain) loss on derivative
financial Instrument (Note 3) (786) 97 (902) (359)
Gain on sale of development
prospect - - (78) -
------------------------------------------------------------------------
6,830 4,634 15,784 12,700
------------------------------------------------------------------------

Earnings before the following 61 2,430 3,323 5,149

Unwind costs on interest rate
swap (Note 6(a)) 1,924 - 1,924 -
------------------------------------------------------------------------

Earnings (loss) before taxes (1,863) 2,430 1,399 5,149
------------------------------------------------------------------------

Tax expense (recovery)
Current 330 169 819 621
Future (919) 882 36 1,477
------------------------------------------------------------------------
(589) 1,051 855 2,098
------------------------------------------------------------------------

Net earnings (loss) (1,274) 1,379 544 3,051

Retained earnings,
beginning of period 14,990 10,664 13,172 8,992
------------------------------------------------------------------------

Retained earnings,
end of period 13,716 12,043 13,716 12,043
------------------------------------------------------------------------

Earnings (loss) per share
(Note 8)
Basic (0.02) 0.02 0.01 0.04
Diluted (0.02) 0.02 0.01 0.04

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands of dollars)
September 30 September 30
2005 2004
------------------------------------------------------------------------

ASSETS
Current assets
Cash - 1,434
Accounts receivable 7,747 2,888
Revenue rebate 327 510
Taxes receivable - 41
Prepaid expenses 821 628
Derivative financial instrument
(Note 3) 855 254
------------------------------------------------------------------------
9,750 5,755

Deferred financing costs
(Note 6(a)) 2,154 -
Capital assets (Note 4) 339,927 220,537
Prospect development costs (Note 5) 11,741 17,299
------------------------------------------------------------------------

TOTAL ASSETS 363,572 243,591
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES
Current liabilities
Other liabilities - 2,290
Taxes payable 18 -
Deferred credit (Note 3) 315 -
Accounts payable and accrued
liabilities 10,300 6,473
Current portion of long-term
debt (Note 6(a)) 1,802 1,697
Revolving construction lines
of credit (Note 6(b)) - 28,800
------------------------------------------------------------------------
12,435 39,260

Long-term debt (Note 6(a)) 197,901 64,800
Future income taxes 18,061 18,259
------------------------------------------------------------------------
228,397 122,319
------------------------------------------------------------------------

Commitments and contingencies
(Note 10)

SHAREHOLDERS' EQUITY
Share capital (Note 7) 120,806 107,779
Contributed surplus (Note 8) 653 321
Retained earnings 13,716 13,172
------------------------------------------------------------------------
135,175 121,272
------------------------------------------------------------------------

TOTAL LIABILITIES AND SHAREHOLDERS'
EQUITY 363,572 243,591
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

Approved by the Board
"signed" "signed"
David J. Stenason Cyrille Vittecoq



CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands of dollars)
3 months ended 9 months ended
September 30 September 30
2005 2004 2005 2004
------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings (loss) (1,274) 1,379 544 3,051
Adjustments for:
Amortization 1,836 1,041 4,128 3,098
Unwind costs on interest
rate swap 1,924 - 1,924 -
Future income tax expense (919) 882 36 1,477
Loss (gain) on derivative
financial instrument (Note 3) (508) 232 (286) (9)
Stock compensation expense
(Note 8) 161 55 332 166
Loss (gain) on sale of
capital assets - - (78) -
------------------------------------------------------------------------
Cash flow from operations
before changes in non-cash
working capital 1,220 3,589 6,600 7,783
------------------------------------------------------------------------
Changes in non-cash working
capital (1,966) 1,537 (8,825) (3,689)
------------------------------------------------------------------------

(746) 5,126 (2,225) 4,094
------------------------------------------------------------------------

FINANCING ACTIVITIES
Long-term debt advances 149,100 - 192,500 -
Long-term debt repayments (48,863) (396) (59,294) (2,611)
Revolving construction
lines of credit advances
(Note 6(b)) - 5,000 23,100 16,100
Revolving construction
lines of credit repayments
(Note 6(b)) (51,900) (3,300) (51,900) (3,300)
Unwind costs on interest
rate swap (1,924) - (1,924) -
Deferred financing costs (1,149) - (1,669) -
Issue of common shares,
net of issue costs (Note 7) 132 12,972 552 13,245
------------------------------------------------------------------------

45,396 14,276 101,365 23,434
------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital asset additions (43,908) (15,267) (99,461) (33,684)
Prospect development costs (742) (972) (2,061) (2,019)
Net cash acquired on acquisition - - 638 -
Proceeds on sale of development
prospects - - 310 -
Proceeds on sale of capital
assets - - - 17
------------------------------------------------------------------------

(44,650) (16,239) (100,574) (35,686)
------------------------------------------------------------------------

NET INCREASE (DECREASE) IN CASH - 3,163 (1,434) (8,158)
CASH, BEGINNING OF PERIOD - 2,460 1,434 13,781
------------------------------------------------------------------------

CASH, END OF PERIOD - 5,623 - 5,623
------------------------------------------------------------------------

Supplemental information
Cash interest paid 2,887 1,316 6,743 3,847
Cash income and capital
taxes paid 255 242 787 790

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2005 and 2004 (Unaudited)
(Tabular amounts in thousands of dollars, except as otherwise noted)


1. SIGNIFICANT ACCOUNTING POLICIES

The accompanying interim consolidated financial statements of Canadian Hydro Developers, Inc. and its wholly-owned subsidiaries (the "Company") have been prepared in accordance with Canadian generally accepted accounting principles and reflect all adjustments (consisting of normal recurring adjustments and accruals) that are, in the opinion of management, necessary for a fair presentation of the results for the interim period.

These interim consolidated financial statements do not include all of the disclosures included in the Company's annual consolidated financial statements. Accordingly, these interim consolidated financial statements should be read in conjunction with the Company's most recent annual consolidated financial statements.

The accounting policies used in the preparation of these interim consolidated financial statements conform to those used in the Company's most recent annual consolidated financial statements, except as listed below.

Effective January 1, 2005, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") accounting guideline for identifying and accounting for variable interest entities ("VIEs"). Under the guideline, the Company is required to identify VIEs, determine whether it is the primary beneficiary of such entities and, if so, to consolidate them. The Company has considered the provisions of the guideline for all joint ventures and their related joint venture, operating and maintenance, marketing, power sales and debt agreements, if any. Factors considered in the analysis include how power sales payments are determined, responsibility and payment for capital, operating and maintenance expenses, and decision making by the joint venture participants. As a result of the review, the Company has determined that it does not have interests in VIEs that require consolidation. As a result of adopting this guideline there is no impact on the Company's financial statements.

2. COMPANY OPERATIONS

Interim results fluctuate due to plant maintenance, seasonal demands and demand for electricity and supply of water, and the timing and recognition of regulatory decisions and policies. Consequently, interim results are not necessarily indicative of annual results.

3. DERIVATIVE FINANCIAL INSTRUMENT

The Company entered into a Contract for Differences ("CFD") with another party whereby the other party has agreed to pay a fixed price to the Company based on the average monthly Pool Price for 110,000 MWh per year of electricity commencing January 1, 2005. While the CFD does not create any obligation by the Company for the physical delivery of electricity to the other party, the Company believed it would have sufficient electrical generation, which was not subject to contract, to satisfy the CFD at December 31, 2004. Because of this, the Company previously determined the CFD would qualify as a hedge. Due to the delay in the start up of the Grande Prairie EcoPower® Centre in early 2005, the CFD did not qualify for hedge accounting for the 6 months ended June 30, 2005. On July 1, 2005, the CFD was determined to re-qualify as a hedge and hedge accounting was prospectively applied on July 1, 2005.

At the time the CFD did not qualify for hedge accounting, it was fair valued and an initial amount of $444,000 was recorded as a derivative financial instrument asset and a deferred credit liability. The initial amount of the deferred credit is being recognized to income over the same period as the corresponding gains or losses associated with the CFD with $43,000 recognized into income each quarter as a gain on derivative financial instrument. During the 6 months ended June 30, 2005, $291,000 in payments received from the other party in connection with the CFD were recognized into income as a gain on derivative financial instrument. The 6 month decrease in the fair value of $558,000 was recognized into income as a loss on derivative financial instrument, resulting in a derivative financial liability of $116,000. On July 1, 2005, when hedge accounting was re-applied, this liability was recognized into earnings. Fair value was determined by taking the difference between the fixed purchase price for electricity and the forward market selling price for electricity for the third quarter of 2005 and the contract price for periods onwards, as no market forward prices existed, and multiplying this by the remaining notional amount of generation for each year under the CFD.

The remaining derivative financial instrument relates to a contract with another party that was disclosed in Note 5 to the audited consolidated financial statements as at and for the year ended December 31, 2004.



4. CAPITAL ASSETS

The major categories of capital assets at cost and related accumulated
amortization are as follows:

September December
30, 2005 31, 2004
-------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
-------------------------------------------

Generating plants
- operating 269,797 26,726 243,071 133,478
- construction-in-progress 95,495 - 95,495 86,295
Vehicles 946 627 319 175
Equipment, other 1,844 802 1,042 589
-------------------------------------------

368,082 28,155 339,927 220,537
-------------------------------------------
-------------------------------------------


For the 3 months ended September 30, 2005, interest costs of $1,258,000 (3 months ended September 30, 2004 - $154,000) and administration expenses of $181,000 (3 months ended September 30, 2004 - $111,000) associated with the construction-in-progress have been capitalized during construction. For the 9 months ended September 30, 2005, interest costs of $2,893,000 (9 months ended September 30, 2004 - $171,000) and administration expenses of $795,000 (9 months ended September 30, 2004 - $415,000) associated with the construction-in-progress have been capitalized during construction. At September 30, 2005, construction-in-progress is comprised of costs relating to the Melancthon I Wind Project ("Melancthon I"; formerly referred to as the "Melancthon Grey Wind Project") (September 30, 2004 - the Grande Prairie EcoPower® Centre, Taylor Wind, and Upper Mamquam projects). Costs associated with Upper Mamquam were transferred from construction-in-progress to operating plants upon commissioning on July 23, 2005. Costs associated with the Grande Prairie EcoPower® Centre were transferred from construction-in-progress to operating plants upon commissioning on June 21, 2005. In addition, costs associated with Melancthon I were transferred from prospect development costs to construction-in-progress, including prospect development costs acquired (see Note 7(b)), during the 3 months ended March 31, 2005.



5. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

September 30, December 31,
2005 2004
$ $
-----------------------------

Dunvegan Hydroelectric Prospect 7,512 6,885
Wind prospects 2,178 9,297
Hydroelectric prospects 2,051 1,117
-----------------------------

Total 11,741 17,299
-----------------------------
-----------------------------


The Company is currently in the process of completing its application to the regulators with respect to the Dunvegan Hydroelectric Prospect. Management anticipates filing the application and requesting a hearing date from the regulators in the first quarter of 2006, with an expected hearing date in the second quarter of 2006, and anticipates a decision will be rendered by the third quarter of 2006.

6. CREDIT FACILITIES

(a) Long-term debt

On February 11, 2005, the Company closed a joint debt private placement financing of the Pingston Hydroelectric Plant with its joint venture participant, Brascan Power Inc. (the "Pingston Debt"). The Pingston Debt consists of a $70,000,000 ($35,000,000 net to the Company), ten-year debt facility maturing on February 11, 2015, bearing interest at 5.281% per annum, with interest payable semi-annually and no principal repayments until maturity. The Pingston Debt is secured with a first fixed charge debenture, a floating charge over real property and an assignment of all material contracts related to the Pingston Hydroelectric Plant, as well as a pledge of the shares of Pingston Power Inc., without recourse to the joint venture participants. The proceeds from this financing are being used for general corporate purposes including, but not limited to, capital expenditures associated with Melancthon I. Concurrent with the closing of the Pingston Debt, the Company's corporate lenders removed the security that was associated with the Company's share of the Pingston Hydroelectric Plant. Costs incurred on the Pingston Debt are deferred and amortized over its 10 year term.

On June 23, 2005, the Company executed an amending agreement with its corporate lenders (the "Lenders") to extend its revolving loan (the "Bank Loan") and revolving construction lines of credit (see Note 6(b)) to September 23, 2005 (collectively, the "Credit Facilities"). Prior to repayment on September 1, 2005, the Bank Loan had a balance of $49,935,000 and the revolving construction lines of credit had a balance of $55,200,000. The Credit Facilities, including the letters of credit, were secured by a first fixed and floating charge debenture on all plants and subsidiary companies, with the exception of the Pingston Hydroelectric Plant and Cowley, a second charge debenture on Cowley, security interest over all present and after acquired personal property, a floating charge over all real property, and an assignment of certain sales agreements.

On July 29, 2005, the Lenders provided a $43,000,000 revolving bridge facility (the "Bridge Facility"), with monthly interest payments at prime plus 1.50% per annum, or at Bankers' Acceptances plus a fee of 2.75% per annum with standby fees of 0.25% for any undrawn portion. The Bridge Facility was used to fund certain initial capital expenditures relating to the construction of Melancthon I and had a maturity date of September 23, 2005.

The Credit Facilities and the Bridge Facility were repaid on September 1, 2005 using proceeds from the Debentures and the Construction Facility (see below).

On September 1, 2005, the Company closed a private debt placement financing of $120,000,000 of senior unsecured debentures (the "Debentures"). The Debentures have a 10-year term, with interest payable semi-annually at a rate of 5.334% and no principal repayments until maturity. The Debentures rank equally and ratably with all other unsecured and unsubordinated indebtedness of the Company for borrowed money. Costs incurred with respect to the Debentures have been deferred and are being amortized over its term. The Company used the proceeds from the Debentures to repay existing credit facilities and for general and corporate purposes.

On September 1, 2005, the Company closed a Credit Agreement with its Lenders for an aggregate of $100,600,000 in unsecured credit facilities consisting of a $75,600,000 construction facility (the "Construction Facility") and a $25,000,000 operating facility (the "Operating Facility"). The Construction Facility is an unsecured, non-revolving credit facility, with a 364-day drawdown period, followed by a two-year non-amortizing term out period, which is being used to assist in the financing of a portion of the capital expenditures associated with Melancthon I. The Operating Facility is a 364-day revolving credit facility, with a 6-month non-amortizing term out period, extendable for one-year periods annually by mutual agreement of the Company and its Lenders and will be used for general corporate purposes. The credit facilities bear interest at Bankers' Acceptances plus a stamping fee of 0.80% per annum. The credit facilities rank equally and ratably with all other unsecured and unsubordinated indebtedness of the Company for borrowed money.

Upon inception of the Bank Loan (see above) on December 19, 2002, the Company entered into an interest rate swap arrangement to fix the interest rate at 6.77% per annum on 100% of the Bank Loan for the first five years and 50% of the Bank Loan in years 6 through 10. As the Bank Loan was retired on September 1, 2005, the Company unwound the interest rate swap at a cost of $1,924,200 which has been charged to earnings during the quarter.

At September 30, 2005, the Company had not drawn any of its available Operating Facility except for letters of credit outstanding with its Lenders in the amount of $18,916,000 (December 31, 2004 - $15,345,000).



2005 2004
----------------------
$ $

Debentures (described above) 120,000 -

Pingston Debt (described above) 35,000 -

Construction Facility (described above) 29,100 -

Bank Loan (described above) - 49,635

Mortgage on Cowley, bearing interest at 10.867%,
secured by the plant, related contracts and a
reserve fund for $725,000 that has been provided
by a letter of credit to the lender. Monthly
repayments of principal and interest are
$121,000 until December 15, 2013 7,886 8,312

Mortgage, bearing interest at 10.7% and secured
by letter of guarantee. Monthly repayments of
principal and interest are $84,000 until
May 31, 2010 3,683 4,122

Mortgage, bearing interest at 10.68%, secured
by letters of guarantee. Monthly repayments
of principal are $31,000 plus interest until
December 30, 2012 2,719 3,000

Promissory note, bearing interest fixed at 6%,
secured by a second fixed charge on three of
the Alberta hydroelectric plants. Monthly
repayments of principal and interest are
$19,000 until August 1, 2012 1,315 1,428
----------------------


199,703 66,497

Less current portion 1,802 1,697
----------------------

Long-term debt 197,901 64,800
----------------------
----------------------


(b) Revolving construction lines of credit

On September 1, 2005, the Company repaid the outstanding balance on its revolving construction lines of credit using proceeds from the Debentures (see Note 6(a)). At December 31, 2004, $28,800,000 was drawn by the Company.



7. SHARE CAPITAL

(a) Issued, common shares

Number of Amount
Shares $
-----------------------
Balance, December 31, 2004 74,683,861 107,779
Issued on acquisition 4,037,687 12,113
Issued on exercise of stock options 736,750 587
Issued on private placement 85,575 350
Share issue costs, net of tax effect of $12,000 - (23)
-----------------------

Balance, September 30, 2005 79,543,873 120,806
-----------------------
-----------------------


On August 23, 2005, the Company issued 85,575 common shares of the Company to a third party as part of an agreement related to the construction of one of the Company's plants. The number of shares issued was based on the 30-day weighted average closing price prior to issuance of $4.09 per common share.

(b) Acquisition

On January 21, 2005, the Company acquired all of the issued and outstanding shares of Canadian Renewable Energy Corporation ("CREC") in exchange for 4,037,687 common shares of the Company valued at $12,113,000 and $47,000 in acquisition costs incurred for a total purchase price of $12,160,000. The common shares issued were valued at the closing price of the Company's shares on the date the Company signed a letter of intent with CREC, less 12%. As a result of the purchase, the Company acquired a 3.2 MW hydroelectric plant, certain development prospects, and 100% of Melancthon I, in which CREC had an option to acquire 50% of prior to January 23, 2005. No bank or other indebtedness was assumed in conjunction with this acquisition.



The allocation of the purchase price of CREC is as follows:
$
---------------

Generating plant - operating 6,934
Prospect development costs 4,450
Working capital 555
Future tax asset 221
---------------

Purchase price 12,160
---------------
---------------


In addition to 4,037,687 common shares of the Company being issued for the acquisition of CREC, 500,000 Series A Special Warrants (the "Series A Warrants"), and 1,750,000 Series B Special Warrants (the "Series B Warrants") were issued, which will vest and automatically convert (without the payment of any additional consideration) into common shares of the Company upon certain events occurring. In the event the Series A and B Warrants vest and automatically convert into common shares of the Company due to certain events occurring, additional consideration will be allocated to the purchase of CREC for accounting purposes.

The Series A Warrants will vest and automatically convert (without the payment of any additional consideration) into common shares if the Company is successful in obtaining a 20 year contract to sell power to OEFC or another Ontario Government agency (the "Contract") by the later of December 31, 2005 and the date the Ontario Government announces an award of the Contract for Misema, if Misema was bid into a request for proposals (a "Government RFP") prior to December 31, 2005. If these conditions are met, then the amount of common shares issued will vary (up to a maximum of 500,000 common shares) based on the price received for power generation in the Contract.

The Series B Warrants will vest and automatically convert (without the payment of any additional consideration) into common shares if the Company is successful in obtaining one or more renewable energy supply contracts through a Government RFP for CREC's development prospects or future phases of Melancthon I (the "RES Contracts") by the later of December 31, 2008 and the date the Ontario Government announces an award of the RES Contracts to the Company, if these projects were bid into a Government RFP prior to December 31, 2008. For each megawatt awarded to the Company under the RES Contract, 8,750 Series B Warrants will vest and automatically convert into an equal number of common shares, up to a maximum of 1,750,000 common shares.

ARC Canadian Energy Venture Fund 2 ("ARC Fund 2") and ARC Energy Venture Fund 3 (together the "ARC Funds") owned 86.6% of the issued and outstanding shares of CREC. As a result of the transaction, 3,494,676 common shares, 433,973 Series A Warrants and 1,518,906 Series B Warrants of the Company were issued to the ARC Funds and ARC Capital Ltd., in aggregate. The ARC Funds and ARC Capital are advised by ARC Financial Corporation whose CEO is an elected director of the Company. The acquisition of CREC has been recorded at the exchange amount, which represents the amount that would have been exchanged between arms' length parties.



8. EARNINGS PER SHARE AND STOCK COMPENSATION

The following table shows the dilutive effect of dilutive securities on
the weighted average common shares outstanding.


3 Months Ended 9 Months Ended
September 30, September 30,
2005 2004 2005 2004
--------------------------------------------------

Basic weighted
average shares
outstanding 79,461,292 70,811,184 78,842,529 69,574,274
Effect of dilutive
securities:
Warrants - 379,746 - 198,031
Options 1,780,822 1,884,972 1,854,943 1,771,960
--------------------------------------------------

Diluted weighted
average shares 81,242,114 73,075,902 80,697,472 71,544,265
--------------------------------------------------
--------------------------------------------------


Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $161,000 or $nil per share for the 3 months ended September 30, 2005 (3 months ended September 30, 2004 - $55,000 or $nil per share) and $332,000 or $nil per share for the 9 months ended September 30, 2005 (9 months ended September 30, 2004 - $166,000 or $nil per share) of compensation expense in the consolidated statement of earnings (loss), with a corresponding increase recorded to contributed surplus in the consolidated balance sheet as at September 30,2005. The weighted average fair value of options granted during the 3 months ended September 30, 2005 was $1.38 per share (9 months ended September 30, 2005 - $1.36 per share), which was estimated using the Black-Scholes option-pricing model, assuming an average risk free interest rate of 3.26% (9 months ended September 30, 2005 - 3.54%), average expected volatility of 37.67% (9 months ended September 30, 2005 - 37.88%), expected weighted average life of 4.0 years (9 months ended September 30, 2005 - 4.3 years), and no annual dividends paid. There were 150,000 options granted during the 3 months ended September 30, 2005 (9 months ended September 30, 2005 - 1,230,000). Effective April 1, 2005, all new options granted expire after five years. Options issued prior to April 1, 2005 have an expiry period of ten years. No stock options were issued during the 3 and 9 months ended September 30, 2004.

If the fair value method of accounting had been used for stock options issued to employees on or after January 1, 2002, but prior to January 1, 2003, then the effect would have been a decrease to net earnings of $31,000 or $nil per share for the 3 months ended September 30, 2005 (3 months ended September 30, 2004 - $31,000 or $nil per share), and $93,000 or $nil per share for the 9 months ended September 30, 2005 (9 months ended September 30, 2004 - $93,000 or nil per share).

9. ADMINISTRATION EXPENSES

Administration expenses for the nine months ended September 30, 2005 include a cash receipt of $750,000, net of associated costs, resulting from a settlement of a lawsuit the Company had with a former insurer and engineering firm associated with a project.

10. COMMITMENTS AND CONTINGENCIES

(a) In January 2005, the Company entered into various foreign exchange contracts, expiring in 2005, which fix the Company's U.S. dollar payments under a wind turbine purchase contract in Canadian dollars. The remaining aggregate amount of U.S. dollar purchases is $6,423,300, which is fixed at a blended average rate of 1.206 for a remaining aggregate Canadian dollar amount of $7,743,617. These foreign exchange contracts qualify as hedges under the CICA guideline on hedging relationships. At September 30, 2005, the fair value of the foreign exchange contracts were a loss of $280,000.

(b) In the ordinary course of maintaining plants and equipment, and in constructing new projects, the Company routinely enters into contracts for goods and services. Subsequent to September 30, 2005, the Company committed to approximately $19,987,000 for goods and services for the Melancthon I Wind Project, which will be expended during the remainder of 2005.

(c) The Company has entered into various contracts for differences ("CFDs") with other parties whereby the other parties have agreed to pay a fixed price to the Company based on the average monthly Pool price for an aggregate of 166,810 MWh per year of electricity commencing between January 1, 2005 and January 1, 2006. The CFDs mature from 2007 to 2024. While the CFDs do not create any obligation by the Company for the physical delivery of electricity to other parties, management believes it has sufficient electrical generation, which is not subject to contract, to satisfy the CFDs. The Company is unable to fair value two of the CFDs for an aggregate of 4,150 MWh per year of electricity because the CFD prices includes the sale of RECs along with the settlement of the average monthly Pool price. At December 31, 2004, the Company fair valued its various CFDs with other parties using the forward market prices for electricity for 2005 and 2006 and, due to the illiquidity of the forward market past 2006, using the 2006 forward market price for 2007 onwards, discounted at 5%. In 2005, given the ongoing illiquidity of the forward market, the Company enhanced its assumptions for fair valuing its CFDs by assuming the actual contract prices contained in the CFDs were the same as the forward prices for periods where no forward market prices exist. Had these assumptions been used at December 31, 2004, the fair value of the Company's CFDs would have resulted in a gain of $1,035,000 compared to a gain of $7,327,000 as disclosed previously. The enhanced assumptions relate to fair value disclosures and have no impact on previously reported earnings. During the 6 months ended June 30, 2005, one of the Company's CFDs no longer qualified as a hedge and hedge accounting was discontinued. On July 1, 2005, the CFD re-qualified as a hedge (see Note 3). As at September 30, 2005, the fair value of the remaining CFDs that continue to qualify as hedges would result in a loss of $1,069,000.


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