Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

November 14, 2006 15:53 ET

Canadian Hydro Announces Third Quarter Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 14, 2006) - Canadian Hydro Developers, Inc. (TSX:KHD) ("Canadian Hydro" or the "Company") reported cash flow from operations(2) of $3,820,000 ($0.03 per share, diluted(3)) on generation of 176 million kWh for the third quarter ended September 30, 2006 ("Q3 2006"), compared to cash flow from operations(2) of $1,220,000 ($0.02 per share, diluted(3)) on generation of 119 million kWh for Q3 2005. The Company reported net earnings of $292,000 ($nil per share, diluted) for Q3 2006, compared to a net loss of $1,274,000 ($0.02 per share, diluted) for Q3 2005.

Cash flow from operations(2) for the 9 months ended September 30, 2006 increased to $13,941,000 ($0.11 per share, diluted(3)) on generation of 526 million kWh, compared to $6,600,000 ($0.08 per share, diluted(3)) on generation of 324 million kWh for the same period in 2005. Net earnings for the 9 months ended September 30, 2006 were $5,568,000 ($0.05 per share, diluted(3)), compared to $544,000 ($0.01 per share, diluted(3)) for the same period in 2005.

Increased hydroelectric generation, the addition of the 67.5 MW Melancthon I Wind Plant ("Melancthon I"), interest income from the investment of cash on hand and improved operating results from the Grande Prairie EcoPower® Centre ("GPEC") led to improved financial results for Q3 2006. This was offset partially by lower wind generation in Alberta.



---------------------------------------------------------------------------
(unaudited) 3 Months Ended 9 Months Ended
September 30, September 30,
2006 2005 2006 2005
---------------------------------------------------------------------------
Financial Results (in thousands of
dollars except per share amounts)
Revenue 11,729 6,891 35,128 19,107
EBITDA(1) 6,818 3,600 20,487 11,936
Cash flow from operations(2) 3,820 1,220 13,941 6,600
Per share (diluted)(3) 0.03 0.02 0.11 0.08
Net earnings (loss) 292 (1,274) 5,568 544
Per share (diluted) - (0.02) 0.05 0.01

Operating Results
Electricity generation - MWh (net) 176,477 119,137 525,785 323,897
Average price received per MWh ($) 66 58 67 59
Electrical generation under contract (%) 88 85 89 85
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(1) EBITDA is provided to assist management and investors in determining
the ability of the Company to generate cash from operations(2). EBITDA
as presented is defined as cash flow from operations(2), plus interest
on debt, net of interest income, 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.
(2) Cash flow from operations before changes in non-cash working capital.
(3) Cash flow from operations(2) per share (diluted) is provided to assist
management and investors in determining the Company's cash flow from
operations(2) 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 2006 Achievements:

- In July 2006, the Company was awarded one 20 year and three 40 year Electricity Purchase Agreements from BC Hydro for the supply of 44.5 MW of electricity from hydroelectric projects. The power will come from the 20 MW Bone Creek, 9.9 MW Clemina Creek, 9.6 MW Serpentine Creek and 5 MW English Creek Hydroelectric Projects.

- Completed and submitted the joint application to the Alberta Energy and Utilities Board and Natural Resources Conservation Board for the Company's 100 MW Dunvegan Hydroelectric Prospect in Alberta in October 2006.

- For the first time since the achievement of commercial operations at GPEC, the plant generated positive cash flow for Q3 2006, with continued improvement anticipated for the fourth quarter.

Subsequent to Q3 2006, the Company entered into an arrangement agreement with Vector Wind Energy Inc. ("Vector") pursuant to which the Company will acquire all of the issued and outstanding common shares of Vector at a cash price of $0.30 per Vector share for total consideration (including acquisition costs) of $6.3 million. The acquisition will be completed pursuant to a statutory plan of arrangement and will require the approval of 66 2/3% of the votes cast by Vector shareholders. Closing of the acquisition is anticipated by year-end. Additionally, the Company and Vector have entered into a conveyancing agreement pursuant to which the Company has acquired three of Vector's wind prospects in Ontario for consideration of $750,000. Vector is a developer of wind energy projects in Canada and currently has 20 active prospect areas with the potential to support over 1,000 MW of wind energy capacity.

"The acquisition of Vector will strategically position the Company for wind development opportunities in Manitoba where future requests for proposals for power purchase contracts for wind are expected to be announced in the near future," said John Keating, Chief Executive Officer. "This acquisition, including the purchase of wind prospects in Ontario, provides the Company the means to further diversify its portfolio across new wind regimes and in different provinces strengthening the potential for future growth."

Canadian Hydro is a developer, owner and operator of 18 renewable energy generation facilities totalling net 230 MW in operation and has an additional 384 MW nearing construction. The renewable generation portfolio is diversified across three technologies (water, wind and biomass) in the provinces of British Columbia, Alberta and Ontario. This portfolio is unique in Canada as all facilities are certified, or slated for certification, under Environment Canada's EcoLogo(M) Program.

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.

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

The following MD&A, dated November 6, 2006, should be read in conjunction with the unaudited interim consolidated financial statements as at and for the 3 and 9 months ended September 30, 2006 and 2005, 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, 2005. 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 that 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 2006, revenue increased 70% to $11,729,000 on generation of 176 million kWh compared to $6,891,000 on generation of 119 million kWh in Q3 2005. For the 9 months ended September 30, 2006, revenue increased 84% to $35,128,000 on increased generation of 526 million kWh compared to $19,107,000 on generation of 324 million kWh for the same period in 2005. For Q3 2006, the increase in revenue was due to a significant increase in generation, as a result of the addition of the Melancthon I Wind Plant ("Melancthon I"), which began commercial operations on March 4, 2006 and improved results at the Grande Prairie EcoPower® Centre ("GPEC"). On a same plant basis, the Company experienced higher hydroelectric generation in Ontario and Alberta due to increased quarter over quarter precipitation, offset partially by lower wind generation, due to less windy conditions in Alberta, and lower hydroelectric generation in B.C., due to below normal water flows.

For the 9 months ended September 30, 2006, the increase in revenue was due to higher generation resulting from the following new plant additions: Melancthon I (as discussed above), GPEC and the Upper Mamquam Hydroelectric Plant ("Mamquam"), which were commissioned in June and July 2005, respectively, in addition to windier conditions in Alberta during the first half of this year. Hydroelectric generation in Ontario was higher than the prior year, mainly due to increased precipitation period over period. Dryer first quarter conditions resulted in lower period over period hydroelectric generation in Alberta. Hydroelectric generation in B.C., on a same plant basis, was lower period over period due to below normal water flows.

Approximately 88% of the Company's generation was sold pursuant to long-term sales contracts in Q3 2006 and 89% for the 9 months ended September 30, 2006 (Q3 2005 and 2005 - 85%). The average price received by the Company for electricity from all operations for Q3 2006 was $66/MWh and $67/MWh for the 9 months ended September 30, 2006 (Q3 2005 - $58/MWh; 2005 - $59/MWh).



Electricity Generation - by Province and Technology

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Electricity Generation - MWh(1)
Q3 2006 Q3 2005 Variance 2006 2005 Variance
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British Columbia 60,024 54,072 + 11% 175,077 131,937 + 33%
Alberta 75,129 58,079 + 29% 216,253 141,021 + 53%
Ontario 41,324 6,986 + 492% 134,455 50,939 + 164%
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Totals 176,477 119,137 + 48% 525,785 323,897 + 62%
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Hydroelectric 98,540 83,395 + 18% 288,476 229,575 + 26%
Wind 47,805 22,394 + 113% 163,236 79,203 + 106%
Biomass 30,132 13,348 + 126% 74,073 15,119 + 390%
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Totals 176,477 119,137 + 48% 525,785 323,897 + 62%
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(1) Reflecting the Company's net interest.


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Electricity Generation for Same Plants - MWh(1,2)
Q3 2006 Q3 2005 Variance 2006 2005 Variance
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Hydroelectric 98,540 83,395 + 18% 288,476 229,575 + 26%
Wind 18,591 22,394 - 17% 86,703 79,203 + 9%
Biomass 30,132 13,348 + 126% 74,073 15,119 + 390%
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Totals 147,263 119,137 + 24% 449,252 323,897 + 39%
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(1) Reflecting the Company's net interest.
(2) Hydroelectric generation for GPEC and Mamquam included for comparison
purposes. GPEC and Mamquam achieved commercial operations in June and
July 2005, respectively.


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Electricity Generation for New Plants - MWh(1)
Q3 2006 2006
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Melancthon I 29,214 76,533
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Total - new 29,214 76,533
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(1) Reflecting the Company's net interest.


Operating Expenses

Operating expenses increased 44% to $4,226,000 in Q3 2006 compared to $2,943,000 in Q3 2005. For the 9 months ended September 30, 2006, operating expenses increased 91% to $12,481,000 from $6,524,000 for the same period in 2005. Gross margins (revenue less operating expenses; expressed as a percentage of revenue) of 64% in Q3 2006 were higher than Q3 2005 (57%). Gross margins for the 9 months ended September 30, 2006 were lower at 64% compared to 66% for the same period in 2005. The increase in operating expenses was due primarily to the addition of Melancthon I, which achieved commercial operations on March 4, 2006 and had no comparable operating expenses in Q3 2005. For the 9 months ended September 30, 2006, operating expenses increased as a result of new plant additions, as mentioned above. GPEC, which encountered issues with commissioning during 2005 and 2006, generated positive cash flow in Q3 2006 and continues to improve in the fourth quarter of 2006.

Interest on Long-Term Debt, Long-Term Debt, Interest Income and Unwind Costs on Interest Rate Swap

Interest on long-term debt (excluding capitalized interest) in Q3 2006 increased 101% to $4,124,000 compared to $2,050,000 in Q3 2005 and for the 9 months ended September 30, 2006, increased 113% to $9,613,000 from $4,517,000 for the same period in 2005. The increase was due to higher outstanding corporate debt, mainly due to the issuance of the unsecured corporate debentures (the "Debentures") in September 2005 and June 2006.

Interest income from the investment of cash on hand in term deposits in Q3 2006 and for the 9 months ended September 30, 2006 was $1,323,000 and $3,707,000, respectively (2005 - $nil).

Capitalized interest associated with construction-in-progress in Q3 2006 was $695,000 (Q3 2005 - $1,258,000) and $1,204,000 for the 9 months ended September 30, 2006 (2005 - $2,893,000). The decrease was due to fewer projects under construction compared to the prior year.

Long-term debt (including current portion) as at September 30, 2006 was $316,801,000 (September 30, 2005 - $199,703,000) compared to $226,765,000 as at December 31, 2005. In June 2006, the Company closed the issuance of an aggregate of $148,000,000 of Debentures in two series by way of private placement. The Series 2 senior unsecured debentures, with a gross principal amount of $27,000,000, have a 10-year term maturing on June 19, 2016 and bear an interest rate of 5.69% per annum with interest paid semi-annually. The Series 3 senior unsecured debentures with a gross principal amount of $121,000,000 have a 12-year term maturing on June 19, 2018 and bear an interest rate of 5.77% per annum with interest paid semi-annually. The proceeds from the debentures were used to retire the Company's construction credit facility for Melancthon I and to fund capital costs associated with the construction of Melancthon II and Wolfe Island and for general corporate purposes. Dominion Bond Rating Service Ltd. ("DBRS") confirmed its rating of BBB with a Stable trend for the Debentures. The offsetting decrease to long-term debt was due to regular repayments during the 9 months ended September 30, 2006.

In Q3 2005, the Company significantly restructured its debt, and as a result, an interest rate swap that fixed the interest rate on a portion of its secured bank credit facilities was unwound at a cost of $1,924,000, which was a one-time charge to earnings during Q3 2005.

As at September 30, 2006, the Company had a 49/51 debt/equity mixture (December 31, 2005 - 41/59) compared to a stated target of 65/35. The debt/equity mixture changed from the prior year due to the issuance of the Debentures, offset by using cash flow from operations and cash received from the equity issuance in December 2005 to finance costs related to construction projects.

Amortization Expense

Amortization expense increased 59% to $2,918,000 for Q3 2006 (Q3 2005 - $1,836,000), and 101% to $8,306,000 for the 9 months ended September 30, 2006 (2005 - $4,128,000) due to new plant additions, as mentioned above. The wind plant is amortized over a 30 year period and the hydroelectric and biomass plants are amortized over 40 year periods.

Administration Expense

Administration expense increased 27% to $996,000 in Q3 2006 (Q3 2005 - $787,000), and increased 108% to $3,311,000 for the 9 months ended September 30, 2006 (2005 - $1,595,000). For the nine months ended September 30, 2005, the Company received 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. The increase in 2006 was also due to moderately higher salary costs with the addition of new employees and increased stock compensation expense due to a higher fair value associated with options granted (Q3 2006 - 125,000; $1.75 per share ($407,000); 2006 - 2,230,000; $1.95 per share ($1,002,000); Q3 2005 - 150,000; $1.38 per share ($161,000); 2005 - 1,230,000; $1.36 per share ($332,000)). Capitalized administration costs associated with construction-in-progress in Q3 2006 were $330,000 (Q3 2005 - $181,000), and $1,427,000 for the 9 months ended September 30, 2006 (2005 - $795,000).

Financial Instruments

When a contract does not meet the criteria for hedge accounting, the changes in the fair value are recorded in income as either a gain or a loss, with a corresponding asset or liability, respectively, on the balance sheet. The gain on derivative financial instrument was $43,000 in Q3 2006 with a loss on derivative financial instrument of $116,000 for the 9 months ended September 30, 2006 compared to a gain of $786,000 in Q3 2005 (2005 - $902,000). In Q3 2006, the gain was comprised of a $43,000 recognition of the deferred credit into income relating to a contract for differences ("CFD") that did not qualify for hedge accounting in the prior year. For the 9 months ended September 30, 2006, the $116,000 loss was a result of a $401,000 fair value decrease of a CFD that expired during the year, offset partially by $156,000 in cash payments from another party in connection with the expired CFD and a $129,000 recognition of the deferred credit. In Q3 2005, the $786,000 gain was comprised of a $465,000 increase in the fair value of various CFDs, $278,000 in cash payments received from other parties relating to CFDs and a $43,000 amortization into income of the deferred credit (see above). For the 9 months ended September 30, 2005, in addition to the above, the $902,000 gain included a $145,000 decrease in the fair value of various CFDs, $175,000 in cash payments received from another party in connection with the expired CFD and a $86,000 recognition of the deferred credit.

The Company has entered into various foreign exchange contracts, expiring in 2007, which fix the Company's U.S. dollar and Euro payments under wind turbine purchase contracts in Canadian dollars. The aggregate remaining amount of U.S. dollar purchases is $14,981,420, which is fixed at a blended rate of 1.1515 for an aggregate Canadian dollar amount of $17,251,105. The aggregate amount of Euro purchases is EUR 136,011,580, which is fixed at a blended average rate of 1.4602 for an aggregate Canadian dollar amount of $198,602,284. These foreign exchange contracts qualify as hedges for accounting purposes. At September 30, 2006, the fair value of the foreign exchange contracts would result in a loss of $5,296,000.

As disclosed in the December 31, 2005 MD&A, the Company has entered into various 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 184,330 MWh per year of electricity from January 1, 2006, maturing from 2007 to 2024. At September 30, 2006, the fair value of the CFDs that qualify as hedges would result in a loss of $562,000.

Taxes

The Company does not anticipate paying cash income taxes for several years, other than in respect of the Cowley Ridge Wind Plant, through its wholly owned subsidiary, Cowley Ridge Wind Power Inc. The Company is also liable for Provincial Capital Taxes in Ontario, which comprise the current tax provision. On May 2, 2006, the Federal Government passed a budget that eliminated the Federal Tax on Large Corporations ("LCT") effective January 1, 2006, and as a result, the Company has lower current taxes compared to the prior year.

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 expense was $246,000 in Q3 2006 (Q3 2005 - future tax recovery of $919,000). Future income tax recovery for the 9 months ended September 30, 2006 was $1,207,000 (2005 - future tax expense of $36,000). For Q3 2006, the increase in future tax expense was due to higher taxable earnings compared to the prior year. For the 9 months ended September 30, 2006, the decrease was due to a reduction in the corporate tax rates as a result of the May 2006 budget as discussed above, combined with tax pools available to the Company to offset current taxes to future periods.

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

Net earnings were $292,000 ($nil per share) in Q3 2006 compared to a net loss of $1,274,000 ($(0.02) per share) in Q3 2005. The increase was due to higher gross margins, interest income, and no unwind costs on interest rate swap and current taxes; offset partially by higher amortization, interest on long-term debt, future tax expense, lower gain on derivative financial instruments and higher administration expense, as discussed above. For the 9 months ended September 30, 2006, net earnings were $5,568,000 ($0.05 per share) compared to $544,000 ($0.01 per share) for the same period in the prior year. The year-to-date increase was mainly due to the same factors as Q3 2006, in addition to a future tax recovery due to the change in corporate tax rates during the year and no unwind costs on interst rate swap. Similarly, excluding non-cash items, cash flow from operations was $3,820,000 for Q3 2006 (Q3 2005 - $1,220,000) and $13,941,000 for the 9 months ended September 30, 2006 (2005 - $6,600,000).

Capital Asset Additions and Prospect Development Costs

Capital asset additions were $91,236,000 in Q3 2006 (Q3 2005 - $43,908,000) and $181,693,000 for the 9 months ended September 30, 2006 (2005 - $99,461,000), resulting in a 49% increase in the net book value of capital assets since December 31, 2005. These additions relate to construction costs associated with Melancthon I, which achieved commercial operations on March 4, 2006, and Melancthon II, which is currently in the approvals process for commencement of construction. Additions of prospect development costs were $6,306,000 in Q3 2006 (Q3 2005 - $742,000) and $16,676,000 for the 9 months ended September 30, 2006 (2005 - $2,061,000), relating primarily to wind turbine equipment deposits for Wolfe Island.



Financial Position

The following chart outlines significant changes in the consolidated
balance sheet from December 31, 2005 to September 30, 2006:

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Increase (Decrease) Explanation
$
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Cash (100,130) Decrease due to capital asset
additions for Melancthon I and
Melancthon II, prospect
development costs, long-term debt
repayments and payments of
accounts payable since year end;
offset partially by the issuance
of Debentures, interest income
received on cash invested in term
deposits, cash flow from
operations, and the issuance of
common shares through the
exercise of stock options.

Accounts receivable 2,626 Increase in uncollected revenue
due to new plant additions and
higher generation in September
2006 compared to December
2005.

Capital assets 178,395 Construction costs related to
Melancthon I and Melancthon II;
partially offset by amortization.

Prospect development costs 16,739 Increase due primarily to costs
related to the development of
Wolfe Island (see Note 5 to the
interim consolidated financial
statements).

Accounts payable and accrued 2,505 Accrued expenses at September 30,
liabilities 2006 combined with accrued interest
expenses due to the issuance of
Debentures.

Long-term debt (including 90,036 Issuance of Debentures; offset by
current portion) repayment of construction
credit facility for Melancthon I
and regular repayments on long
term debt.

Future income taxes (1,181) Decrease due to a reduction in the
federal corporate tax rates as
enacted in the May 2006 Federal
Budget.

Share capital 1,440 Increase due to the issuance of
common shares through the exercise
of stock options.
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Capital Resources and Liquidity

The Company's current capital expenditure plans total approximately $823,300,000 for the construction of three projects in Ontario from 2006 to 2008, four projects in B.C. from 2007 to 2009 and the acquisition of Vector. Up to $188,000,000 of the capital costs are being financed from proceeds of the public offering completed in 2005, a further $104,250,000 from expected future cash flow to be generated by the Company and potential future equity offerings, and the remaining $531,050,000 through completed and anticipated debt financings.

In Q3 2006, the Company issued 126,250 common shares (Q3 2005 - 88,250) through the exercise of stock options at an average exercise price of $2.45 per share (Q3 2005 - $1.50 per share) for gross proceeds of $309,000 (Q3 2005 - $132,000). For the 9 months ended September 30, 2006, the Company issued 1,212,400 common shares (2005 - 736,750) through the exercise of stock options at an average exercise price of $1.14 per share (2005 - $0.80) for gross proceeds of $1,382,000 (2005 - $552,000).

Disclosure Controls

As of the end of the period covered by this quarterly report, the CEO and CFO have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on this evaluation, the CEO and CFO have concluded that the disclosure controls and procedures continue to be effective.



Outstanding Share Data

----------------------------------------------
As at November 6,
2006
(Unaudited)
----------------------------------------------
Basic common shares 119,478,773
Convertible securities:
Warrants 500,000
Options 7,340,257
----------------------------------------------
Fully diluted common shares 127,319,030
----------------------------------------------
----------------------------------------------


Outlook

Reservoir levels in Alberta, where four of the Company's hydroelectric plants are located, are currently at normal levels for this time of year. As a result, hydroelectric generation in Alberta for Q4 2006 is expected to be at average levels. Precipitation in Ontario is normal and is expected to be normal this winter. In B.C., due to dry conditions throughout the summer and into the fall, water flows have been lower than average. As a result, the Company expects below average hydroelectric generation in B.C. for the remainder of the year.

Due to a longer than expected approvals process for the Melancthon II Wind Project, resulting primarily from the provincial Environmental Screening Process, the Company has not yet commenced construction of this 132 MW project. The Company is confident that all expressed issues will be dealt with fairly and the Ontario Ministry of Environment will issue their approval for Melancthon II. Canadian Hydro expects this project to be completed and operational by June 2008; a change to the anticipated in-service date for the project by up to 12 months. The extended approvals process has resulted in an increase of $10,000,000 for a capital cost of $275,000,000. Securing other permits and approvals for Melancthon II remains necessary prior to proceeding to construction; delays in which may also impact the ultimate in-service date and capital cost for the project.

The Company continues to pursue the development of the Dunvegan Hydroelectric Prospect. The Company submitted its joint application to the Alberta Energy and Utilities Board and Natural Resources Conservation Board in October 2006, and anticipates a possible hearing date in the spring of 2007, and a regulatory decision for the approval of construction and operation in the summer of 2007.

In addition, the Company is working diligently on obtaining the necessary permits and approvals for the Ontario projects including the 197.8 MW Wolfe Island Wind Project and the 20 MW (10 MW net to the Company's interest) Island Falls Hydroelectric Project anticipated to achieve commercial operations by October 2008, and the 44.5 MW of hydroelectric projects awarded Electricity Purchase Agreements from BC Hydro anticipated to achieve commercial operations in the fourth quarter of 2009.

Subsequent to quarter-end, the Company entered into an arrangement agreement with Vector Wind Energy Inc. ("Vector") pursuant to which the Company will acquire all of the issued and outstanding common shares of Vector at a cash price of $0.30 per Vector share for a total estimated cost (including acquisition costs) of $6.3 million. The acquisition will be completed pursuant to a statutory plan of arrangement and will require the approval of 66 2/3% of the votes cast by Vector shareholders. Closing of the acquisition is anticipated by year-end. Additionally, the Company and Vector have entered into a conveyancing agreement pursuant to which the Company has acquired three of Vector's wind prospects in Ontario for consideration of $750,000. Vector is a developer of wind energy projects in Canada and currently has 20 active prospect areas with the potential to support over 1,000 MW of wind energy capacity.



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
2006 2005 2006 2005
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Revenue
Electric energy sales 11,651 6,796 34,772 18,780
Revenue rebate 78 95 356 327
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11,729 6,891 35,128 19,107
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Expenses (Other Income)
Operating 4,226 2,943 12,481 6,524
Interest on long-term debt (Note 4) 4,124 2,050 9,613 4,517
Interest income (1,323) - (3,707) -
Amortization 2,918 1,836 8,306 4,128
Administration (Notes 4) 996 787 3,311 1,595
Foreign exchange loss 96 - 7 -
(Gain) loss on derivative financial
Instrument (Note 3) (43) (786) 116 (902)
Gain on sale of development prospects - - - (78)
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10,994 6,830 30,127 15,784
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Earnings before the following 735 61 5,001 3,323

Unwind costs on interest rate swap - 1,924 - 1,924
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Earnings (loss) before taxes 735 (1,863) 5,001 1,399
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Tax expense (recovery)
Current 197 330 640 819
Future 246 (919) (1,207) 36
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443 (589) (567) 855
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Net earnings (loss) 292 (1,274) 5,568 544

Retained earnings, beginning of period 19,268 14,990 13,992 13,172
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Retained earnings, end of period 19,560 13,716 19,560 13,716
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Earnings (loss) per share (Note 8)
Basic - (0.02) 0.05 0.01
Diluted - (0.02) 0.05 0.01

See accompanying notes to the consolidated financial statements



CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED BALANCE SHEETS (Unaudited)
(in thousands of dollars)

September 30, December 31,
2006 2005
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ASSETS
Current assets
Cash 79,671 179,801
Accounts receivable 8,804 6,178
Revenue rebate 871 515
Taxes receivable 73 -
Prepaid expenses 1,196 771
Derivative financial instrument (Note 3) - 401
---------------------------------------------------------------------------

90,615 187,666

Deferred financing costs 2,922 2,072
Capital assets (Note 4) 541,921 363,526
Prospect development costs (Note 5) 46,824 30,085
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TOTAL ASSETS 682,282 583,349
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LIABILITIES
Current liabilities
Taxes payable - 251
Deferred credit (Note 3) 143 272
Accounts payable and accrued liabilities 11,757 9,252
Current portion of long-term debt (Note 6) 1,955 1,838
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13,855 11,613

Long-term debt (Note 6) 314,846 224,927
Future income taxes 19,050 20,231
---------------------------------------------------------------------------

347,751 256,771
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Commitments and contingencies (Note 9)

SHAREHOLDERS' EQUITY
Share capital (Note 7) 313,211 311,771
Contributed surplus (Note 8) 1,760 815
Retained earnings 19,560 13,992
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334,531 326,578
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TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 682,282 583,349
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See accompanying notes to the consolidated financial statements

Approved by the Board
"signed" "signed"
Dennis Erker David J. Stenason



CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands of dollars)

3 months ended 9 months ended
September 30 September 30
2006 2005 2006 2005
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OPERATING ACTIVITIES
Net earnings (loss) 292 (1,274) 5,568 544
Adjustments for:
Amortization 2,918 1,836 8,306 4,128
Unwind costs on interest rate swap - 1,924 - 1,924
Stock compensation expense (Note 8) 407 161 1,002 332
Future income tax expense (recovery) 246 (919) (1,207) 36
Loss (gain) on derivative financial
instrument (Note 3) (43) (508) 272 (286)
Gain on sale of capital assets - - - (78)
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Cash flow from operations before
changes in non-cash working capital 3,820 1,220 13,941 6,600
Changes in non-cash working capital (865) (1,966) (6,377) (8,825)
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2,955 (746) 7,564 (2,225)
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FINANCING ACTIVITIES
Construction credit facility
repayments (Note 6) - - (56,600) -
Long-term debt advances - 149,100 148,000 192,500
Long-term debt repayments (464) (48,863) (1,364) (59,294)
Revolving construction lines of
credit advances - - - 23,100
Revolving construction lines of
credit repayments - (51,900) - (51,900)
Unwind costs on interest rate swap - (1,924) - (1,924)
Deferred financing costs (44) (1,149) (743) (1,669)
Issue of common shares, net of
issue costs (Note 7) 309 132 1,382 552
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(199) 45,396 90,675 101,365
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INVESTING ACTIVITIES
Capital asset additions (91,236) (43,908) (181,693) (99,461)
Prospect development costs (6,306) (742) (16,676) (2,061)
Net cash acquired on acquisition - - - 638
Proceeds on sale of development
prospects - - - 310
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(97,542) (44,650) (198,369) (100,574)
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NET DECREASE IN CASH (94,786) - (100,130) (1,434)
CASH, BEGINNING OF PERIOD 174,457 - 179,801 1,434
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CASH, END OF PERIOD 79,671 - 79,671 -
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Supplemental information
Cash interest paid 5,475 2,887 8,873 6,743
Cash income and capital taxes paid 103 255 676 787

See accompanying notes to the consolidated financial statements



CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2006 and 2005 (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.

Certain hydroelectric activities of the Company are conducted jointly with others and accordingly, the accounts reflect only the proportionate interest of the Company's 50% owned unincorporated joint ventures and limited partnership.

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.

These 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.

2. COMPANY OPERATIONS

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

3. DERIVATIVE FINANCIAL INSTRUMENTS

To support the Company's obligations under a guarantee to a third party, the Company entered into a contract with another party whereby the other party will pay the Alberta Power Pool price to the Company in return for the Company paying the other party a fixed price for approximately 5 MW of electricity per year for three years commencing April 1, 2003. As at December 31, 2005, the Company had recorded $401,000 as a derivative financial instrument asset representing the fair value of the contract. In 2006, this contract expired and as a result, the asset was reversed to reflect a $nil fair market value with a corresponding $401,000 loss on derivative financial instrument recorded into income. Offsetting this loss was $156,000 in payments received from the other party in connection with this contract recognized into income as a gain on derivative financial instruments during the year.

Included in the loss on derivative financial instrument for Q3 2006 is $43,000 (Q3 2005 - $43,000) and for the 9 months ended September 30, 2006, $129,000 (2005 - $129,000) for the amortization of the deferred credit related to a contract that did not qualify for hedge accounting in the prior year. The deferred credit is recognized into income over the life of the contract.

The Company has entered into various foreign exchange contracts, expiring in 2007, which fix the Company's U.S. dollar and Euro payments under wind turbine purchase contracts in Canadian dollars. The aggregate remaining amount of U.S. dollar purchases is $14,981,420, which is fixed at a blended rate of 1.1515 for an aggregate Canadian dollar amount of $17,251,105. The aggregate amount of Euro purchases is EUR 136,011,580, which is fixed at a blended average rate of 1.4602 for an aggregate Canadian dollar amount of $198,602,284. These foreign exchange contracts qualify as hedges for accounting purposes. At September 30, 2006, the fair value of the foreign exchange contracts would result in a loss of $5,296,000.

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 184,330 MWh per year of electricity from January 1, 2006, maturing 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 Renewable Energy Certificates along with the settlement of the average monthly Pool price. The Company's assumptions for fair valuing its CFDs, given the ongoing illiquidity of the forward market, assumes the actual contract prices contained in the CFDs are the same as the forward prices for years where no forward market exists. At September 30, 2006, the fair value of the CFDs that qualify as hedges would result in a loss of $562,000.



4. CAPITAL ASSETS

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

December 31,
September 30, 2006 2005
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Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
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Generating plants
- operating 402,772 36,269 366,503 243,813
- construction-in-progress 173,745 - 173,745 118,317
Vehicles 1,365 870 495 283
Equipment, other 2,240 1,062 1,178 1,113
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580,122 38,201 541,921 363,526
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For the 3 months ended September 30, 2006, interest costs of $695,000 (3 months ended September 30, 2005 - $1,258,000) and administration expenses of $330,000 (3 months ended September 30, 2005 - $181,000) associated with the construction-in-progress have been capitalized during construction. For the 9 months ended September 30, 2006, interest costs of $1,204,000 (9 months ended September 30, 2005 - $2,893,000) and administration expenses of $1,427,000 (9 months ended September 30, 2005 - $795,000) associated with construction-in-progress have been capitalized during construction. In 2006, construction costs of $124,000,000 relating to the Melancthon I Wind Plant ("Melancthon I") were transferred from construction-in-progress to operating plants and prospect development costs of $173,039,000 relating to the Melancthon II Wind Project ("Melancthon II") were transferred into construction-in-progress. In 2005, construction-in-progress related to costs associated with the Upper Mamquam Hydroelectric Plant and Melancthon I.



5. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

September 30, December 31,
2006 2005
$ $
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Wind prospects 34,116 20,004
Dunvegan Hydroelectric Prospect 8,247 7,676
Hydroelectric prospects 4,461 2,405
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Total 46,824 30,085
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The majority of the costs included in wind prospects relate to turbine supply and preliminary engineering and design for the Wolfe Island Wind Project ("Wolfe Island"). In 2006, the Company acquired all of the issued and outstanding shares of Valisa Energy Incorporated ("Valisa"). The purchase price was entirely allocated to prospect development costs. Valisa owns the Serpentine Hydroelectric Project in British Columbia, which costs are included above.

6. LONG-TERM DEBT

At September 30, 2006, the Company had letters of credit in the amount of $22,352,000 (December 31, 2005 - $24,138,000) outstanding with its corporate lenders.



September 30, December 31,
2006 2005
$ $
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Series 1 Debentures, bearing interest at
5.334%, 10-year term with interest payable
semi-annually and no principal repayments
until maturity on September 1, 2015, senior
unsecured 120,000 120,000

Series 2 Debentures, bearing interest at
5.69%, 10-year term with interest payable
semi-annually and no principal repayments
until maturity on June 19, 2016, senior
unsecured 27,000 -

Series 3 Debentures, bearing interest at
5.77%, 12-year term with interest payable
semi-annually and no principal repayments
until maturity on June 19, 2018, senior
unsecured 121,000 -

Pingston Debt, bearing interest at 5.281%,
10-year term with interest payable
semi-annually and no principal repayments
until maturity on February 11, 2015, secured
by the Pingston Hydroelectric Plant, without
recourse to joint venture participants 35,000 35,000

Construction Facility, bearing interest at
Bankers' Acceptances plus a stamping fee of
0.80% per annum, unsecured non revolving
credit facility with a 364-day drawdown period,
followed by a two-year non-amortizing term
out period - 56,600

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 7,261 7,735

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 3,040 3,529

Mortgage, bearing interest at 10.68%, secured
by letters of guarantee. Monthly repayments of
principal are $31,000 plus interest until
December 30, 2012 2,344 2,625

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 1,156 1,276
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316,801 226,765

Less current portion 1,955 1,838
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Long-term debt 314,846 224,927
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In June 2006, the Company closed the issuance of an aggregate of $148,000,000 of unsecured corporate debentures (the "Debentures") in two series by way of private placement. The Series 2 senior unsecured debentures, with a gross principal amount of $27,000,000, have a 10-year term and bear an interest rate of 5.69% per annum with interest paid semi-annually. The Series 3 senior unsecured debentures with a gross principal amount of $121,000,000 have a 12-year term and bear an interest rate of 5.77% per annum with interest paid semi-annually. The proceeds from the debentures were used to retire the Construction Facility for Melancthon I and will be used to fund capital costs associated with the construction of Melancthon II and Wolfe Island and for general corporate purposes.



7. SHARE CAPITAL

Issued, common shares

Number of Amount
Shares $
------------------------------

Balance, December 31, 2005 118,223,873 311,771
Issued on exercise of stock options 1,212,400 1,382
Stock compensation on shares exercised - 58
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Balance, September 30, 2006 119,436,273 313,211
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------------------------------


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,
2006 2005 2006 2005
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Basic weighted average
shares outstanding 119,366,115 79,461,292 119,213,560 78,842,529
Effect of dilutive
securities:
Options 2,270,152 1,780,822 2,563,950 1,854,943
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Diluted weighted average
shares 121,636,267 81,242,114 121,777,510 80,697,472
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Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $407,000 for Q3 2006 (Q3 2005 - $161,000) and $1,002,000 for the 9 months ended September 30, 2006 (2005 - $332,000) of compensation expense in the consolidated statement of earnings, with a corresponding increase recorded to contributed surplus in the consolidated balance sheet as at September 30, 2006. The Company issued 125,000 options in Q3 2006 (Q3 2005 - 150,000) and 2,230,000 options for the 9 months ended September 30, 2006 (2005 - 1,230,000). The weighted average fair value of options granted during Q3 2006 was $1.75 per share (Q3 2005 - $1.38 per share), which was estimated using the Black-Scholes option-pricing model, assuming a risk free interest rate of 4.33% (Q3 2005 - 3.26%), expected volatility of 35.53% (Q3 2005 - 37.67%), expected weighted average life of 4.0 years (Q3 2005 - 4.0 years), and no annual dividends paid. The weighted average fair value of options granted during the 9 months ended September 30, 2006 was $1.95 per share (2005 - $1.36 per share), assuming a risk free interest rate of 4.21% (2005 - 3.54%), expected volatility of 36.00% (2005 - 37.88%), expected weighted average life of 4.0 years (2005 - 4.3 years), and no annual dividends paid.

9. COMMITMENTS AND CONTINGENCIES

In the ordinary course of constructing new projects, the Company routinely enters into contracts for goods and services. As at September 30, 2006, the Company committed to approximately $265,588,000 for goods and services for Melancthon I, Melancthon II and Wolfe Island, which will be expended between 2006 and 2008. Melancthon I was completed in March 2006, and Melancthon II and Wolfe Island are expected to be completed in 2008.

10. SUBSEQUENT EVENTS

On October 12, 2006, the Company entered into an arrangement agreement with Vector Wind Energy Inc. ("Vector") pursuant to which the Company will acquire all of the issued and outstanding common shares of Vector at a cash price of $0.30 per Vector share for a total estimated cost (including acquisition costs) of $6,300,000 million. The acquisition will be completed pursuant to a statutory plan of arrangement and will require the approval of 66 2/3% of the votes cast be Vector shareholders. Additionally, the Company and Vector have entered into a conveyancing agreement pursuant to which the Company has acquired three of Vector's wind prospects in Ontario for consideration of $750,000. Vector is a developer of wind energy projects in Canada and currently has 20 active prospect areas with the potential to support over 1,000 MW of wind energy capacity.

Common shares outstanding: 119,478,773

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