Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

November 14, 2008 08:15 ET

Canadian Hydro Announces Results for the Third Quarter Ended September 30, 2008

CALGARY, ALBERTA--(Marketwire - Nov. 14, 2008) - Canadian Hydro Developers, Inc. (TSX:KHD) -

HIGHLIGHTS

- Increased generation, revenue, and cash flow both quarterly and year-to-date due to new plant additions and higher average electricity prices received;

- Commissioned 52 of the 88 turbines of phase II at Melancthon and expect to be commercially operational on-time and on-budget;

- Installed the 7.5 kilometre submarine transmission line and erected the first 3 turbines at Wolfe Island; and

- Completed the regulatory hearing for the approval of construction and operation of the Dunvegan Hydroelectric Prospect with a decision expected by early 2009.



----------------------------------------------------------------------------
Q3 9 Months
Change Change
2008 2007 % 2008 2007 %
----------------------------------------------------------------------------
Financial Results
(in thousands of
dollars except
where noted)

Revenue 17,398 14,344 + 21 56,520 46,359 + 22
EBITDA 11,336 7,765 + 46 35,314 28,518 + 24
Cash flow 5,454 4,161 + 31 19,410 17,068 + 14
Per share (diluted) 0.04 0.03 + 33 0.13 0.13 -
Net earnings (before
non-cash foreign
exchange loss) 712 162 + 340 660 2,838 - 77
Per share (diluted) 0.01 - + 100 0.01 0.02 - 50
Net earnings (4,986) 162 - 3,177 (294) 2,838 - 110
Per share (diluted) (0.03) - - 100 - 0.02 - 100

Operating Results
Installed capacity
- MW (net) 364 265 + 37 364 265 + 37
Electricity generation
- MWh (net) 246,133 212,031 + 16 763,977 683,758 + 12
kWh per share
(diluted) 1.69 1.56 + 8 5.24 5.17 + 1
Average price received
per MWh ($) 71 68 + 4 74 68 + 9
Electrical generation
under contract (%) 81 77 + 5 78 84 - 7
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For the nine months ended September 30, 2008, revenue, EBITDA and cash flow from operations improved over the same period in the prior year due to:

- The addition of the Le Nordais and Soderglen EcoPower® Centres; and

- Increased Alberta power pool prices;

Offset partially by:

- Increased interest expense from our debt financing for the Le Nordais acquisition, for which we have not yet received the full benefit; and

- Slightly lower gross margins (68% versus 70%) as a result of:

- Additional turnaround maintenance performed at our Grande Prairie EcoPower® Centre (GPEC);

- Continued planned work on the Le Nordais EcoPower® Centre; and

- The Melancthon EcoPower® Centre being down for 28 days in June due to substation expansion for phase II.

Gross margins improved from Q2 2007 (69% vs. 62%) due to operational improvements at GPEC. Le Nordais' operations are expected to improve in Q4 and over the course of 2009, as we bring all of the turbines up to our operational standards.

"The third quarter was an exciting one for Canadian Hydro as we continued to successfully execute on our strategic plan," said John Keating, CEO of Canadian Hydro. "The imminent completion of Melancthon II is the start of the transformation of our Company. With the completion of Wolfe Island in the coming months, we will double the size of Canadian Hydro. This will provide us with the freedom to self-finance the equity portion of increasingly significant projects beyond our current construction program. In addition, we have no need to access the debt markets in any significant way until September 2010, and our lenders are financially strong. As always, we will not sacrifice returns in order to grow and have reacted prudently to the current economic conditions when bidding for new projects. We are extremely well positioned and anticipate benefiting from these uncertain times."

Canadian Hydro is focused on Building a Sustainable Future®. We are a developer, owner and operator of 20 EcoPower® Centres totalling net 364 MW of capacity in operation and have an additional 517 MW in or nearing construction and 1,632 MW of prospects under development. Our renewable generation portfolio is diversified across three technologies (water, wind and biomass) in the provinces of British Columbia, Alberta, Ontario, and Quebec. This portfolio is unique in Canada as all facilities are certified, or slated for certification, under Environment Canada's EcoLogoM Program.

The Toronto Stock Exchange has neither reviewed nor approved this press release.

MANAGEMENT'S DISCUSSION AND ANALYSIS (MD&A)

Advisories

The following MD&A, dated November 6, should be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2007 and 2006 (the Financials). All tabular amounts in the following MD&A are in thousands of dollars, unless otherwise noted, except share and per share amounts. Additional information respecting our Company, including our Annual Information Form, is available on SEDAR at www.sedar.com. Additional advisories with respect to forward looking statements and the use of non-GAAP measures are set out at the end of this MD&A under 'Additional Disclosures'.

EXECUTIVE SUMMARY

We have completed significant milestones in the execution of our strategic plan. We:

- Approached commercial operations of phase II at our Melancthon II Wind Project (Melancthon II), which will increase our net installed capacity by 37% to 496 MW;

- Installed the 7.5 kilometre submarine transmission line and erected the first 3 turbines at the Wolfe Island Wind Project (Wolfe Island); and

- Completed the regulatory hearing for the approval of construction and operation of the Dunvegan Hydroelectric Prospect (Dunvegan) with a decision expected by early 2009.

From an operational perspective, our year-to-date financial results were positively influenced by the following factors:

- The addition of the Le Nordais EcoPower® Centre (Le Nordais) acquired in December 2007 and the Soderglen EcoPower® Centre (Soderglen) acquired in March 2007; and

- Higher average electricity prices received as a result of higher power pool prices in Alberta and the addition of Le Nordais, which has a higher contract price than the average of our other plants;

Offset partially by:

- Increased interest expense from our debt financing for the Le Nordais acquisition, for which we have not yet received the full benefit to cash flow; and

- Slightly lower gross margins (68% vs. 70%) as a result of:

-- Additional turnaround maintenance performed at our Grande Prairie EcoPower® Centre (GPEC);

-- Continued planned work on Le Nordais; and

-- The Melancthon EcoPower® Centre (Melancthon I) being down for 28 days in June due to substation expansion for phase II.

Gross margins improved from the prior quarter (69% vs. 62%) due to operational improvements at GPEC. Le Nordais' operations are expected to improve in Q4 and over the course of 2009, as we bring all of the turbines up to our operational standards.



RESULTS OF OPERATIONS

Revenue and Generation

Quarterly Electricity Generation - by Province and Technology(1)
----------------------------------------------------------------------------
Q3 9 months
2008 2007 2008 2007
MWh MWh Change MWh MWh Change
----------------------------------------------------------------------------
British Columbia 77,844 68,105 + 14 189,780 191,937 - 1
Alberta 104,051 101,682 + 2 329,972 300,273 + 10
Ontario 51,805 42,244 + 23 190,794 191,548 - 1
Quebec 12,433 - + 100 53,431 - + 100
----------------------------------------------------------------------------
Totals 246,133 212,031 + 16 763,977 683,758 + 12
----------------------------------------------------------------------------
Hydroelectric 128,488 104,474 + 23 303,296 300,933 + 1
Wind 83,618 73,957 + 13 365,129 286,513 + 27
Biomass 34,027 33,600 + 1 95,552 96,312 - 1
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Totals 246,133 212,031 + 16 763,977 683,758 + 12
----------------------------------------------------------------------------
kWh per share(2) 1.69 1.56 + 8 5.24 5.17 + 1
----------------------------------------------------------------------------

(1) Reflecting our net interest.
(2) kWh per share based on diluted weighted average shares outstanding.


Revenue in Q3 2008 increased 21% over the prior year as a result of the following factors:

- Increased average prices received, as discussed below;

- The addition of Le Nordais;

- Improved hydroelectric generation in Ontario as a result of a wetter summer resulting in higher water flows than Q3 2007; and

- Improved hydroelectric generation in British Columbia and Alberta as a result of a colder spring with the benefit of increased water flows in July and August;

Offset partially by:

- Lower quarter over quarter generation at Melancthon I due to less wind than Q3 2007.

For the nine months ended September 30, 2008, revenue increased by 22% from 2007 as a result of:

- Increased average prices received, as discussed below;

- Increased generation primarily due to the addition of Le Nordais and a full nine months of generation from Soderglen; and

- Incrementally higher hydroelectric generation in Ontario and British Columbia;

Offset slightly by:

- Lower production at Melancthon as a result of 28 days of downtime in June for a substation expansion required to bring phase II online and less windy conditions in Q3 2008 compared to Q3 2007;

- Lower generation at the Alberta hydroelectric plants as a result of the irrigation canal system being opened later than normal; and

- Lower generation at GPEC as a result of additional downtime incurred in 2008 to complete the annual turnaround maintenance.

We have received an average price of $71/MWh for Q3 2008 and $74/MWh year-to-date, compared to $68/MWh for 2007. This was the result of:

- Higher pool prices received by our merchant Alberta plants in both Q3 2008 (Q3 2008 - $70/MWh, Q3 2007 - $43/MWh) and year to date (2008 - $72/MWh, 2007 - $57/MWh); and

- The addition of Le Nordais, which has a higher contract price than the average of our other plants.

Approximately 81% of our generation was sold pursuant to long-term sales contracts in Q3 2008 (Q3 2007 - 77%) and for the year to date, we have sold 78% under long-term sales contracts, compared to 84% in 2007.

Operating Expenses

Operating expenses increased 36% in Q3 2008 compared to Q3 2007, mainly due to the following factors:

- The addition of Le Nordais as well as the maintenance program required at the site in order to optimize performance and improve the availability of the turbines; and

- Increased operating expenses at GPEC as a result of the increased maintenance work performed in 2008.

On a $/MWh basis, operating expenses increased in Q3 2008 primarily as a result of the above factors.

For the nine months ended September 30, 2008, operating expenses have increased 29% over 2007 as a result of the factors discussed above, as well as a full nine months of operations at Soderglen.

Gross Margins

Gross margins, as a percentage of revenue, decreased for Q3 2008 to 69% from 73% in Q3 2007 due primarily to the lower gross margins at GPEC and lower gross margins at Le Nordais than at our other plants.

For the nine months ended September 30, 2008, gross margins as a percentage of revenue decreased for the nine month period to 68%, as compared to 70% in 2007, due primarily to Le Nordais and GPEC as discussed above. Margins improved from Q2 2008 (69% vs. 62%) due to operational improvements at GPEC.

At GPEC, we have undertaken an increased annual turnaround maintenance program in an effort to improve the operations of the facility. As a result of this, generation increased incrementally in Q3 2008 over Q3 2007 and we expect GPEC to perform consistent with 2007 for the remainder of the year. We continue to work on a detailed plan to improve operations and profitability at GPEC to what we had originally planned.

At Le Nordais, as part of our plan on acquisition of this EcoPower® Centre, we implemented a comprehensive maintenance program, focusing primarily on gearbox maintenance and replacement in order to improve the availability of turbines at the site. The objective of this maintenance program is to have at least 111 of the 133 turbines achieving 98% availability by the end of 2009, and all 133 turbines achieving this target in 2010, which is expected to improve generation above the historical long-term average generation of 165,000 MWh.



Interest on Credit Facilities and Credit Facilities

----------------------------------------------------------------------------
Q3 9 Months
(in thousands of dollars
except where noted) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Gross interest on
credit facilities 11,380 4,700 + 142% 25,924 13,964 + 86%
Capitalized interest (6,070) (950) + 539% (11,447) (2,849) + 302%
----------------------------------------------------------------------------
Net interest expense
on credit facilities 5,310 3,750 + 42% 14,477 11,115 + 30%
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Net interest expense
on credit facilities
per MWh ($/MWh) 21.57 17.68 + 22% 18.95 16.26 + 17%
----------------------------------------------------------------------------
Weighted average
interest rate on
credit facilities (%) 6.65 5.92 + 12% 5.52 5.83 - 5%
----------------------------------------------------------------------------


The increase in net interest expense on credit facilities in 2008 was due to higher outstanding corporate debt. On a $/MWh basis, net interest expense increased in 2008 as we have not yet had the full generation benefit of the Le Nordais acquisition. We have undertaken the following financing activities this year:

- Issued $75,900,000 of 10-year, non-amortizing debentures on June 11, at an average interest rate of 7.073% per annum;

- Added to our existing credit facilities in June with a $292,500,000 construction facility for Wolfe Island, which has a 15-month drawdown period followed by a two-year non-amortizing term out period, bearing interest at Bankers' Acceptances rates plus a stamping fee of 1.375% per annum;

- Increased our Operating Facility by $20,000,000 to $85,000,000, which bears interest at Bankers' Acceptances rates plus a stamping fee of 1.375% per annum; and

- Fixed the interest rates on approximately 50% of our construction facilities at 3.0275% per annum plus the applicable stamping fees until March 31, 2010.

We have a capital intensive business with a multi-year growth horizon. Interest costs incurred as a result of our capital program are capitalized to the project during the construction phase and are part of the estimated capital costs for the project. Capitalized interest associated with construction-in-progress and development prospects increased due to higher outstanding balances on our credit facilities associated with the projects in or nearing construction.

Credit facilities (including current portion) drawn as at September 30, 2008 were $718,377,000 compared to $414,756,000 as at December 31, 2007. The increase was a result of:

- The issuance of our debentures; and

- Increased draws on our construction facilities and Operating Facility, less the usual repayments on certain credit facilities.

Amortization Expense

Amortization expense increased 63% in Q3 2008 from Q3 2007, and for the nine months ended September 30, 2008, increased 48% from 2007, due to the addition of Soderglen and Le Nordais. On a $/MWh basis, amortization expense increased for both the 3 and 9 month periods as we have not yet had the full generation benefit of the Le Nordais acquisition.

Our wind EcoPower® Centres are amortized on a straight-line basis over a 30 year period, except Le Nordais and Taylor, which are amortized over 26 years and 15 years, respectively, and our biomass and hydroelectric EcoPower® Centres are amortized on a straight-line basis over a 40 year period.



Administration Expense

----------------------------------------------------------------------------
Q3 9 Months
(in thousands of dollars
except where noted) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Gross administration
expenses 2,522 2,477 + 2% 7,898 6,955 + 14%
Capitalized
administration
expenses (1,944) (1,408) + 38% (4,272) (3,612) + 18%
----------------------------------------------------------------------------
Net administration
expenses 578 1,069 - 46% 3,626 3,343 + 8%
----------------------------------------------------------------------------
Net administration
expense per MWh ($/MWh) 2.35 5.04 - 53% 4.75 4.89 - 3%
----------------------------------------------------------------------------


Gross administration expense increased 2% in Q3 2008 from Q3 2007 and 14% year-over-year, due to:

- Moderately higher salary costs with the addition of new employees in 2008; and

- Increased costs associated with the recruitment and hiring of these new employees.

On a $/MWh basis, net administration expense decreased for both the 3 and 9 month periods due to increased generation for both periods, as explained above. Additionally, capitalized administration costs associated with construction-in-progress and prospect development costs increased in association with our increased construction and development activity.

Stock Compensation Expense

Stock compensation expense increased 10% in Q3 2008 from Q3 2007 and 20% year-over-year due to additional options issued, offset by lower fair value per option as a result of lower volatility in our share price, which impacts the fair value per option.

Income and Capital Taxes

We do not anticipate paying cash income taxes for several years, other than in respect of the Cowley Ridge EcoPower® Centre, through our wholly owned subsidiary, Cowley Ridge Wind Power Inc. This subsidiary is fully taxable, but is entitled to recover approximately 175% of cash taxes paid annually (limited to 15% of eligible gross revenue).

We are also liable for Provincial Capital Taxes in Ontario and Quebec, which comprise the majority of the current tax provision. Ontario Capital Tax will be eliminated effective July 1, 2010, while Quebec Capital Tax will be eliminated effective January 1, 2011.

The decrease in future income taxes in 2008 is due to lower earnings before taxes, as well as lower future tax rates as compared to the prior year. Our effective tax rate has decreased in 2008 to 21% from 26% in 2007 as a result of lower enacted federal tax rates throughout our tax horizon.

EBITDA, Cash Flow, and Net Earnings

EBITDA

In Q3 2008, EBITDA increased 46% compared to Q3 2007 and 24% year-over-year, due to:

- Increased generation;

- Higher pool prices received in Alberta; and

- Higher absolute gross margins from the addition of Soderglen and Le Nordais;

Offset partially by lower gross margins at GPEC, as discussed above.

On a $/MWh basis, EBITDA increased as a result of the factors discussed above.

Cash Flow

Cash flow in Q3 2008 increased 31% over Q3 2007 as a result of increased gross margins (on an absolute basis) due to the addition of Soderglen and Le Nordais and higher average prices received. On a $/MWh basis, cash flow increased in Q3 2008 compared to the prior year as a result of the same factors, offset partially by higher generation as previously discussed. On a per share basis, cash flow increased 33% in Q3 2008 from Q3 2007 due to the above, offset partially by the dilution of the additional shares issued through our equity financing completed in December 2007 and the exercise of the over-allotment option in January 2008, for which we have not yet had the full benefit to cash flow.

For the nine months ended September 30, 2008, cash flow increased 14% on an absolute basis, and on a $/MWh basis, due to the same factors as discussed above with respect to EBITDA. For the nine months ended September 30, 2008, cash flow per share was consistent with 2007 due to more shares outstanding in 2008 compared to 2007 as discussed above offsetting the absolute increase. Additionally, the proceeds from our equity issuances in 2005 have been used primarily to finance the equity portion of capital costs related to the construction of Melancthon II and Wolfe Island. As a result, the benefits of these equity issues have not yet been reflected in our net earnings or cash flow.

Net Earnings

Net earnings, on an absolute basis, decreased 3,177% in Q3 2008 compared to Q3 2007, and for the nine months ended September 30, 2008, net earnings decreased 110% from 2007, mainly as a result of a non-cash foreign exchange loss from the Euro denominated cash balances ear-marked for turbine payments, offset partially by the factors discussed above with respect to EBITDA and cash flow from operations. Accordingly, on a $/MWh basis, net earnings decreased over the prior year. Adjusting net earnings for the non-cash foreign exchange loss experienced in the quarter, net earnings of $712,000 increased by 340% over net earnings of $162,000 in Q3 2007.

The proceeds from our equity issuances in 2005 are being used to finance the construction of Melancthon II, Wolfe Island, and the B.C. Hydroelectric Projects, and as a result, the benefit of the financings has not yet been reflected in our net earnings or cash flow.



Property, Plant, and Equipment Additions and Prospect Development Costs


----------------------------------------------------------------------------
Q3 9 Months
(in thousands of
dollars) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Property, plant,
and equipment
additions 154,325 4,472 +3,351% 295,188 16,245 +1,717%
Prospect development
cost additions 11,017 3,363 +2,276% 18,767 10,502 + 79%
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Property, plant, and equipment additions relate mainly to:

- Capital expenditures for the $450,000,000 Wolfe Island Wind Project including wind turbine payments and construction costs;

- Costs for the completion of the $285,000,000 Melancthon II Wind Project, which is nearing commercial operations at quarter end; and

- The $76,000,000 B.C. Hydroelectric Projects, which are currently under construction.

Additions of prospect development costs relate primarily to expenditures for Dunvegan.

From time to time, initial site investigations and project economics do not justify us pursuing certain prospects, and as such, these costs are written-off. During the nine months ended September 30, 2008, prospect development costs of $187,000 were written-off (2007 - $nil).

LIQUIDITY AND CAPITAL RESOURCES

The nature of our business requires long lead times from prospect identification through to commissioning of electrical generation facilities. Our investment commitment proceeds in a step-wise fashion through the identification and preparation of our prospects, to securing the associated power purchase contracts, to satisfying the lengthy regulatory requirements, and finally to constructing the facilities.

Given these long lead times from expenditure through to cash flow generation, it is imperative to have a solid and well funded capital structure. We operate with a minimum equity base of 35% on invested capital and fund the majority of our debt on a basis consistent with the long term asset base - mid-term financing is obtained through the construction phases and then converted into a long-term unsecured debenture basis after commissioning, consistent with the power purchase agreements we enter into.

In early 2007, we embarked upon a significant expansion plan to more than double our generating capacity by the end of 2010. The table below summarizes the investments contemplated by this plan and our current expectations as to the funding thereof. We believe we have the necessary cash flow, working capital and access to capital markets to fulfill any obligations and commitments we make in implementing this expansion plan.

In June 2008, we issued debentures for total gross proceeds of $75,900,000, and amended our existing credit agreement, adding an additional $312,500,000 of unsecured credit facilities, for a total of $611,000,000 (see 'Interest on Credit Facilities and Credit Facilities').



----------------------------------------------------------------------------
(in thousands of dollars) As at September 30, 2008
----------------------------------------------------------------------------
Capital expenditure plans through 2012 1,274,120
Spent to date (622,720)
----------------------------------------------------------------------------
Remaining capital expenditures to be financed 651,400
Financed/to be financed by:
Melancthon II and Blue River construction facilities 105,150
Wolfe Island construction facility 143,800
Working capital surplus(1) 18,199
Anticipated construction facilities(2) 281,900
Undrawn & available revolving Operating Facility 4,288
Expected to be funded through cash flow from operations 98,063
----------------------------------------------------------------------------
Difference -
----------------------------------------------------------------------------
(1) Excluding derivative financial instrument asset
(2) See following table with project breakdown


Our current capital expenditure plans are for the following projects either in or nearing construction:

- Melancthon II (commercially operational by November 30, 2008, however, we will continue to draw on its construction facility as final costs are incurred);

- Wolfe Island;

- Island Falls;

- Royal Road;

- Blue River (including Bone, Clemina, and Serpentine Creeks);

- English Creek;

- St. Valentin; and

- New Richmond.

The following table outlines the size and timing of the anticipated credit facilities:



----------------------------------------------------------------------------
(in thousands of dollars) Anticipated construction Anticipated timing of
facility size construction facility
----------------------------------------------------------------------------
Project
Island Falls 28,400 Q3 2009
Royal Road 26,000 Q2 2010
New Richmond 123,500 Q4 2011
St. Valentin 104,000 Q4 2011
----------------------------------------------------------------------------
Total 281,900
----------------------------------------------------------------------------


Exclusive of any new projects that we may be awarded under the two bids discussed below, we will require no additional equity financing for our current projects, and will require only $28 million of debt financing in 2009, relating to the Island Falls Hydroelectric Project.

The construction facilities we have placed and anticipate placing for these projects are, generally, based on 65% of the capital costs of these projects. Our ability to debt finance these projects is predicated on our BBB (Stable) investment grade credit rating. We, generally, cannot draw on construction credit facilities until we have expended 35% of the capital costs of a project, using our equity to pay for this. If timing differences exist between when the costs are expended and the construction facilities are in place, we will employ our cash flow from operations to support our capital expenditure program.

In December 2007, we closed a public offering of common shares through a syndicate of underwriters (the Underwriters) for the issue of 8,800,000 common shares at a price of $6.25 per share for gross proceeds of $55,000,000 ($52,195,000 net of share issue costs). Included in the public offering was an over-allotment option of $5,500,000 ($5,280,000 net of share issue costs), which was fully exercised by the Underwriters in January 2008. The proceeds from the over-allotment were used for general corporate purposes.

As at September 30, 2008, we had a 59/41 debt/equity mixture (December 31, 2007 - 46/54) compared to a stated target of 65/35. We will move towards our stated target as we draw on existing credit facilities and put in place and draw on future construction facilities for the projects discussed above.

OUTLOOK

Branding

In order to strengthen our brand and better capture the renewable nature of our operating facilities, we have rebranded all existing operating facilities under our registered trademark "EcoPower® Centre". Our brand better reflects the renewable nature of our operating facilities, and offers consistency across all three of our technologies, as well as allowing for the addition of other technologies in the future.

Project Updates

Ontario

Melancthon II Wind Project

To date, we have commissioned 52 of the 88 turbines for our 132 MW Melancthon II Wind Project and we expect to be on-budget ($285 million) and on-time for our target commercial operations date of November 30, 2008. Melancthon II is the largest project in our history and is expected to generate 350,600 MWh per year. Together with phase I, it is the largest wind installation in Canada, at 199.5 MW. With the completion of Melancthon II, our total net installed capacity will be 496 MW. This project is fully financed.

Wolfe Island Wind Project

At Wolfe Island, construction is proceeding well, with the pouring of foundations, completion of access roads, and erection of first 3 of the 86 turbines. On October 16, 2008, we successfully laid 7.5 kilometres of submarine transmission line from Wolfe Island to Kingston, which will allow for Wolfe Island's power to be transmitted to the Ontario power grid. This project is fully financed, and the anticipated capital costs and in-service date remain unchanged at $450 million and March 31, 2009, respectively. Our construction plans and target in-service date are based on a normal winter. Should winter conditions be worse than normal, the in-service date could be delayed by up to 3 months.

Royal Road Wind Projects

We continue to work through the approvals process for the $40 million Royal Road Wind Projects in Ontario. The projects are targeted for completion in August 2010. Construction will commence once approvals and debt financing are in place. Wind turbines and related equipment have been ordered consisting of 12, 1.5 MW GE turbines for these 2, 9 MW projects.

Island Falls Hydroelectric Project

We have been working through the approvals process for the $71 million ($35.5 million net to our interest) Island Falls Hydroelectric Project since 2005 and have encountered challenges with respect to permitting, mainly due to fish. In order to successfully address these challenges, we have relocated the project upstream to Yellow Falls. Accordingly, the project has been renamed the Yellow Falls Hydroelectric Project. This change in location has resulted in the project size being adjusted to 16 MW (8 MW net to our interest) from 20 MW (10 MW net to our interest), and the energy estimate revised to 69,600 MWh (34,800 MWh net to our interest) from 93,400 MWh (46,700 MWh net to our interest).

Since signing a long-term power sales contract in 2005, construction costs have increased significantly, most particularly in the first eight months of 2008. We have begun to see a decrease in construction costs, due to the current worldwide economic conditions. We expect this to continue as we firm up the capital costs of this project. We will provide an update to capital costs once we commence construction, which is anticipated in 2009. We currently anticipate a one-year delay to the in-service date of October 31, 2009 to October 31, 2010. The equity portion of the capital costs of this project is in place, and we anticipate completing debt financing for the remainder of the capital costs towards the end of 2009.

British Columbia

Bone, Clemina, Serpentine and English Creek Hydroelectric Projects

Construction activities have been completed for the winter season for Bone and Clemina. Bone, Clemina, Serpentine and English are fully permitted and approved for construction. Since securing Electricity Purchase Agreements in 2006, construction costs have increased significantly, most particularly in the first eight months of 2008. We have begun to see a decrease in construction costs, due to the current worldwide economic conditions. We anticipate that costs will decrease in the coming months when we resume construction on Bone and Clemina and commence construction on Serpentine and English in the spring of 2009. Updated capital cost estimates will be provided at that time. We currently estimate a one-year delay to the target Commercial Operations Date for these projects from October 1, 2009 to October 1, 2010. These projects are fully financed.

Alberta

We continue to pursue the development of Dunvegan. In September, we participated in a joint federal-provincial panel hearing for the approval of construction and operation. We anticipate a regulatory decision from this hearing to be made by early 2009. Regulatory approvals, long-term power sales contracts and financing are required prior to construction commencing. In 2008, we commenced a preliminary seismic and geotechnical investigative work program at the site, in order to expedite preliminary engineering work.

Quebec

We continue to work on the permitting and development of our 50 MW St. Valentin and our 66 MW New Richmond Wind Projects. The capital costs remain unchanged at $160 million and $190 million, respectively, and the target in-service date of both projects remains December 2012. Turbine supply, including cost and delivery have been fixed, which represents over 70% of the capital costs. These projects are subject to regulatory approvals and financing. We anticipate financing the equity portion of these projects through internally generated cash flow and financing the debt portion in Q4 2011.

We do not sacrifice project returns in order to grow or compete. Over the last two years, most particularly in the first eight months of 2008, the industry has been faced with an unprecedented increase in construction costs. Our largest projects, which include Melancthon II, Wolfe Island, New Richmond and St. Valentin, have been insulated largely from these cost increases as the wind turbine supply and prices, which represent the majority of the projects' capital costs, were fixed prior to securing long-term power sales contracts. Given the current economic conditions, we have seen construction costs begin to decrease and expect them to continue to decrease in the coming months. We feel this provides us with an opportunity to improve the economic returns of primarily the hydroelectric projects discussed above.

Upcoming Calls for Power

B.C. and Ontario

We expect to bid up to 55 MW of B.C. hydroelectric prospects into BC Hydro's Clean Power Call, which was announced in June 2008, with submissions due November 25, 2008, and contracts anticipated to be awarded in June of 2009.

In October, we submitted a proposal for a 34 MW wind project into the Ontario Power Authority's request for up to 500 MW of renewable energy supply. Contracts are expected to be awarded in December 2008.

New Business

The solar energy market is one which we continue to monitor and assess on a regular basis. As previously disclosed, we have entered into a Standard Offer Contract (SOC) for a 10 MW solar project in Ontario, at no cost to us to enter into or walk away from the SOC. We view this as a free option as we continue to assess the economic viability of the project. We feel that this is an area where our expertise and proven track record in project identification, construction, and operation will allow us to be a market leader in this market segment, provided that the underlying economics of the projects justify our entrance into the market.

ADDITIONAL DISCLOSURES

Summary of Quarterly Results

The following table sets out selected financial information for each of the eight most recently completed quarters:



----------------------------------------------------------------------------
(in thousands of dollars, Q4 Q1 Q2 Q3
except per share amounts) 2007 2008 2008 2008
----------------------------------------------------------------------------
Total revenue 17,398 19,461 19,661 17,398
EBITDA 10,597 12,699 11,279 11,336
Cash flow 6,687 8,342 5,614 5,454
Net earnings (loss) 5,505 1,809 2,883 (4,986)
Earnings (loss) per share - basic 0.04 0.01 0.02 (0.03)
Earnings (loss) per share - diluted 0.04 0.01 0.02 (0.03)
Generation (MWh) 237,917 256,467 261,377 246,133
Average price received ($/MWh) 73 76 75 71
----------------------------------------------------------------------------

----------------------------------------------------------------------------
(in thousands of dollars, Q4 Q1 Q2 Q3
except per share amounts) 2006 2007 2007 2007
----------------------------------------------------------------------------
Total revenue 13,060 14,738 17,277 14,344
EBITDA 9,152 8,537 12,216 7,765
Cash flow 8,867 5,145 7,762 4,161
Net earnings (loss) 3,328 905 1,771 162
Earnings (loss) per share - basic 0.03 0.01 0.01 -
Earnings (loss) per share - diluted 0.03 0.01 0.01 -
Generation (MWh) 181,096 200,298 271,429 212,031
Average price received ($/MWh) 72 74 64 68
----------------------------------------------------------------------------


The changes over the past eight quarters are due primarily to the addition of Soderglen and Le Nordais, as well as the large non-cash foreign exchange loss in Q3 2008 and increased operating expenses, as previously discussed.

Financial Position

The following chart outlines significant changes in our consolidated balance sheet from December 31, 2007 to September 30, 2008:



----------------------------------------------------------------------------
Increase
(Decrease)
$ Explanation
----------------------------------------------------------------------------
Cash 15,585 Increased as a result of the
increase in credit facilities,
offset by property, plant, and
equipment expenditures.

Property, plant,
and equipment 388,682 Increased as a result of the
reclassification of Wolfe Island,
Melancthon II, Bone Creek, and
Clemina Creek from prospect
development costs, as well as
continued expenditures on these
projects.

Prospect development costs (71,900) Decreased as a result of the
reclassification of Wolfe Island,
Melancthon II, Bone Creek, and
Clemina Creek from prospect
development costs to property,
plant, and equipment, offset by
increased expenditures relating
to Dunvegan.

Accounts payable 26,682 Increased as a result of the
construction activity at Wolfe
Island and Melancthon II.

Acquisition facility (72,300) Repaid with the issuance of the
Series 4 and Series 5 debentures.

Credit facilities 376,528 Increased as a result of the
drawdowns made on the Wolfe Island
and Melancthon II construction
facilities, as well as the issuance
of the Series 4 and Series 5
debentures.

Share capital 7,035 Increased as a result of the over-
allotment option exercised in
January 2008.
----------------------------------------------------------------------------


Disclosure Controls and Internal Controls and Procedures

As of the end of the period covered by this quarterly report, there have been no changes to our disclosure controls and internal controls over financial reporting since December 31, 2007.

Accounting Changes and Future Accounting Changes

Effective January 1, 2008, we adopted Canadian Institute of Chartered Accountants (CICA) handbook sections 3862 - "Financial Instruments Disclosures", section 3863 - "Financial Instruments Presentations", and section 1535 - "Capital Disclosures", which are required to be adopted for fiscal years beginning on or after October 1, 2007. The impact of these changes is exclusively disclosure related, as described in Notes 2, 8 and 9 of the unaudited interim financial statements as at and for the periods ended September 30, 2008.

Effective January 1, 2011, International Financial Reporting Standards (IFRS) will replace current Canadian standards and interpretations as Canadian generally accepted accounting principles for publicly accountable enterprises. Accordingly, we will be adopting the new standards effective at this date. IFRSs are based on a conceptual framework that is substantially the same as that on which Canadian standards are based and cover many of the same topics and reach similar conclusions on many issues. However, within the various standards there are differences which may impact our accounting practices and balances. Currently, we are working to assess the accounting policy choices available under IFRS (including application on a prospective or retroactive basis for certain policies), the impact of the conversion to IFRS on the internal controls and financial reporting procedures, and have commenced training for financial reporting and accounting staff.

OFF-BALANCE SHEET ARRANGEMENTS

At September 30, 2008, we have no off-balance sheet arrangements.

TRANSACTIONS WITH RELATED PARTIES

We pay gross overriding royalties ranging from 1% - 2% on electric energy sales on four of our original hydroelectric plants to a company controlled by J. Ross Keating, President, Operations & Development, and a director. During the three and nine months ended September 30, 2008, royalties totaling $24,000 (2007 - $19,000) and $138,000 (2007 - $47,000), respectively, were incurred.

FINANCIAL INSTRUMENTS

We have a risk management policy that is approved annually by our Board of Directors. Our general philosophy is to avoid unnecessary risk and to limit, to the extent practicable, any significant risks associated with business activities. We may use from time to time derivative financial instruments to manage or hedge commodity price, interest rate, and foreign currency risks. Use of derivatives on a speculative or non-hedged basis is specifically disallowed. Authorization levels for the execution of derivatives for hedging purposes have been set by our Board of Directors and are reviewed quarterly by our Audit Committee. For the period ended September 30, 2008, we had the following financial instruments in place to manage risk:

Contracts for Differences

We have entered into various Contracts for Differences (CFDs) with other parties whereby the other parties have agreed to pay us a fixed price with a weighted average of $53 per MWh based on the average monthly Pool price for an aggregate of 133,950 MWh per year of electricity from January 1, 2008, maturing from 2008 to 2024. While the CFDs do not create any obligation for us to physically deliver electricity to other parties, we believe we have sufficient electrical generation, which is not subject to contract, to satisfy the CFDs. We are unable to fair value two of the CFDs for an aggregate of 4,150 MWh per year of electricity because the CFD price includes the sale of RECs along with the settlement of the average monthly Pool price. Our assumptions for fair valuing our CFDs, given the ongoing illiquidity of the forward market, assume the actual contract prices contained in the CFDs are the same as the forward prices for years where no forward market exists. At January 1, 2007, the fair value of these contracts of $206,000 was recorded on the consolidated balance sheet as a derivative financial liability, with the loss recorded as Other Comprehensive Income (OCI). At September 30, 2008, the fair value of the CFDs was a liability of $988,000.

Foreign Exchange Contracts

We have entered into various foreign exchange contracts, expiring in 2008, which fix our Euro payments under wind turbine purchase contracts in Canadian dollars. The aggregate remaining amount of Euro purchases is EUR 7,403,310, which is fixed at a blended average rate of 1.4677 for an aggregate Canadian dollar amount of $10,865,838. Additionally, on June 11, 2008, concurrent with the issuance of the Series 5 debentures, we entered into a cross-currency swap to fix both the principal and interest payments on the Series 5 debentures. The principal amount of $20,000,000 US dollars were fixed at $20,400,000 Canadian dollars and the semi-annual interest payments of $730,800 US dollars were fixed at $734,400 Canadian dollars. At September 30, 2008, the aggregate fair value of all outstanding foreign exchange contracts was an asset of $1,428,000.

Interest Rate Swap Contracts

We have entered into an interest rate swap contract on our Melancthon II and Wolfe Island Construction Facilities, which fix our interest payments at 3.0275% per annum plus a stamping fee. At September 30, 2008, the fair value of all outstanding interest rate swap contracts was an asset of $535,000.



OUTSTANDING SHARE DATA

----------------------------------------------------------------------------
As at November 6, 2008
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 143,611,223
Convertible securities:
Warrants 4,110,900
Options 6,422,500
----------------------------------------------------------------------------
Fully diluted common shares 154,144,623
----------------------------------------------------------------------------
----------------------------------------------------------------------------


ADVISORIES

Forward-Looking Statements

Certain statements contained in this MD&A, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect, "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" 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, including, but not limited to, changes in construction schedules, weather, water flows, and reservoir levels on irrigation works, wind resources and Pool prices. We believe 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 the MD&A. We do not intend, and do not assume any obligation, to update these forward-looking statements.

Non-GAAP Financial Measures

Included in this MD&A are references to terms that do not have any meanings prescribed in GAAP and may not be comparable to similar measures presented by other companies, including EBITDA, gross margins, cash flow, cash flow per share (diluted), MWh, $/MWh, kWh, kWh per share, and other per share amounts. All references to cash flow relate to cash flow from operations before changes in non-cash working capital. EBITDA is provided to assist management and investors in determining our ability to generate cash flow from operations. EBITDA is defined as cash flow from operations before changes in non-cash working capital, plus interest on debt (net of interest income) and current tax expense.



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

September 30, December 31,
2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------

ASSETS
Current assets
Cash 38,370 22,785
Accounts receivable 18,227 11,897
Derivative financial instrument asset (Note 8) 1,963 -
Prepaid expenses 1,575 568
----------------------------------------------------------------------------
60,135 35,250

Property, plant, and equipment (Note 3) 1,186,069 797,387
Prospect development costs (Note 4) 45,377 117,277
----------------------------------------------------------------------------

TOTAL ASSETS 1,291,581 949,914
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities 38,766 12,084
Current portion of credit facilities (Note 6) 2,218 2,825
Derivative financial instrument liability (Note 8) 988 1,703
Taxes payable 535 304
Acquisition facility (Note 6) - 72,300
----------------------------------------------------------------------------
42,507 89,216

Credit facilities (Note 6) 716,159 339,631
Future income taxes 39,982 39,091
----------------------------------------------------------------------------
798,648 467,938
----------------------------------------------------------------------------
Commitments and contingencies (Note 12)

SHAREHOLDERS' EQUITY
Share capital (Note 7) 455,066 448,031
Contributed surplus (Note 7) 5,836 4,299
Retained earnings 31,055 31,349
----------------------------------------------------------------------------
491,957 483,679
Accumulated other comprehensive income
(loss) (Note 5) 976 (1,703)
----------------------------------------------------------------------------
492,933 481,976
----------------------------------------------------------------------------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 1,291,581 949,914
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying Notes to the Consolidated Financial Statements


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

3 months ended September 30 9 months ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenue
Electric energy sales 17,308 14,255 56,121 45,988
Revenue rebate 90 89 399 371
----------------------------------------------------------------------------
17,398 14,344 56,520 46,359
----------------------------------------------------------------------------
Expenses (income)
Operating 5,317 3,919 17,950 13,884
Amortization 5,501 3,373 15,630 10,554
Interest on credit
facilities 5,310 3,750 14,477 11,115
Administration 578 1,069 3,626 3,343
Stock based compensation 667 605 1,973 1,644
Write-off of prospect
development costs (Note 4) - - 187 -
Interest income (132) (588) (512) (1,224)
Foreign exchange loss 5,865 1,591 584 877
Gain on derivative
financial instrument - (14) - (363)
----------------------------------------------------------------------------
23,106 13,705 53,915 39,830
----------------------------------------------------------------------------

Earnings (loss) before
taxes (5,708) 639 2,605 6,529
----------------------------------------------------------------------------

Tax expense (recovery)
Current and capital 704 442 1,939 1,559
Future (1,426) 35 960 2,132
----------------------------------------------------------------------------
(722) 477 2,899 3,691
----------------------------------------------------------------------------

Net (loss) earnings (4,986) 162 (294) 2,838

Retained earnings,
beginning of period 36,041 25,682 31,349 22,888
----------------------------------------------------------------------------

Transitional adjustment - - - 118

Adjusted retained earnings,
beginning of period 36,041 25,682 31,349 23,006
----------------------------------------------------------------------------

Retained earnings,
end of period 31,055 25,844 31,055 25,844
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Earnings (loss) per share
(Note 10)
Basic (0.03) - - 0.02
Diluted (0.03) - - 0.02


CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Unaudited)
(in thousands of dollars except per share amounts)

3 months ended September 30 9 months ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net (loss) earnings (4,986) 162 (294) 2,838
Other comprehensive
gain (loss):
Unrealized gain
(loss) on derivative
financial instrument
currency hedges 800 (3,003) 1,908 (13,324)

Unrealized gain (loss)
on derivative financial
instrument contracts
for differences 472 621 236 (623)

Unrealized gain on
derivative financial
instrument interest
rate hedges 535 - 535 -

Reclassification of
deferred credit - (14) - (100)
----------------------------------------------------------------------------
Other comprehensive gain
(loss) 1,807 (2,396) 2,679 (14,047)

Comprehensive (loss)
income (3,179) (2,234) 2,385 (11,209)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying Notes to the Consolidated Financial Statements


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

3 months ended September 30 9 months ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------

OPERATING ACTIVITIES
Net (loss) earnings (4,986) 162 (294) 2,838
Adjustments for:
Amortization 5,501 3,373 15,630 10,554
Future income tax
(recovery) expense (1,426) 35 960 2,132
Stock based compensation 667 605 1,973 1,644
Unrealized foreign
exchange losses 5,698 - 954 -
Write-off of prospect
development costs - - 187 -
Gain on derivative
financial instrument - (14) - (100)
----------------------------------------------------------------------------

Cash flow from operations
before changes in non-cash
working capital 5,454 4,161 19,410 17,068
Changes in non-cash
working capital (33,243) (5,640) 934 1,077
----------------------------------------------------------------------------
(27,789) (1,479) 20,344 18,145
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Credit facility
repayments (Note 6) (545) (555) (2,680) (1,532)
Credit facility
advances (Note 6) 164,200 10,000 378,600 10,000
Acquisition facility
repayment (Note 6) - - (72,300) -
Issue of common shares,
net of issue costs (Note 7) 233 17 6,530 669
----------------------------------------------------------------------------
163,888 9,462 310,150 9,137
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Property, plant, and
equipment additions (154,325) (4,472) (295,188) (16,245)
Prospect development
costs (11,017) (3,363) (18,767) (10,502)
Working capital deficit
assumed on acquisition - - - (13,423)
----------------------------------------------------------------------------
(165,342) (7,835) (313,955) (40,170)
----------------------------------------------------------------------------
FOREIGN EXCHANGE ON CASH
HELD IN FOREIGN CURRENCY (5,698) - (954) -
----------------------------------------------------------------------------
NET (DECREASE) INCREASE
IN CASH (34,941) 148 15,585 (12,888)
CASH, BEGINNING OF PERIOD 73,311 48,633 22,785 61,669
----------------------------------------------------------------------------

CASH, END OF PERIOD 38,370 48,781 38,370 48,781
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental information
Cash interest paid 8,234 5,665 20,970 14,408
Cash income and capital
taxes paid 1,413 515 1,525 1,569

See accompanying Notes to the Consolidated Financial Statements


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2008 (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 ("GAAP") 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.

Interim results fluctuate due to plant maintenance, seasonal demands for electricity, supply of water and wind, and the timing and recognition of regulatory decisions and policies. Consequently, interim results are not necessarily indicative of annual results. The Company generally expects interim results for the second and fourth quarters to be higher than those for the first and third.

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, except as noted below.

2. CHANGE IN ACCOUNTING POLICIES

Effective January 1, 2008, the Company adopted Canadian Institute of Chartered Accountants ("CICA") handbook section 3862 - "Financial Instruments Disclosures", section 3863 - "Financial Instruments Presentations", and section 1535 - "Capital Disclosures", which are required to be adopted for fiscal years beginning on or after October 1, 2007. The changes as a result of the adoption of these sections are as follows:

(i) Section 1535 - Under this section, the Company is required to disclose information that enables users of the financial statements to evaluate the Company's objectives, policies, and process for managing capital. These disclosures have been included in Note 9.

(ii) Sections 3862 and 3863 - Under these sections, the Company is required to disclose information that enables users of the financial statements to evaluate the significance of financial instruments for its financial position and performance, as well as the nature and extent of the risks arising from financial instruments to which the Company is exposed at the balance sheet date. These disclosures have been included in Note 8.



3. PROPERTY, PLANT, AND EQUIPMENT

The major categories of property, plant, and equipment at cost and related
accumulated amortization are as follows:

September 30, 2008 December 31, 2007
----------------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
----------------------------------------------------

Generating plants
- operating 644,485 (68,878) 575,607 585,359
- construction-in-
progress 607,275 - 607,275 208,886
Equipment, other 4,867 (2,106) 2,761 2,670
Vehicles 1,681 (1,255) 426 472
----------------------------------------------------

1,258,308 (72,239) 1,186,069 797,387
----------------------------------------------------
----------------------------------------------------


The following amounts have been capitalized to property, plant, and
equipment for the 3 and 9 months ended September 30, 2008 and 2007:

3 months ended 9 months ended
September 30 September 30
2008 2007 2008 2007
-------------------------------------

Interest costs 6,070 374 10,494 1,492
Administrative expenses 1,336 399 3,090 1,230
-------------------------------------
Total 7,406 773 13,584 2,722
-------------------------------------
-------------------------------------


As at September 30, 2008, construction-in-progress (CIP) relates to costs associated with the construction of the Melancthon II and Wolfe Island Wind Projects, and Bone and Clemina Creek Hydroelectric Projects (2007 - Melancthon II). During the 9 months ended September 30, 2008, $220,688,000 was moved from Prospect Development Costs to CIP for Wolfe Island, Bone and Clemina Creek.



4. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

September 30 December 31
2008 2007
$ $
-----------------------------

Hydroelectric and other prospects 13,125 14,184
Wind prospects 19,117 94,344
Dunvegan Hydroelectric Prospect 13,135 8,749
-----------------------------

Total 45,377 117,277
-----------------------------
-----------------------------


The following amounts have been capitalized to prospect development costs
for the 3 and 9 months ended September 30, 2008 and 2007:

3 months ended 9 months ended
September 30 September 30
2008 2007 2008 2007
-------------------------------------

Interest costs - 576 953 1,357
Administrative expenses 608 1,009 1,182 2,382
-------------------------------------
Total 608 1,585 2,135 3,739
-------------------------------------
-------------------------------------


The wind prospect development costs relate to over 1,127 MW of optioned land for wind prospects located primarily throughout Manitoba and Ontario. Included in hydroelectric prospects is $3,220,000 (December 31, 2007 - $2,672,000) in costs related to the development of the Island Falls Hydroelectric Project and $8,781,000 (December 31, 2007 - $9,267,000) in costs related to the development of run-of-river hydroelectric projects in B.C. During the 9 months ended September 30, 2008, all development costs relating to Wolfe Island, Bone and Clemina Creek were transferred to CIP in Property, Plant, and Equipment.

The Company continues to pursue the development of the Dunvegan Hydroelectric Prospect. The Company anticipates a regulatory decision for approval of construction and operation in late 2008 or early 2009. Regulatory approvals, long-term power sales contracts and financing are required prior to proceeding. Should the Company not be successful in obtaining regulatory approvals, the prospect would likely be abandoned and the related prospect development costs would be written off.

For the 9 months ended September 30, 2008, the Company wrote off $187,000 (2007 - $nil) in costs relating to development prospects that were abandoned during the period.



5. ACCUMULATED OTHER COMPREHENSIVE INCOME (AOCI)

AOCI is comprised of the following:

$
---------
Balance, December 31, 2007 (1,703)
Unrealized gain on derivative financial instrument foreign currency
hedges 523
Unrealized gain on derivative financial instrument cross-currency
swap 1,385
Unrealized gain on derivative financial instrument interest rate
hedges 535
Unrealized gain on derivative financial instrument contracts for
differences 236
---------
Accumulated other comprehensive income, September 30, 2008 976
---------
---------


During the 3 and 9 months ended September 30, 2008 there were no amounts reclassified to revenue or expenses, and no gains or losses previously recognized in AOCI were transferred to the statement of earnings.

6. CREDIT FACILITIES

On June 10, 2008, the Company closed a private placement issuance of $75,900,000 in unsecured corporate debentures with a 10-year term, maturing on June 11, 2018, bearing interest at a combined rate of 7.073% per annum (the "Debentures"). The Debentures are comprised of Series 4 unsecured corporate debentures in the amount of $55,500,000 (the "Series 4 Debentures"), and Series 5 unsecured corporate debentures in the amount of US$20,000,000 (the "Series 5 Debentures"). The Series 4 Debentures have a 10-year term maturing on June 11, 2018, and bear an interest rate of 7.027% per annum, with interest paid semi-annually. The Series 5 Debentures have a 10-year term maturing on June 11, 2018, and bear an interest rate of 7.308% per annum, with interest paid semi-annually. As described in Note 8, on June 6, 2008, the Company entered into a cross-currency swap to fix both the principal repayment and the semi-annual interest payments on the Series 5 Debentures. The principal amount of $20,000,000 US dollars was fixed at $20,400,000 Canadian dollars. The semi-annual interest payments of 7.308% per annum were fixed into Canadian dollars at a rate of 7.200% per annum. After giving effect to the cross-currency swap, the principal amounts of the Debentures are fixed at $75,900,000 Canadian dollars with an interest rate of 7.073% per annum.

On June 12, 2008, the Company amended its existing credit agreement, adding an additional $312,500,000 of unsecured credit facilities, for a total of $611,000,000. Prior to this, the Company's $370,800,000 credit facility consisted of $233,500,000 in the aggregate of construction credit facilities for Melancthon II, and certain Blue River Hydroelectric Projects ("Blue River"), a $72,300,000 acquisition facility for the Le Nordais Wind Plant (the "Acquisition Facility"), and a revolving operating facility (the "Operating Facility") of $65,000,000. The amended credit facility includes the $233,500,000 in the aggregate of construction facilities for Melancthon II and Blue River, a $292,500,000 construction facility for Wolfe Island, and an $85,000,000 Operating Facility. On June 12, 2008, the Acquisition Facility was repaid with the proceeds from the issuance of the Company's Debentures. The terms of the Melancthon II and Blue River construction facilities remain unchanged with 18-month and 31-month drawdown periods, respectively, followed by a two-year non-amortizing term out period, bearing interest at Bankers' Acceptances rates plus a stamping fee of 0.70% per annum. The Wolfe Island construction facility has a 15-month drawdown period followed by a two-year non-amortizing term out period. Both the Wolfe Island construction facility and the Operating Facility bear interest at Bankers' Acceptances rates plus a stamping fee of 1.375% per annum.

As described above, the Company has a revolving Operating Facility with its banking syndicate for a total of $85,000,000. As at September 30, 2008, in addition to the amount shown below as drawn, the Company had outstanding letters of credit in the amount of $25,712,000 (December 31, 2007 - $22,174,000) relating primarily to construction activities and security required under long-term sales contracts for electricity.



September 30 December 31
2008 2007
$ $
--------------------------
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 5.690%,
10-year term with interest payable semi-annually and
no principal repayments until maturity on June 19,
2016, senior unsecured 27,000 27,000

Series 3 Debentures, bearing interest at 5.770%,
12-year term with interest payable semi-annually and
no principal repayments until maturity on June 19,
2018, senior unsecured 121,000 121,000

Series 4 Debentures, bearing interest at 7.027%,
10-year term with interest payable semi-annually and
no principal repayments until maturity on June 11,
2018, senior unsecured 55,500 -

Series 5 Debentures, bearing interest at 7.308%,
10-year term with interest payable semi-annually and
no principal repayments until maturity on June 11,
2018, senior unsecured, with a principal of
$20,000,000 denominated in US dollars, with the
principal and interest payments fixed in Canadian
dollars through a cross-currency swap (Note 8) 20,400 -

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

Melancthon II Construction Facility, bearing interest
at Bankers' Acceptances rates plus a stamping fee of
0.70% per annum, unsecured non-revolving credit
facility with an 18-month drawdown period ending the
earlier of 3 months post Commercial Operations Date
(COD) and March 27, 2009, followed by a two-year
non-amortizing term out period. The underlying
Bankers' Acceptances rates have been fixed, under the
interest rate swap described in Note 8 to a fixed rate
of 3.0275%. 129,000 30,000

Wolfe Island Construction Facility, bearing interest
at Bankers' Acceptances rates plus a stamping fee of
1.375% per annum, unsecured non-revolving credit
facility with an 18-month drawdown period ending the
earlier of 3 months post COD and December 12, 2009,
followed by a two-year non-amortizing term out period.
The underlying Bankers' Acceptances rates have been
fixed, under the interest rate swap described in Note
8 to a fixed rate of 3.0275%. 148,700 -

Operating Facility, 364-day revolving credit
facility, with a six month non-amortizing term out
period, extendable for one year periods annually by
mutual agreement of the Company and its Lenders,
bears interest at Bankers' Acceptances rates plus a
stamping fee of 1.375% per annum 55,000 -

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 5,788 6,379

Mortgage, bearing interest at 10.700% and secured by
a letter of guarantee. Monthly repayments of principal
and interest are $84,000 until May 31, 2010 1,555 2,140

Mortgage, bearing interest at 10.680%, secured by
letters of guarantee. Monthly repayments of principal
are $31,000 plus interest until December 30, 2012 1,594 1,875

Promissory note, bearing interest fixed at 6.000%,
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 813 930

Acquisition Facility, bearing interest at the Bankers'
Acceptances rates plus a stamping fee of 0.85% per annum,
unsecured non-revolving credit facility maturing on
June 12, 2008 - 72,300

Note payable to a Canadian private company, assumed on
the acquisition of Le Nordais, unsecured, bearing no
interest, maturing on June 16, 2008 - 678

Deferred financing costs (2,973) (2,546)
--------------------------
718,377 414,756
Less: Acquisition facility - (72,300)
Less: Current portion of credit facilities (2,218) (2,825)
--------------------------

Credit facilities 716,159 339,631
--------------------------
--------------------------


7. SHARE CAPITAL

(a) Common shares and warrants:


Number of Amount
Shares $
-----------------------------
Balance, share capital, December 31, 2007 141,834,973 448,031
Issue of common shares 880,000 5,500
Share issue costs, net of tax effect of $69 - (195)
Issued on exercise of stock options 896,250 1,294
Stock compensation on options exercised - 436
-----------------------------
Balance, share capital, September 30, 2008 143,611,223 455,066
-----------------------------
-----------------------------


On January 8, 2008, the Company closed the sale of 880,000 common shares at an issue price of $6.25 per common share for aggregate gross cash proceeds of $5,500,000 ($5,280,000 net of share issue costs). The common shares were issued pursuant to the exercise by the underwriters of the over-allotment option related to the equity financing closed in December 2007.

The Company has outstanding warrants issued with an exercise price of $7.00 which expire on March 8, 2009. These warrants have been included in share capital above and were allocated a fair value of $3,967,000, which was calculated using the Black-Scholes pricing model.



(b) Stock compensation:

The following table presents the Company's stock option issuances and
expense for the 3 and 9 months ended September 30,2008 and 2007:

3 months ended 9 months ended
September 30 September 30
2008 2007 2008 2007
---------------------------------------
Number of options issued 582,500 595,000 1,160,000 1,780,000
Stock based compensation recognized $ 667 $ 605 $ 1,973 $ 1,644
Average fair value per option $ 1.68 $ 2.00 $ 1.72 $ 2.07
---------------------------------------


The fair value of options issued for the 3 and 9 months ended September 30,
2008 and 2007 were estimated using the Black-Scholes option-pricing model
with the following assumptions:

3 months ended 9 months ended
September 30 September 30
2008 2007 2008 2007
---------------------------------------
Risk free interest rate (%) 3.26 4.49 3.34 4.15
Volatility (%) 32.26 33.04 30.41 33.13
Expected weighted average life (years) 4.00 4.00 4.00 4.00
Annual dividend yield (%) Nil Nil Nil Nil
Vesting period (years) 4.00 4.00 4.00 4.00
---------------------------------------

(c) Contributed surplus:


September 30 September 30
2008 2007
$ $
-----------------------------
Balance, beginning of the period 4,299 2,186
Stock based compensation 1,973 1,644
Stock compensation on options exercised (436) (83)
-----------------------------

Balance, end of period 5,836 3,747
-----------------------------
-----------------------------


8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Categories of Financial Assets and Liabilities

Under GAAP, all financial instruments must initially be recognized at fair value on the balance sheet. The Company has classified each financial instrument into the following categories: held for trading financial assets and financial liabilities, loans and receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses on available for sale financial assets are recognized in other comprehensive income ("OCI") and are transferred to earnings when the asset is disposed of. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are added to the cost of the instrument at its initial carrying amount.

The Company has made the following classifications:

- Cash and cash equivalents are classified as financial assets held for trading and are measured on the balance sheet at fair value;

- Accounts receivable are classified as loans and receivables and are initially measured at fair value and subsequent periodical revaluations are recorded at amortized cost using the effective interest rate method; and

- Accounts payable and accrued liabilities, and credit facilities (including current portion) are classified as other liabilities and are initially measured at fair value and subsequent periodic revaluations are recorded at amortized cost using the effective interest rate method.

As at the transition date of January 1, 2007, the Company recorded an $118,000 increase in retained earnings with a corresponding decrease in the credit facilities liability as a result of applying the effective interest rate method to the Company's debentures. In addition, on transition date, the deferred financing costs, previously recorded in other long-term assets, were netted against the credit facilities liability. As the Company records debt accretion of the deferred financing costs over the remaining term to maturity of the debentures, these costs will be charged to income as interest expense with a corresponding increase to the credit facilities liability.

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximates their fair value at September 30, 2008 and 2007 due to their short-term nature. The Company is exposed to credit related losses, which are minimized as the majority of sales are made under contracts with provincial governmental agencies and large utility customers with extensive operations in British Columbia, Alberta, Ontario, and Quebec. No reclassifications or derecognition of financial instruments occurred in the period.

The Company's credit facilities, as described in Note 6, are comprised of senior unsecured debentures, secured debentures, construction facilities, an operating facility, mortgages and a promissory note and, as such, the Company is exposed to interest rate risk. The Company mitigates this risk by either fixing the interest rates upon the inception of the debt or through interest rate swaps. The fair values of the debentures approximate their book values, based on the Company's current credit worthiness and prevailing market interest rates.

Derivative Instruments and Hedging Activities

Derivative instruments are utilized by the Company to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company's policy is not to utilize derivative instruments for speculative purposes. The Company may choose to designate derivative instruments as hedges.

All hedges are documented at inception including information such as the hedging relationship, the risk management objective and strategy, the method of assessing effectiveness and the method of accounting for the hedging relationship. Hedge effectiveness is reassessed on a quarterly basis. All derivative instruments are recorded on the balance sheet at fair value either in accounts receivable, derivative financial asset or liability, accounts payable and accrued liabilities, or other long-term liabilities. Derivative financial instruments that do not qualify for hedge accounting are classified as held for trading and are recognized on the balance sheet and measured at fair value, with gains and losses on these instruments recorded in gain or loss on derivative financial instruments in the consolidated statement of earnings in the period they occur. Derivative financial instruments that have been designated and qualify for hedge accounting have been classified as fair value or cash flow hedges. For fair value hedges, the gains and losses arising from adjusting the derivative to its fair value are recognized immediately in earnings along with the gain or loss on the hedged item. For cash flow and foreign currency hedges, the effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. For any hedging relationship that has been determined to be ineffective, hedge accounting is discontinued on a prospective basis.

The Company has entered into various foreign exchange contracts, expiring in 2008, which fix the Company's Euro payments under wind turbine purchase contracts in Canadian dollars. The aggregate initial amount of Euro purchases was EUR 118,452,960, which is fixed at a rate of 1.4677 for an aggregate Canadian dollar amount of $173,853,409. As at September 30, 2008, the remaining payments totaled EUR 7,403,310, or $10,865,838 Canadian dollars. As at January 1, 2007, the fair value of all outstanding foreign exchange contracts of $7,894,000 was recorded on the consolidated balance sheet as a derivative financial asset, with the gain recorded in OCI. The fair value of the derivative asset as at September 30, 2008, was $43,000. From time to time, the Company may carry cash denominated in foreign currencies which may give rise to foreign exchange gains and losses as a result of fluctuations in exchange rates with the Canadian dollar.

The Company has entered into various Contracts for Differences ("CFDs") with other parties whereby the other parties have agreed to pay a fixed price with a weighted average of $53 per MWh to the Company based on the average monthly Alberta Power Pool ("Pool") price for an aggregate of 133,950 MWh per year of electricity from January 1, 2008, maturing from 2008 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'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 in future periods where no forward market exists. At January 1, 2007, the fair value of these contracts of $206,000 was recorded on the consolidated balance sheet as a derivative financial liability, with the loss recorded as OCI. At September 30, 2008, the fair value of the derivative liability was $988,000.

On June 11, 2008, concurrent with the issuance of the Series 5 debentures described in Note 6, the Company entered into a cross-currency swap to fix both the principal and interest payments on the Series 5 debentures, which are denominated in US dollars into Canadian dollars. The principal amount of $20,000,000 US dollars was fixed at $20,400,000 Canadian dollars and the semi-annual interest payments of $730,800 US dollars were fixed at $734,400 Canadian dollars. At September 30, 2008, the fair value of the swap of $1,385,000 was recorded on the consolidated balance sheet as a derivative financial asset.

On August 28, 2008, the Company entered into an interest rate swap to fix the interest rate on approximately 50% of our Bankers' Acceptances amounts under the Wolfe Island and Melancthon II Construction Facilities from a variable interest rate based upon the Bankers' Acceptances rates to a fixed rate of 3.0275% per annum plus a stamping fee. At September 30, 2008, the fair value of the swap of $535,000 was recorded on the consolidated balance sheet as a derivative financial asset, with the gain recorded in OCI.

As at September 30, 2008, the Company does not have any outstanding contracts or financial instruments with embedded derivatives that require bifurcation.

Credit Risk, Liquidity Risk, Market Risk, and Interest Rate Risk

The Company has limited exposure to credit risk, as the majority of its sales contracts are with governments and large utility customers with extensive operations in British Columbia, Alberta, Ontario, and Quebec, and the Company's cash is held with major Canadian financial institutions. Historically, the Company has not had collection issues associated with its receivables and the aging of receivables are reviewed on a regular basis to ensure the timely collection of amounts owing to the Company. At September 30, 2008, the aging of the Company's receivables is as follows:



September 30
2008
$
--------------

Current receivables 17,569
Receivables greater than 60 - 120 days 658
Receivables greater than 120 days -
--------------
18,227

Less: Impairment allowance -
--------------
Receivables, end of period 18,227
--------------
--------------


The Company manages its credit risk by entering into sales agreements with creditworthy parties and through regular review of accounts receivable. The maximum exposure to credit risk is represented by the net carrying amount of these financial assets. This risk management strategy is unchanged from the prior year.

The Company manages its liquidity risk associated with its financial liabilities (primarily those described in Note 6) through the use of cash flow generated from operations, combined with strategic use of long term corporate debentures and issuance of additional equity, as required to meet the capital requirements of maturing financial liabilities. The contractual maturities of the Company's long term financial liabilities are disclosed in Note 6, and remaining financial liabilities, consisting of accounts payable, are expected to be realized within one year. As disclosed in Note 9, the Company is in compliance with all financial covenants relating to its financial liabilities as at September 30, 2008. This risk management strategy is unchanged from the prior year.

As disclosed in Note 6, the Company has four credit facilities, which have variable interest rate risks, the Operating Facility and the three construction facilities (Melancthon II, Wolfe Island, and Blue River). These facilities have interest rates based on the Bankers' Acceptances rates, plus a stamping fee ranging from 0.70% to 1.375% per annum. Due to these variable rates, the Company is exposed to interest rate risk. This risk has been mitigated to the greatest extent possible through the interest rate swap described above. The Company also manages this interest rate risk through the issuance of fixed rate, long term debentures which are used to replace the credit facilities upon completion of the project. This risk management strategy is unchanged from the prior year.

The Company's financial instruments that are exposed to market risk are: foreign currency hedges, CFDs, the cross-currency swap, and the interest rate swap, which are impacted by changes in the Canadian dollar/Euro exchange rate, the forward price of electricity in Alberta, the Canadian/US dollar exchange rate, and the Bankers' Acceptances rates respectively. The objective of these financial instruments is to provide a degree of certainty over the future cash flows of the Company and protect the Company from fluctuating exchange rates and commodity prices. These instruments are managed through a periodic review by senior management, during which the value of entering into such contracts is assessed. The Company's financial instruments activities are governed by its risk management policy, as approved by the Board of Directors on an annual basis. Based upon the remaining payments at September 30, 2008, a 1% change in the Canadian dollar/Euro blended forward exchange rate, over the timing of the payments to be made by the Company, would result in a $62,000 impact to AOCI, a 1% change in the forward electricity prices would result in a $27,000 impact to AOCI, a 1% change in the Canadian/US dollar exchange rate would result in an impact of $350,000 to AOCI, and a 1% change in the Bankers' Acceptance rates would result in an impact of $125,000 to AOCI. This risk management strategy is unchanged from the prior year.

9. CAPITAL DISCLOSURES

The Company's stated objective when managing capital (comprised of the Company's debt and shareholders' equity) is to utilize an appropriate amount of leverage to ensure that the Company is able to carry out its strategic plans and objectives. The Company's success of this is monitored through comparison to a targeted debt to equity ratio of 65/35, which the Company believes is an appropriate mix given the current economic conditions in Canada, the Company's growth phase, and the long-term nature of the Company's assets. The Company plans to meet the targeted ratio through the issuance of additional financings, as required to fund the Company's development projects. The Company's current debt/equity mixture is calculated as follows:



September 30 December 31
2008 2007
$ $
-----------------------------
Total debt, including current portion of credit
facilities 718,377 414,756
Shareholders' equity 492,933 481,976
-----------------------------
Total debt and equity 1,211,310 896,732
-----------------------------
-----------------------------

Debt to equity mixture, end of period 59/41 46/54
-----------------------------
-----------------------------


Changes from December 31, 2007 relate primarily to the issuance of new debt described in Note 6, offset slightly by the repayment of credit facilities, in accordance with the original agreements, as well as changes to shareholders' equity relating to current period earnings, the issuance of common shares and the exercise of stock options, described in Note 7.

In accordance with the Company's various lending agreements, the Company is required to meet specific capital requirements. As at September 30, 2008, the Company was in compliance with all externally imposed capital requirements, which consist of covenants in accordance with the Company's borrowing agreements.



10. EARNINGS PER SHARE

The following table shows the effect of dilutive securities on the weighted
average common shares outstanding, as at September 30:

3 months ended 9 months ended
September 30 September 30
2008 2007 2008 2007
-------------------------------------------------
Basic weighted average
shares outstanding 143,541,223 132,855,940 143,383,869 129,410,112
Effect of dilutive
securities:
Options 2,389,754 2,727,572 2,328,754 2,803,396
-------------------------------------------------

Diluted weighted average
shares 145,930,977 135,583,512 145,712,623 132,213,508
-------------------------------------------------
-------------------------------------------------


11. SEGMENTED INFORMATION

Effective January 1, 2008, the Company has identified the following operating segments: Wind, Hydro, and Biomass. These have been identified based upon the nature of operations and technology used in the generation of electricity. As previous internal management reporting had been prepared on a plant by plant basis, rather than by operating segment, comparative information is not readily available and not presented below. The Company analyzes the performance of its operating segments based on their gross margin, which is defined as revenue, less operating expenses.



For the 9 months ended September 30, 2008
---------------------------------------------
Wind Hydro Biomass Total
$ $ $ $
---------------------------------------------
Revenue 30,838 19,267 6,415 56,520
Operating expenses 6,889 4,423 6,638 17,950
---------------------------------------------
Gross margin 23,949 14,844 (223) 38,570
---------------------------------------------
---------------------------------------------

Additions to operating plants 4,019 873 389 5,281
Net book value of operating
plants 381,163 127,899 66,545 575,607


For the 3 months ended September 30, 2008
---------------------------------------------
Wind Hydro Biomass Total
$ $ $ $
---------------------------------------------
Revenue 7,404 7,794 2,200 17,398
Operating expenses 2,120 1,282 1,915 5,317
---------------------------------------------
Gross margin 5,284 6,512 285 12,081
---------------------------------------------
---------------------------------------------

Additions to operating plants 3,854 876 150 4,880
Net book value of operating
plants 381,163 127,899 66,545 575,607

The following table reconciles the additions and net book values of
property, plant, and equipment shown above to the Company's financial
statements as at and for the 9 months ended September 30, 2008:

For the 9 months ended September 30, 2008
---------------------------------------------
CIP and
general
Wind Hydro Biomass corporate Total
$ $ $ assets $ $
---------------------------------------------
Additions to operating plants 4,019 873 389 289,907 295,188
Net book value 381,163 127,899 66,545 610,462 1,186,069
---------------------------------------------


12. 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, 2008, the Company has committed approximately $185,721,000 for goods and services for Melancthon II, Wolfe Island, Royal Road, and the B.C. Hydroelectric projects, which will be expended between 2008 and 2012.

On April 1, 2004, the Company entered into a new 25 year lease agreement (the "Lease") with Ontario Power Generation ("OPG") for the 6.6 MW Ragged Chute Hydroelectric Plant (the "Plant") commencing September 30, 2004. Under the Lease, the Company has agreed to repair the weir at the Plant to the highest minimum standard required by law by November 30, 2008. However, due to force majeure events, the Company will not complete the work and is currently working with the OPG to amend the Lease to extend this date into 2009. The repairs are estimated to cost $4,000,000, of which $1,960,000 has been spent as at September 30, 2008. Upon expiry of the Lease and payment of $6,600,000 by OPG to the Company, the Company will provide OPG with vacant possession of the plant. As the property upon which the Lease is located is owned by the Crown, the Ontario Ministry of Natural Resources has granted consent to the Lease.

13. TRANSACTIONS WITH RELATED PARTIES

The Company pays gross overriding royalties ranging from 1% - 2% on electric energy sales on four of its original hydroelectric plants to a company controlled by the President who is also a director. During the three and nine months ended September 30, 2008, royalties totaling $24,000 (2007 - $19,000) and $138,000 (2007 - $47,000), respectively, were incurred.

Contact Information

  • Canadian Hydro Developers, Inc.
    John Keating
    CEO
    (403) 269-9379
    or
    Canadian Hydro Developers, Inc.
    Kent Brown
    Executive Vice-President & CFO
    (403) 269-9379
    Website: www.canhydro.com