Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

May 13, 2009 17:45 ET

Canadian Hydro Announces Results for the First Quarter Ended March 31, 2009

CALGARY, ALBERTA--(Marketwire - May 13, 2009) - Canadian Hydro Developers, Inc. (TSX:KHD) -

HIGHLIGHTS

- Increased generation, revenue, and EBITDA due to the addition of the 132 MW Melancthon II EcoPower® Centre (Melancthon II) and higher average electricity prices received;

- Erected all 86 turbines and began the commissioning process at our 197.8 MW Wolfe Island Wind Project, which is expected to be commercially operational by June 30, 2009, on-time and on-budget;

- Achieved positive operating income at our Grande Prairie EcoPower® Centre (GPEC), an improvement of 324% in Q1 2009 over the 2008 year; and

- Progressed well on the planned capital programs to improve operations at GPEC and Centre EcoPower® Le Nordais (Le Nordais).



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Q1 Change
2009 2008 %
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Financial Results (in thousands
of dollars except where noted)

Revenue 23,462 19,461 + 21
EBITDA 13,016 12,699 + 2
Cash flow 5,390 8,342 - 35
Per share (diluted) 0.04 0.06 - 33
Net earnings (loss) (2,218) 1,809 - 223
Per share (diluted) (0.02) 0.01 - 300

Operating Results
Installed capacity - MW (net) 496 364 + 36
Electricity generation - MWh (net) 287,450 256,467 + 12
kWh per share (diluted) 2.00 1.78 + 12
Average price received per MWh ($) 82 76 + 8
Electrical generation under contract (%) 79 73 + 8
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For the quarter ended March 31, 2009, revenue and EBITDA improved over the same period in the prior year due to:

- The addition of Melancthon II in November 2008; and

- Improved generation at GPEC.

These factors were offset partially by:

- Lower gross margins (70% versus 74%) mainly due to unseasonably low wind conditions in Ontario and increased Hydro One line outages, which impacted generation at the Melancthon EcoPower® Centre. No additional line outages are planned in 2009. Generation in April 2009 was 29% above the long-term average.

"The first quarter of 2009 was an exciting one for Canadian Hydro as we began to reap the benefit of the completion of Melancthon II in 2008 and continued to successfully execute on our strategic plan," said John Keating, CEO of Canadian Hydro. "Along with the completion of Melancthon II in late 2008, the imminent completion of Wolfe Island will more than double the size of Canadian Hydro. Combined with the anticipated benefits from the programs aimed at increasing efficiency currently underway at GPEC and Le Nordais, we are continuing to benefit from our unique and proven strategy of design, build, and operate. This has allowed us to continue to grow our Company at a significant rate despite the global economic turmoil of the past year."

Canadian Hydro is focused on Building a Sustainable Future®. We are a developer, owner and operator of 20 EcoPower® Centres totalling net 496 MW of capacity in operation and have an additional 383 MW in or nearing construction and 1,525 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 EcoLogo(M) Program.

Common shares outstanding: 143,661,223

MANAGEMENT'S DISCUSSION AND ANALYSIS (MD&A)

Advisories

The following MD&A, dated May 7, 2009, should be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2008 and 2007 (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 completed significant milestones in the execution of our strategic plan during the first quarter of 2009. We:

- Approached completion of our Wolfe Island Wind Project (Wolfe Island), which is anticipated to achieve commercial operations by June 30, 2009, on time and on budget and will increase our net installed capacity by 40% to 694 MW;

- Progressed well on the planned programs under way at our Grande Prairie EcoPower® Centre (GPEC) and Centre EcoPower® Le Nordais (Le Nordais) with the goal of improving operations by the end of 2009; and

- In Alberta, continued to work on permitting the 100 MW Dunvegan Hydroelectric Prospect (Dunvegan).

Revenue and EBITDA, including per share amounts, improved in the first quarter of 2009 over the same period in the prior year due to:

- The addition of phase II of the Melancthon EcoPower® Centre (Melancthon) completed in November 2008; and

- Improved generation and operating results at GPEC as a result of the work program initiated in late 2008.

Cash flow and net earnings, including per share amounts, were lower in the first quarter of 2009 over the same period in the prior year due to:

- Lower gross margins (70% vs. 74%) as a result of:

- Unseasonably low winds in Ontario and increased Hydro One line outages resulting in lower than normal generation at Melancthon. Generation in April 2009 was 29% above the long-term average;

- Lower water levels and increased maintenance at our BC hydroelectric EcoPower® Centres;

- Continued planned work to improve performance at Le Nordais and GPEC; and

- Increased interest expense as a result of the Melancthon II construction facility being charged to earnings rather than project costs, as a result of the project being completed in November 2008.

RESULTS OF OPERATIONS

Revenue and Generation



Quarterly Electricity Generation - by Province and Technology(1)

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Q1
2009 2008
MWh MWh Change
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British Columbia 5,312 31,328 - 83
Alberta 112,941 118,777 - 5
Ontario 148,166 79,424 + 87
Quebec 21,031 26,938 - 22
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Totals 287,450 256,467 + 12
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Hydroelectric 32,845 54,446 - 40
Wind 223,011 172,892 + 29
Biomass 31,594 29,129 + 8
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Totals 287,450 256,467 + 12
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kWh per share(2) 2.00 1.78 + 12
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(1) Reflecting our net interest.
(2) kWh per share based on diluted weighted average shares outstanding.


Revenue in Q1 2009 increased 21% over the prior year as a result of the following factors:

- The addition of Melancthon II in November 2008;

- Improved hydroelectric generation in Ontario due to higher water flows than Q1 2008; and

- Improved generation at GPEC as a result of the work program currently underway;

Offset partially by:

- Lower generation at our BC hydroelectric EcoPower® Centres due to lower water levels and increased downtime for planned maintenance;

- The inclusion in Q1 2008 of a one-time metering adjustment at our Akolkolex Hydroelectric EcoPower® Centre (Akolkolex) of 21,011 MWh, which benefited generation in Q1 2008;

- Lower generation at Melancthon as a result of unseasonably low wind conditions and an increased number of Hydro One line outages. No additional line outages are planned by Hydro One in 2009;

- Lower generation at our Alberta wind EcoPower® Centres due to lower wind levels than Q1 2008; and

- Lower generation at Le Nordais due to the work program currently underway, which is expected to be completed by year end.

Generation decreased from Q4 2008 as a result of lower wind generation in Ontario and lower hydroelectric generation in British Columbia. At Akolkolex, we completed significant required planned maintenance and capital upgrades including the installation of new runners, which were required as part of the normal life cycle of the facility. As a result of these repairs, Akolkolex had minimal generation for the quarter. Akolkolex is back on-line as of May 7, 2009, in advance of spring freshet, the highest generating period in the year.

We have received an average price of $82/MWh for Q1 2009, compared to $76/MWh for 2008. This was the result of the addition of Melancthon II, which has a higher contract price than the average of our other EcoPower® Centres. This was offset by lower pool prices received by our merchant Alberta plants in Q1 2009 (Q1 2009 - $52/MWh, Q1 2008 - $77/MWh) due to lower natural gas prices and lower demand as a result of the current worldwide economic downturn, both of which influence the spot market price in Alberta. This decline in pool price was mitigated by the fact that approximately 79% of our generation was sold pursuant to long-term sales contracts in Q1 2009 (Q1 2008 - 73%).

Operating Expenses

Operating expenses increased 35% in Q1 2009 compared to Q1 2008, mainly due to the following factors:

- The addition of Melancthon II;

- Work at Le Nordais and GPEC in order to optimize performance and improve the availability of the EcoPower® Centres; and

- Increased planned maintenance expenditures at our BC hydroelectric EcoPower® Centres.

On a $/MWh basis, operating expenses increased in Q1 2009 primarily as a result of the above factors.

Gross Margins

Gross margins, as a percentage of revenue, decreased for Q1 2009 to 70% from 74% in Q1 2008 due primarily to the increase in operating expenses described above. This decrease was also impacted by the lower than normal generation at Melancthon during the quarter, as many of our operating costs are fixed and do not have a directly proportional relationship with generation.



Interest on Credit Facilities and Credit Facilities

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(in thousands of dollars Q1 Change
except where noted) 2009 2008 %
----------------------------------------------------------------------------
Gross interest on credit facilities 9,230 5,679 + 63
Capitalized interest (2,172) (1,255) + 73
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Net interest expense on credit
facilities 7,058 4,424 + 60
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Net interest expense on credit
facilities per MWh ($/MWh) 24.55 17.25 + 42
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Interest income 75 205 - 63
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The increase in net interest expense on credit facilities in 2009 was due to higher outstanding corporate debt, which increased a result of the achievement of commercial operations (COD) of Melancthon II. Prior to COD, interest was capitalized to the project.

On a $/MWh basis, net interest expense increased in 2009 as a result of the increase in corporate debt and lower than expected generation.

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 March 31, 2009 were $841,408,000 compared to $835,796,000 as at December 31, 2008. The increase was a result of increased draws on our construction facilities, less the usual repayments on certain credit facilities.

Amortization Expense

Amortization expense increased 52% in Q1 2009 from Q1 2008 due to the addition of Melancthon II. On a $/MWh basis, amortization expense increased for the 3 month period as a result of lower than expected generation at Melancthon.

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

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(in thousands of dollars Q1 Change
except where noted) 2009 2008 (%)
----------------------------------------------------------------------------
Gross administration expenses 4,243 2,224 + 91
Capitalized administration expenses (1,236) (411) + 201
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Net administration expenses 3,007 1,813 + 66
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Net administration expense per MWh
($/MWh) 10.48 7.02 + 49
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Gross administration expense increased 91% in Q1 2009 from Q1 2008. Over the past year, we have become a much larger company and are on the verge of doubling our installed capacity. As a result, administration expenses and staff numbers have increased as well.

On a $/MWh basis, net administration expense increased for the 3 month period due to the reasons 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 decreased 7% in Q1 2009 from Q1 2008 due to a lower fair value per option as a result of a lower share price, which impacts the calculation of 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.

Future income taxes decreased 221% due to lower earnings before taxes. Our effective tax rate remains unchanged at 21% in 2009.

EBITDA, Cash Flow, and Net Earnings

EBITDA

In Q1 2009, EBITDA increased 2% compared to Q1 2008 due to:

- Increased generation as a result of the Melancthon II addition; and

- Higher prices received.

This was offset partially by:

- lower than expected generation from Melancthon and our BC hydroelectric EcoPower® Centres; and

- higher administrative expenses, as discussed above.

On a $/MWh basis, EBITDA decreased as a result of the factors discussed above with respect to operating expenses.

Cash Flow

Cash flow in Q1 2009 decreased 35% from Q1 2008 as a result of:

- Lower gross margins due to lower than expected generation from Melancthon and our BC hydroelectric EcoPower® Centres and higher administrative expenses;

- Higher interest expenses as a result of interest from the Melancthon construction facility no longer being charged to the project costs; and

- Higher administrative and capital taxes as compared to the prior year.

On a per share basis, cash flow decreased 33% in Q1 2009 from Q1 2008 due to the above. 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, our B.C. Hydroelectric Projects and Wolfe Island. The benefits of these equity issues will not be fully reflected in our cash flow until a full year of operations at these projects.

Net Earnings

Net earnings, on an absolute basis, decreased 223% in Q1 2009 compared to Q1 2008, mainly as a result of:

- Lower gross margins mainly due to lower than expected generation from Melancthon and our BC hydroelectric EcoPower® Centres and higher administrative expenses, as discussed above;

- Higher interest expenses as a result of interest from the Melancthon construction facility no longer being charged to the project costs; and

- Higher amortization expense as a result of the addition of Melancthon II.

These expenses were offset partially by a future income tax recovery due to lower taxable income. Accordingly, on a $/MWh basis, net earnings decreased over the prior year.

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. The benefits of these equity issues will not be fully reflected in our net earnings until a full year of operations at these projects



Property, Plant, and Equipment Additions and Prospect Development Costs

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(in thousands of dollars) Q1 2009 Q1 2008 Change
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Property, plant, and equipment additions 47,417 4,441 + 968%
Prospect development cost additions 4,004 12,150 - 67%
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Property, plant, and equipment additions relate mainly to capital expenditures for the $475,000,000 Wolfe Island Wind Project.

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

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 will generate the necessary cash flow and working capital to meet the equity needs of new projects. Subject to conditions in the capital markets at the time, we expect to have adequate access to financing to fulfill all the obligations that may be required to implement 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 March 31 2009
----------------------------------------------------------------------------
Capital expenditure plans through 2012 1,014,120
Spent to date (503,285)
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Remaining capital expenditures to be financed 510,835
Financed/to be financed by:
Blue River construction facilities 48,900
Wolfe Island construction facility 32,000
Working capital(1) (24,887)
Anticipated construction facilities(2) 281,900
Undrawn & available revolving Operating Facility 54,914
Expected to be funded through cash flow from operations 118,008
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Difference -
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(1) Excluding derivative financial instrument assets and liabilities
(2) See following table with project breakdown


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

- Wolfe Island;

- Yellow 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:



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Anticipated Anticipated timing
construction of construction
(in thousands of dollars) facility size facility
----------------------------------------------------------------------------
Project
Yellow Falls 28,400 Q3 2009
Royal Road 26,000 Q1 2010
New Richmond 123,500 Q4 2011
St. Valentin 104,000 Q4 2011
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Total 281,900
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Exclusive of any new projects that we may be awarded under the calls for power 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 Yellow Falls Hydroelectric Project. With the upcoming completion of Wolfe Island, we expect to have the ability to finance the equity portion of approximately one 100 MW project each year from free cash flow.

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. Generally, we 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 employ our cash flow from operations to support our capital expenditure program.

We have no requirements to significantly access the debt markets until September 2010 when the Melancthon II Construction Facility matures. While we anticipate that funds in the debt market will be available at economic interest rates, it is currently not possible to guarantee that these funds will be available when required.

As at March 31, 2009, we had a 64/36 debt/capital mixture (December 31, 2008 - 63/37) 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. We monitor our lending covenants on a continuous basis and based on our projections, will continue to comply with all externally imposed covenants.

OUTLOOK

Project Updates

Ontario

Wolfe Island Wind Project

At Wolfe Island, construction has reached its final stages with all 86 turbines erected, the substation constructed and operational, and the commissioning of turbines well underway. 10 of the 86 turbines are currently providing power to the grid. The anticipated capital costs and in-service date remain unchanged at $475 million and June 30, 2009, respectively. The completion of Wolfe Island represents a major milestone and will increase our installed capacity by 40% to 694 MW. With the completion of Melancthon II and Wolfe Island, we will have successfully doubled the size of our Company within 8 months, which is a testament to our ability to complete projects and execute on our strategic plan.

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. However, we expect the OPA to offer an optional form of contract amendment to provide a one-year extension to the target in-service date. Regulatory approvals and debt financing are required prior to proceeding with construction.

Yellow Falls Hydroelectric Project

We continue to work on obtaining permits and approvals to proceed to construction of our 16.0 MW (8.0 MW net to our interest), $71,000,000 ($35,500,000 net to our interest) Yellow Falls Hydroelectric Project. Yellow Falls has a 20-year RES II Contract with the OPA for the purchase of electricity and Renewable Energy Certificates (RECs). Our target completion date for this project is October 2010. Regulatory approvals and financing are required prior to proceeding with construction.

British Columbia

Bone, Clemina, Serpentine and English Creek Hydroelectric Projects

At March 31, 2009, we were engaged in the development of the following hydroelectric projects:

- 18.0 MW, $49,000,000 Bone Creek;

- 11.0 MW, $27,000,000 Clemina Creek;

- 9.6 MW, $28,000,000 Serpentine Creek; and

- 5.0 MW, $10,000,000 English Creek.

The targeted completion date for all four B.C. projects is the fourth quarter of 2010. Bone has a 20-year and Clemina, Serpentine and English have 40-year Electricity Purchase Agreements (EPAs) with BC Hydro, for the purchase of electricity and RECs. In addition, we will receive funding under ecoENERGY for Renewable Power program (eRI) for Bone, Clemina and Serpentine, and expect to be eligible for English Creek. Construction activities were completed for the winter season for Bone and Clemina in October 2008. Since securing EPAs in 2006, construction costs have increased significantly. Recently, we have begun to see a decrease in construction costs due to the current worldwide economic conditions. We are currently in the process of obtaining construction cost estimates and we will provide an update on these projects in Q2 2009. We currently estimate a one-year delay to the target commercial operations date for these projects from October 1, 2009 to October 1, 2010. There is no assurance that construction costs will decrease to economic levels, and this may impact the viability of these projects.

Alberta

Dunvegan Hydroelectric Project

On April 29, 2009, we achieved another significant milestone at Dunvegan when the Dunvegan Hydro Development Act came into force under Alberta legislature. This act is another step in our permitting and approvals process as it authorizes the Alberta Utilities Commission (AUC) to make an order for the construction and operation of the project. The AUC can now approve applications previously filed. On May 7, 2009, we received AUC approval. We continue to work on obtaining all permits required to proceed to construction, completing the detailed design and developing a marketing strategy for the power. The timing of construction will be dependent upon obtaining equity and debt financing at appropriate rates, finalizing our capital costs and construction schedule and marketing the power and RECs at economic levels on a long-term basis to creditworthy counterparties. With the upcoming completion of Wolfe Island, we expect to have the ability to finance the equity portion of approximately one 100 MW project each year from free cash flow. As a result, due to current market conditions, we may choose to proceed slowly with Dunvegan, using our free cash flow as opposed to issuing equity at a higher cost of capital than we have historically achieved. Dunvegan is currently estimated to cost between $500 and $600 million, however, we plan to update this estimate once detailed design is complete. The remaining permits, long-term power sale contracts and financing are required prior to proceeding to construction.

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.

Calls for Power

B.C.

We submitted a proposal for a 50 MW hydroelectric prospect into BC Hydro's Clean Power Call, in November 2008. Contracts under this Clean Power Call are anticipated to be awarded in June of 2009.

Ontario Green Energy Act

On February 23, 2009, Ontario Bill 150 "Green Energy and Green Economy Act" was tabled at the Legislative Assembly of Ontario. This act proposes the addition of an advanced renewable tariff that offers renewable energy producers guaranteed access to the grid at a price set by the regulatory authority. Generally, tariff prices are established at a rate that enables developers to cover the cost of their projects and to earn a reasonable return on their investment. The proposed tariff rates would be at a premium to those available under the current Standard Offer Program in Ontario. We continue to monitor this legislation, and view it as having a positive impact on our business.

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 one 10 MW solar project in Ontario and will work on a second 10 MW contract under the proposed Ontario Green Energy Act's Feed in Tariff Program. In recent months, we have seen a decrease in the cost of solar panels world wide, which is improving the economics of this technology. In addition, we are working on the development of a tracking system to improve the anticipated output of the solar panels. We feel 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:

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(in thousands of dollars,
except per share amounts) Q2 2008 Q3 2008 Q4 2008 Q1 2009
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Total revenue 19,661 17,398 23,578 23,462
EBITDA 11,279 11,336 14,457 13,016
Cash flow 5,614 5,454 7,487 5,390
Net earnings (loss) 2,883 (4,986) 1,225 (2,218)
Earnings (loss) per share - basic 0.02 (0.03) 0.01 (0.02)
Earnings (loss) per share - diluted 0.02 (0.03) 0.01 (0.02)
Generation (MWh) 261,377 246,133 302,104 287,450
kWh per share (diluted) 1.80 1.69 2.07 2.00
Average price received ($/MWh) 75 71 78 82
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(in thousands of dollars,
except per share amounts) Q2 2007 Q3 2007 Q4 2007 Q1 2008
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Total revenue 17,277 14,344 17,398 19,461
EBITDA 12,216 7,765 10,597 12,699
Cash flow 7,762 4,161 6,687 8,342
Net earnings (loss) 1,771 162 5,505 1,809
Earnings (loss) per share - basic 0.01 - 0.04 0.01
Earnings (loss) per share - diluted 0.01 - 0.04 0.01
Generation (MWh) 271,429 212,031 237,917 256,467
kWh per share (diluted) 2.01 1.56 1.76 1.78
Average price received ($/MWh) 64 68 73 76
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The changes over the past eight quarters are due primarily to the addition of Le Nordais and Melancthon II, as well as the large non-cash foreign exchange loss in Q3 2008, increased operating, interest and amortization expenses, as previously discussed.

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 or internal controls over financial reporting since December 31, 2008.

Accounting Changes and Future Accounting Changes

Effective January 1, 2008, the Company adopted Canadian Institute of Chartered Accountants ("CICA") handbook section 3064 - "Goodwill and Intangible Assets".

The CICA has issued the following handbook sections, which will become effective between 2009 and 2011:

(i) Section 1582 - "Business Combinations" - Section 1582 replaces Section 1581 - "Business Combinations" and provides the Canadian equivalent to International Financial Reporting Standards ("IFRS") 3 - Business Combinations. This applies to a transaction in which the acquirer obtains control of one or more businesses. Most assets acquired and liabilities assumed, including contingent liabilities that are considered to be improbable, will be measured at fair value. Any interest in the acquiree owned prior to obtaining control will be remeasured at fair value at the acquisition date, eliminating the need for guidance on step acquisitions. Additionally, a bargain purchase will result in recognition of a gain and acquisition costs must be expensed. The Company will adopt this standard on January 1, 2011.

(ii) Section 1601 - "Consolidations" and Section 1602 - "Non-controlling Interests". Section 1601 and Section 1602 replace Section 1600 - "Consolidated Financial Statements". Section 1602 provides the Canadian equivalent to International Accounting Standard 27 - "Consolidated and Separate Financial Statements", for non-controlling interests. The Company will adopt this standard on January 1, 2011

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 March 31, 2009, 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 months ended March 31, 2009, royalties totaling $9,000 (2007 - $12,000) 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 March 31, 2009, 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, maturing from 2009 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 March 31, 2009, the fair value of the CFDs was an asset of $195,000.

Foreign Exchange Contracts

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 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 March 31, 2009, the aggregate fair value of all outstanding foreign exchange contracts was an asset of $5,913,000.

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 a blended rate of 2.41% per annum plus a stamping fee for an all-in rate of 3.71%. At March 31, 2009, the fair value of all outstanding interest rate swap contracts was a liability of $11,933,000.



OUTSTANDING SHARE DATA

----------------------------------------------------------------------------
As at May 7, 2009
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 143,661,223
Convertible securities:
Options 9,387,200
----------------------------------------------------------------------------
Fully diluted common shares 153,048,423
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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, 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)

March 31, December 31,
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

ASSETS

CURRENT
Cash 8,228 33,839
Accounts receivable (Note 8) 14,650 31,925
Derivative financial instrument asset (Note 8) 6,108 4,954
Prepaid expenses 1,664 962
----------------------------------------------------------------------------
30,650 71,680

Property, plant, and equipment (Note 3) 1,336,776 1,288,446
Prospect development costs (Note 4) 53,567 50,006

----------------------------------------------------------------------------
----------------------------------------------------------------------------
TOTAL ASSETS 1,420,993 1,410,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES

CURRENT
Accounts payable and accrued liabilities 45,793 39,085
Derivative financial instrument liability (Note 8) 11,933 12,273
Current portion of long-term debt (Note 6) 2,389 2,364
Taxes payable 1,247 1,177
----------------------------------------------------------------------------
61,362 54,899

Long-term debt (Note 6) 839,019 833,432
Future income taxes 38,854 39,564
----------------------------------------------------------------------------

939,235 927,895
----------------------------------------------------------------------------
COMMITMENTS & CONTINGENCIES (Note 12)

SHAREHOLDERS' EQUITY

Share capital and warrants (Note 7) 451,247 455,066
Contributed surplus (Note 7) 10,985 6,399
Retained earnings 30,062 32,280
----------------------------------------------------------------------------
492,294 493,745
Accumulated other comprehensive loss (Note 5) (10,536) (11,508)
----------------------------------------------------------------------------
481,758 482,237
----------------------------------------------------------------------------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 1,420,993 1,410,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 March 31
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenue
Electric energy sales 23,305 19,275
Revenue rebate 157 186
----------------------------------------------------------------------------
23,462 19,461
----------------------------------------------------------------------------
Expenses (income)
Operating 7,004 5,150
Amortization 7,617 5,029
Interest on credit facilities 7,058 4,424
Administration 3,007 1,813
Foreign exchange loss (gain) 985 (201)
Stock based compensation 672 722
Interest income (75) (205)
Reclassification of amounts from other
comprehensive income (Note 5) (500) -
----------------------------------------------------------------------------
25,768 16,732
----------------------------------------------------------------------------

(Loss) earnings before taxes (2,306) 2,729
----------------------------------------------------------------------------

Tax (recovery) expense
Current and capital 643 138
Future (731) 782
----------------------------------------------------------------------------
(88) 920
----------------------------------------------------------------------------

Net (loss) earnings (2,218) 1,809

Retained earnings, beginning of period 32,280 31,349
----------------------------------------------------------------------------

Retained earnings, end of period 30,062 33,158
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(Loss) earnings per share (Note 10)
Basic (0.02) 0.01
Diluted (0.02) 0.01


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

3 months ended March 31
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net (loss) earnings (2,218) 1,809
Other comprehensive gain (loss):
Unrealized gain on derivative financial
instrument currency hedges, net of tax 937 3,982
Unrealized gain on derivative financial
instrument contracts for differences 1,047 119
Unrealized loss on derivative financial
instrument interest rate hedges (512) -
Reclassified to net earnings (500) -
----------------------------------------------------------------------------
Other comprehensive gain 972 4,101

Comprehensive (loss) income (1,246) 5,910
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 March 31
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

OPERATING ACTIVITIES
Net (loss) earnings (2,218) 1,809
Adjustments for:
Amortization 7,617 5,029
Future income tax (recovery) expense (731) 782
Stock based compensation 672 722
Reclassification of amounts from other
comprehensive income (500) -
Unrealized foreign exchange losses 550 -
----------------------------------------------------------------------------

Cash flow from operations before changes
in non-cash working capital 5,390 8,342
Changes in non-cash working capital 15,264 2,610
----------------------------------------------------------------------------
20,654 10,952
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Credit facility repayments (Note 6) (23,489) (439)
Credit facility advances (Note 6) 28,600 -
Issue of common shares, net of issue costs (Note 7) 95 6,084
----------------------------------------------------------------------------
5,206 5,645
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Property, plant, and equipment additions (47,417) (4,441)
Prospect development costs (4,004) (12,150)
----------------------------------------------------------------------------
(51,421) (16,591)
----------------------------------------------------------------------------

----------------------------------------------------------------------------
FOREIGN EXCHANGE ON CASH HELD IN FOREIGN CURRENCY (50) -
----------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH (25,611) 6
CASH, BEGINNING OF PERIOD 33,839 22,785
----------------------------------------------------------------------------

CASH, END OF PERIOD 8,228 22,791
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental information
Cash interest paid 7,243 4,528
Cash income and capital taxes paid 594 -

See accompanying Notes to the Consolidated Financial Statements


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2009 (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.

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

2. CHANGE IN ACCOUNTING POLICIES

(a) Accounting Changes

Effective January 1, 2009, the Company adopted Canadian Institute of Chartered Accountants ("CICA") handbook section 3064 - "Goodwill and Intangible Assets", which replaces section 3062 "Goodwill and Other Intangible Assets". This new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets.

(b) Future Accounting Pronouncements

The CICA has issued the following handbook sections, which will become effective between 2009 and 2011. The Company is currently in the process of evaluating the requirements of the new standards:

(i) Section 1582 - "Business Combinations" - Section 1582 replaces Section 1581 - "Business Combinations" and provides the Canadian equivalent to International Financial Reporting Standards ("IFRS") 3 - Business Combinations. This applies to a transaction in which the acquirer obtains control of one or more businesses. Most assets acquired and liabilities assumed, including contingent liabilities that are considered to be improbable, will be measured at fair value. Any interest in the acquiree owned prior to obtaining control will be remeasured at fair value at the acquisition date, eliminating the need for guidance on step acquisitions. Additionally, a bargain purchase will result in recognition of a gain and acquisition costs must be expensed. The Company will adopt this standard on January 1, 2011.

(ii) Section 1601 - "Consolidations" and Section 1602 - "Non-controlling Interests". Section 1601 and Section 1602 replace Section 1600 - "Consolidated Financial Statements". Section 1602 provides the Canadian equivalent to International Accounting Standard 27 - "Consolidated and Separate Financial Statements", for non-controlling interests. The Company will adopt this standard on January 1, 2011.

(iii) Effective January 1, 2011, IFRS will replace current Canadian standards and interpretations as Canadian GAAP for publicly accountable enterprises. Accordingly, the Company will be adopting the new standards effective at this date.

3. PROPERTY, PLANT, AND EQUIPMENT

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



March 31, 2009 December 31, 2008
---------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
---------------------------------------------
Generating plants
- operating 935,746 82,232 853,514 856,291
- construction-in-progress 479,969 - 479,969 428,592
Equipment, other 5,241 2,171 3,070 2,918
Vehicles 2,101 1,878 223 645
---------------------------------------------

1,423,057 86,281 1,336,776 1,288,446
---------------------------------------------
---------------------------------------------


The following amounts have been capitalized to property, plant, and
equipment for the 3 months ended March 31, 2009 and 2008:

2009 2008
------------------------
Interest costs 2,172 302
Administrative expenses 547 46
------------------------
Total 2,719 348
------------------------
------------------------


As at March 31, 2009, construction-in-progress (CIP) relates to costs associated with the construction of the Wolfe Island Wind Project, and the Bone and Clemina Creek Hydroelectric Projects (2008 - Melancthon II). During the 3 months ended March 31, 2009, $nil was moved from Prospect Development Costs to CIP (Q1 2008 - $nil).



4. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

March 31, December 31,
2009 2008
$ $
------------------------

Dunvegan Hydroelectric Prospect 17,950 16,703
Manitoba Wind Prospects 7,310 7,744
British Columbia Hydroelectric Projects 6,875 6,066
Royal Road Wind Projects 6,345 6,160
New Richmond and St. Valentin Wind Projects 5,721 5,156
Other Hydroelectric and Wind Prospects 4,923 3,918
Yellow Falls Hydroelectric Project 3,483 3,350
Solar Prospects 960 909
------------------------
Total 53,567 50,006
------------------------
------------------------


The following amounts have been capitalized to prospect development costs
for the 3 months ended March 31, 2009 and 2008:

2009 2008
------------------------
------------------------

Interest costs - 953
Administrative expenses 689 365
------------------------
Total 689 1,318
------------------------
------------------------

For the 3 months ended March 31, 2009, the Company wrote off $nil (2008 -
$nil) in costs relating to development prospects that were abandoned during
the period.


5. ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCL)

AOCL is comprised of the following:


$
---------
Balance, December 31, 2008 (11,508)
Unrealized gain on derivative financial instrument cross-currency
swap, net of tax 937
Unrealized loss on derivative financial instrument interest rate
hedges (512)
Unrealized gain on derivative financial instrument contracts for
differences (CFDs) 1,047
Amounts reclassified to net earnings (500)
---------
Accumulated other comprehensive loss, March 31, 2009 (10,536)
---------
---------


During the 3 months ended March 31, 2009, $500,000 was reclassified from AOCL to the statement of earnings, related to the cross currency swap (Note 8). Notwithstanding future changes in the value of the cross-currency swap described in Note 8, no additional amounts are expected to be reclassified from AOCL to net earnings within the next 12 months.

6. CREDIT FACILITIES

The Company has a revolving Operating Facility with its banking syndicate for a total of $85,000,000. As at March 31, 2009, in addition to the $7,000,000 shown below as drawn, the Company had outstanding letters of credit in the amount of $23,086,000 (December 31, 2008 - $30,292,000) relating primarily to construction activities and security required under long-term sales contracts for electricity.



March 31, December 31,
2009 2008
$ $
-------------------------
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 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 (Note 8). 24,992 24,492

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
EcoPower® Centre, 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, which ended December 27, 2008,
followed by a two-year non-amortizing
term out period to September 26, 2010 (Note 8). 184,600 184,600

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 commercial operations and September
12, 2009, followed by a two-year non-amortizing
term out period (Note 8). 260,500 231,900

Blue River Construction Facility, bearing interest
at Bankers' Acceptances rates plus a
stamping fee of 0.70% per annum, unsecured
non-revolving credit facility with a 31-month
drawdown period ending January 27, 2010, followed
by a two-year non-amortizing term out
period. - -

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. 7,000 30,000

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. 5,367 5,580

Mortgage, bearing interest at 10.680%, secured by
letters of guarantee. Monthly repayments
of principal are $31,000 plus interest until
December 30, 2012. 1,406 1,500

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. 1,132 1,350

Promissory note, bearing interest fixed at 6.000%,
secured by a second fixed charge on three
of the Alberta hydroelectric EcoPower® Centres.
Monthly repayments of principal and
interest are $19,000 until August 1, 2012 725 769
------------------------

844,222 838,691
Less: Deferred financing costs (2,814) (2,895)
------------------------
841,408 835,796
Less: Current portion of credit facilities (2,389) (2,364)
------------------------
Credit facilities 839,019 833,432
------------------------
------------------------


7. SHARE CAPITAL

(a) Common shares and warrants:

Number of Amount
Shares $
----------------------------
Balance, share capital, December 31, 2008 143,611,223 455,066
Warrants, reclassified to contributed surplus
(Note 7(c)) - (3,967)
Issued on exercise of stock options 50,000 95
Stock compensation on options exercised - 53
----------------------------
Balance, share capital, March 31, 2009 143,661,223 451,247
----------------------------
----------------------------


(b) Stock compensation:

The following table presents the Company's stock option issuances and
expense for the 3 months ended March 31, 2009 and 2008:


2009 2008
----------------------------

Number of options issued 25,000 55,000
Stock based compensation recognized $ 672 $ 722
Average fair value per option $ 1.08 $ 1.58
----------------------------
----------------------------

The fair value of options issued for the 3 months ended March 31, 2009 and
2008 were estimated using the Black-Scholes option-pricing model with the
following assumptions:

2009 2008
----------------------------

Risk free interest rate (%) 1.52 3.51
Volatility (%) 37.93 28.26
Expected weighted average life (years) 4.0 4.0
Annual dividend yield (%) 0.0 0.0
Vesting period (years) 4.0 4.0
----------------------------
----------------------------


(c) Contributed surplus:


March 31 March 31
2009 2008
$ $
-------------------------
Balance, beginning of the period 6,399 4,299
Stock based compensation 672 722
Reclassification of expired warrants 3,967 -
Stock compensation on options exercised (53) (181)
-------------------------
Balance, end of period 10,985 4,840
-------------------------
-------------------------


During the quarter, 4,110,900 warrants valued at $3,967,000 relating to the acquisition of GW Power Corporation on March 8, 2007 expired without exercise. The corresponding value was reclassified from share capital to contributed surplus.

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 periodic 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.

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximates their fair value at March 31, 2009 and 2008 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 creditworthiness and prevailing market interest rates.

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 is reviewed on a regular basis to ensure the timely collection of amounts owing to the Company. At March 31, 2009, the aging of the Company's receivables is as follows:



March 31
2009
$
----------
Current receivables 14,602
Receivables between 60 - 120 days 48
Receivables greater than 120 days -
----------
14,650
Less: Impairment allowance -
----------
Receivables, end of period 14,650
----------
----------


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 March 31, 2009. 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 below. 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: CFDs, the cross-currency swap, and the interest rate swap, which are impacted by changes in 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 instrument 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 March 31, 2009, a 1% change in the forward electricity prices would result in a $27,000 impact to AOCL, a 1% change in the Canadian/US dollar exchange rate would result in an impact of $351,000 to AOCL, and a 1% change in the Bankers' Acceptances rates would result in an impact of $1,000 to AOCL. This risk management strategy is unchanged from the prior year.




Derivative Instruments and Hedging Activities

March 31 December 31
2009 2008
$ $
-------------------------
Derivative Financial Instrument Assets

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 was fixed at $20,400,000
Canadian and the semi-annual interest payments of
$730,800 US were fixed at $734,400 Canadian.
After giving effect to the cross-currency swap, the
principal amounts of the Series 4 and 5 Debentures
are fixed at $75,900,000 Canadian with an interest
rate of 7.073% per annum. 5,913 4,954

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, maturing from 2009 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. 195 (852)
----------------------
6,108 4,102
----------------------
----------------------

Derivative Financial Instrument Liabilities

On August 28 and December 16, 2008, the Company
entered into interest rate swaps to fix the
interest rate on the 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 2.41% per annum plus a stamping fee. 11,933 11,421
----------------------
11,933 11,421
----------------------
----------------------


As at March 31, 2009, the Company does not have any outstanding contracts or financial instruments with embedded derivatives that require bifurcation.

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 debt ratio is measured against a targeted debt to capital 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/capital mixture is calculated as follows:

March 31 December 31
2009 2008
$ $
---------------------------

Total debt, including current portion of credit
facilities 841,408 835,796
Shareholders' equity 481,758 482,237
---------------------------
Total capital 1,323,166 1,318,033
---------------------------
---------------------------
Debt to capital mixture, end of period 64/36 63/37
---------------------------
---------------------------


Changes from December 31, 2008 relate primarily to draws on construction facilities 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 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 March 31, 2009, the Company was in compliance with all externally imposed capital requirements, which consist of the following covenants in accordance with the Company's borrowing agreements:

- Debt to total capitalization ratio - the Company cannot exceed a debt to total capitalization ratio of 0.65:1. Total capitalization is defined as long term debt (including current portion of credit facilities and derivative financial instrument liabilities) plus shareholders' equity, which includes AOCL.

- Interest service coverage ratio - the Company shall not have an interest service coverage ratio below 2.50:1. Interest service coverage is calculated by dividing EBITDA (defined as net income, plus depreciation, income taxes, interest expense net of interest income, stock compensation expense and non-cash foreign exchange and prospect development cost write offs) by interest expense, on a rolling four quarter basis. Both EBITDA and interest expense are annualized for new EcoPower® Centre additions.

- Maintenance covenant - the Company must not have outstanding secured indebtedness exceeding 20% of its asset base, defined as net assets plus accumulated amortization.

The following table presents the contractual maturities of the Company's financial liabilities, including interest payments, to maturity:



Carrying Contractual 2009 2010 2011 2012 -
Amount Cash Flows onwards
$ $ $ $ $ $
-----------------------------------------------------
Credit facilities 841,408 1,024,590 20,544 223,024 287,727 493,295
Accounts payable and
accrued
liabilities 45,793 45,793 45,793 - - -
Taxes payable 1,247 1,247 1,247 - - -
-----------------------------------------------------
Total 888,448 1,071,630 67,584 223,024 287,727 493,295
-----------------------------------------------------
-----------------------------------------------------


Historically, the Company has re-financed its debt obligations through the issuance of corporate debentures.



10. EARNINGS PER SHARE

The following table shows the effect of dilutive securities on the weighted
average common shares outstanding, as at March 31:

2009 2008
----------------------------
Basic weighted average shares outstanding 143,656,779 142,001,305
Effect of dilutive securities:
Options - 2,048,281
----------------------------
Diluted weighted average shares 143,656,779 144,049,586
----------------------------
----------------------------


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. The Company analyzes the performance of its operating segments based on their gross margin, which is defined as revenue, less operating expenses.



For the 3 months ended March 31, 2009
---------------------------------------
Wind Hydro Biomass Total
$ $ $ $
---------------------------------------
Revenue 18,782 2,238 2,442 23,462
Operating expenses 3,223 1,623 2,158 7,004
---------------------------------------
Gross margin 15,559 615 284 16,458
---------------------------------------
---------------------------------------

Additions to operating plants 3,402 151 1,031 4,584
Net book value of operating plants 656,856 129,481 67,177 853,514


For the 3 months ended March 31, 2008
---------------------------------------
Wind Hydro Biomass Total
$ $ $ $
---------------------------------------
Revenue 13,755 3,417 2,289 19,461
Operating expenses 2,481 744 1,925 5,150
---------------------------------------
Gross margin 11,274 2,673 364 14,311
---------------------------------------
---------------------------------------

Additions to operating plants 272 160 264 696
Net book value of operating plants 384,376 129,099 67,245 580,720


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 3 months ended March 31, 2009 and 2008:

For the 3 months ended March 31, 2009
---------------------------------------------------
Wind Hydro Biomass CIP and general Total
$ $ $ corporate assets $ $
---------------------------------------------------
Additions to operating
plants 3,402 151 1,031 42,833 47,417
Net book value 656,856 129,481 67,177 483,262 1,336,776
---------------------------------------------------


For the 3 months ended March 31, 2008
---------------------------------------------------
Wind Hydro Biomass CIP and general Total
$ $ $ corporate assets $ $
---------------------------------------------------
Additions to operating
plants 272 160 264 3,324 4,020
Net book value 384,376 129,099 67,245 215,659 796,379
---------------------------------------------------


12. COMMITMENTS AND CONTINGENCIES

In the ordinary course of constructing new projects, the Company routinely enters into contracts for goods and services. As at March 31, 2009, the Company has committed approximately $52,405,000 for goods and services for Wolfe Island, Dunvegan, Royal Road, and the B.C. Hydroelectric projects, which will be expended between 2009 and 2010.

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 $2,988,000 has been spent as at March 31, 2009. 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 months ended March 31, 2009, royalties totaling $9,000 (2008 - $12,000) were incurred.

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

Contact Information

  • Canadian Hydro Developers, Inc. - Investor Relations
    Kathy Boutin
    Vice President, Finance
    (403) 298-0256
    Email: kboutin@canhydro.com
    or
    Canadian Hydro Developers, Inc. - Media Relations
    Lindsey Moen
    Communications Coordinator
    (403) 802-2099
    Email: lmoen@canhydro.com
    Website: www.canhydro.com