Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

May 15, 2008 14:01 ET

Canadian Hydro Announces Results for the First Quarter Ended March 31, 2008

CALGARY, ALBERTA--(Marketwire - May 15, 2008) - Canadian Hydro Developers, Inc. (TSX:KHD)

HIGHLIGHTS

- Obtained all final permits and approvals required to complete construction of the Melancthon II Wind Project;

- Awarded two, 20 year electricity Supply Contracts from Hydro-Quebec Distribution for the 50 MW St. Valentin and the 66 MW New Richmond wind prospects in Quebec;

- Opened an office on Wolfe Island, in anticipation of the completion of permitting and commencement of construction of our wind project this summer;

- Transitioned operations of the Le Nordais Wind Plant, hiring 9 new staff with immediate plans to hire an additional 5 staff; and

- Prepared for construction on the Bone and Clemina Creek Hydroelectric Projects in the summer of 2008 and continued to work on obtaining the remaining major licenses and permits for the Serpentine and English Creek Hydroelectric Projects in British Columbia, where construction is expected to commence in the fall of 2008.



----------------------------------------------------------------------------
Q1
Change
2008 2007 %
----------------------------------------------------------------------------
Financial Results (in thousands of dollars
except where noted)

Revenue 19,461 14,738 + 32
EBITDA 12,699 8,537 + 49
Cash flow from operations 8,342 5,145 + 62
Per share (diluted) 0.06 0.04 + 50
Net earnings 1,809 905 +100
Per share (diluted) 0.01 0.01 -

Operating Results
Installed capacity - MWh (net) 364 265 + 37
Electricity generation - MWh (net) 248,425 200,298 + 24
KWh per share (diluted) 1.72 1.60 + 8
Average price received per MWh 78 74 + 5
Electrical generation under contract (%) 73 80 - 9
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Our acquisitions of the Soderglen and Le Nordais Wind Plants in 2007 resulted in an increase in generation for this quarter, as compared to Q1 2007. This increase in generation was offset partially by lower generation on a same plant basis for the first quarter, due to a less windy quarter in Ontario compared to the prior year, and lower generation at the Grande Prairie EcoPower® Centre.

"The first quarter of 2008 showed the positive impact of our two strategic acquisitions made in 2007, leading to a record first quarter for the Company," said John Keating, CEO of Canadian Hydro. "With the construction of Melancthon II, Wolfe Island, and our B.C. hydro projects, 2008 will be an important year for us as we continue to add to our diversified and growing portfolio."

Canadian Hydro is focused on Building a Sustainable Future®. We are a developer, owner and operator of 20 power generation facilities 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 EcoLogo(M) Program.

Common shares outstanding: 143,378,723

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

Advisories

The following MD&A, dated May 2, 2008 (with the exception of the 'Outstanding Share Data', which is dated May 15, 2008), 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") and related Notes. 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'.



RESULTS OF OPERATIONS

Revenue

Quarterly Electricity Generation - by Province and Technology(1)
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Q1 2008 Q1 2007
MWh MWh Change
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British Columbia 31,328 29,206 + 7%
Alberta 110,735 85,802 + 29%
Ontario 79,424 85,290 - 7%
Quebec 26,938 - + 100%
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Totals 248,425 200,298 + 24%
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Hydroelectric 54,446 54,900 - 1%
Wind 172,892 117,354 + 47%
Biomass 21,087 28,044 - 25%
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Totals 248,425 200,298 + 24%
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kWh per share(2) 1.72 1.60 + 8%
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(1) Reflecting our net interest.
(2) kWh per share based on diluted weighted average shares outstanding.


Revenue in Q1 2008 increased 32% over Q1 2007 to $19,461,000 on generation of 248,425 MWh, compared to revenue of $14,738,000 on generation of 200,298 MWh in Q1 2007. This increase was a result of a full quarter of generation from our Soderglen Wind Plant ("Soderglen"), which was acquired on March 8, 2007, as well as the addition of our Le Nordais Wind Plant ("Le Nordais"), acquired December 17, 2007. This was offset partially by a less windy first quarter in Ontario, and lower generation at our Grande Prairie EcoPower® Centre ("GPEC").

We received an average price of $78/MWh for the first quarter, compared to $74/MWh for Q1 2007. This was a result of the addition of Le Nordais, which has a higher contract price than existing plants and a higher pool price received at Soderglen. Approximately 73% of our generation was sold pursuant to long-term sales contracts in Q1 2008 (Q1 2007 - 80%). Alberta Power Pool ("Pool") prices received in Q1 2008 ($77/MWh) were higher than Q1 2007 ($64/MWh). Our objective is to sell at least 75% of our generation under long-term contracts and expect that, on an annual basis in 2008, we will meet our objective.

Operating Expenses

Operating expenses increased 5% in Q1 2008 to $5,150,000 compared to $4,888,000 Q1 2007, mainly due to the addition of Soderglen and Le Nordais, offset slightly by decreased operating expenses at GPEC. On a $/MWh basis, operating expenses have decreased over the prior quarter due to increased quarter over quarter generation, and the acquisitions of Soderglen and Le Nordais, which have lower operating costs per MWh compared to our biomass and hydro plants.

Gross Margins

Gross margins (revenue less operating expenses; expressed as a percentage of revenue) improved in Q1 2008 to $14,311,000 from $9,850,000 in Q1 2007 due to the addition of Soderglen and Le Nordais, as well as improved gross margins at GPEC as a result of decreased operating expenditures.



Interest on Credit Facilities, Credit Facilities and Interest Income

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Q1
Change
(in thousands of dollars except where noted) 2008 2007 %
----------------------------------------------------------------------------
Interest on credit facilities, including
capitalized interest 5,679 4,587 + 24
Capitalized interest 1,255 950 + 32
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Net interest expense on credit facilities 4,424 3,637 + 22
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Net interest expense on credit facilities per
MWh ($/MWh) 17.81 18.16 - 2
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Interest income 205 457 - 55
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The increase in interest on credit facilities (excluding capitalized interest) was due to higher outstanding corporate debt, mainly due to the bridge facility, which we closed in December 2007 for our acquisition of Le Nordais.

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) as at March 31, 2008 were $414,317,000 compared to $414,756,000 as at December 31, 2007. The decrease was due to regular repayments on certain credit facilities.

Amortization Expense

Amortization expense increased 58% in Q1 2008 to $5,029,000 from $3,192,000 in Q1 2007 due to the addition of Soderglen in March 2007 and Le Nordais in December 2007. Our wind plants are amortized on a straight-line basis over a 30 year period, except Le Nordais which is amortized over 26 years, and our biomass and hydroelectric plants are amortized on a straight-line basis over a 40 year period.

Administration Expense

Administration expense increased 14% in Q1 2008 to $1,813,000 from $1,586,000 in Q1 2007, due to moderately higher salary costs with the addition of new employees and increased stock compensation expense due to a greater number of options vesting in the quarter compared to the prior year. Capitalized administration costs associated with construction-in-progress and prospect development costs in Q1 2008 were $411,000 (Q1 2007 - $610,000) associated with our continued construction and development activity.

Taxes

We do not anticipate paying cash income taxes for several years, other than in respect of the Cowley Ridge Wind Plant, through its wholly owned subsidiary, Cowley Ridge Wind Power Inc. Cowley Ridge Wind Power Inc. is fully taxable, but is entitled to recover approximately 175% of cash taxes paid annually (limited to 15% of eligible gross revenue) in accordance with the Revenue Rebate Regulation of the Alberta Small Power Research and Development Act. This Regulation will apply until the associated power sale agreements expire in 2013 (9.0 MW) and 2014 (9.9 MW). We are also liable for Provincial Capital Taxes in Ontario, which comprise the majority of the current tax provision. Ontario Capital Tax will be eliminated effective January 1, 2009.

Future income tax expense was $782,000 in Q1 2008 (Q1 2007 - $613,000). The increase in Q1 2008 is due to higher earnings before taxes, offset partially by lower future tax rates as compared to the prior year.

EBITDA, Cash Flow from Operations, and Net Earnings

EBITDA

In Q1 2008, EBITDA of $12,699,000 increased 49% compared to $8,537,000 in Q1 2007 due to our addition of Soderglen and Le Nordais. On a $/MWh basis, EBITDA increased in Q1 2008 compared to the prior year, due to the benefit to EBITDA from our newly acquired Le Nordais, and the benefit of a full windy season at Soderglen, which was only partially included in Q1 2007.

Cash Flow from Operations

Cash flow from operations in Q1 2008 of $8,342,000 improved both on an absolute and per MWh basis over Q1 2007 at $5,145,000 due to the same factors as discussed above with respect to EBITDA, offset partially by increased interest expense. On a $/MWh basis, cash flow increased in Q1 2008 compared to the prior year due to increased generation revenues and lower operating expenses. On a per share basis, cash flow increased 50% in Q1 2008 to $0.06 per share from $0.04 in Q1 2007. This was a result of the factors discussed above, offset partially by additional shares issued through our bought-deal equity financing completed in December 2007 and the exercise of the over allotment option in January 2008.

Net Earnings

Net earnings, on an absolute basis, increased 100% in Q1 2008 to $1,809,000 compared to $905,000 in Q1 2007 due to the same factors as discussed above with respect to EBITDA and cash flow from operations. On a per share basis, these absolute increases were offset by additional shares outstanding due to the bought deal equity financing completed in December 2007, and the exercise of the over allotment option in January 2008, resulting in earnings per share of $0.01 in Q1 2008 and Q1 2007. On a $/MWh basis, net earnings increased 40% to $7/MWh in Q1 2008 from $5/MWh in Q1 2007 as a result of the factors discussed above with respect to EBITDA.

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 benefits of the financings have not yet been reflected in our net earnings or cash flow from operations.



Property, Plant, and Equipment Additions and Prospect Development Costs

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(in thousands of dollars) Q1 2008 Q1 2007 Change
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Property, plant, and equipment
additions 4,442 6,861 - 35%
Prospect development cost additions 12,150 3,601 + 237%
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Property, plant, and equipment additions relate mainly to costs for Melancthon II, which is currently under construction. Additions of prospect development costs relate primarily to equipment deposits and expenditures for the Wolfe Island Wind Project ("Wolfe Island"), the B.C. projects, and the Dunvegan Hydroelectric Prospect ("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 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.

In early 2007, we embarked upon a significant expansion plan to triple our generating capacity by the end of 2010. The following table 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.



----------------------------------------------------------------------------
As at March 31,
(in thousands of dollars except where noted) 2008
----------------------------------------------------------------------------
Capital expenditure plans through 2012 1,234,120
Spent to date (304,743)
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Remaining capital expenditures to be financed 929,377
Financed/to be financed by:
Melancthon II and Blue River Construction Facilities 203,500
Working capital surplus(1) 20,993
Anticipated construction facilities 569,200
Undrawn & available revolving operating credit facility 41,696
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Difference (93,988)
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(1) Excluding derivative financial instrument asset and bridge facility


The difference is expected to be funded through cash flow from operations.

Our current capital expenditure plans are for: Melancthon II, Wolfe Island, Island Falls, Royal Road, Blue River, English Creek, St. Valentin, and New Richmond projects which are either in or nearing construction. 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 are 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. With the addition Royal Road St. Valentin, and New Richmond, we will require additional equity, as shown in the previous table. Depending on the timing of expenditures, we plan to fund this capital requirement through cash flow from operations.

In December 2007, we closed a public offering of common shares on a bought-deal basis 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 will be used for general corporate purposes.

As at March 31, 2008, we had a 46/54 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

Project Updates

Ontario

We now have all approvals, permits and financing in place to complete the $285 million Melancthon II Wind Project, which is anticipated to be operational no later than November 2008. We have completed all access roads and turbine foundations in one of the two townships where the plant is located representing 66 of the 88 turbines. We have received all major permits and approvals to proceed to construction in the second township (with the remaining 22 turbines).

At Wolfe Island, we have completed all approvals for construction with the exception of the environmental approvals process, which is anticipated to be completed by June 2008. We have received a positive decision from the Director of the Ministry of Environment with respect to our provincial environmental approvals and we are currently awaiting the Minister's final review of the Director's decision. We are in the process of completing the construction financing for this project, which is anticipated to close in June 2008.

We continue to work through the approvals process for the $71 million ($35.5 million net to our interest) Island Falls Hydroelectric Project and the $40 million Royal Road Wind Projects in Ontario. The projects are targeted for completion by October 2009, and August 2010, respectively. Construction will commence once approvals and debt financing are in place. Wind turbines and related equipment have been ordered for the Royal Road Wind Projects, consisting of 12, 1.5 MW GE turbines for these 2, 9 MW projects.

British Columbia

Approvals and financing are complete for the $49 million Bone and $27 million Clemina Creek Hydroelectric Projects, and construction will commence this summer. The $22 million Serpentine and $10 million English Creek Hydroelectric Projects are nearly through the approvals process and construction is expected to follow shortly thereafter. All B.C. hydroelectric projects are anticipated to be operational by the fourth quarter of 2009.

Alberta

We continue to pursue the development of Dunvegan. In January 2008, we participated in a joint pre-hearing with the Alberta Utilities Commission (AUC) and Natural Resources and Conservation Board (NRCB) and a final hearing was scheduled for April 22, 2008. However, in March, the federal government elevated our project to a Comprehensive Review or a full panel. We now anticipate a joint hearing with the federal government, the AUC, and the NRCB for the approval of construction and operation in 2008. Regulatory approvals, long-term power sale contracts and financing are required, prior to construction commencing.

Long-Term Sales Contracts

Quebec

On May 5, 2008, we were awarded two, 20 year Electricity Supply Contracts ("PPAs") from Hydro-Quebec Distribution ("HQD") for our 50 MW St. Valentin ("St. Valentin") and our 66 MW New Richmond ("New Richmond") Wind Prospects through our Venterre joint venture. St. Valentin is expected to generate 143,900 MWh per year of power and will consist of 25, 2 MW E82 Enercon wind turbines at an estimated capital cost of $160 million, including capitalized interest. Approximately 72% of the capital cost is fixed, including a turbine supply agreement. New Richmond is expected to generate 178,700 MWh per year of power and will consist of 33, 2 MW E82 Enercon wind turbines, at an estimated capital cost of $190 million, including capitalized interest. Approximately 79% of the capital cost is fixed, including a turbine supply agreement.

The target internal rate of return for both of these projects on a pre-tax, unlevered basis is 11%. This clearly demonstrates that we can compete in an increasingly competitive marketplace without sacrificing returns. The target in service date of both projects is December 2012, and is subject to regulatory approvals, including approval from Le Regie de L'Energie, and financing. Under the terms of the Venterre joint venture agreement, TCI Renewables Limited is the developer of the project and will continue to be the public interface for permits and approvals for the projects and, as 100% owners, we will build and operate the projects. The financial terms of the joint venture are confidential.

As part of the PPA award for New Richmond, we have agreed with HQD not to proceed with the up to 70 MW expansion of Le Nordais ("Le Nordais Expansion") at this time. Due to transmission line congestion in the Gaspe Peninsula, we were given the choice to either continue on with Le Nordais Expansion, or to accept the New Richmond PPA. Based on our analysis, we determined that it was most prudent to proceed with New Richmond. Should transmission upgrades occur, we may re-visit Le Nordais Expansion at a future date.

B.C and Ontario

We expect to bid at least 55 MW of our 260 MW of B.C. hydroelectric prospects into BC Hydro's planned call for power in the spring of 2008. In addition, we plan to submit a 70 MW wind prospect into the Ontario Power Authority's request for up to 500 MW of renewable energy supply, expected to be announced in the near term.

New Business

The solar energy market is one which we continue to monitor and assess on a regular basis. As a result of the Ontario Power Authority's Standard Offer Contract ("SOC") for solar energy projects offering a significant premium over existing prices ($420/MWh), combined with improving costs in the photovoltaic cell market, we have begun to review the economics of a solar project. As a result of these factors, we have entered into an SOC for a 10 MW solar project, 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 with little risk of doing so. 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

Financial Position

The following chart outlines significant changes in the consolidated balance
sheet from December 31, 2007 to March 31, 2008:
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Increase
(Decrease) Explanation
$
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Property, plant, and (1,008) The decrease is due to increased
equipment amortization in the quarter,
as a result of a full quarter of
depreciation for Le Nordais,
offset slightly by expenditures for
Melancthon II.

Prospect development 8,983 The increase is due to
expenditures at Wolfe Island
and the costs B.C. Hydro projects.

Derivative financial 4,101 The increase in the value of
instrument the derivative financial
asset / liability instruments was due to changes in the
Canadian Dollar - Euro foreign
exchange rates, resulting in
an increased fair value of our
foreign exchange contracts
which qualify for hedge
accounting. In addition, the fair
value of our contracts for differences
("CFDs") increased, due to
changes in the forward price
of the power pool.

Share capital 6,334 The increase is due to the
exercise of the over allotment option
of the December 2007 private
placement, as well as the
issuance of shares from the
exercise of stock options.


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 the Company's disclosure controls and internal controls over financial reporting since year end. Based on this evaluation, we have concluded that the design of these controls and procedures continues to be appropriate.

Accounting Changes

Effective January 1, 2008, the Company 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 period ended March 31, 2008.



Outstanding Share Data
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As at May 15, 2008
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 143,378,723
Convertible securities:
Warrants 4,110,900
Options 5,621,250
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Fully diluted common shares 153,110,873
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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 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, cash flow from operations, cash flow from operations per share (diluted), MWh and other per share amounts. All references to cash flow from operations related 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,
2008 2007
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ASSETS
Current assets
Cash and cash equivalents 22,791 22,785
Accounts receivable 12,238 11,897
Derivative financial instrument asset (Note 8) 3,502 -
Prepaid expenses 929 568
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39,460 35,250


Property, plant, and equipment (Note 3) 796,379 797,387
Prospect development costs (Note 4) 126,260 117,277
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TOTAL ASSETS 962,099 949,914
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LIABILITIES
Current liabilities
Bridge facility (Note 6) 72,300 72,300
Accounts payable and accrued liabilities 12,112 12,084
Current portion of credit facilities (Note 6) 2,853 2,825
Derivative financial instrument liability (Note 8) 1,104 1,703
Taxes payable - 304
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88,369 89,216


Credit facilities (Note 6) 339,164 339,631
Future income taxes 39,805 39,091
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467,338 467,938
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Commitments and contingencies (Note 12)

SHAREHOLDERS' EQUITY
Share capital and warrants (Note 7) 454,365 448,031
Contributed surplus (Note 7) 4,840 4,299
Retained earnings 33,158 31,349
Accumulated other comprehensive income (Note 5) 2,398 (1,703)
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494,761 481,976

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TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 962,099 949,914
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See accompanying Notes to the Consolidated Financial Statements


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

3 months ended March 31 2008 2007
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Revenue
Electric energy sales 19,275 14,579
Revenue rebate 186 159
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19,461 14,738
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Expenses (income)
Operating 5,150 4,888
Amortization 5,029 3,192
Interest on credit facilities 4,424 3,637
Administration 1,813 1,586
Stock based compensation 722 478
Foreign exchange gain (201) (10)
Interest income (205) (457)
Gain on derivative financial instrument - (306)
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16,732 13,008
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Earnings before taxes 2,729 1,730
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Tax expense
Current 138 212
Future 782 613
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920 825
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Net earnings 1,809 905

Retained earnings, beginning of period 31,349 22,888

Transitional adjustment (see Note 8) - 118
----------------------------------------------------------------------------
Adjusted retained earnings, beginning of period 31,349 23,006
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Retained earnings, end of period 33,158 23,911
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Earnings per share (Note 10)
Basic 0.01 0.01
Diluted 0.01 0.01

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

3 months ended March 31 2008 2007
----------------------------------------------------------------------------
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Net earnings 1,809 905

Other comprehensive income (see Note 5):
Unrealized gain on derivative financial instrument
currency hedges 3,982 3,053
Unrealized gain (loss) on derivative financial
instrument contracts for differences 119 (1,018)
Amortization of deferred credit - (43)
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Other comprehensive income 4,101 1,992

Comprehensive income 5,910 2,897
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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 2008 2007
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OPERATING ACTIVITIES
Net earnings 1,809 905
Adjustments for:
Amortization 5,029 3,192
Stock based compensation 722 478
Future income tax expense 782 613
Gain on derivative financial instrument - (43)
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Cash flow from operations before changes in non-cash
working capital 8,342 5,145
Changes in non-cash working capital 2,610 5,885
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10,952 11,030
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FINANCING ACTIVITIES
Issue of common shares, net of issue costs (Note 7) 6,084 (63)
Credit facility repayments (439) (483)
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5,645 (546)
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INVESTING ACTIVITIES
Property, plant, and equipment additions (4,441) (6,861)
Prospect development costs (12,150) (3,601)
Working capital deficit acquired on acquisition - (13,423)
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(16,591) (23,885)
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 6 (13,401)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 22,785 61,669
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CASH AND CASH EQUIVALENTS, END OF PERIOD 22,791 48,268
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Supplemental information
Cash interest paid 4,528 3,387
Cash income and capital taxes paid - 182

See accompanying Notes to the Consolidated Financial Statements

CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 expects interim results for the second and fourth quarters to be higher than those for the first and third quarters of 2008.

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 depreciation are as follows:



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

Generating plants
- operating 639,450 58,730 580,720 585,359
- construction-in-progress 212,478 - 212,478 208,886
Vehicles 1,566 1,113 453 472
Equipment, other 4,517 1,789 2,728 2,670
---------------------------------------------
858,011 61,632 796,379 797,387
---------------------------------------------
---------------------------------------------


For the 3 months ended March 31, 2008, interest costs of $302,000 (3 months ended March 31, 2007 - $559,000) and administration expenses of $46,000 (3 months ended March 31, 2007 - $185,000) associated with the construction-in-progress have been capitalized during construction. In both 2008 and 2007, construction-in-progress relates to costs associated with the construction of the Melancthon II Wind Project.

4. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:



March 31, December 31,
2008 2007
$ $
-------------------------
Wind prospects 100,031 94,344
Hydroelectric and other prospects 16,772 14,184
Dunvegan Hydroelectric Prospect 9,457 8,749
-------------------------

Total 126,260 117,277
-------------------------
-------------------------


Interest costs of $953,000 (March 31, 2007 - $391,000) and administration expenses of $365,000 (March 31, 2007 - $425,000) associated with prospect development costs have been capitalized for projects leading up to construction. Included in wind prospects are $77,828,000 (December 31, 2007 - $71,702,000) in costs with respect to the Wolfe Island Wind Project ("Wolfe Island"). The remaining 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 $2,839,000 (December 31, 2007 - $2,672,000) in costs related to the development of the Island Falls Hydroelectric Project and $10,097,000 (December 31, 2007 - $9,267,000) in costs related to the development of 43.6 MW of run-of-river hydroelectric projects in B.C.

The Company continues to pursue the development of the Dunvegan Hydroelectric Prospect. The Company anticipates a hearing and regulatory decision for approval of construction and operation in 2008. 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.



5. ACCUMULATED OTHER COMPREHENSIVE INCOME ("AOCI")

AOCI, including transition amounts, is comprised of the following:

$
--------
Balance, December 31, 2007 (1,703)
Unrealized gain on derivative financial instrument foreign
currency hedges 3,982
Unrealized gain on derivative financial instrument contracts
for differences 119
--------
Accumulated other comprehensive income, March 31, 2008 2,398
--------
--------


6. CREDIT FACILITIES

March 31, 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 5.69%,
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 5.77%,
12-year term with interest payable semi annually and
no principal repayments until maturity on June 19,
2018, senior unsecured 121,000 121,000

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

Le Nordais Bridge Facility, interest at the Bankers'
Acceptances rate plus a stamping fee of 0.85% per
annum, unsecured non-revolving credit facility
maturing on June 12, 2008, unless extended for
additional six-month term to December 12, 2008, at
the Company's option, upon payment of an extension fee 72,300 72,300

Construction Facility, bearing interest at Bankers'
Acceptances plus a stamping fee of 0.70% per annum,
unsecured non-revolving credit facility with an
18-month drawdown period, followed by a two-year
non-amortizing term out period 30,000 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 6,186 6,379

Mortgage, bearing interest at 10.7% and secured by
letter of guarantee. Monthly repayments of principal
and interest are $84,000 until May 31, 2010 1,957 2,140

Mortgage, bearing interest at 10.68%, secured by
letters of guarantee. Monthly repayments of principal
are $31,000 plus interest until December 30, 2012 1,781 1,875

Promissory note, bearing interest fixed at 6%, secured
by a second fixed charge on three of the Alberta
hydroelectric plants. Monthly repayments of principal
and interest are $19,000 until August 1, 2012 901 930

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

Deferred financing costs (2,486) (2,546)
----------------------
414,317 414,756
Less: Bridge facility (72,300) (72,300)
Less: Current portion of credit facilities (2,853) (2,825)
----------------------

Credit facilities 339,164 339,631
----------------------
----------------------


The Company has a revolving Operating Facility with its banking syndicate for a total of $65,000,000. As at March 31, 2008, the Company had no debt outstanding on this facility other than letters of credit in the amount of $23,304,000 (December 31, 2007 - $22,174,000) outstanding relating primarily to construction activities and security required under long-term sales contracts for electricity.



7. SHARE CAPITAL AND WARRANTS

(a) Common shares and warrants:

Number of Amount
Shares $
--------------------------
Balance, common shares, December 31, 2007 141,834,973 444,064
Balance, warrants, December, 31 2007 (Note 7(b)) - 3,967
Issue of common shares 880,000 5,500
Share issue costs, net of tax effect of $69 - (195)
Issued on exercise of stock options 663,750 848
Stock compensation on options exercised - 181
--------------------------
Balance, March 31, 2008 143,378,723 454,365
--------------------------
--------------------------


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 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.



(b) Warrants:

Number of Amount
Warrants $
--------------------------
Balance, December 31, 2007 and March 31, 2008 4,110,900 3,967
--------------------------
--------------------------


The warrants issued have an exercise price of $7.00, and expire on March 8, 2009. These warrants have been allocated a fair value of $3,967,000, which was calculated using the Black-Scholes pricing model.

(c) Stock compensation:

Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $722,000 for Q1 2008 (Q1 2007 - $478,000) of compensation expense in the consolidated statement of earnings, with a corresponding increase recorded to contributed surplus in the consolidated balance sheet as at March 31, 2008. The Company issued 55,000 options in Q1 2008 (Q1 2007 - 365,000). The weighted average fair value of options granted during Q1 2008 was $1.58 per share (Q1 2007 - $1.99 per share), which was estimated using the Black-Scholes option-pricing model, assuming a risk free interest rate of 3.51% (Q1 2007 - 3.95%), expected volatility of 28.26% (Q1 2007 - 32.99%), expected weighted average life of 4.0 years (Q1 2007 - 4.0 years), no annual dividends paid, and vesting 25% per year, over 4 years.



(d) Contributed surplus:

March 31, March 31,
2008 2007
--------------------------------

Balance, beginning of the period 4,299 2,186
Stock based compensation 722 478
Stock compensation on options exercised (181) (10)
--------------------------------

Balance, end of period 4,840 2,654
--------------------------------
--------------------------------


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 periodical 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 March 31, 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, a construction facility, a bridge facility, 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 amount of Euro purchases is 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 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 March 31, 2008 was $3,502,000.

The Company has entered into various Contracts for Differences ("CFDs") with other parties whereby the other parties have agreed to pay a fixed price 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 March 31, 2008, the fair value of the derivative liability was $1,104,000.

As at March 31, 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 March 31, 2008 the aging of the Company's receivables is as follows:



March 31, 2008
----------------
Current receivables 11,544
Receivables greater than 60 - 120 days 694
Receivables greater than 120 days -
----------------
12,238
Less: Impairment allowance -
----------------
Receivables, end of period 12,238
----------------
----------------


The Company manages its credit risk by entering into sales agreements with credit worthy parties and through regular review of accounts receivable. 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, 2008. 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 and CFDs, which are impacted by changes in the Canadian Dollar - Euro exchange rate, and the forward price of electricity in Alberta, 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 March 31, 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 $1,001,000 impact to Accumulated Other Comprehensive Income ("AOCI"), and a 1% change in the forward electricity prices would result in a $20,000 impact to AOCI. This risk management strategy is unchanged from the prior year.

As disclosed in Note 6, the Company has two credit facilities which have variable interest rate risks, the Le Nordais Bridge Facility and the Construction Facility. Both of these facilities have interest rates based on the Bankers' Acceptance rate, plus a stamping fee of 0.85% and 0.70% per annum, respectively. Due to these variable rates, the Company is exposed to an interest rate risk. A 1% increase, on an absolute basis, in the Bankers' Acceptance rate would result in additional interest expense, on an annual basis, of approximately $100,000. The Company 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.

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's current debt/equity mixture is calculated as follows:



March 31, December 31,
2008 2007
$ $
-------------------------
Total debt, including bridge facility and
current portion of credit facilities 414,317 414,756
Shareholders' equity 494,761 481,976
-------------------------
Total debt and equity 909,078 896,732

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


Changes from December 31, 2007 relate primarily to 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 March 31, 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 March 31:

2008 2007
----------------------------
Basic weighted average shares outstanding 142,001,305 122,825,224
Effect of dilutive securities:
Options 2,048,281 2,743,993
----------------------------

Diluted weighted average shares outstanding 144,049,586 125,569,217
----------------------------
----------------------------


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 operating income, which is defined as revenue, less operating expenses.



Wind Hydro Biomass Total
$ $ $ $
---------------------------------------
Revenue 13,755 3,417 2,289 19,461
Operating expenses 2,481 744 1,925 5,150
---------------------------------------
Operating income 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:

2008
$
---------
Additions to operating plants above 696
Additions to property, plant and equipment relating to construction
in process and general corporate assets 3,324
---------
Total additions to property, plant, and equipment 4,020
---------
Net book value of operating plants 580,720
Net book value of property, plant and equipment relating to
construction in process and general corporate assets 215,659
---------
Total net book value of property, plant, and equipment 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, 2008, the Company has committed approximately $290,459,000 for goods and services for Melancthon II, Wolfe Island, Royal Road, and the B.C. projects, which will be expended between 2008 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 June 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 July 1, 2008. The Company is currently amending the Lease to extend this date. The repairs are estimated to cost $4,000,000, of which $1,381,000 has been spent as at March 31, 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.

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

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