Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

August 14, 2007 12:07 ET

Canadian Hydro Announces Second Quarter Results

CALGARY, ALBERTA--(Marketwire - Aug. 14, 2007) - Canadian Hydro Developers, Inc. (TSX:KHD) ("Canadian Hydro" or the "Company") reported cash flow from operations2 of $7,762,000 ($0.06 per share, diluted3) on generation of 271 million kWh for the second quarter ended June 30, 2007 ("Q2 2007"), compared to cash flow from operations2 of $8,034,000 ($0.07 per share, diluted3) on generation of 222 million kWh for Q2 2006. The Company reported net earnings of $1,771,000 ($0.01 per share, diluted) for Q2 2007, compared to net earnings of $5,712,000 ($0.05 per share, diluted) for Q2 2006.

Cash flow from operations2 for the 6 months ended June 30, 2007 increased to $12,907,000 ($0.10 per share, diluted(3) on generation of 472 million kWh, compared to $10,121,000 ($0.08 per share, diluted(3) on generation of 349 million kWh for the same period in 2006. Net earnings for the 6 months ended June 30, 2007 were $2,676,000 ($0.02 per share, diluted(3), compared to $5,276,000 ($0.04 per share, diluted3) for the same period in 2006.

The addition of the Soderglen Wind Plant, improved operating results from the Grande Prairie EcoPower® Centre and higher wind generation in Ontario resulted in improved operating results in Q2 2007. However, higher current and future taxes resulted in lower net earnings compared to the prior year. The future tax recovery in the prior year was unusually high due to changes in corporate tax rates enacted in Q2 2006.

 

----------------------------------------------------------------------------
3 Months Ended 6 Months Ended
June 30, June 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Financial Results (in thousands of
dollars except per share amounts)
Revenue 17,277 14,457 32,015 23,399
EBITDA(1) 12,216 9,902 20,753 13,669
Cash flow from operations(2) 7,762 8,034 12,907 10,121
Per share (diluted)(3) 0.06 0.07 0.10 0.08
Net earnings 1,771 5,712 2,676 5,276
Per share (diluted) 0.01 0.05 0.02 0.04

Operating Results
Electricity generation - MWh (net) 271,429 222,445 471,727 349,309
Average price received per MWh ($) 64 65 68 67
Electrical generation under contract (%) 80 91 80 90
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(1) EBITDA is provided to assist management and investors in determining the
ability of the Company to generate cash from operations(2). EBITDA as
presented is defined as cash flow from operations(2), plus interest on
debt (net of interest income) and current tax expense. This measure does
not have any meaning prescribed in Canadian generally accepted
accounting principles ("GAAP") and may not be comparable to similar
measures presented by other companies.
(2) Cash flow from operations before changes in non-cash working capital.
(3) Cash flow from operations(2) per share (diluted) is provided to assist
management and investors in determining the Company's cash flow from
operations(2) on a per share basis and does not have any meaning
prescribed in GAAP and may not be comparable to similar measures
presented by other companies.


Q2 2007 Achievements:

- Received a final decision from the Ontario Minister of the Environment regarding the Melancthon II Wind Project's ("Melancthon II") Environmental Assessment, which allowed the Company to submit the Statement of Completion and proceed with the project, subject to any other permits or approvals;

- Signed a Standard Offer Contract with the Ontario Power Authority for the 3.2 MW Misema Hydrolectric Plant, under which the Company will receive $110 per MWh for power generated at Misema, increasing to $145 per MWh during on-peak hours until May 2027;

- Readied wind prospects for bids into Manitoba Hydro's call for wind power, and submitted 3 bids for projects between 99 MW and 300 MW in size; and

- Obtained all necessary permits and approvals to proceed to construction with the Bone Creek and Clemina Creek Hydroelectric Projects ("Bone Creek" and "Clemina Creek"), which are expected to start later this summer.

"The positive decisions in Ontario with respect to the Company's Environmental Assessment process for Melancthon II marks a major milestone for Canadian Hydro," said John Keating, CEO. "With the Ontario Municipal Board Hearing complete for the Melancthon Township, and the Amaranth Township Hearing scheduled for September, we anticipate commencing construction late this fall. We've also received all necessary permits and approvals for Bone and Clemina Creek, gearing up for construction late this summer."

Canadian Hydro is a developer, owner and operator of 19 power generation facilities totalling net 265 MW of capacity in operation and has an additional 385 MW nearing construction. The renewable generation portfolio is diversified across three technologies (water, wind and biomass) in the provinces of British Columbia, Alberta and Ontario. This portfolio is unique in Canada as all facilities are certified, or slated for certification, under Environment Canada's EcoLogoM Program.

Canadian Hydro is passionate about meeting the goals of investors and the needs of the environment. As industry leaders, Canadian Hydro is focused on building a sustainable future for Canada and with over 17 years experience, Canadian Hydro is a working model for the unlimited development potential of low-impact renewable energy.

Common shares outstanding: 132,853,723

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

The following MD&A, dated August 3, 2007, should be read in conjunction with the unaudited interim consolidated financial statements as at and for the 3 and 6 months ended June 30, 2007 and 2006, and should also be read in conjunction with the audited consolidated financial statements and MD&A included in the Annual Report as at and for the year ended December 31, 2006. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). All tabular amounts in the following MD&A are in thousands of Canadian dollars unless otherwise noted. Additional information respecting the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

Forward-Looking Statements

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

Revenue

For Q2 2007, revenue increased 20% to $17,277,000 on generation of 271 million kWh compared to $14,457,000 on generation of 222 million kWh in Q2 2006. For the 6 months ended June 30, 2007, revenue increased 37% to $32,015,000 on increased generation of 472 million kWh compared to $23,399,000 on generation of 349 million kWh for the same period in 2006. For Q2 2007, the increase in revenue was due to a full quarter of operations at the 70.5 MW (35.25 MW, net) Soderglen Wind Plant ("Soderglen"), which was acquired on March 8, 2007, in addition to improved operations at the Grande Prairie EcoPower® Centre ("GPEC"), and windier conditions at the Melancthon I Wind Plant ("Melancthon I"). Generation at the remaining plants was consistent with Q2 2006.

For the 6 months ended June 30, 2007, the increase in revenue was due to the increase in generation as a result of the addition of Soderglen, as discussed above, a full 6 months of operations at Melancthon I, which became operational on March 4, 2006, improved operations at GPEC and windier conditions in Alberta. Hydroelectric generation was consistent with the prior year.

Approximately 80% of the Company's generation was sold pursuant to long-term sales contracts in Q2 2007 and the 6 months ended June 30, 2007 (Q2 2006 - 91%; 2006 - 90%). The average price received by the Company for electricity from all operations for Q2 2007 was $64/MWh (Q2 2006 - $65/MWh) and $68/MWh for the 6 months ended June 30, 2007 (2006 - $67/MWh).



Electricity Generation - by Province and Technology

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Electricity Generation - MWh(1)
Q2 2007 Q2 2006 Variance 2007 2006 Variance
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British Columbia 94,627 96,176 - 2% 123,832 115,053 + 8%
Alberta 112,789 68,413 + 65% 198,591 141,125 + 41%
Ontario 64,013 57,856 + 11% 149,304 93,131 + 60%
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Totals 271,429 222,445 + 22% 471,727 349,309 + 35%
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Hydroelectric 141,559 142,081 -% 196,459 189,937 + 4%
Wind 95,202 62,117 + 53% 212,556 115,431 + 84%
Biomass 34,668 18,247 + 90% 62,712 43,941 + 43%
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Totals 271,429 222,445 + 22% 471,727 349,309 + 35%
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(1) Reflecting the Company's net interest.

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Electricity Generation for Same Plants - MWh(1,2)
Q2 2007 Q2 2006 Variance 2007 2006 Variance
----------------------------------------------------------------------------
Hydroelectric 141,559 142,081 -% 196,459 189,937 + 4%
Wind 68,532 62,117 + 10% 174,398 115,431 + 51%
Biomass 34,668 18,247 + 90% 62,712 43,941 + 43%
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Totals 244,759 222,445 + 10% 433,569 349,309 + 24%
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(1) Reflecting the Company's net interest.
(2) Wind generation for 2006 includes Melancthon I, which became operational
on March 4, 2006 and generated 47,320 MWh in 2006.

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Electricity Generation for New Plants - MWh(1)
Q2 2007 2007
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Soderglen 26,670 38,158
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Total - new 26,670 38,158
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(1) Reflecting the Company's net interest.


Operating Expenses

Operating expenses increased 29% to $5,077,000 in Q2 2007 compared to $3,941,000 in Q2 2006. For the 6 months ended June 30, 2007, operating expenses increased 21% to $9,965,000 from $8,255,000 for the same period in 2006. The increase in operating expenses was due primarily to the addition of Soderglen and for the 6 months ended June 30, 2007, a full period of operations at Melancthon I. Gross margins (revenue less operating expenses; expressed as a percentage of revenue) of 71% for Q2 2007 were lower than the same quarter in the prior year (Q2 2006 - 73%), mainly due to slightly lower gross margins at Soderglen compared to the Company's other wind plants. Gross margins for the 6 months ended June 30, 2007 were higher at 69% compared to 65% for the same period in 2006. For the 6 months ended June 30, 2007, gross margins improved due to improved operations over the prior year at GPEC.

Interest on Long-Term Debt, Long-Term Debt and Interest Income

Interest on long-term debt (excluding capitalized interest) in Q2 2007 increased 31% to $3,728,000 compared to $2,837,000 in Q2 2006 and for the 6 months ended June 30, 2007, increased 34% to $7,365,000 from $5,489,000 for the same period in 2006. The increase is due to higher outstanding corporate debt, mainly due to the issuance of the unsecured Series 2 and Series 3 corporate debentures in June 2006.

Interest income from the investment of cash on hand in term deposits decreased 83% to $179,000 in Q2 2007 compared to $1,069,000 in Q2 2006. For the 6 months ended June 30, 2007, interest income decreased 73% to $636,000 compared to $2,384,000 for the same period in 2006.

Capitalized interest associated with construction-in-progress and development prospects in Q2 2007 was $950,000 (Q2 2006 - $214,000) and $1,899,000 for the 6 months ended June 30, 2007 (2006 - $640,000). The increase was due to projects with higher costs under or nearing construction compared to the prior year (Q2 2007 and 2007 - the Melancthon II Wind Project ("Melancthon II") and the Wolfe Island Wind Project ("Wolfe Island"); Q2 2006 - Melancthon II; 2006 - Melancthon I and Melancthon II).

Long-term debt (including current portion) as at June 30, 2007 was $312,686,000 (June 30, 2006 - $317,265,000) compared to $316,327,000 as at December 31, 2006. The decrease was due to the reclassification of deferred financing costs to long-term debt (see Note 6 to the interim consolidated financial statements) as well as regular repayments on the long-term debt during the quarter.

As at June 30, 2007, the Company had a 43/57 debt/equity mixture (December 31, 2006 - 48/52) compared to a stated target of 65/35. The debt/equity mixture has changed from the prior year due to the equity issued for the GW acquisition on March 8, 2007.

Amortization Expense

Amortization expense increased 31% to $3,989,000 for Q2 2007 (Q2 2006 - $3,057,000), and 33% to $7,181,000 for the 6 months ended June 30, 2007 (2006 - $5,388,000) due to the addition of Melancthon I in March 2006 and Soderglen in March 2007. These wind plants are amortized over a 30 year period.

Administration Expense

Administration expense increased 27% to $1,249,000 in Q2 2007 compared to $987,000 in Q2 2006. For the 6 months ended June 30, 2007, administration expense increased 43% to $3,313,000 compared to $2,315,000 for the same period in the prior year. The increase in Q2 2007 and 2007 was due to moderately higher salary costs with the addition of new employees and increased stock compensation expense due to a higher fair value for options granted compared to the prior year. For Q2 2007, this increase was partially offset by certain bonuses paid in Q1 2007, which were paid in the second quarter in the prior year. Capitalized administration costs associated with construction-in-progress and prospect development costs in Q2 2007 were $1,594,000 (Q2 2006 - $773,000) and $2,204,000 for the 6 months ended June 30, 2007 (2006 - $1,965,000).

Financial Instruments

Effective January 1, 2007, the Company must recognize unrealized gains and losses on certain derivative financial instruments through the Consolidated Statement of Other Comprehensive Income ("OCI"). See Notes 2(b) and 6 to the Consolidated Interim Financial Statements for the impact of financial instruments on the balance sheet and OCI.

Taxes

The Company does not anticipate paying cash income taxes for several years, other than in respect of the Cowley Ridge Wind Plant, through its wholly owned subsidiary, Cowley Ridge Wind Power Inc. On May 2, 2006, the Federal Government passed a budget that eliminated the Federal Government Tax on Large Corporations ("LCT") effective January 1, 2006. The Company is, however, liable for Provincial Capital Taxes in Ontario, which comprise the majority of the current tax provision. The Provincial Capital Taxes in Ontario in 2007 have increased significantly as the result of the Company's capital build program in Ontario, including Melancthon I, Melancthon II, Wolfe Island and Island Falls.

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

Future income tax expense was $1,484,000 in Q2 2007 (Q2 2006 - future tax recovery of $1,040,000), and $2,097,000 for the 6 months ended June 30, 2007 (2006 - future tax recovery of $1,453,000). The increase, in comparison to the prior year, was mainly due to a future income tax recovery recognized in Q2 2006 as a result of a reduction in the corporate tax rates due to the May 2006 budget, as discussed above.

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

Net earnings were $1,771,000 ($0.01 per share) in Q2 2007 compared to $5,712,000 ($0.05 per share) in Q2 2006. The decrease is a result of higher current and future taxes, interest on long-term debt, operating expenses, amortization and administrative expenses; offset partially by increased contributions from the addition of Soderglen and improved operations at GPEC and a higher foreign exchange gain, as explained above.

For the 6 months ended June 30, 2007, net earnings were $2,676,000 ($0.02 per share) compared to $5,276,000 ($0.04 per share) for the same period in the prior year. The decrease was due to the same factors as discussed above as well as a full 6 months of operations at Melancthon I. Excluding non-cash items such as future taxes, cash flow from operations was $7,762,000 in Q2 2007 (Q2 2006 - $8,034,000) and $12,907,000 for the 6 months ended June 30, 2007 (2006 - $10,121,000).

Capital Asset Additions and Prospect Development Costs

Capital asset additions, excluding non-cash items, were $4,912,000 in Q2 2007 (Q2 2006 - $66,823,000) and $11,773,000 for the 6 months ended June 30, 2007 (2006 - $90,457,000). These additions relate mainly to costs for Melancthon II, which is currently in the approvals process for commencement of construction. In Q1 2007, the Company also acquired GWP, which owns 50% of Soderglen, through the issuance of shares. As a result, the net book value of capital assets has increased 21% since December 31, 2006. Additions of prospect development costs were $3,538,000 in Q2 2007 (Q2 2006 - $1,680,000) and $7,139,000 for the 6 months ended June 30, 2007 (2006 - $10,370,000), relating primarily to equipment deposits for the Wolfe Island Wind Project ("Wolfe Island"), the B.C. projects and the Dunvegan Hydroelectric Prospect ("Dunvegan").



Financial Position

The following chart outlines significant changes in the consolidated balance
sheet from December 31, 2006 to June 30, 2007:

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Increase Explanation
(Decrease)
$
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Cash (13,036) Decrease mainly due to the assumption of a working
capital deficit from GWP, capital asset additions for
Melancthon II, prospect development costs, long-term
debt repayments and changes in non-cash working
capital; offset partially by cash flow from
operations(2) , and interest income received on cash
invested in term deposits.

Accounts Decrease due to lower interest receivable at June 30,
receivable (3,234) 2007 in comparison to the prior quarter as a result
of less cash on hand invested in term deposits.

Capital Increase due to the acquisition of Soderglen and
assets 112,947 costs incurred for the development of Melancthon II
(see Notes 3 and 4 to the interim consolidated
financial statements).

Deferred Reclassified to long-term debt. Refer to Note 7 to
financing the interim consolidated financial statements.
costs (2,628)


Prospect Increase due to costs incurred on the development of
development Wolfe Island, the B.C. projects, and Dunvegan.
costs 6,898


Derivative Increase due to implementation of new CICA handbook
financial section 3855 . Financial Instruments . Recognition
instrument and Measurement. Represents the aggregate
liability 3,877 unrecognized derivative financial instruments
liability related to the Company's contracts for
differences ("CFDs") and Euro foreign exchange
contracts that qualify for hedge accounting.

Long-term Decrease due to reclassification of deferred
debt financing costs to long-term debt. See Note 7 to the
(including interim consolidated financialstatements.
current
portion) (3,641)


Future Increase due to future tax liability assumed on the
income acquisition of GWP (see Note 3 to the interim
taxes 22,703 consolidated financial statements) and the future tax
liability on the exercise of the Series A Special
Warrants (see Note 8(a)) to the interim consolidated
financial statements).

Share Increase due to the shares and warrants issued for
capital 80,367 the acquisition of GWP (see Note 3 to the interim
consolidated financial statements) and the exercise
of the Series A Special Warrants, in addition to the
issuance of common shares through the exercise of
stock options, net of share issue costs (see Note
8 to the interim consolidated financial statements).


Capital Resources and Liquidity

The Company's current capital expenditure plans total approximately $820,500,000 for the construction of three projects in Ontario and four projects in B.C. from 2007 to 2009. Up to $188,000,000 of the capital costs are being financed from proceeds of the public equity offering completed in 2005, a further $93,850,000 from expected future cash flow to be generated by the Company and potential future equity offerings, and the remaining $538,650,000 through completed and anticipated debt financings.

In Q2 2007, the Company issued 335,000 common shares (Q2 2006 - 21,250) through the exercise of stock options at an average exercise price of $2.22 per share (Q2 2006 - $2.08 per share) for gross proceeds of $743,000 (Q2 2006 - $44,000). For the 6 months ended June 30, 2007, the Company issued 369,000 common shares (2006 - 1,086,150) through the exercise of stock options at an average exercise price of $2.20 per share (2006 - $0.99) for gross proceeds of $812,000 (2006 - $1,073,000). In 2007, the Company also issued 12,332,700 common shares at a value of $72,763,000 and 4,110,900 warrants at a value of $3,967,000 for the acquisition of GWP (see Note 3 to the interim consolidated financial statements).

Disclosure Controls

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

Internal Controls and Procedures

As of the end of the period covered by this quarterly report, the Company has evaluated the design of its internal controls and procedures over financial reporting. Based on this evaluation, the Company has concluded that the design of these internal controls and procedures over financial reporting continue to be appropriate.

Financial Instruments and Hedging Activities

Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") handbook section 3855, "Financial Instruments - Recognition and Measurement," section 3865, "Hedges," section 1530, "Comprehensive Income" and section 3861, "Financial Instruments - Disclosure and Presentation." These standards have been adopted prospectively. See Note 2(b) to the interim consolidated financial statements.

Accounting Changes

Effective January 1, 2007, the Company adopted revised CICA handbook section 1506, "Accounting Changes." The revisions were made to harmonize section 1506 with International Financial Reporting Standards. The changes covered by this section include changes in accounting policy, changes in accounting estimates and correction of errors. Under section 1506, voluntary changes in accounting policy are only permitted if they result in financial statements that provide more reliable and relevant information. When a change in accounting policy is made, this change is applied retrospectively unless impractical. Changes in accounting estimates are generally applied prospectively and material prior period errors are corrected retrospectively. This section also outlines additional disclosure requirements when accounting changes are applied including justification for voluntary changes, complete description of the policy, primary source of GAAP and detailed effect on financial statement line items. Section 1506 is effective for fiscal years beginning on or after January 1, 2007.



Outstanding Share Data

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As at August 3, 2007
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 132,853,723
Convertible securities:
Warrants (see Note 8 (b)) 4,110,900
Options 6,388,750
----------------------------------------------------------------------------
Fully diluted common shares 143,353,373
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Outlook

Reservoir levels where the Company's Alberta hydroelectric plants are located are currently at above normal levels for this time of year. However, water flows to these plants are controlled by Alberta Environment and are dependent on irrigation needs in rural areas downstream. As a result, it is too early to determine whether this will result in average or above average hydroelectric generation in Alberta for Q3 2007.

The extended period of hot weather during the second quarter produced high rates of snowmelt throughout the mountains surrounding the Company's B.C. hydroelectric plants. As a result, snowmelt is largely complete in most areas. Unless there is normal to above normal rainfall in the upcoming months, or average to above average temperatures that effect glacier melt, the Company expects average to below average hydroelectric generation in B.C. for Q3 2007.

Precipitation forecasts in Ontario for Q3 2007 are normal. As a result, the Company expects average hydroelectric generation in Ontario this summer. However, it is too early to determine whether this will result in hydroelectric generation in Ontario being different in 2007 versus 2006.

Alberta Power Pool ("Pool") prices in Q2 2007 ($50/MWh) were lower than Q2 2006 ($54/MWh) due to lower natural gas spot prices and warmer weather in the Northwest region, which impact power prices. Pool prices for the 6 months ended June 30, 2007 ($57/MWh) were slightly higher than Q2 2006 ($55/MWh) due to higher natural gas prices in the beginning of the year. The average Pool price for July 2007 was $156/MWh, compared to $50/MWh for June 2007, and $128/MWh for the month of July 2006.

The Ontario Minister of the Environment (the "Minister") completed her review and upheld the March 9, 2007 decision by the Director of the Environmental Assessment and Approvals Branch. The Director decided that an Individual Environmental Assessment is not required for Melancthon II. Based on this final determination by the Minister, Canadian Hydro has submitted the required Statement of Completion and will proceed with Melancthon II, subject to any other permits or approvals required, including the Ontario Municipal Board's ("OMB") hearing for planning approvals for the Amaranth Township, for which a hearing date has been set for September 11, 2007. The OMB hearing for Melancthon II occurred on July 31, 2007. An Oral Decision was provided by the OMB Board Member conducting the hearing on the portion of Melancthon II located in the Melancthon Township. As a result, the Company expects to receive all of the necessary permits required from the Melancthon Township regarding construction and operation of Melancthon II. The Company continues to analyze the impact, if any, the later than expected OMB hearing dates will have on the project schedule and capital costs and will provide an update following the decision from the OMB hearing for the Amaranth Township.

The Company has received all necessary approvals and permits for its B.C. Bone Creek and Clemina Creek Hydroelectric Projects and will be commencing construction later this summer. The Company anticipates obtaining all necessary approvals and permits for the Serpentine and English Hydroelectric Projects this upcoming winter and spring, respectively. Construction will commence thereafter. These projects were awarded Electricity Purchase Agreements from BC Hydro in August of 2006 and are expected to be operational in Q4 2009.

The Company is currently completing Supplemental Information Requests ("SIR") with respect to Dunvegan in Alberta. Once the SIRs are complete, the Company anticipates that the Alberta Energy and Utilities Board and the Natural Resources Conservation Board will set a hearing date for the approval of design and construction of Dunvegan. The Company anticipates a hearing and regulatory decision for approval of construction and operation early in 2008.

In July 2007, the Company submitted bids for 3 projects into Manitoba Hydro's call for power. Manitoba Hydro is expected to notify participants who have succeeded to the second round of the bid process and are invited to negotiate a power purchase agreement with Manitoba Hydro by September 2007, with potential contracts signed in the spring of 2008.



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

3 months ended June 30, 6 months ended June 30,
2007 2006 2007 2006
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Revenue
Electric energy sales 17,154 14,338 31,733 23,121
Revenue rebate 123 119 282 278
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17,277 14,457 32,015 23,399
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Expenses (Other Income)
Operating 5,077 3,941 9,965 8,255
Interest on long-term
debt (Notes 4 and 5) 3,728 2,837 7,365 5,489
Interest income (179) (1,069) (636) (2,384)
Amortization 3,989 3,057 7,181 5,388
Administration (Notes 4
and 5) 1,249 987 3,313 2,315
(Gain) loss on derivative
financial instrument
(Note 2(b)) (43) (43) (349) 159
Foreign exchange gain (704) (25) (714) (89)
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13,117 9,685 26,125 19,133
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Earnings before taxes 4,160 4,772 5,890 4,266
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Tax (recovery) expense
Current 905 100 1,117 443
Future 1,484 (1,040) 2,097 (1,453)
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2,389 (940) 3,214 (1,010)
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Net earnings 1,771 5,712 2,676 5,276

Retained earnings, beginning
of period 23,793 13,556 22,888 13,992
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Transitional adjustment
(see Note 2(b) and Note 7) 118 - 118 -
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Adjusted retained earnings,
beginning of period 23,911 13,556 23,006 13,992
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Retained earnings, end
of period 25,682 19,268 25,682 19,268
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Earnings per share (Note 8)
Basic 0.01 0.05 0.02 0.04
Diluted 0.01 0.05 0.02 0.04



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

3 months ended June 30, 6 months ended June 30,
2007 2006 2007 2006
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----------------------------------------------------------------------------

Net earnings (loss) 1,771 5,712 2,676 5,276

Other comprehensive income
(see Note 2(b)):
Unrealized loss on
derivative financial
instrument currency
hedges (13,374) - (10,321) -
Unrealized loss on
derivative financial
instrument contracts
for differences (226) - (1,244) -
Reclassification of
deferred credit (43) - (86) -
----------------------------------------------------------------------------
Other comprehensive earnings (13,643) - (11,651) -

Comprehensive (loss) income (11,872) 5,712 (8,975) 5,276
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See accompanying notes to the consolidated financial statements



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

June 30, December 31,
2007 2006
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ASSETS
Current assets
Cash and cash equivalents 48,633 61,669
Accounts receivable 10,296 13,530
Prepaid expenses 1,203 535
Revenue rebate 817 594
Taxes receivable 109 -
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61,058 76,328

Deferred financing costs - 2,628
Capital assets (Note 4) 660,744 547,797
Prospect development costs (Note 5) 67,187 60,289
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TOTAL ASSETS 788,989 687,042
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LIABILITIES
Current liabilities
Accounts payable and accrued liabilities 8,524 9,587
Current portion of long-term debt (Note 7) 2,081 1,996
Derivative financial instrument liability (Note 2(b)) 3,877 -
Taxes payable - 100
Deferred credit (Note 2(b)) - 85
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14,482 11,768

Long-term debt (Note 7) 310,605 314,331
Future income taxes 44,720 22,017
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369,807 348,116
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Commitments and contingencies (Note 10)

SHAREHOLDERS' EQUITY
Share capital (Note 8) 394,219 313,852
Contributed surplus (Note 9) 3,144 2,186
Retained earnings 25,682 22,888
Accumulated other comprehensive (loss)
income (Note 6) (3,863) -
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419,182 338,926
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TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 788,989 687,042
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 June 30, 6 months ended June 30,
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings 1,771 5,712 2,676 5,276
Adjustments for:
Amortization 3,989 3,057 7,181 5,388
Future income tax expense
(recovery) 1,484 (1,040) 2,097 (1,453)
Stock compensation expense
(Note 9) 561 348 1,039 595
(Gain) loss on derivative
financial instrument
(Note 2 (b)) (43) (43) (86) 315
----------------------------------------------------------------------------

Cash flow from operations
before changes in non-cash
working capital 7,762 8,034 12,907 10,121
Changes in non-cash working
capital 832 (1,899) 6,717 (5,512)
----------------------------------------------------------------------------

8,594 6,135 19,624 4,609
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Issue of common shares,
net of issue costs (Note 8) 715 44 652 1,073
Construction credit facility
repayments - (56,600) - (56,600)
Deferred financing costs - (713) - (699)
Long-term debt advances - 148,000 - 148,000
Long-term debt repayments (494) (454) (977) (900)
----------------------------------------------------------------------------

221 90,277 (325) 90,874
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital asset additions (4,912) (66,823) (11,773) (90,457)
Prospect development costs (3,538) (1,680) (7,139) (10,370)
Working capital deficit
assumed on acquisition - - (13,423) -
Proceeds on sale of
development prospects - - - -
----------------------------------------------------------------------------

(8,450) (68,503) (32,335) (100,827)
----------------------------------------------------------------------------

NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS 365 27,909 (13,036) (5,344)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 48,268 146,548 61,669 179,801
----------------------------------------------------------------------------

CASH AND CASH EQUIVALENTS,
END OF PERIOD 48,633 174,457 48,633 174,457
----------------------------------------------------------------------------

Supplemental information
Cash interest paid 5,356 382 8,743 3,398
Cash income and capital
taxes paid 872 331 1,054 573


See accompanying notes to the consolidated financial statements



CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2007 and 2006 (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 and demand for electricity and 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 from the first and third quarters of 2007.

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

(a) ACCOUNTING CHANGES

Effective January 1, 2007, the Company adopted revised Canadian Institute of Chartered Accountants ("CICA") handbook section 1506, "Accounting Changes." The changes covered by this section include changes in accounting policy, changes in accounting estimates and correction of errors. Under section 1506, voluntary changes in accounting policy are only permitted if they result in financial statements that provide more reliable and relevant information. When a change in accounting policy is made, this change is applied retrospectively unless impractical. Changes in accounting estimates are generally applied prospectively and material prior period errors are corrected retrospectively. CICA Section 1506 is effective for fiscal years beginning on or after January 1, 2007. The only impact in the current year is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with CICA handbook section 3862 - Financial Instruments Disclosures and section 3863 Financial Instruments Presentations which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected the only effect on the Company will be incremental disclosures regarding the significance of financial instruments for the entity's financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed.

(b) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Effective January 1, 2007, the Company adopted CICA handbook section 3855, "Financial Instruments - Recognition and Measurement," section 3865, "Hedges," section 1530, "Comprehensive Income" and section 3861, "Financial Instruments - Disclosure and Presentation." The Company has adopted these standards prospectively and the comparative interim consolidated financial statements have not been restated. Transition amounts have been recorded in retained earnings or accumulated other comprehensive income.

(i) Financial Instruments

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 derecognized. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method.

The Corporation has made the following classifications:

- Cash and cash equivalents are classified as financial assets held for trading and are measured at fair value. Gains and losses related to periodical revaluation are recorded in net income.

- Accounts receivable and revenue rebate 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.

- Accounts payable and accrued liabilities, taxes payable and long-term debt (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.

(ii) 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 136,011,580, which is fixed at a blended average rate of 1.4602 for an aggregate Canadian dollar amount of $198,602,284. These foreign exchange contracts are classified as foreign currency cash flow hedges for accounting purposes. At January 1, 2007, the fair value of these contracts of $7,894,000 was recorded on the consolidated balance sheet as a derivative financial asset, with the gain recorded in OCI.

At June 30, 2007, the aggregate amount of remaining Euro purchases is EUR 118,452,960, which is fixed at a blended average rate of 1.4677 for an aggregate Canadian dollar amount of $173,853,409. The fair value change since transition was a loss of $10,321,000.

In February 2007, the Company unwound its U.S. dollar foreign exchange contracts for a cash gain of $263,000, which was recognized in income as a gain on derivative financial instrument as the contracts expired in the quarter.

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 $54 per MWh to the Company based on the average monthly Pool price for an aggregate of 148,780 MWh per year of electricity from January 1, 2007, maturing from 2007 to 2024. While the CFDs do not create any obligation by the Company for the physical delivery of electricity to other parties, management believes it has sufficient electrical generation, which is not subject to contract, to satisfy the CFDs. The Company's assumptions for fair valuing its CFDs, given the ongoing illiquidity of the forward market, assumes the actual contract prices contained in the CFDs are the same as the forward prices for future 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 OCI. At June 30, 2007, the fair value change since transition was recorded resulting in an additional loss of $1,244.000.

(iii) Embedded Derivatives

Derivatives embedded in other financial instruments or contracts are separated from their host contracts and accounted for as derivatives when their economic characteristics and risks are not closely related to those of the host contract; the terms of the embedded derivative are the same as those of a free standing derivative and the combined instrument or contract is not measured at fair value, with changes in fair value recognized in interest and other expenses, net. The Company selected January 1, 2003 as the transition date for embedded derivatives, as such only contracts or financial instruments entered into or modified after the transition date were examined for embedded derivatives. As at June 30, 2007 and December 31, 2006, the Company does not have any outstanding contracts or financial instruments with embedded derivatives that require bifurcation.

(iv) Comprehensive income

Comprehensive income consists of net earnings and OCI. OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge and the change in fair value of any available for sale financial instruments. Amounts included in OCI are shown net of tax. Accumulated other comprehensive income ("AOCI") is a new equity category comprised of the cumulative amounts of OCI. See Note 9 for the composition of AOCI.

3. ACQUISITIONS

On March 8, 2007, the Company acquired all of the issued and outstanding shares of GW Power Corporation ("GWP"). The acquisition price for GWP consisted of three common shares of Canadian Hydro plus one common share purchase warrant for each issued and outstanding share of GWP. Each warrant, which expires on March 8, 2009, is exercisable into one common share upon payment of $7.00 per share. As a result of the GWP acquisition, the Company issued 12,332,700 common shares at a value of $72,763,000 calculated using a volume weighted average price of the Company's shares of $5.90. The 4,110,900 warrants issued have been allocated a fair value of $3,967,000, which was estimated using the Black-Scholes pricing model, assuming a risk free interest rate of 4.13%, expected volatility of 35.42%, expected weighted average life of two years, and no annual dividends paid.

This total purchase price, including acquisition costs of $282,000, has been allocated and recorded as follows:



$
---------

Soderglen Wind Plant 108,066
Future tax liability (19,236)
Working capital deficit, including cash and non-cash items (12,370)
Other long-term assets 419
---------

Purchase price 76,879
---------
---------

GWP owns 50% of the 70.5 MW Soderglen Wind Plant located in southern
Alberta, as well as prospects for the development of up to 145 MW of wind
power located in Alberta and Ontario.

4. CAPITAL ASSETS

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

December 31,
June 30, 2007 2006
-----------------------------------------------
Accumulated Net Book Net Book
Cost Depreciation Value Value
$ $ $ $
-----------------------------------------------
Generating plants
- operating 518,186 46,742 471,444 363,739
- construction-in-progress 187,078 - 187,078 182,275
Vehicles 1,571 982 589 523
Equipment, other 2,848 1,215 1,633 1,260
-----------------------------------------------

709,683 48,939 660,744 547,797
-----------------------------------------------
-----------------------------------------------


For the 3 months ended June 30, 2007, interest costs of $559,000 (3 months ended June 30, 2006 - $83,000) and administration expenses of $646,000 (3 months ended June 30, 2006 - $336,000) associated with the construction-in-progress have been capitalized during construction. For the 6 months ended June 30, 2007, interest costs of $1,118,000 (6 months ended June 30, 2006 - $509,000) and administration expenses of $831,000 (6 months ended June 30, 2006 - $1,097,000) associated with the construction-in-progress have been capitalized during construction. In both 2007 and 2006, construction-in-progress relates to costs associated with the development of the Melancthon II Wind Project. In Q1 2006, construction-in-progress also related to the Melancthon I Wind Project until March 2006, when costs were transferred to operating plants.



5. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

June 30, December 31,
2007 2006
$ $
------------------------------

Wind prospects 50,330 46,310
Dunvegan Hydroelectric Prospect 8,722 8,268
Hydroelectric prospects 8,135 5,711
------------------------------

Total 67,187 60,289
------------------------------
------------------------------


Interest costs of $391,000 (3 months ended June 30, 2006 - $131,000) and administration expenses of $948,000 (3 months ended June 30, 2006 - $437,000) associated with prospect development costs have been capitalized leading up to construction. For the 6 months ended June 30, 2007, interest costs of $781,000 (6 months ended June 30, 2006 - $131,000) and administration expenses of $1,373,000 (6 months ended June 30, 2006 - $868,000) associated with prospect development costs have been capitalized leading up to construction. Included in wind prospects are $29,505,000 in costs with respect to the Wolfe Island Wind Project ("Wolfe Island") and $7,616,000 in costs with respect to the December 2006 acquisition of Vector Wind Energy Inc. The prospect development costs relate to over 1,000 MW of optioned land for wind prospects located primarily throughout Manitoba and Ontario.

The Company continues to pursue the development of the Dunvegan Hydroelectric Prospect. In 2006, the Company completed and submitted the joint application to the Alberta Energy and Utilities Board and Natural Resources Conservation Board. The Company anticipates a hearing and regulatory decision for approval of construction and operation early 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.



6. ACCUMULATED OTHER COMPREHENSIVE INCOME

AOCI, including transition amounts, is comprised of the following:
$
--------
Balance, December 31, 2006 -
Transitional adjustments on adoption of new accounting policies
(see Note 2(b)):
Unrealized gain on derivative financial instrument foreign
currency hedges 7,894
Unrealized loss on derivative financial instrument contracts for
differences (206)
Reclassification of deferred credit 100
--------
Opening balance, January 1, 2007 7,788
Unrealized loss on derivative financial instrument foreign
currency hedges (10,321)
Unrealized loss on derivative financial instrument contracts for
differences (1,244)
Reclassification of deferred credit (86)
--------
Accumulated other comprehensive income, June 30, 2007 (3,863)
--------
--------

As at June 30, 2007, AOCI is comprised of an unrealized loss on derivative
financial instrument foreign currency hedges of $2,427,000, an unrealized
loss on derivative financial instrument contracts for differences of
$1,450,000 and a gain of $14,000 for the reclassification of the deferred
credit.

7. LONG-TERM DEBT

At June 30, 2007, the Company had letters of credit in the amount of
$23,427,000 (December 31, 2006 - $22,622,000) outstanding with its corporate
lenders.

June 30, December 31,
2007 2006
$ $
-----------------------

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

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 6,745 7,093

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 2,511 2,869

Mortgage, bearing interest at 10.68%, secured by
letters of guarantee. Monthly repayments of principal
are $31,000 plus interest until December 30, 2012 2,063 2,250

Promissory note, bearing interest fixed at 6%,
secured by a second fixed charge on three of the
Alberta hydroelectric plants. Monthly repayments of
principal and interest are $19,000 until August 1,
2012 1,031 1,115

Deferred financing costs (1) (2,664) -
-----------------------

312,686 316,327

Less current portion 2,081 1,996
-----------------------

Long-term debt 310,605 314,331
-----------------------
-----------------------

(1) Refer to Note 2(b). As at the transition date of January 1, 2007, the
Company recorded a $118,000 increase in retained earnings with a
corresponding decrease in the long-term debt 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 net against the
long-term debt liability. As the Company records in debt accretion 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 long-term debt liability.

8. SHARE CAPITAL

(a) Issued, common shares:

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

Balance, December 31, 2006 119,652,023 313,852
Issue of common shares (see Note 3) 12,332,700 72,763
Issuance of warrants (see Note 3) - 3,967
Share issue costs, net of tax effect of $40,000 - (119)
Issued on exercise of stock options 369,000 812
Issued on exercise of warrants 500,000 2,863
Stock compensation on shares exercised - 81
-----------------------

Balance, June 30, 2007 132,853,723 394,219
-----------------------
-----------------------


During the quarter, the 500,000 Series A Special Warrants, issued for the acquisition of Canadian Renewable Energy Corporation, vested and automatically converted (without the payment of additional consideration) into common shares of the Company as the Company signed a 20-year power sales contract with the Ontario Power Authority for the Misema Hydroelectric Plant. The 500,000 common shares of the Company were valued at $2,863,000 based on the 10-day weighted average closing price prior to issuance of $5.73 per common share. This additional consideration, including the future tax impact, was allocated to the Misema Hydroelectric Plant.



(b) Warrants:

Number of Amount
Warrants $
-----------------------

Balance, December 31, 2006 500,000 -
Issuance of warrants (see Note 3) 4,110,900 3,967
Exercise of warrants (see Note 8(a)) (500,000) -
-----------------------

Balance, June 30, 2007 4,110,900 3,967
-----------------------
-----------------------

9. EARNINGS PER SHARE AND STOCK COMPENSATION

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

3 Months Ended June 30, 6 Months Ended June 30,
2007 2006 2007 2006
---------------------------------------------------

Basic weighted average
shares outstanding 132,462,020 119,297,894 127,658,641 119,136,018
Effect of dilutive
securities:
Options 2,799,503 2,462,988 2,768,260 2,633,338
---------------------------------------------------

Diluted weighted average
shares 135,261,523 121,760,882 130,426,901 121,769,356
---------------------------------------------------
---------------------------------------------------


Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $561,000 for Q2 2007 (Q2 2006 - $348,000) and $1,039,000 for the 6 months ended June 30, 2007 (2006 - $595,000) of compensation expense in the consolidated statement of earnings, with a corresponding increase recorded to contributed surplus in the consolidated balance sheet as at June 30, 2007. The Company issued 820,000 options in Q2 2007 (Q2 2006 - 410,000) and 1,185,000 options for the 6 months ended June 30, 2007 (2006 - 2,105,000). The weighted average fair value of options granted during Q2 2007 was $2.16 per share (Q2 2006 - $1.90 per share), which was estimated using the Black-Scholes option-pricing model, assuming a risk free interest rate of 4.55% (Q2 2006 - 4.23%), expected volatility of 34.45% (Q2 2006 - 35.89%), expected weighted average life of 4.0 years (Q2 2006 - 4.0 years), and no annual dividends paid. The weighted average fair value of options granted during the 6 months ended June 30, 2007 was $2.11 per share (2006 - $1.96 per share), assuming a risk free interest rate of 4.03% (2006 - 4.16%), expected volatility of 33.17% (2006 - 36.20%), expected weighted average life of 4.0 years (2006 - 4.0 years), and no annual dividends paid.

10. COMMITMENTS AND CONTINGENCIES

In the ordinary course of constructing new projects, the Company routinely enters into contracts for goods and services. As at June 30, 2007, the Company has committed approximately $260,000,000 for goods and services for Melancthon II, Wolfe Island, and the B.C. projects, which will be expended between 2007 and 2009.

11. SUBSEQUENT EVENT

Subsequent to quarter end, the Company closed the sale of a 21 MW wind prospect, which was acquired through its purchase of Vector Wind Energy Inc. in December 2006, for proceeds of $1,270,000. No gain or loss was recorded on the sale.

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