Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

August 15, 2005 15:13 ET

Canadian Hydro Announces Second Quarter Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 15, 2005) - Canadian Hydro Developers, Inc. (TSX:KHD) (the "Company") reported cash flow from operations for the second quarter ended June 30, 2005 ("Q2 2005") of $3,639,000 ($0.05 per share, diluted2) on generation of 124 million kWh, compared to $3,469,000 ($0.05 per share, diluted2) on generation of 117 million kWh for Q2 2004. Net earnings were $1,713,000 ($0.02 per share, diluted) for Q2 2005, compared to $1,791,000 ($0.03 per share, diluted) on for Q2 2004.

Cash flow from operations for the six months ended June 30, 2005 increased to $5,380,000 ($0.07 per share, diluted(2)) on generation of 205 million kWh, compared to $4,194,000 ($0.06 per share, diluted(2)) on generation of 178 million kWh for the same period in 2004. Net earnings for the six months ended June 30, 2005 were $1,818,000 ($0.02 per share, diluted), compared to $1,672,000 ($0.02 per share, diluted) for the same period in 2004.

The start up of the Taylor Wind Plant in December 2004, the acquisition of the Misema Hydroelectric Plant in January 2005, higher water flows in Alberta and higher wind generation on a same plant basis resulted in higher generation for Q2 2005 compared to Q2 2004. These were offset partially by lower average Power Pool of Alberta ("Pool") prices received for electricity on the Company's merchant plants (Q2 2005 - $49/MWh; Q2 2004 - $63/MWh). For the six months ended June 30, 2005, these same factors, with the exception of wind generation, which was lower for the six month period on a same plant basis, plus higher water flows in B.C. resulted in higher generation and stronger financial results compared to the same period in the prior year. The year-to-date average Pool price received for electricity on the Company's merchant plants was $47/MWh in 2005 compared to $54/MWh in 2004. Approximately 85% of the Company's generation was sold under various long-term sales agreements for Q2 2005 and for the six months ended June 30, 2005 (Q2 2004 - 90%; 2004 - 88%), with the balance being exposed to the Pool.



------------------------------------------------------------------------
3 Months Ended 6 Months Ended
June 30, June 30,
(unaudited) 2005 2004 2005 2004
------------------------------------------------------------------------
Financial Results (in
thousands of dollars
except per share amounts)
Revenue 6,983 6,633 12,216 10,785
EBITDA (1) 5,103 5,032 8,336 7,360
Cash flow from operations 3,639 3,469 5,380 4,194
Per share (diluted) (2) 0.05 0.05 0.07 0.06
Net earnings 1,713 1,791 1,818 1,672
Per share (diluted) 0.02 0.03 0.02 0.02

Operating Results
Electricity generation
- MWh (net) 123,507 116,500 204,760 178,330
Average price received
per MWh ($) 57 57 60 60
Electrical generation
under contract (%) 85 90 85 88
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) EBITDA is provided to assist management and investors in determining
the ability of the Company to generate cash from operations. EBITDA
as presented is defined as cash flow from operations, plus interest
on debt 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 per share (diluted) is provided to assist
management and investors in determining the Company's cash flow from
operations 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 2005 Achievements:

- Achieved commercial operations at the $64.9 million, 25 MW Grande Prairie EcoPower® Centre on June 21, 2005;

- Substantially completed construction on the $38.9 million, 25 MW Upper Mamquam Hydroelectric Project, which began commercial operations on July 23, 2005;

- Commenced construction on the $126 million, 67.5 MW Melancthon Grey Wind Project in Ontario;

- Readied several hundred megawatts of renewable energy prospects for bids into upcoming calls for power in Ontario and B.C. later this year and next; and

- Subsequent to Q2 2005, obtained an investment grade credit rating of BBB, with a Stable trend from Dominion Bond Rating Service Ltd. in anticipation of a 10 year, $120 million unsecured corporate debt private placement that will be used primarily to refinance debt with the Company's existing lenders.

"With the commissioning of both the Grande Prairie EcoPower® Centre and the Upper Mamquam Hydroelectric Plant, we have reached our growth target of 53 MW for 2005," said John Keating, Chief Executive Officer. "The addition of these assets to our diversified portfolio of renewable energy plants will strengthen our ability to generate long-term, stable cash flows."

On the topic of the Company's current construction project, Mr. Keating noted, "Construction on the Melancthon Grey Wind Project is now underway, progressing well and is projected to be commercially operational by the end of March 2006."

Canadian Hydro is a developer, owner and operator of 17 low-impact renewable power plants with a net capacity of 162 MW, which are all certified or slated for certification under the EcoLogoM program. The Company's Melancthon Grey Wind Project is slated for certification as a low-impact renewable energy facility upon completion.

Canadian Hydro Developers, Inc. is passionate about meeting the goals of investors and the needs of the environment. As industry leaders, Canadian Hydro is focused on building a sustainable future for Canada and with over 15 years experience, Canadian Hydro is the working model for the unlimited development potential of low-impact renewable energy.

Common shares outstanding: 79,434,048

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

The following MD&A, dated August 5, 2005, should be read in conjunction with the unaudited interim consolidated financial statements as at and for the 3 and 6 months ended June 30, 2005 and 2004, 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, 2004. 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 2005, revenue increased 5% to $6,983,000 on increased generation of 124 million kWh compared to $6,633,000 on generation of 117 million kWh in Q2 2004. For the 6 months ended June 30, 2005, revenue increased 13% to $12,216,000 on increased generation of 205 million kWh compared to $10,785,000 on generation of 178 million kWh for the same period in 2004. The increase in revenue in the current quarter was due to increased generation, offset partially by lower average Pool prices received for electricity on the Company's merchant plants (Q2 2005 - $49/MWh; Q2 2004 - $63/MWh). The increased generation in Q2 2005 was due to the addition of the Taylor Wind Plant in December 2004, the acquisition of the Misema Hydroelectric Plant on January 21, 2005, higher water flows in Alberta and higher wind generation on a same plant basis. The year-to-date increase in revenue was due to the same factors as Q2 2005 with average Pool prices received for electricity on the Company's merchant plants of $47/MWh in 2005 compared to $54/MWh in 2004. The increased year-to-date generation was due to the same factors as Q2 2005 with the exception of wind generation, which was lower for the six month period on a same plant basis, plus extremely warm and wet weather in B.C. and Alberta in Q1 2005, which produced markedly higher water flows and hydroelectric generation.

Approximately 85% of the Company's generation was sold pursuant to long-term sales contracts in Q2 2005 and for the 6 months ended June 30, 2005 (Q2 2004 - 90%; 2004 - 88%). The average price received by the Company for electricity from all operations for Q2 2005 was $57/MWh (Q2 2004 - $57/MWh). The average price received by the Company for electricity from all operations for the 6 months ended June 30, 2005 was $60/MWh (2004 - $60/MWh).



Electricity Generation - by Province and Technology

------------------------------------------------------------------------
Electricity Generation - MWh(1)
Q2 2005 Q2 2004 Variance 2005 2004 Variance
------------------------------------------------------------------------
British Columbia 57,302 59,305 - 3% 77,865 61,669 + 26%
Alberta 41,792 36,801 + 14% 82,942 77,069 + 8%
Ontario 24,413 20,394 + 20% 43,953 39,592 + 11%
------------------------------------------------------------------------
Totals 123,507 116,500 + 6% 204,760 178,330 + 15%
------------------------------------------------------------------------
------------------------------------------------------------------------
Hydroelectric 98,492 95,981 + 3% 146,180 120,090 + 22%
Wind 23,245 20,354 + 14% 56,810 57,953 - 2%
Biomass 1,770 - -% 1,770 - -%
Natural Gas - 165 - 100% - 287 - 100%
------------------------------------------------------------------------
Totals 123,507 116,500 + 6% 204,760 178,330 + 15%
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Reflecting the Company's net interest.


Operating Expenses

Q2 2005 operating expenses increased 43% to $2,056,000 from $1,433,000 in Q2 2004. For the 6 months ended June 30, 2005, operating expenses increased 34% to $3,581,000 from $2,679,000 for the same period in 2004. Gross margins (revenue less operating expenses; expressed as a percentage of revenue) were lower at 71% in Q2 2005 (Q2 2004 - 78%) and 71% for the 6 months ended June 30, 2005 (6 months ended June 30, 2004 - 75%). The increase in operating expenses was due primarily to higher sub-lease costs at Ragged Chute, resulting from the new sub-lease agreement that commenced on June 30, 2004, and the addition of the Taylor Wind Plant, Misema Hydroelectric Plant and Grande Prairie EcoPower® Centre, which had no comparable operating expenses from these plants in the prior year.

Gross margins on biomass plants, such as the Grande Prairie EcoPower® Centre, are typically less than hydroelectric or wind plants. However, the return on average capital employed (i.e. the ratio of cash flow from operations, plus current tax expense and interest on long-term debt to average capital assets, excluding construction-in-progress) from the Grande Prairie EcoPower®Centre is anticipated to be similar to the return on average capital employed from the Company's hydroelectric and wind plants.

Interest on Debt, Long-Term Debt and Revolving Construction Lines of Credit

Interest on debt (excluding capitalized interest) in Q2 2005 decreased 12% to $1,219,000 compared to $1,389,000 in Q2 2004 and for the 6 months ended June 30, 2005, decreased 9% to $2,467,000 from $2,714,000 for the same period in 2004. The decrease in interest expense was due to lower quarter over quarter outstanding debt on completed projects. Interest on the Pingston Debt (see below) was capitalized to the Melancthon Grey Wind Project as the proceeds are being used for capital costs related to this project.

Capitalized interest associated with construction-in-progress in Q2 2005 was $990,000 (Q2 2004 - $17,000) and $1,635,000 for the 6 months ended June 30, 2005 (2004 - $17,000). The increase was due to $51,900,000 being drawn on the Company's $55,100,000 construction lines of credit (the "Construction Lines") and the $35,000,000 Pingston Debt (see below) being used to finance a portion of the Melancthon Grey Wind Project, whereas $11,100,000 was drawn on the Construction Lines during the 3 and 6 months ended June 30, 2004.

Long-term debt (including current portion) as at June 30, 2005 was $99,466,000 (June 30, 2004 - $64,696,000) compared to $66,497,000 as at December 31, 2004. The increase was due to the Company closing a joint debt private placement financing of the Pingston Hydroelectric Plant with its joint venture participant, Brascan Power Inc. (the "Pingston Debt") on February 1, 2005; offset partially by regular repayments on the long-term debt during the year.

The Pingston Debt consists of a $70 million ($35 million net to the Company), 10 year debt facility maturing on February 11, 2015, at 5.281% per annum, with interest payable semi-annually and no principal repayments until maturity. The Pingston Debt is secured with a first fixed charge debenture, a floating charge over real property and an assignment of all material contracts related to the Pingston Hydroelectric Plant, as well as a pledge of the shares of Pingston Power Inc., without recourse to the joint venture participants. The Pingston Debt obtained a credit rating of A (High) with a Stable trend by Dominion Bond Rating Service Ltd. ("DBRS"), and was purchased by a variety of Canadian-based life insurance companies and pension funds. Concurrent with the closing of the Pingston Debt, the Company's corporate lenders removed the security that was associated with the Company's share of the Pingston Hydroelectric Plant.

On June 23, 2005, the Company executed an amending agreement with its corporate lenders (the "Lenders") to extend its revolving loan (the "Loan") and revolving construction lines of credit (see Note 6(b)) to September 23, 2005 (collectively, the "Credit Facilities"). The Company anticipates closing a private debt placement financing (the "Corporate Bonds") of up to $120 million of senior unsecured debentures, which have been assigned a preliminary rating of BBB with a Stable trend by DBRS, are expected to mature in 10 years with no principal repayments until maturity.

The DBRS rating of BBB for the Corporate Bonds is based on the Company's diversified portfolio of low cost, reliable, long life assets, long-term Power Purchase Agreements ("PPAs") with high credit quality counterparties (the majority of which are rated A (high) to AA by DBRS), an experienced management team with a proven track record in developing, constructing and operating small to medium sized generating facilities, significant tax loss carryforwards, and the potential for high quality growth opportunities.

The Company plans to use the proceeds from the proposed bond offering to repay bank facilities of approximately $105 million with the existing four-bank lender group, as well as for general corporate and other purposes including the long-term financing of current and future assets. The proposed Corporate Bonds will provide the Company with a debt capital markets platform for long-term fixed rate financing appropriate for its long-term power assets and for financing future growth in developing long-term contracted renewable power generation assets.

Subsequent to June 30, 2005, two of the Company's corporate lenders committed to provide the Company with an unsecured, 364-day revolving, with a two-year term out, credit facility for up to the lesser of $80 million or 60% of the capital expenditures associated with the Melancthon Grey Wind Project (the "Melancthon Grey Credit Facility"). In addition, these lenders will provide an unsecured, $25 million, 364-day, with a 6-month term out, revolving operating facility (the "Operating Facility"). The Operating Facility will be extendable each 364 days for an additional 364 days upon written request of the Company and approval of these lenders. These facilities will bear interest at Bankers' Acceptances plus a stamping fee of 0.80% per annum, plus standby fees of 0.20% per annum for any undrawn portion of the facilities, with interest and standby fees payable monthly and no principal repayments until maturity. Proceeds of the Operating Facility will be used to repay and reissue the Letters of Credit and for general corporate purposes. Both facilities will rank equally and ratably with all other unsecured and unsubordinated indebtedness of the Company for borrowed money. Closing of the Unsecured Credit Facilities is contingent upon the successful closing of the Corporate Bonds.

Subsequent to June 30, 2005, the Company closed a $43 million revolving bridge facility (the "Bridge Facility") with its Lenders to fund certain initial capital expenditures relating to the construction of the Melancthon Grey Wind Project. The Bridge Facility has a maturity date of September 23, 2005, and is expected to be repaid with proceeds from the Melancthon Grey Credit Facility. The security for the Bridge Facility is the same security as for the Credit Facilities and Letters of Credit. The Bridge Facility bears monthly interest payments at prime plus 1.50% per annum, or at Bankers' Acceptances plus a stamping fee of 2.75% per annum with standby fees of 0.25% for any undrawn portion of the Bridge Facility.

At June 30, 2005, the Company was not in compliance with one of its Credit Facilities' covenants, which requires the Company to maintain a current ratio of not less than 1.0:1.0, which is defined as current assets to current liabilities, excluding the current portion of long-term debt and revolving construction lines of credit. The Company's Lenders have waived compliance for this covenant. The Company was not in compliance with this covenant due to the fact that it had not yet obtained debt financing for the Melancthon Grey Wind Project, which was subsequently obtained (see Bridge Facility and Melancthon Grey Credit Facility above). Management has determined that it is likely the Company will be in compliance with all Credit Facilities' covenant requirements at September 30, 2005, and will continue to be for at least one year from the balance sheet date. Accordingly, the Loan has been classified as a long-term liability.

With the addition of the Pingston Debt and assuming $3,216,000 in available credit at June 30, 2005 from the Construction Lines and revolving loan is drawn by the Company, the Company has a 55/45 debt/equity ratio (December 31, 2004 - 44/56), closer to the Company's revised target of 65/35.

Amortization Expense

Amortization expense increased 16% to $1,201,000 for Q2 2005 (Q2 2004 - $1,036,000), and 11% to $2,292,000 for the 6 months ended June 30, 2005 (2004 - $2,057,000), due primarily to the addition of the Pingston Expansion Hydroelectric Plant in April 2004, the Taylor Wind Plant in December 2004, the Misema Hydroelectric Plant in January 2005 and the Grande Prairie EcoPower® Centre in June 2005. The hydroelectric and biomass plants are amortized on a straight-line basis over a 40 year period, and the wind plant is amortized on a straight-line basis over a 15 year period.

Administration Expense

Administration expense decreased 86% to $53,000 for Q2 2005 (Q2 2004 - $370,000), and decreased 25% to $808,000 for the 6 months ended June 30, 2005 (2004 - $1,072,000). The decreases were due primarily to the Company receiving a cash payment of $750,000, net of associated costs, as a result of a settlement of a lawsuit the Company had with a former insurer and engineering firm associated with a project. This was offset partially by higher stock compensation expense due to 980,000 stock options being issued in Q2 2005 (2005 - 1,080,000 stock options issued), bonuses paid to certain employees, as well as moderately higher salary costs due to the addition of four new employees in 2005. Capitalized administration costs associated with construction-in-progress for Q2 2005 were $396,000 (Q2 2004 -$159,000) and $614,000 for the 6 months ended June 30, 2005 (2004 - $305,000). The Grande Prairie EcoPower® Centre, Upper Mamquam Hydroelectric and Melancthon Grey Wind Projects, totaling 117.5 MW, were under construction in Q2 2005 compared to four projects, totaling 60.9 MW, under construction in Q2 2004.

Gain on Derivative Financial Instruments

Gain on derivative financial instruments decreased to $216,000 in Q2 2005 compared to a gain of $402,000 in Q2 2004. In Q2 2005, the gain was the result of a $126,000 increase in the fair value of one of the Company's contract for differences ("CFD") and $127,000 in cash payments received from another party in connection with the CFD. In addition, in the first quarter, one of the Company's contracts did not qualify for hedge accounting. The fair value of the contract on January 1, 2005 was a gain of $444,000. The gain is recognized into income over the period to which the gain relates with $43,000 recognized in Q2 2005. In Q2 2005, as the contract did not qualify for hedge accounting due to additional delays with the start-up of the Company's Grande Prairie EcoPower Centre, a loss of $80,000 was recognized in earnings representing the change in the fair value of the contract from the prior quarter. On July 1, 2005, the Contract re-qualified as a hedge and hedge accounting will be prospectively applied.

For the 6 months ended June 30, 2005, the gain on derivative financial instruments decreased to $116,000 from $456,000 for the same period in 2004. In addition to the above, a loss of $478,000 was recorded at March 31, 2005, for the change in the fair value of the CFD that no longer qualified for hedge accounting. This loss was offset by the amortization of the gain of $43,000, a $126,000 increase in the fair value of one of the Company's contracts for differences, and $209,000 in cash settlements received from two other parties in connection with the CFDs.

Taxes

The Company does not anticipate current income taxes, other than in respect of the Cowley Ridge Wind Plant, through its wholly owned subsidiary, for several years. However, the Company is liable for the Federal Tax on Large Corporations ("LCT") and Provincial Capital Taxes in Ontario. The provision for these taxes comprises the current tax provision. The Company's larger capital base in 2005 resulted in higher current taxes compared to the prior year. This was offset partially by a decrease in the LCT rate from 0.2% to 0.175% of capital, less a $50,000,000 capital deduction in 2005. LCT will be phased out by the Federal Government by January 1, 2008.

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 $790,000 in Q2 2005 (Q2 2004 - $842,000) and $955,000 for the 6 months ended June 30, 2005 (2004 - $595,000). The decrease in Q2 is due to lower taxable earnings combined with tax pools available to the Company to offset current taxes to future periods compared to higher taxable earnings in Q2 2004. The increase for the 6 months ended June 30, 2005 is due to higher taxable earnings, resulting from the first quarter, compared to the prior year.

Net Earnings and Cash Flow from Operations

Net earnings were $1,713,000 ($0.02 per share) in Q2 2005 compared to $1,791,000 ($0.03 per share) in Q2 2004. The decrease was due primarily to higher operating costs, amortization and taxes, and a decrease in the gain on derivative financial instruments, as described above; offset partially by higher revenue, gain on the sale of development prospects (see 'Gain on Sale of Development Prospects' below), lower administration expenses and interest on debt. For the 6 months ended June 30, 2005, net earnings were $1,818,000 ($0.02 per share) compared to $1,672,000 ($0.02 per share) for the same period in 2004. The year-to-date increase was due to the same factors as Q2 2005 in addition to higher revenue in the first quarter as compared to the prior year. Similarly, excluding non-cash items, cash flow from operations was $3,639,000 for Q2 2005 (Q2 2004 - $3,469,000) and $5,380,000 for the 6 months ended June 30, 2005 (2004 - $4,194,000).

Capital Asset Additions, Prospect Development Costs and Gain on Sale of Development Prospects

Capital asset additions were $35,600,000 in Q2 2005 (Q2 2004 - $12,494,000) and $55,553,000 for the 6 months ended June 30, 2005 (2004 - $18,417,000), resulting in a 34% increase in the net book value of capital assets since December 31, 2004. These investment activities relate to construction costs and equipment purchases incurred for the Grande Prairie EcoPower® Centre, Upper Mamquam Hydroelectric and Melancthon Grey Wind Projects. Prospect development costs were $890,000 in Q2 2005 (Q2 2004 - $752,000) and $1,319,000 for the 6 months ended June 30, 2005 (2004 - $1,047,000), relating primarily to costs associated with the Dunvegan Hydroelectric Prospect, and new wind and hydroelectric prospects in Ontario and B.C., respectively (see Note 5 to the interim consolidated financial statements). These additions exclude the acquisition of Canadian Renewable Energy Corporation ("CREC"), which was acquired with common shares issued by the Company (see 'Capital Resources and Liquidity' below). Costs associated with the Melancthon Grey Wind Project were transferred from development costs to construction-in-progress, including prospect development costs acquired (see Note 7(b) to the interim consolidated financial statements), during the 3 months ended March 31, 2005. During the quarter, the Company sold certain wind energy development prospects acquired from the acquisition of CREC on January 21, 2005, for proceeds of $310,000, plus an additional contingent payment should the purchasers be successful in constructing wind generating assets within a certain period of time following the sale. These sales resulted in a gain of $78,000 being recognized in Q2 2005.

Financial Position

The following chart outlines significant changes in the consolidated balance sheet from December 31, 2004 to June 30, 2005:



------------------------------------------------------------------------
Increase
(Decrease)
$ Explanation
------------------------------------------------------------------------
Cash (1,434) Decrease due to capital asset additions
related to construction projects, prospect
development costs incurred, long-term debt
repayments, and payment of other liabilities
and accounts payable since year end; offset
partially by Pingston Debt, drawings on the
Construction Lines and Loan, cash flow from
operations, collection of year end
receivables, and settlement of a lawsuit
in 2005.

Accounts 1,315 Increase in uncollected revenue from
receivable hydroelectric plants as generation was higher
in June 2005 than in December 2004.

Revenue rebate 232 Increase due to Q1 2005 accrual for revenue
rebate and 2004 revenue rebate that is
expected to be refunded in August 2005.

Prepaid expenses 533 Increase due to prepaid property taxes and
short-term financing costs, offset partially
by the amortization of certain prepaid
expenses.

Derivative 136 Fair value change from December 31, 2004 of a
financial CFD that is no longer considered a hedge
instrument under the new CICA accounting guideline on
hedging relationships and the fair value
change from January 1, 2005 of a CFD that
did not qualify as a hedge on June 30, 2005.
(see Note 3 to the interim consolidated
financial statements).

Deferred 520 Increase due to costs incurred on long-term
financing costs debt financings that are and will be
amortized over the life of the debt.

Capital assets 75,658 Construction costs related to the Grande
Prairie EcoPower® Centre, Upper Mamquam
Hydroelectric and Melancthon Grey Wind
Projects, and the acquisition of the Misema
Hydroelectric Plant (see Note 7(b) to the
interim consolidated financial statements),
partially offset by amortization.

Prospect (6,357) Decrease due to the transfer of the
development Melancthon Grey Wind Project into
costs construction -in-progress and the sale of
certain development prospects; offset
partially by the acquisition of development
prospects (see Note 7(b) to the interim
consolidated financial statements) and costs
related to the development of new prospects.

Other (1,750) Decrease due to payments in amounts owing to
liabilities a third party (see Note 14(b) to the audited
consolidated financial statements as at and
for the year ended December 31, 2004).

Deferred credit 358 Fair value of a CFD (see Note 3 to the
interim consolidated financial statements),
net of recognition to net earnings.

Accounts payable 672 Project and financing costs accrued at June
and accrued 30, 2005, partially offset by the payment of
liabilities project costs accrued at December 31, 2004.

Revolving 23,100 Advances for payment of project costs
construction incurred on the Grande Prairie EcoPower®
lines of credit Centre and Upper Mamquam Hydroelectric Plant.

Long-term debt 32,900 Increase due to the closing of the Pingston
Debt in February 2005 and drawings on the
Loan, partially offset by repayment of
long-term debt.

Future income 722 Increase due to future income taxes that are
taxes expected to be paid by the Company in the
future, based on the Company's taxable
position at June 30, 2005, offset partially
by the acquisition of a future tax asset
(see Note 7(b) to the interim consolidated
financial statements) and the tax effect on
share issue costs.

Share capital 12,545 Common share issuances for the acquisition
of Canadian Renewable Energy Corporation and
option exercises (see Note 7(a) and (b) to the
interim consolidated financial statements).
------------------------------------------------------------------------


Capital Resources and Liquidity

On January 21, 2005, the Company acquired the shares of CREC in exchange for 4,037,687 common shares of the Company valued at $12,113,000, $47,000 in acquisition costs and 2,250,000 special warrants, which will vest and automatically convert into common shares of the Company upon certain events occurring. CREC was an independent power producer with an operating 3.2 MW hydroelectric plant and several hundred megawatts of wind and hydroelectric development prospects in Ontario. CREC was purchased for its operating plant and to strategically position the Company in Ontario for future long-term contracts for renewable energy that may be awarded by the Ontario government. ARC Financial Corporation, whose CEO is an elected director of CHD and whose private equity fund is a large shareholder of the Company, advise two private equity funds that owned 86.6% of CREC. See Note 7(b) to the interim consolidated financial statements.

The Company issued 153,500 common shares at an average exercise price of $1.11 per share for gross proceeds of $170,000 during Q2 2005 and 648,500 common shares at an average price of $0.70 per share for gross proceeds of $455,000 during the 6 months ended June 30, 2005, due to the exercise of expiring stock options. The use of gross proceeds from the $30,007,000 ($28,889,000 net) equity issuance on July 11, 2003 remains unchanged from December 31, 2004.

The Company's current capital expenditure plans total approximately $164,900,000 and are comprised of the Upper Mamquam Hydroelectric and Melancthon Grey Wind Projects. At June 30, 2005, $90,342,000 has been spent on these projects and is included in capital assets as construction-in-progress (see Note 4 to the interim consolidated financial statements). The remaining $74,558,000 of capital expenditures will be financed through $3,216,000 in undrawn and available credit from the Construction Lines and revolving loan, the $43,000,000 in available Bridge Facility, and ultimately, the anticipated new Melancthon Grey Credit Facility of the lesser of 60% of the capital costs of the Melancthon Grey Wind Project or $80,000,000.

Impact of New Accounting Pronouncements

Effective January 1, 2005, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") accounting guideline for identifying and accounting for variable interest entities ("VIEs"). Under the guideline, the Company is required to identify VIEs, determine whether it is the primary beneficiary of such entities and, if so, to consolidate them. The Company has considered the provisions of the guideline for all joint ventures and their related joint venture, operating and maintenance, marketing, power sales and debt agreements, if any. Factors considered in the analysis include how power sales payments are determined, responsibility and payment for capital, operating and maintenance expenses, and decision making by the joint venture participants. As a result of the review, the Company has determined that it does not have interests in VIEs that require consolidation. As a result of adopting this guideline there is no impact on the Company's financial statements.

Financial Instruments

In January 2005, the Company entered into various foreign exchange contracts, expiring in 2005, which fix the Company's U.S. dollar payments under a wind turbine purchase contract in Canadian dollars. The remaining aggregate amount of U.S. dollar purchases is $25,693,000, which is fixed at a blended average rate of 1.206 for a remaining aggregate Canadian dollar amount of $30,992,000. These foreign exchange contracts qualify as hedges under the CICA guideline on hedging relationships. At June 30, 2005, the fair value of the foreign exchange contract was a gain of $440,000. The change in fair value of the interest rate swap was due primarily to the decrease in the value of the Canadian dollar from inception of the contracts to June 30, 2005, which was used in determining fair value.

As disclosed in the December 31, 2004 MD&A, the Company has entered into an interest rate swap that qualifies as a hedge under the CICA guideline on hedging relationships. The fair value of the interest rate swap at June 30, 2005 was a loss of $1,981,000 (December 31, 2004 - loss of $1,476,000). The change in fair value of the interest rate swap was due primarily to the decrease in long term interest rates, offset partially by the increase in short term interest rates from December 31, 2004 to June 30, 2005, which were used in determining fair value. Upon closing of the Corporate Bonds and repayment of the Loan and Construction Facilities, the Company expects to unwind the interest rate swap. The Company anticipates to repay its bank facilities of approximately $105 million with the existing four-bank lender group.

As disclosed in the December 31, 2004 MD&A, the Company has entered into several contracts for differences ("CFDs") that qualified as hedges under the CICA guideline on hedging relationships. At December 31, 2004, the Company fair valued the CFDs using the forward market prices for electricity for 2005 and 2006 and, due to the illiquidity of the forward market past 2006, using the 2006 forward market price for 2007 onwards, discounted at 5%. Given the ongoing illiquidity of the forward market, in 2005, the Company enhanced its assumptions for fair valuing its CFDs by assuming the actual contract prices contained in the CFDs were the same as the forward prices for periods where no forward market prices exist. Had these assumptions been used at December 31, 2004, the fair value of the Company's CFDs would have resulted in a gain of $1,035,000 compared to a gain of $7,327,000 as disclosed previously. The enhanced assumptions relate to fair value disclosures and have no impact on previously reported earnings. During the 3 and 6 months ended June 30, 2005, one of the Company's CFDs no longer qualified for hedge accounting. As a result, a loss of $478,000 and $80,000, respectively, was recognized into earnings (see Note 3 to the interim consolidated financial statements). At June 30, 2005, the fair value of the CFDs that qualify as hedges would result in a gain of $24,000 (see Note 10(b) to the interim consolidated financial statements).



Outstanding Share Data

---------------------------------------------------------------------
As at August 5, 2005
(Unaudited)
---------------------------------------------------------------------
Basic common shares 79,429,548
Convertible securities:
Warrants 2,250,000
Options 4,316,400
---------------------------------------------------------------------
6,566,400
---------------------------------------------------------------------
Diluted common shares 85,995,948
---------------------------------------------------------------------
---------------------------------------------------------------------


Outlook

The $64.9 million Grande Prairie EcoPower® Centre began commercial operations on June 21, 2005, and is expected to generate approximately 88,000 MWh from this plant in 2005 (162,700 MWh per year on a full year basis). On July 23, 2005, the Company achieved commercial operations at the $38.9 million Upper Mamquam Hydroelectric Plant. The Company has satisfied all of the requirements under its 20-year electricity purchase agreement with BC Hydro to formally declare commercial operations to have begun, except for one technical requirement relating to a communications line with the plant that the Company expects will be addressed when a labour dispute involving employees of Telus Communications Inc. has been settled. However, BC Hydro has provided the Company with notice that it will consider the plant to be operational and will pay for electricity delivered since July 23, 2005, pending resolution of the communications line issue. The Upper Mamquam Hydroelectric Plant is expected to generate approximately 32,900 MWh of electricity and RECs for the remainder of 2005 (98,200 MWh per year on a full year basis). With the addition of these plants, the Company has achieved its installed capacity growth target of 53 MW for 2005. These plants are expected to positively impact the Company's financial results for the remainder of 2005 and onwards.

Construction has commenced on the $126 million Melancthon Grey Wind Project, with turbine delivery scheduled to commence in August 2005. This plant is expected to generate 194,800 MWh on a full year basis and is expected to positively impact the Company's financial results in 2006 and onwards, beginning in April 2006.

Reservoir levels in Alberta, where the Company's hydroelectric plants are located, are currently at normal levels for this time of year. Major floods during the second quarter have impacted Alberta Environment's long-lead forecast for the third quarter of 2005, with expected precipitation below normal levels. Below normal precipitation levels increase the need for irrigation from farmers and ranchers this summer, which improves water flows to the Company's plants, generally. Because of this, the Company expects average or above average hydroelectric generation in Alberta for the third quarter.

Precipitation in B.C., where the Company's operating plants and construction project are located, was very high in Q1 2005 due to a prolonged intense Pacific frontal storm system that commenced in mid-January resulting in higher than normal water flows and hydroelectric generation in B.C. In the second quarter, slightly above normal temperatures and rainfall led to snowmelt earlier than normal in the season. As a result, snowpacks in the region are currently at 13% of normal. However, since both the Pingston and Alkolkolex hydroelectric plants experience glacier run-off, as long as temperatures are normal or above normal throughout the summer for glacial melt, the Company expects average hydroelectric generation for these plants for the remainder of the year.

Currently, all of the remaining snow in the mountains surrounding the Upper Mamquam Hydroelectric Plant has melted and the snow water basin index is at 10% of normal. Unless the area receives above normal rainfall over the next few months, there is potential for very low summer season flows in the Mamquam River. Since commissioning the plant on July 23, 2005, the Company has experienced low water flows, however, it is too early to determine the impact on resulting generation for the remainder of 2005.

Ontario had a wet winter similar to the prior year and has experienced normal to below normal precipitation this spring and summer. Because of this, the Company expects average to below average hydroelectric generation in Ontario for the third quarter.

Pool prices in Q2 2005 ($51/MWh) were lower than those in Q2 2004 ($59/MWh). Year-to-date 2005 pool prices (2005 - $50/MWh) were lower than those in the same period in the prior year (2004 - $54/MWh). Pool prices for the remainder of 2005 are expected to be higher than those in Q2 2005 due to higher gas prices. The average Pool price for July 2005 was $38/MWh, compared to $55/MWh for the month of June 2005 and $57/MWh for the month of July 2004. The average Pool price for August (as of August 5, 2005) was $75/MWh.




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

3 Months Ended 6 Months Ended
June 30, June 30,
2005 2004 2005 2004
------------------------------------------------------------------------

Revenue
Electric energy sales 6,888 6,543 11,984 10,525
Revenue rebate 95 90 232 260
------------------------------------------------------------------------
6,983 6,633 12,216 10,785
------------------------------------------------------------------------

Expenses
Operating 2,056 1,433 3,581 2,679
Interest on debt (Note 4) 1,219 1,389 2,467 2,714
Amortization 1,201 1,036 2,292 2,057
Administration (Notes 4 and 9) 53 370 808 1,072
Gain on derivative financial
instrument (Note 3) (216) (402) (116) (456)
Gain on sale of development
prospects (78) - (78) -
------------------------------------------------------------------------
4,235 3,826 8,954 8,066
------------------------------------------------------------------------

Earnings before taxes 2,748 2,807 3,262 2,719
------------------------------------------------------------------------

Tax expense
Current 245 174 489 452
Future 790 842 955 595
------------------------------------------------------------------------
1,035 1,016 1,444 1,047
------------------------------------------------------------------------

Net earnings 1,713 1,791 1,818 1,672

Retained earnings,
beginning of period 13,277 8,873 13,172 8,992
------------------------------------------------------------------------

Retained earnings, end of period 14,990 10,664 14,990 10,664
------------------------------------------------------------------------

Earnings per share (Note 8)
Basic 0.02 0.03 0.02 0.02
Diluted 0.02 0.03 0.02 0.02

See accompanying notes to the consolidated financial statements


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

June 30, December 31,
2005 2004
------------------------------------------------------------------------

ASSETS
Current assets
Cash - 1,434
Accounts receivable 4,203 2,888
Revenue rebate 742 510
Taxes receivable 43 41
Prepaid expenses 1,161 628
Derivative financial instrument (Note 3) 390 254
------------------------------------------------------------------------

6,539 5,755

Deferred financing costs (Note 6(a)) 520 -
Capital assets (Note 4) 296,195 220,537
Prospect development costs (Note 5) 10,942 17,299
------------------------------------------------------------------------

TOTAL ASSETS 314,196 243,591
------------------------------------------------------------------------

LIABILITIES
Current liabilities
Other liabilities 540 2,290
Deferred credit (Note 3) 358 -
Accounts payable and accrued liabilities 7,145 6,473
Current portion of long-term debt (Note 6(a)) 1,766 1,697
Revolving construction lines
of credit (Note 6(b)) 51,900 28,800
------------------------------------------------------------------------

61,709 39,260

Long-term debt (Note 6(a)) 97,700 64,800
Future income taxes 18,981 18,259
------------------------------------------------------------------------

178,390 122,319
------------------------------------------------------------------------

Commitments and contingencies (Note 10)

SHAREHOLDERS' EQUITY
Share capital (Note 7) 120,324 107,779
Contributed surplus (Note 8) 492 321
Retained earnings 14,990 13,172
------------------------------------------------------------------------

135,806 121,272
------------------------------------------------------------------------

TOTAL LIABILITIES AND
SHAREHOLDERS' EQUITY 314,196 243,591
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

Approved by the Board

"signed" "signed"
David J. Stenason Cyrille Vittecoq


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

3 Months Ended 6 Months Ended
June 30, June 30,
2005 2004 2005 2004
------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings 1,713 1,791 1,818 1,672
Adjustments for:
Amortization 1,201 1,036 2,292 2,057
Future income tax expense 790 842 955 595
Stock compensation
expense (Note 8) 103 55 171 111
(Gain) loss on derivative
financial instrument
(Note 3) (90) (255) 222 (241)
Gain on sale of
development prospects (78) - (78) -
------------------------------------------------------------------------

Cash flow from operations 3,639 3,469 5,380 4,194
Changes in non-cash
working capital (1,417) (1,367) (6,859) (5,226)
------------------------------------------------------------------------

2,222 2,102 (1,479) (1,032)
------------------------------------------------------------------------

FINANCING ACTIVITIES
Issue of common shares,
net of issue costs (Note 7) 170 169 420 273
Revolving construction
lines of credit advances
(Note 6(b)) 19,400 11,100 23,100 11,100
Deferred financing costs (170) - (520) -
Long-term debt advances 8,400 - 43,400 -
Long-term debt repayments (5,119) (684) (10,431) (2,215)
------------------------------------------------------------------------

22,681 10,585 55,969 9,158
------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital asset additions (35,600) (12,494) (55,553) (18,417)
Prospect development costs (890) (752) (1,319) (1,047)
Net cash acquired on
acquisition (Note 7(b)) - - 638 -
Proceeds on sale of
development prospects 310 - 310 -
Proceeds on sale of
capital assets - - - 17
------------------------------------------------------------------------

(36,180) (13,246) (55,924) (19,447)
------------------------------------------------------------------------

NET DECREASE IN CASH (11,277) (559) (1,434) (11,321)
CASH, BEGINNING OF PERIOD 11,277 3,019 1,434 13,781
------------------------------------------------------------------------

CASH, END OF PERIOD - 2,460 - 2,460
------------------------------------------------------------------------
------------------------------------------------------------------------

Supplemental information
Cash interest paid 1,908 1,220 3,856 2,531
Cash income and capital
taxes paid 301 272 532 548

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2005 and 2004 (Unaudited)
(Tabular amounts in thousands of dollars, except as otherwise noted)


1. SIGNIFICANT ACCOUNTING POLICIES

The accompanying interim consolidated financial statements of Canadian Hydro Developers, Inc. and its wholly-owned subsidiaries (the "Company") have been prepared in accordance with Canadian generally accepted accounting principles and reflect all adjustments (consisting of normal recurring adjustments and accruals) that are, in the opinion of management, necessary for a fair presentation of the results for the interim period.

These interim consolidated financial statements do not include all of the disclosures included in the Company's annual consolidated financial statements. Accordingly, these interim consolidated financial statements should be read in conjunction with the Company's most recent annual consolidated financial statements.

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

Effective January 1, 2005, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") accounting guideline for identifying and accounting for variable interest entities ("VIEs"). Under the guideline, the Company is required to identify VIEs, determine whether it is the primary beneficiary of such entities and, if so, to consolidate them. The Company has considered the provisions of the guideline for all joint ventures and their related joint venture, operating and maintenance, marketing, power sales and debt agreements, if any. Factors considered in the analysis include how power sales payments are determined, responsibility and payment for capital, operating and maintenance expenses, and decision making by the joint venture participants. As a result of the review, the Company has determined that it does not have interests in VIEs that require consolidation. As a result of adopting this guideline there is no impact on the Company's financial statements.

2. COMPANY OPERATIONS

Interim results fluctuate due to plant maintenance, seasonal demands and demand for electricity and supply of water, 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 third quarters to be higher than those from the first and fourth quarters of 2005.

3. DERIVATIVE FINANCIAL INSTRUMENT

The Company entered into a Contract for Differences ("CFD") with another party whereby the other party has agreed to pay a fixed price to the Company based on the average monthly Pool Price for 110,000 MWh per year of electricity commencing January 1, 2005. While the CFD does not create any obligation by the Company for the physical delivery of electricity to the other party, the Company believed it would have sufficient electrical generation, which was not subject to contract, to satisfy the CFD at December 31, 2004. Because of this, the Company previously determined the CFD would qualify as a hedge. Due to the delay in the start up of the Grande Prairie EcoPower® Centre in early 2005, the CFD did not qualify for hedge accounting for the 6 months ended June 30, 2005.

Accordingly, on January 1, 2005, the CFD was fair valued and an initial amount of $444,000 was recorded as a derivative financial instrument asset and a deferred credit liability. The initial amount of the deferred credit is being recognized to income over the same period as the corresponding gains or losses associated with the CFD, of which $43,000 and $86,000 were recognized into income as gains on derivative financial instrument during the 3 and 6 months ended June 30, 2005, respectively. During the 3 and 6 months ended June 30, 2005, $164,000 and $291,000, respectively, in payments received from the other party in connection with the CFD were recognized into income as a gain on derivative financial instrument and the 3 and 6 month decrease in the fair value of $478,000 and $558,000, respectively, was recognized into income as a loss on derivative financial instrument, resulting in a derivative financial liability of $116,000. Fair value was determined by taking the difference between the fixed purchase price for electricity and the forward market selling price for electricity for the third quarter of 2005 and the contract price for periods onwards, as no market forward prices exist, and multiplying this by the remaining notional amount of generation for each year under the CFD. Subsequent to June 30, 2005, the CFD was determined to re-qualify as a hedge and hedge accounting commenced on July 1, 2005.

The remaining derivative financial instrument relates to a contract with another party that was disclosed in Note 5 to the audited consolidated financial statements as at and for the year ended December 31, 2004.

During the quarter, the Company entered into CFDs with other parties whereby the parties have agreed to pay a fixed price to the Company based on the average Pool prices for an aggregate 18,370 MWh per annum. The contracts begin on January 1, 2006 and June 1, 2006, and expire on December 31, 2006 and May 31, 2016, respectively. While the CFDs do not create any obligation by the Company for the physical delivery of electricity to the other parties, the Company believes it will have sufficient electrical generation to satisfy the CFDs throughout their term, and as such, the Company expects the CFDs to qualify as hedges. At June 30, 2005, the fair value of the CFDs was $nil due to the illiquidity of the forwards market.

4. CAPITAL ASSETS

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



June 30, December 31,
2005 2004
---------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
---------------------------------------------

Generating plants
- operating 229,692 25,032 204,660 133,478
- construction-in-progress 90,342 - 90,342 86,295
Vehicles 873 583 290 175
Equipment, other 1,648 745 903 589
---------------------------------------------

322,555 26,360 296,195 220,537
---------------------------------------------
---------------------------------------------


For the 3 months ended June 30, 2005, interest costs of $990,000 (3 months ended June 30, 2004 - $17,000) and administration expenses of $396,000 (3 months ended June 30, 2004 - $159,000) associated with the construction-in-progress have been capitalized during construction. For the 6 months ended June 30, 2005, interest costs of $1,635,000 (6 months ended June 30, 2004 - $17,000) and administration expenses of $614,000 (6 months ended June 30, 2004 - $304,628) associated with the construction-in-progress have been capitalized during construction. At June 30, 2005, construction-in-progress is comprised of costs relating to the Upper Mamquam Hydroelectric Project and the Melancthon Grey Wind Project (June 30, 2004 - the Grande Prairie EcoPower® Centre, Taylor Wind, and Upper Mamquam). Costs associated with the Grande Prairie EcoPower® Centre were transferred from construction-in-progress to operating plants upon commissioning on June 21, 2005. In addition, costs associated with the Melancthon Grey Wind Project were transferred from development costs to construction-in-progress, including prospect development costs acquired (see Note 7(b)), during the 3 months ended March 31, 2005.

5. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:



June 30, December 31,
2005 2004
$ $
--------------------------------

Dunvegan Hydroelectric Prospect 7,394 6,885
Hydroelectric prospects 1,837 1,117
Wind prospects 1,711 9,297
--------------------------------

Total 10,942 17,299
--------------------------------
--------------------------------


6. CREDIT FACILITIES

(a) Long-term debt

On February 11, 2005, the Company closed a joint debt private placement financing of the Pingston Hydroelectric Plant with its joint venture participant, Brascan Power Inc. (the "Pingston Debt"). The Pingston Debt consists of a $70 million ($35 million net to the Company), ten-year debt facility maturing on February 11, 2015, at 5.281% per annum, with interest payable semi-annually and no principal repayments until maturity. The Pingston Debt is secured with a first fixed charge debenture, a floating charge over real property and an assignment of all material contracts related to the Pingston Hydroelectric Plant, as well as a pledge of the shares of Pingston Power Inc., without recourse to the joint venture participants. The proceeds from this financing are being used for general corporate purposes including, but not limited to, capital expenditures associated with the Melancthon Grey Wind Project. Concurrent with the closing of the Pingston Debt, the Company's corporate lenders removed the security that was associated with the Company's share of the Pingston Hydroelectric Plant. Costs incurred on the Pingston Debt are deferred and amortized over its 10 year term.

On June 23, 2005, the Company executed an amending agreement with its corporate lenders (the "Lenders") to extend its revolving loan (the "Loan") and revolving construction lines of credit (see Note 6(b)) to September 23, 2005 (collectively, the "Credit Facilities"). The Company anticipates closing a private debt placement financing (the "Corporate Bonds") of up to $120 million of senior unsecured debentures, the proceeds of which will be used to repay the Credit Facilities and for general corporate purposes. The Company expects that the debentures will have a 10-year term, with interest payable semi-annually and no principal repayments until maturity. The Corporate Bonds will rank equally and ratably with all other unsecured and unsubordinated indebtedness of the Company for borrowed money. Costs incurred with respect to the Corporate Bonds are deferred and will be amortized over its 10 year term.

At June 30, 2005, the Company had $16,000 available and undrawn on its Loan.

Upon inception of the Company's Loan on December 19, 2002, the Company entered into an interest rate swap arrangement to fix the interest rate at 6.77% per annum on 100% of the Loan for the first five years and 50% of the Loan in years 6 through 10. At June 30, 2005, the fair value of the interest rate swap was a loss of $1,981,000 (December 31, 2004 - loss of $1,476,000). The Company anticipates unwinding the interest rate swap upon closing of the Corporate Bond and repayment of the Loan at which time the Company expects to make a payment as it anticipates that the fair value of the interest rate swap will continue to be negative. This anticipated payment will be charged to earnings when incurred.

At June 30, 2005, the Company had letters of credit in the amount of $16,549,000 (December 31, 2004 - $15,345,000) outstanding with its Lenders (the "Letters of Credit").

The Credit Facilities and Letters of Credit are secured by a first fixed and floating charge debenture on all plants and subsidiary companies, with the exception of the Pingston Hydroelectric Plant and Cowley, a second charge debenture on Cowley, security interest over all present and after acquired personal property, a floating charge over all real property, and an assignment of certain sales agreements.



2005 2004
$ $
--------------------
Revolving reducing loan, bearing interest at prime
plus 0.75% or Bankers' Acceptances plus a 2%
stamping fee (see above for interest rate swap)
with monthly interest payments 48,435 49,635

Pingston Debt (described above) 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 8,032 8,312

Mortgage, bearing interest at 10.7% and secured
by letter of guarantee. Monthly repayments of
principal and interest are $84,000 until
May 31, 2010 3,833 4,122

Mortgage, bearing interest at 10.68%, secured
by letters of guarantee. Monthly repayments of
principal are $31,000 plus interest until
December 30, 2012 2,813 3,000

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 1,353 1,428
--------------------

99,466 66,497

Less current portion 1,766 1,697
--------------------

Long-term debt 97,700 64,800
--------------------
--------------------


Subsequent to June 30, 2005, two of the Company's corporate lenders committed to provide the Company with an unsecured, 364-day revolving, with a two-year term out, credit facility for up to the lesser of $80 million or 60% of the capital expenditures associated with the Melancthon Grey Wind Project (the "Melancthon Grey Credit Facility"). In addition, these lenders will provide an unsecured, $25 million, 364-day, with a six-month term out, revolving operating facility (the "Operating Facility"). The Operating Facility will be extendable each 364 days for an additional 364 days upon written request of the Company and approval of these lenders. These facilities will bear interest at Bankers' Acceptances plus a stamping fee of 0.80% per annum, plus standby fees of 0.20% per annum for any undrawn portion of the facilities, with interest and standby fees payable monthly and no principal repayments until maturity. Proceeds of the Operating Facility will be used to repay and reissue the Letters of Credit and for general corporate purposes. Both facilities will rank equally and ratably with all other unsecured and unsubordinated indebtedness of the Company for borrowed money. Closing of the Unsecured Credit Facilities is contingent upon the successful closing of the Corporate Bonds.

Subsequent to June 30, 2005, the Company closed a $43 million revolving bridge facility (the "Bridge Facility") with its Lenders to fund certain initial capital expenditures relating to the construction of the Melancthon Grey Wind Project. The Bridge Facility has a maturity date of September 23, 2005, and is expected to be repaid with proceeds from the Melancthon Grey Credit Facility. The security for the Bridge Facility is the same security as for the Credit Facilities and Letters of Credit. The Bridge Facility bears monthly interest payments at prime plus 1.50% per annum, or at Bankers' Acceptances plus a stamping fee of 2.75% per annum with standby fees of 0.25% for any undrawn portion of the Bridge Facility.

At June 30, 2005, the Company was not in compliance with one of its Credit Facilities' covenants, which requires the Company to maintain a current ratio of not less than 1.0:1.0, which is defined as current assets to current liabilities, excluding current portion of long-term debt and revolving construction lines of credit. The Company's Lenders have waived compliance for this covenant. Accordingly, the Loan has been classified as a long-term liability. The Company was not in compliance with this covenant due to the fact that it had not yet obtained debt financing for the Melancthon Grey Wind Project, which was subsequently obtained (see Bridge Facility and Melancthon Grey Credit Facility above.

(b) Revolving construction lines of credit

At June 30, 2005, $51,900,000 was drawn by the Company (December 31, 2004 - $28,800,000), leaving $3,200,000 of available undrawn Construction Lines (December 31, 2004 - $26,300,000).



7. SHARE CAPITAL

(a) Issued, common shares

Number of Amount
Shares $
------------------------
Balance, December 31, 2004 74,683,861 107,779
Issued on acquisition 4,037,687 12,113
Issued on exercise of stock options 648,500 455
Share issue costs, net of tax effect of $12,000 - (23)
------------------------

Balance, June 30, 2005 79,370,048 120,324
------------------------
------------------------


(b) Acquisition

On January 21, 2005, the Company acquired all of the issued and outstanding shares of Canadian Renewable Energy Corporation ("CREC") in exchange for 4,037,687 common shares of the Company valued at $12,113,000 and $47,000 in acquisition costs incurred for a total purchase price of $12,160,000. The common shares issued were valued at the closing price of the Company's shares on the date the Company signed a letter of intent with CREC, less 12%. As a result of the purchase, the Company acquired a 3.2 MW hydroelectric plant, certain development prospects, and 100% of the Melancthon Grey Wind Project, in which CREC had an option to acquire 50% of prior to January 23, 2005. No bank or other indebtedness was assumed in conjunction with this acquisition.



The allocation of the purchase price of CREC is as follows:

$
-------------

Generating plant - operating 6,934
Prospect development costs 4,450
Working capital 555
Future tax asset 221
-------------

Purchase price 12,160
-------------
-------------


In addition to 4,037,687 common shares of the Company being issued for the acquisition of CREC, 500,000 Series A Special Warrants (the "Series A Warrants"), and 1,750,000 Series B Special Warrants (the "Series B Warrants") were issued, which will vest and automatically convert (without the payment of any additional consideration) into common shares of the Company upon certain events occurring. In the event the Series A and B Warrants vest and automatically convert into common shares of the Company due to certain events occurring, additional consideration will be allocated to the purchase of CREC for accounting purposes.

The Series A Warrants will vest and automatically convert (without the payment of any additional consideration) into common shares if the Company is successful in obtaining a 20 year contract to sell power to OEFC or another Ontario Government agency (the "Contract") by the later of December 31, 2005 and the date the Ontario Government announces an award of the Contract for Misema, if Misema was bid into a request for proposals (a "Government RFP") prior to December 31, 2005. If these conditions are met, then the amount of common shares issued will vary (up to a maximum of 500,000 common shares) based on the price received for power generation in the Contract.

The Series B Warrants will vest and automatically convert (without the payment of any additional consideration) into common shares if the Company is successful in obtaining one or more renewable energy supply contracts through a Government RFP for CREC's development prospects or future phases of the Melancthon Grey Wind Project (the "RES Contracts") by the later of December 31, 2008 and the date the Ontario Government announces an award of the RES Contracts to the Company, if these projects were bid into a Government RFP prior to December 31, 2008. For each megawatt awarded to the Company under the RES Contract, 8,750 Series B Warrants will vest and automatically convert into an equal number of common shares, up to a maximum of 1,750,000 common shares.

ARC Canadian Energy Venture Fund 2 ("ARC Fund 2") and ARC Energy Venture Fund 3 (together the "ARC Funds") owned 86.6% of the issued and outstanding shares of CREC. As a result of the transaction, 3,494,676 common shares, 433,973 Series A Warrants and 1,518,906 Series B Warrants of the Company were issued to the ARC Funds and ARC Capital Ltd., in aggregate. The ARC Funds and ARC Capital are advised by ARC Financial Corporation whose CEO is an elected director of the Company. The acquisition of CREC has been recorded at the exchange amount, which represents the amount that would have been exchanged between arms' length parties.

8. EARNINGS PER SHARE AND STOCK COMPENSATION

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



3 Months Ended 6 Months Ended
June 30, June 30,
2005 2004 2005 2004
-----------------------------------------------

Basic weighted average
shares outstanding 79,326,823 68,995,215 78,601,776 68,949,023
Effect of dilutive
securities:
Warrants - 346,841 - 136,770
Options 1,482,354 1,836,245 1,538,552 1,756,014
-----------------------------------------------

Diluted weighted
average shares 80,809,177 71,178,301 80,140,328 70,841,807
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Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $103,000 or $nil per share for the 3 months ended June 30, 2005 (3 months ended June 30, 2004 - $55,000 or $nil per share) and $171,000 or $nil per share for the 6 months ended June 30, 2005 (6 months ended June 30, 2004 - $111,000 or $nil per share) 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, 2005. The weighted average fair value of options granted during the 3 months ended June 30, 2005 was $1.32 per share (6 months ended June 30, 2005 - $1.36 per share), which was estimated using the Black-Scholes option-pricing model, assuming an average risk free interest rate of 3.51% (6 months ended June 30, 2005 - 3.58%), average expected volatility of 37.95% (6 months ended June 30, 2005 - 37.91%), expected weighted average life of 4.0 years (6 months ended June 30, 2005 - 4.4 years), and no annual dividends paid. There were 980,000 options granted during the 3 months ended June 30, 2005 (6 months ended June 30, 2005 - 1,080,000). Effective April 1, 2005, all new options granted expire after five years. Options issued prior to April 1, 2005 have an expiry period of ten years.

If the fair value method of accounting had been used for stock options issued to employees on or after January 1, 2002, but prior to January 1, 2003, then the effect would have been a decrease to net earnings of $31,000 or $nil per share for the 3 months ended June 30, 2005 (3 months ended June 30, 2004 - $31,000 or $nil per share), and $62,000 or $nil per share for the 6 months ended June 30, 2005 (6 months ended June 30, 2004 - $62,000 or nil per share).

9. ADMINISTRATION EXPENSES

Administration expenses include a cash receipt of $750,000, net of associated costs, resulting from a settlement of a lawsuit the Company had with a former insurer and engineering firm associated with a project.

10. COMMITMENTS AND CONTINGENCIES

(a) The Company has entered into various foreign exchange contracts with other parties that fix the Company's U.S. dollar payments under a wind turbine purchase contract in Canadian dollars, expiring in 2005. The remaining aggregate amount of U.S. dollar purchases is $30,992,000, which is fixed at a blended average rate of 1.206 for a remaining aggregate Canadian dollar amount of $25,693,000. At June 30, 2005, the fair value of the foreign exchange contracts would result in a gain of $440,000.

(b) At December 31, 2004, the Company fair valued its various CFDs with other parties using the forward market prices for electricity for 2005 and 2006 and, due to the illiquidity of the forward market past 2006, using the 2006 forward market price for 2007 onwards, discounted at 5%. In 2005, given the ongoing illiquidity of the forward market, the Company enhanced its assumptions for fair valuing its CFDs by assuming the actual contract prices contained in the CFDs were the same as the forward prices for periods where no forward market prices exist. Had these assumptions been used at December 31, 2004, the fair value of the Company's CFDs would have resulted in a gain of $1,035,000 compared to a gain of $7,327,000 as disclosed previously. The enhanced assumptions relate to fair value disclosures and have no impact on previously reported earnings. During the 3 and 6 months ended June 30, 2005, one of the Company's CFDs no longer qualified as a hedge and hedge accounting was discontinued for the contract. On July 1, 2005, the CFD re-qualified as a hedge (see Note 3). As at June 30, 2005, the fair value of the remaining CFDs that continue to qualify as hedges would result in a gain of $24,000.

(c) In the ordinary course of maintaining plants and equipment, and in constructing new projects, the Company routinely enters into contracts for goods and services. Subsequent to June 30, 2005, the Company has committed to approximately $38,650,000 for goods and services for the Grande Prairie EcoPower® Centre, the Upper Mamquam Hydroelectric Project, and the Melancthon Grey Wind Project, which will be expended during the remainder of 2005.

(d) During June 2005, the Company entered into CFDs with other parties whereby the parties have agreed to pay a fixed price to the Company based on the average Pool prices for an aggregate 18,370 MWh per annum. The contracts begin on January 1, 2006 and June 1, 2006, and expire on December 31, 2006 and May 31, 2016, respectively. While the CFDs do not create any obligation by the Company for the physical delivery of electricity to the other parties, the Company believes it will have sufficient electrical generation to satisfy the CFDs throughout their term, and as such, the Company expects the CFDs to qualify as hedges. At June 30, 2005, the fair value of the CFDs was $nil due to the illiquidity of the forwards market.

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