Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

May 12, 2005 16:23 ET

Canadian Hydro Announces First Quarter Results

CALGARY, ALBERTA--(CCNMatthews - May 12, 2005) - Canadian Hydro Developers, Inc. (TSX:KHD) (the "Company") reported cash flow from operations of $1,741,000 ($0.02 per share, diluted2) on generation of 81 million kWh for the first quarter ended March 31, 2005 ("Q1 2005"), compared to cash flow from operations of $725,000 ($0.01 per share, diluted2) on generation of 62 million kWh for Q1 2004. The Company reported net earnings of $105,000 ($nil per share, diluted) for Q1 2005, compared to a net loss of $119,000 ($nil per share, diluted) for Q1 2004.

An extremely warm and wet quarter in B.C. and Alberta resulting in markedly higher water flows and hydroelectric generation, and lower interest costs. These were offset partially by higher generation from plants with lower long-term sales contract prices (Q1 2005 - $68/MWh; Q1 2004 - $71/MWh), higher operating costs, amortization, and taxes, which resulted in higher financial results in Q1 2005 compared to Q1 2004. Average Power Pool of Alberta ("Pool") prices received on the Company's merchant plants during the quarter were comparable to Q1 2004 (Q1 2005 - $43/MWh; Q1 2004 - $42/MWh). Approximately 86% of the Company's generation was sold under various long-term sales agreements in Q1 2005 (Q1 2004 - 85%), with the balance being exposed to the Pool.



------------------------------------------------------------------------
3 Months Ended
March 31 (unaudited),
2005 2004
------------------------------------------------------------------------
Financial Results
(in thousands of dollars except per share amounts)
Revenue 5,233 4,152
EBITDA(1) 3,233 2,328
Cash flow from operations 1,741 725
Per share (diluted)(2) 0.02 0.01
Earnings (loss) 105 (119)
Per share (diluted) - -

Operating Results
Electricity generation - MWh (net) 81,221 61,830
Average price received per MWh ($) 64 67
Power generation under contract (%) 86 85
------------------------------------------------------------------------
------------------------------------------------------------------------

(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.


Q1 2005 Achievements:

- Positioned Company for growth in Ontario with the acquisition of up to 400 MW of renewable energy prospects and a 3.2 MW hydroelectric plant from the all stock purchase of Canadian Renewable Energy Corporation;

- Reduced the Company's cost of capital and improved leverage towards targeted levels through an A (High) with a Stable trend DBRS rated, 10 year, $35 million project debt private placement at 5.281% per annum, with principal due on maturity;

- Neared commercial operations for the Grande Prairie EcoPower® Centre;

- Readied the 67.5 MW Melancthon Grey Wind Project for construction later this spring; and

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

"With the expected completion of our Grande Prairie EcoPower® Centre by May 2005, we will have achieved the third milestone in our current slate of construction projects," said John Keating, Chief Executive Officer. "With biomass added to our portfolio of renewable energy plants, we continue to diversify on both a technological and geographical basis, which strengthens our ability to generate long-term, stable cash flows."

On the topic of projects under or nearing construction, Mr. Keating noted, "The 25 MW Upper Mamquam Hydroelectric Project is progressing well and is expected it to be commercially operational by the end of June 2005. We have secured the delivery of GE Wind turbines, are making good progress on permitting and expect to commence construction on the 67.5 MW Melancthon Grey Wind project later this spring."

Canadian Hydro is a developer, owner and operator of low-impact renewable power plants, which are all certified under the EcoLogoM program. The Company's future projects, including the Upper Mamquam Hydroelectric and Melancthon Grey Wind Projects, are slated for certification as low-impact renewable energy facilities.

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: 79,216,548

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

The following MD&A, dated May 5, 2005, should be read in conjunction with the unaudited interim consolidated financial statements as at and for the 3 months ended March 31, 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 dollars unless otherwise noted. Additional information respecting the Company, including its Annual Information Form, is available on SEDAR at http://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 Q1 2005, revenue increased 26% to $5,233,000 on generation of 81 million kWh compared to $4,152,000 on generation of 62 million kWh in Q1 2004. The increase in revenue was due to a 31% increase in generation; offset partially by higher generation from plants with lower long-term sales contract prices (Q1 2005 - $68/MWh; Q1 2004 - $71/MWh). The higher generation in Q1 2005 was the result of extremely warm and wet weather in B.C. and Alberta, which produced markedly higher water flows and hydroelectric generation and moderately higher generation in Ontario due to the addition of the 3.2 MW Misema Hydroelectric Plant that was acquired on January 21, 2005; offset partially by lower wind levels and generation. Generally, Q1 is the lowest annual hydroelectric generation period in B.C. and Alberta.

Approximately 86% of the Company's generation was sold pursuant to long-term sales contracts in Q1 2005 (Q1 2004 - 85%). Average Power Pool of Alberta ("Pool") prices received on the Company's merchant plants during the quarter were comparable to Q1 2004 (Q1 2005 - $43/MWh; Q1 2004 - $42/MWh). The average price received by the Company for electricity from all operations for Q1 2005 was $64/MWh (Q1 2004 - $67/MWh).



Electricity Generation - by Province and Technology

------------------------------------------------------------------------
Electricity Generation - MWh(1)
Q1 2005 Q1 2004 Variance
------------------------------------------------------------------------
British Columbia 20,563 2,364 +770%
Alberta 41,150 40,268 + 2%
Ontario 19,508 19,198 + 2%
------------------------------------------------------------------------
Totals 81,221 61,830 + 31%
------------------------------------------------------------------------
Hydroelectric 47,656 24,109 + 98%
Wind 33,565 37,599 - 11%
Natural Gas - 122 -100%
------------------------------------------------------------------------
Totals 81,221 61,830 + 31%
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Reflecting the Company's net interest.


Operating Expenses

Operating expenses increased 22% to $1,525,000 in Q1 2005 compared to $1,246,000 in Q1 2004. Gross margins (revenue less operating expenses; expressed as a percentage of revenue) were consistent at 69% in Q1 2005 (Q1 2004 - 70%). 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, the addition of the Taylor Wind Plant in December 2004 and the Misema Hydroelectric Plant in January 2005 with no comparable operating expenses from these plants in Q1 2004.

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

Interest on long-term debt (excluding capitalized interest) in Q1 2005 decreased 6% to $1,248,000 compared to $1,325,000 in Q1 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 primarily for this project.

Capitalized interest associated with construction-in-progress in Q1 2005 was $645,000 compared to $nil in Q1 2004. The increase was due to $32,500,000 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, no amounts were drawn on the Construction Lines during Q1 2004.

Long-term debt (including current portion) as at March 31, 2005 was $96,185,000 (March 31, 2004 - $65,380,000) 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 11, 2005; offset partially by regular repayments on the long-term debt during the quarter. The Company has $4,716,000 of undrawn credit available under its revolving reducing loan with its corporate lenders (see Note 6(a) to the interim consolidated financial statements).

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 Inc., 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.

With the addition of the Pingston Debt and assuming $27,316,000 in available credit from the Construction Lines and revolving reducing loan is drawn by the Company, the Company will have a 54/46 debt/equity mixture (December 31, 2004 - 44/56), closer to its stated target of 60/40.

Amortization Expense

Amortization expense increased 7% to $1,091,000 for Q1 2005 (Q1 2004 - $1,021,000) due to the addition of the Pingston Expansion Hydroelectric Plant in April 2004, the Taylor Wind Plant in December 2004 and the Misema Hydroelectric Plant in January 2005. The hydroelectric and wind plants are amortized over a 40 year and 15 year period, respectively.

Administration Expense

Administration expense increased 8% to $755,000 in Q1 2005 compared to $702,000 in Q1 2004. The increase was due primarily to higher stock compensation expense due to 100,000 stock options being issued in January 2005, as well as moderately higher salary costs due to the addition of two new employees in 2005. Capitalized administration costs associated with construction-in-progress in Q1 2005 were $218,000 compared to $146,000 in Q1 2004. The Grande Prairie EcoPower® Centre, Upper Mamquam Hydroelectric and Melancthon Grey Wind Projects, totaling 117.5 MW, were under construction in Q1 2005 compared to four projects, totaling 60.9 MW, under construction in Q1 2004.

Loss (Gain) on Derivative Financial Instruments

Loss on derivative financial instruments increased to $100,000 in Q1 2005 compared to a gain of $54,000 in Q1 2004. The increase in the loss was due to a decrease from January 1, 2005 to March 31, 2005 in the fair value of one of the Company's contract for differences ("CFD") that no longer qualified as a hedge during Q1 2005 by $478,000; offset partially by cash payments of $164,000 from another party in connection with the CFD in Q1 2005 and $43,000 for the recognition of the deferred credit associated with the CFD to income (see Note 3 to the interim consolidated financial statements). The increase in the loss was offset partially by an increase from December 31, 2004 to March 31, 2005 in the fair value of a contract by $123,000 (December 31, 2003 to March 31, 2004 - decrease in the fair value by $14,000), and by lower cash payments of $48,000 from another party in connection with the contract in Q1 2005 (Q1 2004 - $68,000). The contract is explained in Note 5 to the audited consolidated financial statements as at and for the year ended December 31, 2004.

Taxes

The Company does not anticipate paying income tax, 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. In Q1 2005, the LCT rate decreased from 0.2% to 0.175% of capital, less a $50,000,000 capital deduction, resulting in lower current tax expense compared to Q1 2004. 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 $165,000 in Q1 2005 compared to a recovery of $247,000 in Q1 2004. The increase was due to higher taxable earnings in the current quarter combined with tax pools available to the Company to offset current taxes to future periods compared to lower taxable earnings in Q1 2004.

Net Earnings (Loss) and Cash Flow from Operations

The Company had net earnings of $105,000 ($nil per share) in Q1 2005 compared to a net loss of $119,000 ($nil per share) in Q1 2004. The increase in net earnings was due to higher generation and lower interest on long-term debt; offset partially by lower average prices received for the Company's generation, higher operating and administration costs, loss on derivative financial instrument, and tax expense, as described above. Similarly, excluding non-cash items, cash flow from operations of $1,741,000 in Q1 2005 increased 140% from $725,000 in Q1 2004.

Capital Asset Additions and Prospect Development Costs

Capital asset additions were $19,953,000 in Q1 2005 (Q1 2004 - $5,923,000), resulting in a 9% increase in the net book value of capital assets. 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). 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 $429,000 in Q1 2005 (Q1 2004 - $295,000), relating primarily to costs associated with the Dunvegan Hydroelectric Prospect, and new hydroelectric and wind prospects in B.C. and Ontario (see Note 5 to the interim consolidated financial statements).



Financial Position

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

------------------------------------------------------------------------
Increase
(Decrease)
$ Explanation
------------------------------------------------------------------------
Cash 9,843 Increase due to Pingston Debt,
collection of year end receivables and
cash flow from operations in Q1 2005;
offset partially by capital asset
additions related to construction
projects, prospect development costs,
long-term debt repayments and payment of
accounts payable since year end.

Accounts receivable (164) Decrease in uncollected revenue from
wind and Ontario plants as generation
was lower in March than in December.

Revenue rebate 137 Increase due to Q1 2005 accrual for
revenue rebate and 2004 revenue rebate
that is typically refunded in Q2.

Prepaid expenses (204) Decrease due to amortization of certain
prepaids.

Derivative financial 89 Fair value change from December 31, 2004
instrument of a CFD that is no longer considered a
hedge as of January 1, 2004 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 March
31, 2005.

Deferred financing 485 Increase due to costs incurred on debt
costs financing that are amortized over the
life of the debt.

Capital assets 41,276 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(a) to the interim consolidated
financial statements), partially offset
by amortization.

Prospect development (6,981) Decrease due to the transfer of the
costs Melancthon Grey Wind Project into
construction-in-progress; offset
partially by the acquisition of
development prospects (see Note 6 to the
interim consolidated financial
statements) and costs related to the
development of new prospects.

Other liabilities (787) Decrease due to payments in amounts
owing to a third party (see Note 14(b)
to the audited consolidated financial
statements as at and for the year ended
December 31, 2004).

Accounts payable (1,014) Payment of project costs accrued at
and accrued December 31, 2004, partially offset by
liabilities project and deferred financing costs
accrued at March 31, 2005.

Deferred credit 401 Fair value of a CFD (see Note 3 to the
interim consolidated financial
statements), net of recognition to
income.

Revolving 3,700 Advances for payment of project costs
construction lines incurred on the Grande Prairie
of credit EcoPower® Centre, Upper Mamquam
Hydroelectric Plant.

Long-term debt 29,688 Increase due to the closing of the
Pingston Debt in February 2005,
partially offset by repayment of
long-term debt.

Future income taxes (68) Decrease due to the acquisition of a
future tax asset (see Note 7(a) to the
interim consolidated financial
statements), the tax effect on share
issue costs, and future income taxes
that are expected to be paid by the
Company in the future, based on the
Company's taxable position at March 31,
2005.

Share capital 12,375 Common share issuances for the
acquisition of Canadian Renewable Energy
Corporation and option exercises (see
Note 7(a) 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(a) to the interim consolidated financial statements.

The Company issued 495,000 common shares at an average exercise price of $0.58 per share for gross proceeds of $285,000 during Q1 2005. 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 $224,500,000 and are comprised of the Grande Prairie EcoPower® Centre, Upper Mamquam Hydroelectric and Melancthon Grey Wind Projects. At March 31, 2005, $121,447,000 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 $103,053,000 of capital expenditures will be financed through $27,316,000 in available credit from the Construction Lines and revolving reducing loan, $7,046,000 in working capital (excluding the Construction Lines), cash flow from operations, and an anticipated new construction line of credit in the amount of $72,000,000 for the Melancthon Grey Wind Project.

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 aggregate amount of U.S. dollar purchases is $57,810,000, which is fixed at a blended average rate of 1.207 for an aggregate Canadian dollar amount of $69,773,000. These foreign exchange contracts qualify as hedges under the CICA guideline on hedging relationships. At March 31, 2005, the fair value of the foreign exchange contract was a gain of $37,000. 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 March 31, 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 hedges under the CICA guideline on hedging relationships. The fair value of the interest rate swap at March 31, 2005 was a loss of $1,257,000 (December 31, 2004 - loss of $1,476,000). The change in fair value of the interest rate swap was due primarily to the increase in short term interest rates from December 31, 2004 to March 31, 2005, which were used in determining fair value.

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%. Effective March 31, 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 years 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 three months ended March 31, 2005, one of the Company's CFDs no longer qualified for hedge accounting (see Note 3 to the interim consolidated financial statements). At March 31, 2005, the fair value of the remaining CFDs that continue to qualify as hedges would result in a gain of $357,000.



Outstanding Share Data

-------------------------------------------------------
As at May 5, 2005
(Unaudited)
-------------------------------------------------------
Basic common shares 79,216,548
Convertible securities:
Options 3,448,900
-------------------------------------------------------
Fully diluted common shares 82,665,448
-------------------------------------------------------
-------------------------------------------------------


Outlook

The $63 million Grande Prairie EcoPower® Centre began generating steam heat and electricity in March 2005 and is expected to be fully commissioned in May 2005. The Company expects generation from this plant in 2005 to be approximately 110,000 MWh (175,000 MWh on a full year basis). The $38 million Upper Mamquam Hydroelectric Project and the $123 million Melancthon Grey Wind Project are expected to achieve commercial operations by the end of Q2 2005 and the end of Q1 2006, respectively. Once operational, these projects are expected to positively impact the Company's financial results in 2005 and onwards.

The Company has an installed capacity growth target of 53.2 MW in 2005, and has revised its originally targeted generation growth in 2005 over 2004 from 210,000 MWh to 190,000 MWh, resulting from the expected start-up of the Grande Prairie EcoPower® Centre being moved from Q1 2005 to May 2005. On an annualized basis, these projects are expected to generate approximately 300,000 MWh per year.

Reservoir levels in Alberta, where the Company's hydroelectric plants are located, are currently at above normal levels for this time of year due to the very warm and wet weather in the early part of 2005 and the more recent normal to near normal precipitation. Depending on the need for irrigation from farmers and ranchers this spring and summer, which impacts water flows to the Company's plants, the Company expects average to above average hydroelectric generation in Alberta for the remainder of the year.

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, which resulted in higher than normal water flows and hydroelectric generation in B.C. Snow packs in the mountains surrounding the Pingston and Akolkolex Hydroelectric Plants are currently at 86% of normal levels. The Company expects average hydroelectric generation at these plants for the remainder of the year because snow packs are near normal and water flows could be enhanced with glacial melt. Snow packs in the mountains surrounding the Upper Mamquam Hydroelectric Plant at March 31, 2005 were well below normal levels. Unless significant snow accumulations occurred in April and spring precipitation is at least normal, there is potential for low summer seasonal flow in the Mamquam River. While it is too early to determine this, the Company expects average to below average water levels and resulting generation at the Upper Mamquam Hydroelectric Project once it achieves commercial operations by the end of Q2 2005.

Ontario had a wet winter similar to the prior year and has experienced normal to below normal precipitation this spring. However, it is too early to determine whether this will result in hydroelectric generation in Ontario being different for the remainder 2005 versus 2004.

Pool prices in Q1 2005 ($46/MWh) were higher to those in Q1 2004 ($41/MWh) notwithstanding the addition of the 450 MW Genesee coal-fired generation plant in Alberta in December 2004. Pool prices for the remainder of 2005 are expected to be higher than those in Q1 2005 due to increased planned maintenance at other parties' large power plants, higher gas prices, and expected lower hydroelectric production in the Pacific Northwest. The average Pool price for April 2005 was $50/MWh, compared to $45/MWh for the month of March 2005 and $52/MWh for the month of April 2004. The average forward Pool price for May and June 2005 on the Alberta electricity forwards market is $59/MWh (May and June 2004 - $58/MWh), $59/MWh for Q3 2005 (Q3 2004 - $62/MWh) and $60/MWh for Q4 2005 (Q4 2004 - $61/MWh).



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

3 months ended March 31 2005 2004
------------------------------------------------------------------------

Revenue
Electric energy sales 5,096 3,982
Revenue rebate 137 170
------------------------------------------------------------------------
5,233 4,152
------------------------------------------------------------------------

Expenses (income)
Operating 1,525 1,246
Interest on long-term debt (Note 4) 1,248 1,325
Amortization 1,091 1,021
Administration (Note 4) 755 702
Loss (gain) on derivative financial
instrument (Note 3) 100 (54)
------------------------------------------------------------------------
4,719 4,240
------------------------------------------------------------------------

Earnings (loss) before taxes 514 (88)
------------------------------------------------------------------------

Tax expense (recovery)
Current 244 278
Future 165 (247)
------------------------------------------------------------------------
409 31
------------------------------------------------------------------------

Net earnings (loss) 105 (119)

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

Retained earnings, end of period 13,277 8,873
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per share (Note 8)
Basic - -
Diluted - -

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED BALANCE SHEETS (Unaudited)
(in thousands of dollars)
March 31, December 31,
2005 2004
------------------------------------------------------------------------

ASSETS
Current assets
Cash 11,277 1,434
Accounts receivable 2,724 2,888
Revenue rebate 647 510
Taxes receivable 28 41
Prepaid expenses 424 628
Derivative financial instruments (Note 3) 343 254
------------------------------------------------------------------------
15,443 5,755

Deferred financing costs (Note 6(a)) 485 -
Capital assets (Note 4) 261,813 220,537
Prospect development costs (Note 5) 10,318 17,299
------------------------------------------------------------------------

TOTAL ASSETS 288,059 243,591
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES
Current liabilities
Other liabilities 1,503 2,290
Accounts payable and accrued liabilities 5,459 6,473
Deferred credit (Note 3) 401 -
Current portion of long-term debt (Note 6(a)) 1,736 1,697
Revolving construction lines of credit (Note 6(b)) 32,500 28,800
------------------------------------------------------------------------

41,599 39,260

Long-term debt (Note 6(a)) 94,449 64,800
Future income taxes 18,191 18,259
------------------------------------------------------------------------

154,239 122,319
------------------------------------------------------------------------
Commitments and contingencies (Note 9)

SHAREHOLDERS' EQUITY
Share capital (Note 7(a)) 120,154 107,779
Contributed surplus (Note 8) 389 321
Retained earnings 13,277 13,172
------------------------------------------------------------------------

133,820 121,272
------------------------------------------------------------------------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 288,059 243,591
------------------------------------------------------------------------
------------------------------------------------------------------------

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 March 31 2005 2004
------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings (loss) 105 (119)
Adjustments for:
Amortization 1,091 1,021
Loss on derivative financial instrument (Note 3) 312 14
Stock compensation expense (Note 8) 68 56
Future income tax expense (recovery) 165 (247)
------------------------------------------------------------------------

Cash flow from operations 1,741 725
Changes in non-cash working capital (5,442) (3,859)
------------------------------------------------------------------------

(3,701) (3,134)
------------------------------------------------------------------------

FINANCING ACTIVITIES
Issue of common shares, net of issue costs (Note 7) 250 104
Long-term debt advances (Note 6(a)) 35,000 -
Long-term debt repayments (5,312) (1,531)
Revolving construction lines of credit advances 3,700 -
Deferred financing costs (350) -
------------------------------------------------------------------------

33,288 (1,427)
------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital asset additions (19,953) (5,923)
Prospect development costs (429) (295)
Net cash acquired on acquisition (Note 7(b)) 638 -
Proceeds on sale of capital assets - 17
------------------------------------------------------------------------

(19,744) (6,201)
------------------------------------------------------------------------

NET INCREASE (DECREASE) IN CASH 9,843 (10,762)
CASH, BEGINNING OF PERIOD 1,434 13,781
------------------------------------------------------------------------
------------------------------------------------------------------------

CASH, END OF PERIOD 11,277 3,019
------------------------------------------------------------------------
------------------------------------------------------------------------

Supplemental information
Cash interest paid 1,948 1,311
Cash income and capital taxes paid 231 276

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
March 31, 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.

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 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 INSTRUMENTS

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 three months ended March 31, 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 was recognized into income as a gain on derivative financial instrument during the three months ended March 31, 2005. During the three months ended March 31, 2005, $164,000 in payments received from the other party in connection with the Contract were recognized into income as a gain on derivative financial instrument and the decrease in the fair value of $478,000 was recognized into income as a loss on derivative financial instrument, resulting in a derivative financial instrument liability of $34,000. Fair value was determined by taking the difference between the fixed purchase price for electricity and the forward market selling price for electricity for 2005 through 2007 and the contract price for 2008 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 March 31, 2005, the CFD was determined to re-qualify as a hedge and hedge accounting commenced on April 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.

4. CAPITAL ASSETS

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



March 31, December 31,
2005 2004
--------------------------------------------
Accumulated Net Book Net Book
Cost Depreciation Value Value
$ $ $ $
--------------------------------------------

Generating plants
- operating 163,427 23,901 139,526 133,478
- construction-in-progress 121,447 - 121,447 86,295
Vehicles 795 535 260 175
Equipment, other 1,303 723 580 589
--------------------------------------------

286,972 25,159 261,813 220,537
--------------------------------------------
--------------------------------------------


For the 3 months ended March 31, 2005, interest costs of $645,000 (3 months ended March 31, 2004 - $nil) and administration expenses of $218,000 (3 months ended March 31, 2004 - $146,000) associated with the construction-in-progress have been capitalized during construction. At March 31, 2005, construction-in-progress is comprised of costs relating to the Grande Prairie EcoPower® Centre, Upper Mamquam Hydroelectric Project and Melancthon Grey Wind Project (March 31, 2004 - Grande Prairie EcoPower® Centre, Taylor Wind Project, and Pingston Expansion and Upper Mamquam Hydroelectric Projects). During the 3 months ended March 31, 2005, costs of $11,957,000 for the Melancthon Grey Wind Project were transferred to construction-in-progress from prospect development costs, including prospect development costs (see Note 7(a)).



5. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

March 31, December 31,
2005 2004
$ $
--------------------------------

Dunvegan Hydroelectric Prospect 7,181 6,885
Wind prospects 1,720 9,297
Hydroelectric prospects 1,417 1,117
--------------------------------

Total 10,318 17,299
--------------------------------
--------------------------------


6. CREDIT FACILITIES

(a) Long-term debt

At March 31, 2005, the Company had $4,716,000 available and undrawn on its revolving reducing loan (the "Loan") with its corporate lenders.

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 six through 10. At March 31, 2005, the fair value of the interest rate swap was a loss of $1,257,000 (December 31, 2004 - loss of $1,476,000).

At March 31, 2005, the Company had letters of credit in the amount of $15,549,000 (December 31, 2004 - $15,345,000) outstanding with its corporate lenders.

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), 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 proceeds from this financing will be 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.



2005 2004
$ $
-------------------
Revolving reducing loan, bearing interest at prime 44,735 49,635
plus 0.75% or Bankers' Acceptances plus a 2%
stamping fee (see above for interest rate swap)
with monthly interest payments

Pingston Debt (described above) 35,000 -

Mortgage on Cowley, bearing interest at 10.867%, 8,174 8,312
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

Mortgage, bearing interest at 10.7% and secured 3,980 4,122
by letter of guarantee. Monthly repayments of
principal and interest are $84,000 until
May 31, 2010

Mortgage, bearing interest at 10.68%, secured 2,905 3,000
by letters of guarantee. Monthly repayments of
principal are $31,000 plus interest until
December 30, 2012

Promissory note, bearing interest fixed at 6%, 1,391 1,428
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
-------------------

96,185 66,497

Less current portion 1,736 1,697
-------------------

Long-term debt 94,449 64,800
-------------------
-------------------


(b) Revolving construction lines of credit

At March 31, 2005, $32,500,000 was drawn by the Company (December 31, 2004 - $28,800,000), leaving $22,600,000 of available undrawn Construction Lines (December 31, 2004 - $26,300,000).



7. SHARE CAPITAL

(a) Issued, common shares

Number of
Shares Amount $
------------------------
Balance, December 31, 2004 74,683,861 107,779
Issued on acquisition 4,037,687 12,113
Issued on exercise of stock options 495,000 285
Share issue costs, net of tax effect of $12,000 - (23)
------------------------

Balance, March 31, 2005 79,216,548 120,154
------------------------
------------------------


(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 March 31,
2005 2004
-------------------------

Basic weighted average shares outstanding 77,868,673 68,902,830
Effect of dilutive securities:
Options 2,092,914 1,703,123
-------------------------

Diluted weighted average shares 79,961,587 70,605,953
-------------------------
-------------------------


Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $68,000 or $nil per share (3 months ended March 31, 2004 - $56,000 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 and for the 3 months ended March 31, 2005. The weighted average fair value of options granted during the 3 months ended March 31, 2005 was $1.71 per share, which was estimated using the Black-Scholes option-pricing model, assuming a risk free interest rate of 4.28%, expected volatility of 37.53%, expected weighted average life of eight years, and no annual dividends paid. There were no options granted during the 3 months ended March 31, 2004.

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 March 31, 2005, and an increase in net loss of $31,000 or $nil per share for the 3 months ended March 31, 2004.

9. 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 aggregate amount of U.S. dollar purchases is $57,810,000, which is fixed at a blended average rate of 1.207 for an aggregate Canadian dollar amount of $69,773,000. At March 31, 2005, the fair value of the foreign exchange contracts would result in a gain of $37,000.

(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%. Effective March 31, 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 years 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 three months ended March 31, 2005, one of the Company's CFDs no longer qualified as a hedge and hedge accounting was discontinued for the contract (see Note 3). At March 31, 2005, the fair value of the remaining CFDs that continue to qualify as hedges would result in a gain of $357,000.

(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 March 31, 2005, the Company has committed to approximately $15,801,000 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.

10. SUBSEQUENT EVENT

Subsequent to March 31, 2005, the Company settled a lawsuit it had with a former insurer and engineering firm associated with a project, resulting in a cash payment of $750,000 by the insurer and engineering firm to the Company, net of associated costs. The proceeds from the settlement will be recognized as a gain in the Company's consolidated statement of earnings for the three and six months ended June 30, 2005.

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