Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

August 14, 2006 13:05 ET

Canadian Hydro Announces Second Quarter Results

CALGARY, CANADA--(CCNMatthews - Aug. 14, 2006) - Canadian Hydro Developers, Inc. (TSX:KHD) ("Canadian Hydro" or the "Company") reported cash flow from operations(2) of $8,034,000 ($0.07 per share, diluted(3)) on generation of 222 million kWh for the second quarter ended June 30, 2006 ("Q2 2006"), compared to cash flow from operations(2) of $3,639,000 ($0.05 per share, diluted(3)) on generation of 124 million kWh for Q2 2005. The Company reported net earnings of $5,712,000 ($0.05 per share, diluted) for Q2 2006, compared to net earnings of $1,713,000 ($0.02 per share, diluted) for Q2 2005.

Cash flow from operations(2) for the 6 months ended June 30, 2006 increased to $10,121,000 ($0.08 per share, diluted(3)) on generation of 349 million kWh, compared to $5,380,000 ($0.07 per share, diluted(3)) on generation of 205 million kWh for the same period in 2005. Net earnings for the 6 months ended June 30, 2006 were $5,276,000 ($0.04 per share, diluted(3)), compared to $1,818,000 ($0.02 per share, diluted(3)) for the same period in 2005.

Consistent quarter-over-quarter same plant operations, combined with the early start-up of the 67.5 MW Melancthon I Wind Plant ("Melancthon I"), the contribution from the July 2005 commissioned Upper Mamquam Hydroelectric Plant ("Mamquam"), interest income from the investment of cash on hand, and lower taxes due to reduced corporate tax rates led to improved financial results for Q2 2006. This was offset partially by lower than expected operating results from the Grande Prairie EcoPower® Centre ("GPEC").



3 Months Ended 6 Months Ended
June 30, June 30,
(unaudited) 2006 2005 2006 2005
------------------------------------------------------------------------
Financial Results (in thousands of
dollars except per share amounts)
Revenue 14,457 6,983 23,399 12,216
EBITDA(1) 9,902 5,103 13,669 8,336
Cash flow from operations(2) 8,034 3,639 10,121 5,380
Per share (diluted)(3) 0.07 0.05 0.08 0.07
Net earnings 5,712 1,713 5,276 1,818
Per share (diluted) 0.05 0.02 0.04 0.02

Operating Results
Electricity generation - MWh (net) 222,445 123,507 349,309 204,760
Average price received per MWh ($) 65 57 67 60
Electrical generation under contract (%) 91 85 90 85
------------------------------------------------------------------------
(1) EBITDA is provided to assist management and investors in determining
the ability of the Company to generate cash from operations2. EBITDA
as presented is defined as cash flow from operations2, plus interest
on debt, net of interest income, and current tax expense. This
measure does not have any meaning prescribed in Canadian generally
accepted accounting principles ("GAAP") and may not be comparable to
similar measures presented by other companies.
(2) Cash flow from operations before changes in non-cash working
capital.
(3) Cash flow from operations(2) per share (diluted) is provided to
assist management and investors in determining the Company's cash
flow from operations(2) on a per share basis and does not have any
meaning prescribed in GAAP and may not be comparable to similar
measures presented by other companies.


Q2 2006 Achievements:

- Closed on the issuance of $148 million in senior unsecured debentures for which Dominion Bond Rating Service confirmed its investment grade credit rating of BBB with a Stable trend for the Company; and

- Made progress on the application to the joint Alberta Energy and Utilities Board and Natural Resources Conservation Board for the Company's Dunvegan Hydroelectric Prospect in Alberta, which is expected to be submitted in the summer of 2006.

Subsequent to Q2 2006, the Company was awarded one 20 year and three 40 year Electricity Purchase Agreements from BC Hydro for the supply of 44.5 MW of electricity from hydroelectric projects. The power will come from the 20 MW Bone Creek, 9.9 MW Clemina Creek, 9.6 MW Serpentine Creek and 5 MW English Creek Hydroelectric Projects.

"The issuance of additional corporate debentures this quarter consistent with the investment grade debt structure established in September 2005 brings Canadian Hydro closer to our debt financing target of 65% of capital costs," said John Keating, Chief Executive Officer. "This lower weighted average cost of capital affords the Company the required financial flexibility and appropriate leverage to finance future growth."

Canadian Hydro is a developer, owner and operator of 18 renewable energy generation facilities totalling net 230 MW in operation and has an additional 385 MW nearing construction. The renewable generation portfolio is diversified across three technologies (water, wind and biomass) in the provinces of British Columbia, Alberta and Ontario. This portfolio is unique in Canada as all facilities are certified, or slated for certification, under Environment Canada's EcoLogo(M) Program.

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: 119,357,523


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

The following MD&A, dated August 4, 2006, should be read in conjunction with the unaudited interim consolidated financial statements as at and for the 3 and 6 months ended June 30, 2006 and 2005, 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, 2005. 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 2006, revenue increased 107% to $14,457,000 on generation of 222 million kWh compared to $6,983,000 on generation of 124 million kWh in Q2 2005. For the 6 months ended June 30, 2006, revenue increased 92% to $23,399,000 on increased generation of 349 million kWh compared to $12,216,000 on generation of 205 million kWh for the same period in 2005. For Q2 2006, the increase in revenue was due to a 40% increase in generation as a result of new plant additions, including the Melancthon I Wind Plant ("Melancthon I"), which became operational nearly one month ahead of schedule, the Grande Prairie EcoPower® Centre ("GPEC") and the Upper Mamquam Hydroelectric Plant ("Mamquam"). On a same plant basis, the Company experienced higher hydroelectric generation in B.C. and Alberta due to warm and wet weather and higher wind generation due to a windier season in Alberta. Hydroelectric generation in Ontario was consistent with the prior year.

For the 6 months ended June 30, 2006, the increase in revenue was due to the increase in generation as a result of new plant additions as discussed above, in addition to a windier season in Alberta. Hydroelectric generation in B.C. was lower compared to the prior year, mainly due to much higher than normal generation in the first quarter of 2005, as a result of extremely warm and wet weather. Hydroelectric generation in Ontario was consistent with the prior year generation.

Approximately 91% of the Company's generation was sold pursuant to long-term sales contracts in Q2 2006 and 90% for the 6 months ended June 30, 2006 (Q2 2005 and 2005 - 85%). The average price received by the Company for electricity from all operations for Q2 2006 was $65/MWh and $67/MWh for the 6 months ended June 30, 2006 (Q2 2005 - $57/MWh; 2005 - $60/MWh).



Electricity Generation - by Province and Technology

------------------------------------------------------------------------
Electricity Generation - MWh(1)
------------------------------------------------------------------------
Q2 2006 Q2 2005 Variance 2006 2005 Variance
------------------------------------------------------------------------
British Columbia 96,176 57,302 + 68% 115,053 77,865 + 48%
Alberta 68,413 41,792 + 64% 141,125 82,942 + 70%
Ontario 57,856 24,413 + 137% 93,131 43,953 + 112%
------------------------------------------------------------------------
Totals 222,445 123,507 + 80% 349,309 204,760 + 71%
------------------------------------------------------------------------
Hydroelectric 142,081 98,492 + 44% 189,937 146,180 + 30%
Wind 62,117 23,245 + 167% 115,431 56,810 + 103%
Biomass 18,247 1,770 + 931% 43,941 1,770 + 2382%
------------------------------------------------------------------------
Totals 222,445 123,507 + 80% 349,309 204,760 + 71%
------------------------------------------------------------------------
(1) Reflecting the Company's net interest.

------------------------------------------------------------------------
Electricity Generation for Same Plants MWh(1)(2)
------------------------------------------------------------------------

Q2 2006 Q2 2005 Variance 2006 2005 Variance
------------------------------------------------------------------------
Hydroelectric 105,348 98,492 + 7% 141,625 146,180 (3)%
Wind 28,487 23,244 + 23% 68,111 56,810 + 20%
------------------------------------------------------------------------
Totals 133,835 121,736 + 10% 209,736 202,990 + 3%
------------------------------------------------------------------------
(1) Reflecting the Company's net interest.
(2) Biomass generation excluded for comparison purposes as operational
for 9 days only during the 6 months ended June 30, 2005.



Electricity Generation for New Plants - MWh(1)
------------------------------------------------------------------------
Q2 2006 2006
------------------------------------------------------------------------
Melancthon I 33,629 47,320
GPEC 18,247 43,941
Mamquam 36,734 48,312
------------------------------------------------------------------------
Total - new 88,610 139,573
------------------------------------------------------------------------
(1) Reflecting the Company's net interest.


Operating Expenses

Operating expenses increased 92% to $3,941,000 in Q2 2006 compared to $2,056,000 in Q2 2005. For the 6 months ended June 30, 2006, operating expenses increased 131% to $8,255,000 from $3,581,000 for the same period in 2005. Gross margins (revenue less operating expenses; expressed as a percentage of revenue) of 73% in Q2 2006 were slightly higher than Q2 2005 (71%). Gross margins for the 6 months ended June 30, 2006 were lower at 65% compared to 71% for the same period in 2005. The increase in operating expenses was due primarily to the addition of biomass operations in Q2 2005, which has higher operating expenses and lower gross margins than the Company's hydroelectric and wind plants, and the addition of Melancthon I and Mamquam with little or no comparable operating expenses in Q2 2005. In addition, GPEC continued to encounter issues with commissioning during 2006, resulting in higher than expected operating expenses. However, GPEC has seen an improvement over the prior year and continued improvement into the third quarter of 2006. Excluding GPEC, the gross margins for Q2 2006 and the 6 months ended June 30, 2006 were 85% and 80%, respectively, an improvement over 2005.

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

Interest on long-term debt (excluding capitalized interest) in Q2 2006 increased 133% to $2,837,000 compared to $1,219,000 in Q2 2005 and for the 6 months ended June 30, 2006, increased 122% to $5,489,000 from $2,467,000 for the same period in 2005. The increase was due to higher outstanding corporate debt, mainly due to the issuance of the unsecured corporate debentures (the "Debentures") in September 2005 and June 2006.

Interest income from the investment of cash on hand in term deposits in Q2 2006 and for the six months ended June 30, 2006 was $1,069,000 and $2,384,000, respectively (2005 - $nil).

Capitalized interest associated with construction-in-progress in Q2 2006 was $83,000 (Q2 2005 - $990,000) and $509,000 for the 6 months ended June 30, 2006 (2005 - $1,635,000). The decrease was due to fewer projects under construction compared to the prior year (Q2 2006 - Melancthon II; 2006 - Melancthon I and Melancthon II; Q2 2005 and 2005 - Melancthon I, GPEC and Mamquam).

Long-term debt (including current portion) as at June 30, 2006 was $317,265,000 (June 30, 2005 - $99,466,000) compared to $226,765,000 as at December 31, 2005. In June 2006, the Company closed the issuance of an aggregate of $148,000,000 of Debentures in two series by way of private placement. The Series 2 senior unsecured debentures, with a gross principal amount of $27,000,000, have a 10-year term maturing on June 19, 2016 and bear an interest rate of 5.69% per annum with interest paid semi-annually. The Series 3 senior unsecured debentures with a gross principal amount of $121,000,000 have a 12-year term maturing on June 19, 2018 and bear an interest rate of 5.77% per annum with interest paid semi-annually. The proceeds from the debentures were used to retire the Company's construction credit facility for Melancthon I and to fund capital costs associated with the construction of Melancthon II and Wolfe Island and for general corporate purposes. Dominion Bond Rating Service Ltd. ("DBRS") confirmed its rating of BBB with a Stable trend for the Debentures. The offsetting decrease to long-term debt was due to regular repayments during the 6 months ended June 30, 2006.

As at June 30, 2006, the Company has a 49/51 debt/equity mixture (December 31, 2005 - 41/59) compared to a stated target of 65/35. The debt/equity mixture changed from the prior year due to the issuance of the Debentures, offset by using cash flow from operations and cash received from the equity issuance in December 2005 to finance costs related to construction projects as opposed to increasing drawings on the construction facility, which was retired in June 2006.

Amortization Expense

Amortization expense increased 155% to $3,057,000 for Q2 2006 (Q2 2005 - $1,201,000), and 135% to $5,388,000 for the 6 months ended June 30, 2006 (2005 - $2,292,000) due to the addition of Melancthon I in March 2006, Mamquam in July 2005 and GPEC in June 2005. The wind plant is amortized over a 30 year period and the hydroelectric and biomass plants are amortized over a 40 year period.

Administration Expense

Administration expense increased to $987,000 in Q2 2006 (Q2 2005 - $53,000), and increased to $2,315,000 for the 6 months ended June 30, 2006 (2005 - $808,000). In Q2 2005, the Company received 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. The increase in 2006 was also due to moderately higher salary costs with the addition of new employees and increased stock compensation expense due to a higher fair value associated with options granted (Q2 2006 - 410,000; 2006 - 2,105,000; Q2 2005 - 980,000; 2005 - 1,080,000). Capitalized administration costs associated with construction-in-progress in Q2 2006 were $336,000 (Q2 2005 - $396,000), and $1,097,000 for the 6 months ended June 30, 2006 (2005 - $614,000). In Q2 2006, Melancthon II (132 MW) was being readied for construction, and Melancthon I (67.5 MW) was under construction during the first quarter of 2006. In 2005, GPEC, Mamquam, and Melancthon I, totaling 117.5 MW, were under construction.

Financial Instruments

When a contract does not meet the criteria for hedge accounting, the changes in the fair value are recorded in income as either a gain or a loss, with a corresponding asset or liability, respectively, on the balance sheet. The gain on derivative financial instrument is $43,000 in Q2 2006 with a loss on derivative financial instrument of $159,000 for the 6 months ended June 30, 2006 compared to a gain of $216,000 in Q2 2005 (2005 - $116,000). In Q2 2006, the loss is comprised of the $43,000 recognition of the deferred credit into income relating to a contract for differences ("CFD") that did not qualify for hedge accounting in the prior year. For the 6 months ended June 30, 2006, the loss is a result of the $401,000 fair value decrease of a CFD that expired during the year, offset partially by $156,000 in cash payments from another party in connection with the expired CFD and the $86,000 recognition of the deferred credit. In Q2 2005, the gain was comprised of a $46,000 increase in the fair value of various CFDs, $127,000 in cash payments received from other parties relating to CFDs and the $43,000 amortization into income of the deferred credit (see above). For the 6 months ended June 30, 2005, in addition to the above, the gain included a $191,000 decrease in the fair value of various CFDs, $48,000 in cash payments received from another party in connection with the expired CFD and the $43,000 recognition of the deferred credit.

As disclosed in the December 31, 2005 MD&A, the Company has entered into various CFDs with other parties whereby the other parties have agreed to pay a fixed price to the Company based on the average monthly Pool price for an aggregate of 184,330 MWh per year of electricity from January 1, 2006, maturing from 2007 to 2024. At June 30, 2006, the fair value of the CFDs that qualify as hedges would result in a loss of $256,000.

Taxes

The Company does not anticipate paying cash income taxes for several years, other than in respect of the Cowley Ridge Wind Plant, through its wholly owned subsidiary, Cowley Ridge Wind Power Inc. The Company is also liable for Provincial Capital Taxes in Ontario, which comprise the current tax provision. On May 2, 2006, the Federal Government passed a budget that eliminated the Federal Tax on Large Corporations ("LCT") effective January 1, 2006, and as a result, the Company has lower current taxes compared to the prior year.

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 recovery was $1,040,000 in Q2 2006 (Q2 2005 - future tax expense of $790,000), and $1,453,000 for the 6 months ended June 30, 2006 (2005 - future tax expense of $955,000). The difference is due to a reduction in the corporate tax rates as a result of the May 2006 budget as discussed above, in addition to changes in taxable earnings during the periods, combined with tax pools available to the Company to offset current taxes to future periods.

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

Net earnings were $5,712,000 ($0.05 per share) in Q2 2006 compared to $1,713,000 ($0.02 per share) in Q2 2005. The increase is due to the future tax recovery, contributions from new plant additions including Melancthon I and Mamquam, and interest income from the investment of cash on hand; offset partially by lower than expected operating results from GPEC. GPEC operating results have not met expectations; however, they have improved over the prior year and continue to improve in Q3 2006 as the Company continues to focus on operational improvements. For the 6 months ended June 30, 2006, net earnings were $5,276,000 ($0.04 per share) compared to $1,818,000 ($0.02 per share) for the same period in the prior year. The year-to-date increase was due to the same factors as Q2 2006, in addition to higher revenue from the addition of Melancthon I on March 4, 2006. Similarly, excluding non-cash items, cash flow from operations was $8,034,000 for Q2 2006 (Q2 2005 - $3,639,000) and $10,121,000 for the 6 months ended June 30, 2006 (2005 - $5,380,000).

Capital Asset Additions and Prospect Development Costs

Capital asset additions were $66,823,000 in Q2 2006 (Q2 2005 - $35,600,000) and $90,457,000 for the 6 months ended June 30, 2006 (2005 - $55,553,000), resulting in a 24% increase in the net book value of capital assets since December 31, 2005. These additions relate to construction costs associated with Melancthon I, which achieved commercial operations on March 4, 2006, and Melancthon II, which is currently in the approvals process. Additions of prospect development costs were $1,680,000 in Q2 2006 (Q2 2005 - $890,000) and $10,370,000 for the 6 months ended June 30, 2006 (2005 - $1,319,000), relating primarily to wind turbine equipment deposits for Wolfe Island.

Financial Position

The following chart outlines significant changes in the consolidated balance sheet from December 31, 2005 to June 30, 2006:



------------------------------------------------------------------------
Increase (Decrease) Explanation
$
------------------------------------------------------------------------
Cash (5,344) Decrease due to capital asset
additions for Melancthon I
and Melancthon II, prospect
development costs, long-term
debt repayments and payments
of accounts payable since
year end; offset partially by
the issuance of Debentures,
interest income received on
cash invested in term
deposits, cash flow from
operations, and the issuance
of common shares through the
exercise of stock options.

Accounts receivable 2,795 Increase in uncollected
revenue due to new plant
additions and higher
generation in June 2006
compared to December 2005.

Capital assets 87,535 Construction costs related to
Melancthon I and Melancthon
II; partially offset by
amortization.

Prospect development costs 10,868 Increase due to costs related
to the development of Wolfe
Island (see Note 5 to the
interim consolidated
financial statements).

Long-term debt (including current
portion) 90,500 Issuance of Debentures;
offset by repayment of
construction credit facility
for Melancthon I and regular
repayments on long-term debt.

Future income taxes (1,427) Decrease due to a reduction
in the federal corporate tax
rates as enacted in the May
2006 Federal Budget.
------------------------------------------------------------------------


Capital Resources and Liquidity

The Company's current capital expenditure plans total approximately $717,000,000 for the construction of three projects in Ontario from 2006 to 2008. Up to $190,200,000 of the capital costs will be financed from proceeds of the public offering completed in 2005 and anticipated future offerings, a further $62,500,000 from expected future cash flow to be generated by the Company and potential future equity offerings, and the remaining $464,300,000 through completed and anticipated debt financings.

In Q2 2006, the Company issued 21,250 common shares (Q2 2005 - 153,500) through the exercise of stock options at an average exercise price of $2.08 per share (Q2 2005 - $1.11 per share) for gross proceeds of $44,000 (Q2 2005 - $170,000). For the 6 months ended June 30, 2006, the Company issued 1,086,150 common shares (2005 - 648,500) through the exercise of stock options at an average exercise price of $0.99 per share (2005 - $0.70) for gross proceeds of $1,073,000 (2005 - $455,000).

Disclosure Controls

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



Outstanding Share Data

------------------------------------------------------------------------
As at August 4, 2006
(Unaudited)
------------------------------------------------------------------------
Basic common shares 119,357,523
Convertible securities:
Warrants 500,000
Options 5,128,500
------------------------------------------------------------------------
Fully diluted common shares 124,986,023
------------------------------------------------------------------------
------------------------------------------------------------------------


Outlook

Reservoir levels in Alberta, where four of the Company's hydroelectric plants are located, are currently at above normal levels for this time of year. Depending on the need for irrigation from farmers and ranchers this 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.

In B.C., snow packs in the mountains surrounding Mamquam are currently at slightly above normal levels. Provided that precipitation levels are normal, the Company expects average to above average water levels for the next quarter. Snow packs in the mountains surrounding the Pingston and Akolkolex Hydroelectric Plants are currently at below normal levels due to a warm spring which led to snowmelt earlier than normal in the season. 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 at these plants for the remainder of the year.

Precipitation in Ontario is normal and is expected to be slightly below normal this summer. However, it is too early to determine whether hydroelectric generation at the Company's plants will be different for the remainder of 2006 versus 2005.

Due to a longer than expected approvals process for the Melancthon II Wind Project, resulting primarily from the provincial Environmental Screening Process, the Company has not yet commenced construction of this 132 MW project. The Company is confident that all expressed issues will be dealt with fairly and the Ontario Ministry of Environment will issue their approval for Melancthon II. Canadian Hydro expects this project to be completed and operational by June 2008; a change to the anticipated in-service date for the project by up to 12 months. The extended approvals process has resulted in an increase of $10,000,000 for a capital cost of $275,000,000. Securing other permits and approvals for Melancthon II remains necessary prior to proceeding to construction; delays in which may also impact the ultimate in-service date and capital cost for the project.

The Company continues to pursue the development of the Dunvegan Hydroelectric Prospect. With the two-year physical modeling program on the plant for fish passage complete, the Company plans to submit its application to the joint Alberta Energy and Utilities Board and Natural Resources Conservation Board in the summer of 2006, with a possible hearing date in the spring of 2007, and a regulatory decision in the summer of 2007. In addition, the Company is working diligently on obtaining the necessary permits and approvals for the 44.5 MW of hydroelectric projects recently awarded Electricity Purchase Agreements from BC Hydro.



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,
2006 2005 2006 2005
------------------------------------------------------------------------
------------------------------------------------------------------------

Revenue
Electric energy sales 14,338 6,888 23,121 11,984
Revenue rebate 119 95 278 232
------------------------------------------------------------------------
14,457 6,983 23,399 12,216
------------------------------------------------------------------------

Expenses (Other Income)
Operating 3,941 2,056 8,255 3,581
Interest on long-term debt (Note 4) 2,837 1,219 5,489 2,467
Interest income (1,069) - (2,384) -
Amortization 3,057 1,201 5,388 2,292
Administration (Note 4) 987 53 2,315 808
(Gain) loss on derivative financial
instrument (Note 3) (43) (216) 159 (116)
Foreign exchange gain (25) - (89) -
Gain on sale of development
prospects - (78) - (78)
------------------------------------------------------------------------
9,685 4,235 19,133 8,954
------------------------------------------------------------------------

Earnings before taxes 4,772 2,748 4,266 3,262
------------------------------------------------------------------------

Tax (recovery) expense
Current 100 245 443 489
Future (1,040) 790 (1,453) 955
------------------------------------------------------------------------
(940) 1,035 (1,010) 1,444
------------------------------------------------------------------------

Net earnings 5,712 1,713 5,276 1,818

Retained earnings, beginning of
period 13,556 13,277 13,992 13,172
------------------------------------------------------------------------

Retained earnings, end of period 19,268 14,990 19,268 14,990
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per share (Note 8)
Basic 0.05 0.02 0.04 0.02
Diluted 0.05 0.02 0.04 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,
2006 2005
------------------------------------------------------------------------
------------------------------------------------------------------------

ASSETS
Current assets
Cash and cash equivalents 174,457 179,801
Accounts receivable 8,973 6,178
Revenue rebate 793 515
Prepaid expenses 709 771
Taxes receivable 94 -
Derivative financial instrument (Note 3) - 401
------------------------------------------------------------------------

185,026 187,666

Deferred financing costs 3,043 2,072
Capital assets (Note 4) 451,061 363,526
Prospect development costs (Note 5) 40,953 30,085
------------------------------------------------------------------------

TOTAL ASSETS 680,083 583,349
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES

Current liabilities
Accounts payable and accrued liabilities 10,304 9,252
Current portion of long-term debt (Note 6) 1,915 1,838
Deferred credit (Note 3) 186 272
Taxes payable - 251
------------------------------------------------------------------------

12,405 11,613

Long-term debt (Note 6) 315,350 224,927
Future income taxes 18,804 20,231
------------------------------------------------------------------------

346,559 256,771
------------------------------------------------------------------------

Commitments and contingencies (Note 9)

SHAREHOLDERS' EQUITY
Share capital (Note 7) 312,877 311,771
Contributed surplus (Note 8) 1,379 815
Retained earnings 19,268 13,992
------------------------------------------------------------------------

333,524 326,578
------------------------------------------------------------------------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 680,083 583,349
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

Approved by the Board
"signed" "signed"
David J. Stenason Kevin Brown

CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands of dollars)
3 months ended 6 months ended
June 30, June 30,
2006 2005 2006 2005
------------------------------------------------------------------------
------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings 5,712 1,713 5,276 1,818
Adjustments for:
Amortization 3,057 1,201 5,388 2,292
Future income tax (recovery)
expense (1,040) 790 (1,453) 955
Stock compensation expense (Note 8) 348 103 595 171
(Gain) loss on derivative financial
instrument (Note 3) (43) (90) 315 222
Gain on sale of development
prospects - (78) - (78)
------------------------------------------------------------------------

Cash flow from operations before
changes in non-cash working
capital 8,034 3,639 10,121 5,380
Changes in non-cash working capital (1,899) (1,417) (5,512) (6,859)
------------------------------------------------------------------------

6,135 2,222 4,609 (1,479)
------------------------------------------------------------------------

FINANCING ACTIVITIES
Issue of common shares, net of
issue costs (Note 7) 44 170 1,073 420
Revolving construction lines of
credit advances - 19,400 - 23,100
Construction credit facility
repayments (Note 6) (56,600) - (56,600) -
Deferred financing costs (713) (170) (699) (520)
Long-term debt advances (Note 6) 148,000 8,400 148,000 43,400
Long-term debt repayments (454) (5,119) (900) (10,431)
------------------------------------------------------------------------

90,277 22,681 90,874 55,969
------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital asset additions (66,823) (35,600) (90,457) (55,553)
Prospect development costs (1,680) (890) (10,370) (1,319)
Net cash acquired on acquisition - - - 638
Proceeds on sale of development
prospects - 310 - 310
------------------------------------------------------------------------

(68,503) (36,180) (100,827) (55,924)
------------------------------------------------------------------------

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 27,909 (11,277) (5,344) (1,434)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 146,548 11,277 179,801 1,434
------------------------------------------------------------------------

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

Supplemental information
Cash interest paid 382 1,908 3,398 3,856
Cash income and capital taxes paid 331 301 573 532

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006 and 2005 (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.

Certain hydroelectric activities of the Company are conducted jointly with others and accordingly, the accounts reflect only the proportionate interest of the Company's 50% owned unincorporated joint ventures.

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.

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 2006.

3. DERIVATIVE FINANCIAL INSTRUMENTS

To support the Company's obligations under a guarantee to a third party, the Company entered into a contract with another party whereby the other party will pay the Alberta Power Pool price to the Company in return for the Company paying the other party a fixed price for approximately 5 MW of electricity per year for three years commencing April 1, 2003. As at December 31, 2005, the Company had recorded $401,000 as a derivative financial instrument asset representing the fair value of the contract. In 2006, this contract expired and as a result, the asset was reversed to reflect a $nil fair market value with a corresponding $401,000 loss on derivative financial instrument recorded into income. Offsetting this loss was $156,000 in payments received from the other party in connection with this contract recognized into income as a gain on derivative financial instruments during the year.

Included in the loss on derivative financial instrument for Q2 2006 is $43,000 (Q2 2005 - $43,000) and for the 6 months ended June 30, 2006, $86,000 (2005 - $86,000) for the amortization of the deferred credit related to a contract that did not qualify for hedge accounting in the prior year. The deferred credit is recognized into income over the life of the contract.

The Company has entered into various foreign exchange contracts, expiring in 2007, which fix the Company's U.S. dollar and Euro payments under wind turbine purchase contracts in Canadian dollars. The aggregate remaining amount of U.S. dollar purchases is $83,078,784, which is fixed at a blended rate of 1.1515 for an aggregate Canadian dollar amount of $95,665,220. The aggregate amount of Euro purchases is EUR 136,011,580, which is fixed at a blended average rate of 1.4602 for an aggregate Canadian dollar amount of $198,602,284. These foreign exchange contracts qualify as hedges for accounting purposes.

The Company has entered into various Contracts for Differences ("CFDs") with other parties whereby the other parties have agreed to pay a fixed price to the Company based on the average monthly Pool price for an aggregate of 184,330 MWh per year of electricity from January 1, 2006, maturing from 2007 to 2024. While the CFDs do not create any obligation by the Company for the physical delivery of electricity to other parties, management believes it has sufficient electrical generation, which is not subject to contract, to satisfy the CFDs. The Company is unable to fair value two of the CFDs for an aggregate of 4,150 MWh per year of electricity because the CFD prices includes the sale of Renewable Energy Certificates along with the settlement of the average monthly Pool price. The Company's assumptions for fair valuing its CFDs, given the ongoing illiquidity of the forward market, assumes the actual contract prices contained in the CFDs are the same as the forward prices for years where no forward market exists. At June 30, 2006, the fair value of the CFDs that qualify as hedges would result in a loss of $256,000.

4. CAPITAL ASSETS

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



December 31,
June 30, 2006 2005
--------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
--------------------------------------------
Generating plants
- operating 401,279 33,454 367,825 243,813
- construction-in-progress 81,531 - 81,531 118,317
Vehicles 1,365 813 552 283
Equipment, other 2,124 971 1,153 1,113
--------------------------------------------

486,299 35,238 451,061 363,526
--------------------------------------------
--------------------------------------------


For the 3 months ended June 30, 2006, interest costs of $83,000 (3 months ended June 30, 2005 -- $990,000) and administration expenses of $336,000 (3 months ended June 30, 2005 -- $396,000) associated with the construction-in-progress have been capitalized during construction. For the 6 months ended June 30, 2006, interest costs of $509,000 (6 months ended June 30, 2005 -- $1,635,000) and administration expenses of $1,097,000 (6 months ended June 30, 2005 --$614,000) associated with the construction-in-progress have been capitalized during construction. In 2006, construction costs of $123,464,000 relating to the Melancthon I Wind Plant ("Melancthon I") were transferred from construction-in-progress to operating plants and prospect development costs of $81,531,000 relating to the Melancthon II Wind Project ("Melancthon II") were transferred into construction-in-progress. In 2005, construction-in-progress related to costs associated with the Upper Mamquam Hydroelectric Plant and Melancthon I.



5. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

June 30, 2006 December 31,
$ 2005
$
-------------------------------------

Wind prospects 28,923 20,004
Dunvegan Hydroelectric Prospect 8,026 7,676
Hydroelectric prospects 4,004 2,405
-------------------------------------

Total 40,953 30,085
-------------------------------------
-------------------------------------


The majority of the costs included in wind prospects relate to turbine supply and preliminary engineering and design for the Wolfe Island Wind Project ("Wolfe Island"). In 2006, the Company acquired all of the issued and outstanding shares of Valisa Energy Incorporated ("Valisa"). The purchase price was entirely allocated to prospect development costs. Valisa owns the Serpentine Hydroelectric Prospect in British Columbia, which costs are included above.

6. LONG-TERM DEBT

At June 30, 2006, the Company had letters of credit in the amount of $22,427,000 (December 31, 2005 -- $24,138,000) outstanding with its corporate lenders.



June 30, December 31,
2006 2005
$ $
----------------------
Series 1 Debentures, bearing interest at 5.334%,
10-year term with interest payable semi-annually
and no principal repayments until maturity,
senior unsecured 120,000 120,000

Series 2 Debentures, bearing interest at 5.69%,
10-year term with interest payable semi-annually
and no principal repayments until maturity,
senior unsecured 27,000 -

Series 3 Debentures, bearing interest at 5.77%,
12-year term with interest payable semi-annually
and no principal repayments until maturity,
senior unsecured 121,000 -

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

Construction Facility, bearing interest at
Bankers' Acceptances plus a stamping fee of
0.80% per annum, unsecured non revolving credit
facility with a 364-day drawdown period,
followed by a two-year non-amortizing term out
period - 56,600

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 7,423 7,735

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 3,207 3,529

Mortgage, bearing interest at 10.68%, secured by
letters of guarantee. Monthly repayments of
principal are $31,000 plus interest until
December 30, 2012 2,438 2,625

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 1,197 1,276
----------------------

317,265 226,765

Less current portion 1,915 1,838
----------------------

Long-term debt 315,350 224,927
----------------------
----------------------


In June 2006, the Company closed the issuance of an aggregate of $148,000,000 of unsecured corporate debentures (the "Debentures") in two series by way of private placement. The Series 2 senior unsecured debentures, with a gross principal amount of $27,000,000, have a 10-year term maturing on June 19, 2016 and bear an interest rate of 5.69% per annum with interest paid semi-annually. The Series 3 senior unsecured debentures with a gross principal amount of $121,000,000 have a 12-year term maturing on June 19, 2018 and bear an interest rate of 5.77% per annum with interest paid semi-annually. The proceeds from the debentures were used to retire the Construction Facility for Melancthon I and will be used to fund capital costs associated with the construction of Melancthon II and Wolfe Island and for general corporate purposes.

7. SHARE CAPITAL

Issued, common shares



Number of Amount
Shares $
---------------------
Balance, December 31, 2005 118,223,873 311,771
Issued on exercise of stock options 1,086,150 1,073
Stock compensation on shares exercised - 33

---------------------

Balance, June 30, 2006 119,310,023 312,877
---------------------
---------------------


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,
2006 2005 2006 2005
----------------------------------------------
Basic weighted average
shares outstanding 119,297,894 79,326,823 119,136,018 78,601,776
Effect of dilutive
securities:
Options 2,462,988 1,482,354 2,633,338 1,538,552
----------------------------------------------
Diluted weighted average
shares 121,760,882 80,809,177 121,769,356 80,140,328
----------------------------------------------
----------------------------------------------


Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $348,000 for Q2 2006 (Q2 2005 - $103,000) and $595,000 for the 6 months ended June 30, 2006 (2005 -$171,000) of compensation expense in the consolidated statement of earnings, with a corresponding increase recorded to contributed surplus in the consolidated balance sheet as at June 30, 2006. The Company issued 410,000 options in Q2 2006 (Q2 2005 - 980,000) and 2,105,000 options for the 6 months ended June 30, 2006 (2005 - 1,080,000). The weighted average fair value of options granted during Q2 2006 was $1.90 per share (Q2 2005 - $1.32 per share), which was estimated using the Black-Scholes option-pricing model, assuming a risk free interest rate of 4.23% (Q2 2005 - 3.51%), expected volatility of 35.89% (Q2 2005 - 37.95%), expected weighted average life of 4.0 years (Q2 2005 - 4.0 years), and no annual dividends paid. The weighted average fair value of options granted during the 6 months ended June 30, 2006 was $1.96 per share (2005 - $1.36 per share), assuming a risk free interest rate of 4.16% (2005 - 3.58%), expected volatility of 36.20% (2005 - 37.91%), expected weighted average life of 4.0 years (2005 - 4.4 years), and no annual dividends paid.

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 in net earnings of $15,000 for Q2 2006 (Q2 2005 - $31,000) and $45,000 for the 6 months ended June 30, 2006 (2005 -$62,000).

9. COMMITMENTS AND CONTINGENCIES

In the ordinary course of constructing new projects, the Company routinely enters into contracts for goods and services. As at June 30, 2006, the Company committed to approximately $431,628,000 for goods and services for Melancthon I, Melancthon II and Wolfe Island, which will be expended between 2006 and 2008. Melancthon I was completed in March 2006, and Melancthon II and Wolfe Island are expected to be completed in 2008.



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