Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

November 14, 2007 13:08 ET

Canadian Hydro Announces September 30th Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 14, 2007) - Canadian Hydro Developers, Inc. (TSX:KHD):

HIGHLIGHTS

- Hired Chief Operating Officer, Jamie Urquhart. Ross Keating's title changes to President, Operations & Development to focus more on the development of new prospects;

- Closed $233.5 million in credit facilities for the construction of Melancthon II and certain Blue River Hydro Projects;

- Completed the municipal hearings for Melancthon II. Construction has commenced in one of the two townships where the plant is located. We will start construction in the second township once final approvals are received; and

- Completed all local level approvals for Wolfe Island, with the exception of the Provincial Environmental Approval.



----------------------------------------------------------------------------
Q3 % 9 months %
(unaudited) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Financial Results (in
thousands of dollars
except per share
amounts)
Revenue 14,344 11,729 + 22% 46,359 35,128 + 32%
EBITDA 7,765 6,818 + 14% 28,518 20,487 + 39%
Cash flow from
operations 4,161 3,820 + 9% 17,068 13,941 + 22%
Per share (diluted) 0.03 0.03 -% 0.13 0.11 + 18%
Net earnings 162 292 - 45% 2,838 5,568 - 49%
Per share (diluted) - - -% 0.02 0.05 - 60%

Operating Results
Electricity generation
- MWh (net) 212,031 176,477 + 20% 683,758 525,785 + 30%
Average price received
per MWh $67.65 $66.46 + 2% $67.80 $66.81 + 1%
Electrical generation
under contract 77% 88% - 11% 84% 89% - 5%
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Higher wind and hydro generation on a same plant basis, the addition of Soderglen and improved operations at GPEC resulted in higher cash flow from operations in Q3 2007. Overall, net earnings decreased compared to Q3 2006 as a result of a higher foreign exchange loss of $1,591,000 on Euros earmarked for payments on a Euro-denominated wind turbine purchase contract.

For 2007, Soderglen and a full 9 months of operations at Melancthon I improved operating results. However, higher current and future taxes resulted in decreased net earnings compared to the prior year.

"We've made significant progress in advancing several construction projects," said John Keating, CEO of Canadian Hydro. "With the OMB hearings for Melancthon II complete and local level approvals in hand for Wolfe Island, we're on our way to completing our two largest plants to date."

Canadian Hydro is a developer, owner and operator of 19 power generation facilities totalling net 265 MW of capacity in operation and has an additional 403 MW in or nearing construction. The renewable generation portfolio is diversified across three technologies (water, wind and biomass) in the provinces of British Columbia, Alberta and Ontario. This portfolio is unique in Canada as all facilities are certified, or slated for certification, under Environment Canada's EcoLogoM Program.

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

Common shares outstanding: 132,943,723

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

Advisories

The following MD&A, dated November 5, 2007, should be read in conjunction with the unaudited interim consolidated financial statements as at and for the 3 and 9 months ended September 30, 2007 and 2006, and should also be read in conjunction with the audited consolidated financial statements and MD&A included in the Annual Report as at and for the year ended December 31, 2006. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). All tabular amounts in the following MD&A are in thousands of Canadian dollars unless otherwise noted. Additional information respecting the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com. Additional advisories with respect to forward looking statements and the use of non-GAAP measures are set out at the end of this MD&A under 'Additional Disclosures'.



RESULTS OF OPERATIONS

Revenue

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Revenue ($ in millions) 46.4 35.1 11.7 13.1 14.7 17.3 14.3
Revenue per MWh ($/MWh) 68 67 66 72 74 64 68
----------------------------------------------------------------------------


Quarterly Electricity Generation - by Province and Technology(1)
----------------------------------------------------------------------------
Q3 2007 Q3 2006 2007 2006
MWh MWh Change MWh MWh Change
----------------------------------------------------------------------------
British Columbia 68,105 60,024 + 13% 191,937 175,077 + 10%
Alberta 101,682 75,129 + 35% 300,273 216,253 + 39%
Ontario 42,244 41,324 + 2% 191,548 134,455 + 42%
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Totals 212,031 176,477 + 20% 683,758 525,785 + 30%
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Hydroelectric 104,474 98,540 + 6% 300,933 288,476 + 4%
Wind 73,957 47,805 + 55% 286,513 163,236 + 76%
Biomass 33,600 30,132 + 12% 96,312 74,073 + 30%
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Totals 212,031 176,477 + 20% 683,758 525,785 + 30%
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kWh per share(2) 1.56 1.45 + 8% 5.17 4.32 + 20%
----------------------------------------------------------------------------

(1) Reflecting the Company's net interest.
(2) kWh per share based on diluted weighted average shares outstanding.


Higher generation on a same plant basis and the addition of the 70.5 MW (35.25 MW, net) Soderglen Wind Plant ("Soderglen"), which was acquired on March 8, 2007, resulted in increased generation in Q3 2007 compared to the same quarter in the prior year. For the 9 months ended September 30, 2007, generation increased compared to the prior year due to the same factors above, in addition to a full period of operations at the Melancthon I Wind Plant ("Melancthon I"), which became operational on March 4, 2006.



Electricity Prices

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Average Pool Price Received 75 66 87 83 54 42 79
Average Price Received 68 67 66 72 74 64 68
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Approximately 77% of the Company's generation was sold pursuant to long-term sales contracts in Q3 2007 and 84% for the 9 months ended September 30, 2007 (Q3 2006 - 88%; 2006 - 89%). Alberta Power Pool ("Pool") prices in Q3 2007 were lower than Q3 2006 due to lower natural gas spot prices and warmer weather in the U.S. Pacific Northwest region, which impact power prices. Pool prices for the 9 months ended September 30, 2007 were consistent with the prior year.



Operating Expenses

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Operating Expenses
($ in millions) 13.9 12.5 4.2 4.2 4.9 5.1 3.9
Operating Expenses per MWh
($/MWh) 20 24 24 23 24 19 18
Gross Margin ($ in millions) 32.5 22.6 7.5 8.9 9.9 12.2 10.4
Gross Margin % 70 64 64 68 67 71 73
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Operating expenses decreased 7% in Q3 2007 compared to Q3 2006, mainly due to improved operations at the Grande Prairie EcoPower® Centre ("GPEC"), offset slightly by the addition of Soderglen. For the 9 months ended September 30, 2007, operating expenses increased 11% from for the same period in 2006 due to the addition of Soderglen and a full period of operations at Melancthon I. On a $/MWh basis, operating expenses have decreased over the prior quarter due to the addition of Soderglen, which has lower operating costs per MWh compared to our biomass and hydro plants. In addition, generation has increased at both GPEC and Melancthon I, resulting in lower operating costs per MWh.

Gross margins (revenue less operating expenses; expressed as a percentage of revenue) continue to improve mainly due to improved operations at GPEC. Compared to the same quarter in the prior year, GPEC's gross margin improved by approximately $220,000. For the 9 months ended September 30, 2007, GPEC's gross margin improved $2,002,000 compared to the same period in the prior year.



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

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Interest Expense
($ in millions) 11.1 9.6 4.1 3.4 3.6 3.7 3.8
Interest Expense per MWh
($/MWh) 16 18 23 19 18 14 18
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----------------------------------------------------------------------------
(in thousands of
dollars except where 9 months
noted) Q3 2007 Q3 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Interest on long-term
debt, including
capitalized interest 4,700 5,079 - 7% 13,964 11,108 + 26%
Capitalized interest (950) (955) - 1% (2,849) (1,495) + 91%
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Total interest on
long-term debt 3,750 4,124 + 9% 11,115 9,613 + 16%
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Total interest on
long-term debt per
MWh ($/MWh) 19.39 21.28 - 9% 18.63 14.08 + 32%
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Interest income 588 1,323 - 56% 1,224 3,707 - 67%
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The increase in interest on long-term debt (excluding capitalized interest) was due to higher outstanding corporate debt, mainly due to the issuance of the unsecured Series 2 and Series 3 corporate debentures in June 2006.

Interest income decreased due to less cash on hand invested in term deposits as previously raised equity funds were invested in construction-in-progress and development prospects.

Capitalized interest associated with construction-in-progress and development prospects increased due to projects with higher costs under or nearing construction compared to the prior year.

Long-term debt (including current portion) as at September 30, 2007 was $322,248,000 (September 30, 2006 - $316,801,000) compared to $316,327,000 as at December 31, 2006. The increase was due to drawdowns on the revolving credit facility, offset partially by the reclassification of deferred financing costs to long-term debt (see Note 6 to the interim consolidated financial statements) and regular repayments on the long-term debt.



Amortization Expense

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Amortization Expense
($ in millions) 10.6 8.3 2.9 3.2 3.2 4.0 3.4
Amortization Expense per MWh
($/MWh) 15 16 17 18 16 15 16
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Amortization expense increased due to the addition of Melancthon I in March 2006 and Soderglen in March 2007. Our wind plants are amortized on a straight-line basis over a 30 year period and our biomass and hydroelectric plants are amortized on a straight-line basis over a 40 year period.



Administration Expense

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Administration Expense
($ in millions) 5.0 3.3 1.0 1.0 2.1 1.2 1.7
Administration Expense per
MWh ($/MWh) 7 6 6 5 10 5 7
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The increase in administration expense in Q3 2007 and 2007 was due to moderately higher salary costs with the addition of new employees and increased stock compensation expense due to a higher fair value for options granted compared to the prior year. In Q1 2007, administration expense increased due to certain bonuses paid during the quarter. Capitalized administration costs associated with construction-in-progress and prospect development costs in Q3 2007 were $1,408,000 (Q3 2006 - $781,000) and $3,612,000 for the 9 months ended September 30, 2007 (2006 - $2,745,000) due to increased activity.

Taxes

We do not anticipate paying cash income taxes for several years, other than in respect of the Cowley Ridge Wind Plant, through its wholly owned subsidiary, Cowley Ridge Wind Power Inc. On May 2, 2006, the Federal Government passed a budget that eliminated the Federal Government Tax on Large Corporations ("LCT") effective January 1, 2006. The Company is, however, liable for Provincial Capital Taxes in Ontario, which comprise the majority of the current tax provision. The Provincial Capital Taxes in Ontario ("OCT") in 2007 have increased significantly as a result of the Company's capital build program in Ontario, including Melancthon I, Melancthon II, Wolfe Island, Island Falls and Royal Road. OCT will be eliminated effective January 1, 2009.

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 $35,000 in Q3 2007 (Q3 2006 - $246,000), and $2,132,000 for the 9 months ended September 30, 2007 (2006 - future tax recovery of $1,207,000). The decrease in Q3 2007 is due to lower taxable earnings in the quarter. The increase in 2007, in comparison to the prior year, was mainly due to a future income tax recovery recognized in 2006 as a result of a reduction in the corporate tax rates due to the May 2006 budget, as discussed above.



EBITDA, Net Earnings and Cash Flow from Operations

EBITDA

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9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
EBITDA ($ in millions) 28.5 20.5 6.8 9.2 8.5 12.2 7.8
EBITDA per MWh ($/MWh) 42 39 39 51 43 45 37
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In Q3 2007, EBITDA increased compared to the prior year due to the addition of Soderglen and improved operations at GPEC, offset partially by a $1,591,000 foreign exchange loss on Euros earmarked for payments on a Euro-denominated wind turbine contract. For the 9 months ended September 30, 2007, EBITDA increased due to the same factors noted above, in addition to a full period of operations at Melancthon I. On a $/MWh basis, EBITDA decreased in Q3 2007 compared to the prior year due to the foreign exchange loss discussed above and the fact that we have not yet had the benefit to EBITDA from the windy season at Soderglen, which is expected in Q4 2007 and Q1 2008.



Cash Flow from Operations

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Cash Flow from Operations
($ in millions) 17.1 13.9 3.8 8.9 5.1 7.8 4.2
Cash Flow from Operations
per MWh ($/MWh) 25 27 22 49 26 29 20
----------------------------------------------------------------------------


Cash flow from operations improved over the prior year due to the same factors as discussed above with respect to EBITDA. On a $/MWh basis, cash flow decreased in both Q3 2007 and 2007 compared to the prior year due to the foreign exchange loss and fact that we have not yet had the benefit to cash flow from the windy season at Soderglen, as discussed above.



Net Earnings

----------------------------------------------------------------------------
9 months Q3 Q4 Q1 Q2 Q3
2007 2006 2006 2006 2007 2007 2007
----------------------------------------------------------------------------
Net Earnings ($ in millions) 2.8 5.6 0.3 3.3 0.9 1.8 0.2
Net Earnings per MWh
($/MWh) 4 11 2 18 5 7 1
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Net earnings were lower in Q3 2007 ($nil per share) compared to Q3 2006 ($nil per share) due to the same factors as discussed above with respect to EBITDA and cash flow from operations. For the 9 months ended September 30, 2007, the decrease compared to the prior year was also due to higher current taxes, mainly OCT as a result of our increased activity in Ontario. Net earnings per share for the 9 months ended September 30, 2007 were $0.02 compared to $0.05 in the prior year.



Capital Asset Additions and Prospect Development Costs

----------------------------------------------------------------------------
(in thousands of 9 months
dollars) Q3 2007 Q3 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Capital asset additions 4,472 91,236 - 95% 16,245 181,693 - 91%
Prospect development
cost additions 3,363 6,306 - 47% 10,502 16,676 - 59%
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Capital asset additions relate mainly to costs for Melancthon II, which is currently under construction. Additions of prospect development costs relate primarily to equipment deposits for the Wolfe Island Wind Project ("Wolfe Island"), the B.C. projects and the Dunvegan Hydroelectric Prospect ("Dunvegan").



LIQUIDITY AND CAPITAL RESOURCES

----------------------------------------------------------------------------
As at September 30,
(in thousands of dollars except where noted) 2007
----------------------------------------------------------------------------
Capital expenditure plans 860,500
Spent to date (233,230)
----------------------------------------------------------------------------
Remaining capital expenditures to be financed 627,270
Financed/to be financed by:
Melancthon II and Blue River Construction Facilities 233,500
Working capital surplus 40,573
Anticipated construction facilities 337,010
Undrawn & available revolving operating credit facility 31,573
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Surplus remaining 15,386
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Our current capital expenditure plans are for: Melancthon II, Wolfe Island, Island Falls, Royal Road, Blue River, and English Creek projects, which are either in or nearing construction. The construction facilities we have placed and anticipate placing for these projects are, generally, based on 65% of the capital costs of these projects. Our ability to debt finance these projects are predicated on our BBB (Stable) investment grade credit rating. We, generally, cannot draw on construction credit facilities until we have expended 35% of the capital costs of a project, using our equity to pay for this. If timing differences exist between when the costs are expended and the construction facilities are in place, we will employ our cash flow from operations to support our capital expenditure program.

On September 27, 2007, we amended our credit agreement with our corporate lenders (the "Lenders") to include unsecured, non-revolving construction facilities for Melancthon II and certain Blue River projects (the "Construction Facilities") in the amount of $233,500,000. The Melancthon II and Blue River Construction Facilities have 18-month and 31-month drawdown periods, respectively, followed by a two-year non-amortizing term out period. The Construction Facilities bear interest at Bankers' Acceptances plus a stamping fee of 0.70% per annum. The Construction Facilities rank equally and ratably with all other unsecured and unsubordinated indebtedness of the Company for borrowed money.

As at September 30, 2007, we had a 48/52 debt/equity mixture (December 31, 2006 - 48/52) compared to a stated target of 65/35.

OUTLOOK

In October 2007, we completed the Ontario Municipal Board's ("OMB") hearing for planning approvals for the Amaranth Township (21 of 88 turbines). A final decision is expected before the end of 2007. Once this decision is received, we anticipate commencing construction on the Amaranth portion of Melancthon II. We currently have all of our approvals and are under construction on the Melancthon Township portion (67 of 88 turbines) of Melancthon II.

We've completed all major approvals and permits required to proceed to construction of Wolfe Island, with the exception of the Environmental Review Report ("ERR"), which will be submitted on November 19, 2007. Once the ERR is completed and approved, we will have all substantial permits in hand to proceed to construction shortly thereafter.

We have completed our Supplemental Information Requests ("SIR") with respect to Dunvegan in Alberta. Once the SIRs are accepted, we anticipate that the Alberta Energy and Utilities Board and the Natural Resources Conservation Board will set a hearing date for the approval of design and construction of Dunvegan. We anticipate a hearing and regulatory decision for approval of construction and operation early in 2008.

All necessary permits and approvals to proceed to construction with Bone Creek and Clemina Creek Hydroelectric Projects have been received. Construction will commence in the spring of 2008.

We continue to work on our approvals and permits for the remainder of our projects nearing construction, including English Creek, Serpentine Creek, Royal Road and Island Falls.

The average Pool price for October 2007 was $65/MWh compared to $49/MWh for September 2007.



ADDITIONAL DISCLOSURES

Financial Position

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

----------------------------------------------------------------------------
Increase
(Decrease) Explanation
$
----------------------------------------------------------------------------
Cash (12,888) Decrease mainly due to the assumption of a
working capital deficit from GW Power
Corporation ("GWP"), capital asset additions
for Melancthon II, prospect development
costs, long-term debt repayments
and changes in non-cash working capital;
offset partially by cash flow from
operations, and interest income received on
cash invested in term deposits.

Accounts receivable (4,507) Decrease due mainly to lower interest
receivable at September 30, 2007 compared to
the prior year as a result of less cash on
hand invested in term deposits.

Capital assets 118,517 Increase due to the acquisition of Soderglen
and costs incurred for the development of
Melancthon II (see Notes 3 and 4 to the
interim consolidated financial statements).

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

Prospect development 15,269 Increase due to costs incurred on the
costs development of Wolfe Island, the B.C.
projects, and Dunvegan.

Derivative financial 6,259 Increase due to implementation of new CICA
instrument liability handbook section 3855 "Financial
Instruments, Recognition and Measurement".
Represents the aggregate unrecognized
derivative financial instruments liability
related to the Company's contracts for
differences ("CFDs") and Euro foreign
exchange contracts that qualify for hedge
accounting.

Long-term debt 5,921 Increase due to drawdowns on the revolving
(including current operating line, offset by the
portion) reclassification of deferred financing costs
to long-term debt (see Note 7 to the interim
consolidated financial statements).

Future income taxes 22,736 Increase due to future tax liability assumed
on the acquisition of GWP (see Note 3 to the
interim consolidated financial statements)
and the future tax liability on the exercise
of the Series A Special Warrants (see Note
8(a) to the interim consolidated financial
statements).

Share capital 80,386 Increase due to the shares and warrants
issued for the acquisition of GWP (see Note
3 to the interim consolidated financial
statements) and the exercise of the Series A
Special Warrants, in addition to the
issuance of common shares through the
exercise of stock options, net of share
issue costs (see Note 8 to the interim
consolidated financial statements).


Disclosure Controls

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

Internal Controls and Procedures

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

Financial Instruments and Hedging Activities

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

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

Accounting Changes

Effective January 1, 2007, the Company adopted revised CICA handbook section 1506, "Accounting Changes." The revisions were made to harmonize section 1506 with International Financial Reporting Standards. See Note 2(a) to the interim consolidated financial statements.



Outstanding Share Data

----------------------------------------------------------------------------
As at November 5,
2007
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 132,943,723
Convertible securities:
Warrants (see Note 8 (b)) 4,110,900
Options 6,593,750
----------------------------------------------------------------------------
Fully diluted common shares 143,648,373
----------------------------------------------------------------------------
----------------------------------------------------------------------------


ADVISORIES

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, including, but not limited to, changes in weather, water flows, reservoir levels on irrigation works, wind resources, and Pool prices. 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.

Non-GAAP Financial Measures

Included in this MD&A and elsewhere in this report are references to terms that do not have any meaning prescribed in GAAP and may not be comparable to similar measures presented by other companies, including EBITDA cash flow from operations, cash flow from operations per share (diluted), MWh and other per share amounts. All references to cash flow from operations relate to cash flow from operations before changes in non-cash working capital. In addition, EBITDA is provided to assist management and investors in determining our ability to generate cash flow from operations. EBITDA is defined as cash flow from operations before changes in non-cash working capital, plus interest on debt (net of interest income) and current tax expense.



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

3 months ended 9 months ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenue
Electric energy sales 14,255 11,651 45,988 34,772
Revenue rebate 89 78 371 356
----------------------------------------------------------------------------
14,344 11,729 46,359 35,128
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Expenses (Other Income)
Operating 3,919 4,226 13,884 12,481
Interest on long-term debt (Notes 4
and 5) 3,750 4,124 11,115 9,613
Interest income (588) (1,323) (1,224) (3,707)
Amortization 3,373 2,918 10,554 8,306
Administration (Notes 4 and 5) 1,674 996 4,987 3,311
Foreign exchange loss 1,591 96 877 7
(Gain) loss on derivative financial
Instrument (Note 2(b)) (14) (43) (363) 116
----------------------------------------------------------------------------
13,705 10,994 39,830 30,127
----------------------------------------------------------------------------

Earnings before taxes 639 735 6,529 5,001
----------------------------------------------------------------------------

Tax expense (recovery)
Current 442 197 1,559 640
Future 35 246 2,132 (1,207)
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477 443 3,691 (567)
----------------------------------------------------------------------------

Net earnings 162 292 2,838 5,568

Retained earnings, beginning of period 25,682 19,268 22,888 13,992
----------------------------------------------------------------------------

Transitional adjustment (see Note 2(b)
and (Note 7)) - - 118 -

Adjusted retained earnings, beginning
of period 25,682 19,268 23,006 13,992
----------------------------------------------------------------------------

Retained earnings, end of period 25,844 19,560 25,844 19,560
----------------------------------------------------------------------------
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Earnings per share (Note 9)
Basic - - 0.02 0.05
Diluted - - 0.02 0.05

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENT OF COMPREHENSIVE (LOSS) INCOME (Unaudited)
(in thousands of dollars except per share amounts)

3 months ended 9 months ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net earnings 162 292 2,838 5,568

Other comprehensive loss
(see Note 2(b)):
Unrealized loss on derivative
financial instrument currency hedges (3,003) - (13,324) -
Unrealized gain on derivative
financial instrument contracts for
differences 621 - (623) -
Reclassification of deferred credit (14) - (100) -
----------------------------------------------------------------------------
Other comprehensive loss (2,396) - (14,047) -

Comprehensive (loss) income (2,234) 292 (11,209) 5,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements



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

September 30, December 31,
2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------

ASSETS
Current assets
Cash and cash equivalents 48,781 61,669
Accounts receivable 9,023 13,530
Prepaid expenses 1,276 535
Revenue rebate 906 594
Taxes receivable 73 -
----------------------------------------------------------------------------

60,059 76,328

Deferred financing costs - 2,628
Capital assets (Note 4) 666,314 547,797
Prospect development costs (Note 5) 75,558 60,289
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TOTAL ASSETS 801,931 687,042
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----------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities 11,101 9,587
Current portion of long-term debt (Note 7) 2,126 1,996
Derivative financial instrument liability
(Note 2(b)) 6,259 -
Taxes payable - 100
Deferred credit (Note 2(b)) - 85
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19,486 11,768

Long-term debt (Note 7) 320,122 314,331
Future income taxes 44,753 22,017
----------------------------------------------------------------------------

384,361 348,116
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Commitments and contingencies (Note 10)

SHAREHOLDERS' EQUITY
Share capital and warrants (Note 8) 394,238 313,852
Contributed surplus (Note 8(c)) 3,747 2,186
Retained earnings 25,844 22,888
Accumulated other comprehensive (loss) income
(Note 6) (6,259) -
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417,570 338,926
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TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 801,931 687,042
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----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements



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

3 months ended 9 months ended
September 30 September 30
2007 2006 2007 2006
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OPERATING ACTIVITIES
Net earnings 162 292 2,838 5,568
Adjustments for:
Amortization 3,373 2,918 10,554 8,306
Stock compensation expense
(Note 8(c)) 605 407 1,644 1,002
Future income tax expense (recovery) 35 246 2,132 (1,207)
(Gain) loss on derivative financial
instrument (Note 2(b)) (14) (43) (100) 272
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Cash flow from operations before
changes in non-cash working capital 4,161 3,820 17,068 13,941
Changes in non-cash working capital (5,640) (865) 1,077 (6,377)
----------------------------------------------------------------------------

(1,479) 2,955 18,145 7,564
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Construction credit facility
repayments - - - (56,600)
Long-term debt advances 10,000 - 10,000 148,000
Long-term debt repayments (498) (464) (1,475) (1,364)
Deferred financing costs (57) (44) (57) (743)
Issue of common shares, net of issue
costs (Note 8) 17 309 669 1,382
----------------------------------------------------------------------------

9,462 (199) 9,137 90,675
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital asset additions (4,472) (91,236) (16,245) (181,693)
Prospect development costs (3,363) (6,306) (10,502) (16,676)
Working capital deficit assumed on
acquisition - - (13,423) -
----------------------------------------------------------------------------

(7,835) (97,542) (40,170) (198,369)
----------------------------------------------------------------------------

NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 148 (94,786) (12,888) (100,130)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 48,633 174,457 61,669 179,801
----------------------------------------------------------------------------

CASH AND CASH EQUIVALENTS,
END OF PERIOD 48,781 79,671 48,781 79,671
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental information
Cash interest paid 5,665 5,475 14,408 8,873
Cash income and capital taxes paid 515 103 1,569 676

See accompanying notes to the consolidated financial statements


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2007 (Unaudited)
(Tabular amounts in thousands of dollars, except as otherwise noted)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


1. SIGNIFICANT ACCOUNTING POLICIES

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

Interim results fluctuate due to plant maintenance, seasonal demands and demand for electricity and supply of water and wind, and the timing and recognition of regulatory decisions and policies. Consequently, interim results are not necessarily indicative of annual results. The Company expects interim results for the second and fourth quarters to be higher than those from the first and third quarters of 2007.

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

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

2. CHANGE IN ACCOUNTING POLICIES

(a) ACCOUNTING CHANGES

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

(b) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

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

(i) Financial Instruments

All financial instruments must initially be recognized at fair value on the balance sheet. The Company has classified each financial instrument into the following categories: held for trading financial assets and financial liabilities, loans and receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses on available for sale financial assets are recognized in other comprehensive income ("OCI") and are transferred to earnings when the asset is derecognized. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method.

The Corporation has made the following classifications:

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

- Accounts receivable and revenue rebate are classified as loans and receivables and are initially measured at fair value and subsequent periodical revaluations are recorded at amortized cost using the effective interest rate method.

2. CHANGE IN ACCOUNTING POLICIES

- Accounts payable and accrued liabilities and long-term debt (including current portion) are classified as other liabilities and are initially measured at fair value and subsequent periodical revaluations are recorded at amortized cost using the effective interest rate method.

(ii) Derivative Instruments and Hedging Activities

Derivative instruments are utilized by the Company to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company's policy is not to utilize derivative instruments for speculative purposes. The Company may choose to designate derivative instruments as hedges.

All hedges are documented at inception including information such as the hedging relationship, the risk management objective and strategy, the method of assessing effectiveness and the method of accounting for the hedging relationship. Hedge effectiveness is reassessed on a quarterly basis.

All derivative instruments are recorded on the balance sheet at fair value either in accounts receivable, derivative financial asset or liability, accounts payable and accrued liabilities, or other long-term liabilities. Derivative financial instruments that do not qualify for hedge accounting are classified as held for trading and are recognized on the balance sheet and measured at fair value, with gains and losses on these instruments recorded in gain or loss on derivative financial instruments in the consolidated statement of earnings in the period they occur. Derivative financial instruments that have been designated and qualify for hedge accounting have been classified as fair value or cash flow hedges. For fair value hedges, the gains and losses arising from adjusting the derivative to its fair value are recognized immediately in earnings along with the gain or loss on the hedged item. For cash flow and foreign currency hedges, the effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. For any hedging relationship that has been determined to be ineffective, hedge accounting is discontinued on a prospective basis.

The Company has entered into various foreign exchange contracts, expiring in 2008, which fix the Company's Euro payments under wind turbine purchase contracts in Canadian dollars. The aggregate amount of Euro purchases is EUR 136,011,580, which is fixed at a blended average rate of 1.4602 for an aggregate Canadian dollar amount of $198,602,284. These foreign exchange contracts are classified as foreign currency cash flow hedges for accounting purposes. At January 1, 2007, the fair value of these contracts of $7,894,000 was recorded on the consolidated balance sheet as a derivative financial asset, with the gain recorded in OCI.

At September 30, 2007, the aggregate amount of remaining Euro purchases is EUR 118,452,960, which is fixed at a blended average rate of 1.4677 for an aggregate Canadian dollar amount of $173,853,409. The fair value change since transition was a loss of $13,324,000.

The Company has entered into various Contracts for Differences ("CFDs") with other parties whereby the other parties have agreed to pay a fixed price with a weighted average of $54 per MWh to the Company based on the average monthly Pool price for an aggregate of 148,780 MWh per year of electricity from January 1, 2007, maturing from 2007 to 2024. While the CFDs do not create any obligation by the Company for the physical delivery of electricity to other parties, management believes it has sufficient electrical generation, which is not subject to contract, to satisfy the CFDs. The Company's assumptions for fair valuing its CFDs, given the ongoing illiquidity of the forward market, assumes the actual contract prices contained in the CFDs are the same as the forward prices for future years where no forward market exists. At January 1, 2007, the fair value of these contracts of $206,000 was recorded on the consolidated balance sheet as a derivative financial liability, with the loss recorded as OCI. At September 30, 2007, the fair value change since transition was recorded resulting in an additional loss of $623,000.

(iii) Embedded Derivatives

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

(iv) Comprehensive income

Comprehensive income consists of net earnings and OCI. OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge and the change in fair value of any available for sale financial instruments. Amounts included in OCI are shown net of tax. Accumulated other comprehensive income ("AOCI") is a new equity category comprised of the cumulative amounts of OCI. See Note 6 for the composition of AOCI.

3. ACQUISITIONS

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



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

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

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


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

4. CAPITAL ASSETS

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



September 30, December 31,
2007 2006
-----------------------------------------------
Accumulated Net Book Net Book
Cost Depreciation Value Value
$ $ $ $
-----------------------------------------------
Generating plants
- operating 518,576 49,790 468,786 363,739
- construction-in-progress 195,151 - 195,151 182,275
Vehicles 1,616 1,046 570 523
Equipment, other 3,280 1,473 1,807 1,260
-----------------------------------------------

718,623 52,309 666,314 547,797
-----------------------------------------------
-----------------------------------------------


For the 3 months ended September 30, 2007, interest costs of $374,000 (3 months ended September 30, 2006 - $695,000) and administration expenses of $399,000 (3 months ended September 30, 2006 - $330,000) associated with the construction-in-progress have been capitalized during construction. For the 9 months ended September 30, 2007, interest costs of $1,492,000 (9 months ended September 30, 2006 - $1,204,000) and administration expenses of $1,230,000 (9 months ended September 30, 2006 - $1,427,000) associated with the construction-in-progress have been capitalized during construction. In both 2007 and 2006, construction-in-progress relates to costs associated with the development of the Melancthon II Wind Project. In Q1 2006, construction-in-progress also related to the Melancthon I Wind Project until March 2006, when costs were transferred to operating plants.



5. PROSPECT DEVELOPMENT COSTS

Prospect development costs are comprised of the following:

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

Wind prospects 55,112 46,310
Hydroelectric and other prospects 11,468 5,711
Dunvegan Hydroelectric Prospect 8,978 8,268
-----------------------------------

Total 75,558 60,289
-----------------------------------
-----------------------------------


Interest costs of $576,000 (3 months ended September 30, 2006 - $260,000) and administration expenses of $1,009,000 (3 months ended September 30, 2006 - $451,000) associated with prospect development costs have been capitalized leading up to construction. For the 9 months ended September 30, 2007, interest costs of $1,357,000 (9 months ended September 30, 2006 - $291,000) and administration expenses of $2,382,000 (9 months ended September 30, 2006 - $1,318,000) associated with prospect development costs have been capitalized leading up to construction. Included in wind prospects are $34,392,000 in costs with respect to the Wolfe Island Wind Project ("Wolfe Island") and $7,616,000 in costs with respect to the December 2006 acquisition of Vector Wind Energy Inc. The prospect development costs relate to over 1,000 MW of optioned land for wind prospects located primarily throughout Manitoba and Ontario.

The Company continues to pursue the development of the Dunvegan Hydroelectric Prospect. In 2006, the Company completed and submitted the joint application to the Alberta Energy and Utilities Board and Natural Resources Conservation Board. The Company anticipates a hearing and regulatory decision for approval of construction and operation early in 2008. Regulatory approvals, long-term power sales contracts and financing are required prior to proceeding. Should the Company not be successful in obtaining regulatory approvals, the prospect would likely be abandoned and the related prospect development costs would be written off.



6. ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME

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

$
---------
Balance, December 31, 2006 -
Transitional adjustments on adoption of new accounting policies
(see Note 2(b)):
Unrealized gain on derivative financial instrument foreign
currency hedges 7,894
Unrealized loss on derivative financial instrument contracts
for differences (206)
Reclassification of deferred credit 100
---------
Opening balance, January 1, 2007 7,788
Unrealized loss on derivative financial instrument foreign
currency hedges (13,324)
Unrealized loss on derivative financial instrument contracts
for differences (623)
Reclassification of deferred credit (100)
---------
Accumulated other comprehensive (loss) income, September 30, 2007 (6,259)
---------
---------


As at September 30, 2007, AOCI is comprised of an unrealized loss on derivative financial instrument foreign currency hedges of $5,416,000, an unrealized loss on derivative financial instrument contracts for differences of $829,000 and a gain of $14,000 for the reclassification of the deferred credit.



7. LONG-TERM DEBT

September 30, December 31,
2007 2006
$ $
-----------------------------------
Series 1 Debentures, bearing interest at
5.334%, 10-year term with interest
payable semi-annually and no principal
repayments until maturity on September 1,
2015, senior unsecured 120,000 120,000

Series 2 Debentures, bearing interest at
5.69%, 10-year term with interest
payable semi-annually and no principal
repayments until maturity on June 19,
2016, senior unsecured 27,000 27,000

Series 3 Debentures, bearing interest at
5.77%, 12-year term with interest
payable semi-annually and no principal
repayments until maturity on June 19,
2018, senior unsecured 121,000 121,000

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

Operating Facility, 364-day revolving
credit facility, with a six month
non-amortizing term out period,
extendable for one year periods annually
by mutual agreement of the Company and
its Lenders, bears interest at Bankers'
Acceptances plus a stamping fee of 0.80%
per annum 10,000 -

Mortgage on Cowley, bearing interest at
10.867%, secured by the plant, related
contracts and a reserve fund for $725,000
that has been provided by a letter of
credit to the lender. Monthly repayments
of principal and interest are $121,000
until December 15, 2013 6,564 7,093

Mortgage, bearing interest at 10.7% and
secured by letter of guarantee. Monthly
repayments of principal and interest are
$84,000 until May 31, 2010 2,331 2,869

Mortgage, bearing interest at 10.68%,
secured by letters of guarantee. Monthly
repayments of principal are $31,000 plus
interest until December 30, 2012 1,969 2,250

Promissory note, bearing interest fixed
at 6%, secured by a second fixed charge
on three of the Alberta hydroelectric
plants. Monthly repayments of principal
and interest are $19,000 until August 1,
2012 988 1,115

Deferred financing costs (1) (2,604) -
-----------------------------------

322,248 316,327

Less current portion 2,126 1,996
-----------------------------------

Long-term debt 320,122 314,331
-----------------------------------
-----------------------------------

(1) Refer to Note 2(b). As at the transition date of January 1, 2007, the
Company recorded a $118,000 increase in retained earnings with a
corresponding decrease in the long-term debt liability as a result of
applying the effective interest rate method to the Company's debentures.
In addition, on transition date, the deferred financing costs,
previously recorded in other long-term assets, were net against the
long-term debt liability. As the Company records debt accretion of the
deferred financing costs over the remaining term to maturity of the
debentures, these costs will be charged to income as interest expense
with a corresponding increase to the long-term debt liability.


At September 30, 2007, the Company had letters of credit in the amount of $23,427,000 (December 31, 2006 - $22,622,000) outstanding with its corporate lenders. At September 30, 2007, the undrawn amount on the revolving operating facility is $31,573,000 (December 31, 2006 - $2,378,000).

On September 27, 2007, the Company amended the credit agreement with its corporate lenders (the "Lenders") to include unsecured, non-revolving construction facilities for Melancthon II and certain Blue River projects (the "Construction Facilities") in the amount of $233,500,000. The Melancthon II and Blue River Construction Facilities have 18-month and 31-month drawdown periods, respectively, followed by a two-year non-amortizing term out period. The Construction Facilities bear interest at Bankers' Acceptances plus a stamping fee of 0.70% per annum. The Construction Facilities rank equally and ratably with all other unsecured and unsubordinated indebtedness of the Company for borrowed money.



8. SHARE CAPITAL AND WARRANTS

(a) Issued, common shares:

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

Balance, December 31, 2006 119,652,023 313,852
Issue of common shares (see Note 3) 12,332,700 72,763
Issuance of warrants (see Note 3) - 3,967
Share issue costs, net of tax effect of
$40,000 - (119)
Issued on exercise of stock options 372,000 829
Issued on exercise of warrants 500,000 2,863
Stock compensation on shares exercised - 83
---------------------------------

Balance, September 30, 2007 132,856,723 394,238
---------------------------------
---------------------------------


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

(b) Warrants:



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

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

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


(c) Stock compensation:

Using the fair value method of accounting for stock options issued to employees on or after January 1, 2003, the Company recognized $605,000 for Q3 2007 (Q3 2006 - $407,000) and $1,644,000 for the 9 months ended September 30, 2007 (2006 - $1,002,000) of compensation expense in the consolidated statement of earnings, with a corresponding increase recorded to contributed surplus in the consolidated balance sheet as at September 30, 2007. The Company issued 595,000 options in Q3 2007 (Q3 2006 - 125,000) and 1,780,000 options for the 9 months ended September 30, 2007 (2006 - 2,230,000). The weighted average fair value of options granted during Q3 2007 was $2.00 per share (Q3 2006 - $1.75 per share), which was estimated using the Black-Scholes option-pricing model, assuming a risk free interest rate of 4.49% (Q3 2006 - 4.33%), expected volatility of 33.04% (Q3 2006 - 35.53%), expected weighted average life of 4.0 years (Q3 2006 - 4.0 years), and no annual dividends paid. The weighted average fair value of options granted during the 9 months ended September 30, 2007 was $2.07 per share (2006 - $1.95 per share), assuming a risk free interest rate of 4.15% (2006 - 4.21%), expected volatility of 33.13% (2006 - 36.00%), expected weighted average life of 4.0 years (2006 - 4.0 years), and no annual dividends paid.



9. EARNINGS PER SHARE

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

3 Months Ended 9 Months Ended
September 30, September 30,
2007 2006 2007 2006
---------------------------------------------------
Basic weighted average
shares outstanding 132,855,940 119,366,115 129,410,112 119,213,560
Effect of dilutive
securities:
Options 2,727,572 2,270,152 2,803,396 2,563,950
---------------------------------------------------

Diluted weighted average
shares 135,583,512 121,636,267 132,213,508 121,777,510
---------------------------------------------------
---------------------------------------------------


10. COMMITMENTS AND CONTINGENCIES

In the ordinary course of constructing new projects, the Company routinely enters into contracts for goods and services. As at September 30, 2007, the Company has committed approximately $263,000,000 for goods and services for Melancthon II, Wolfe Island, and the B.C. projects, which will be expended between 2007 and 2009.

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

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