Canadian Hydro Developers, Inc.

Canadian Hydro Developers, Inc.

February 23, 2009 09:00 ET

Canadian Hydro Announces December 31, 2008 Year End and Fourth Quarter Results

CALGARY, ALBERTA--(Marketwire - Feb. 23, 2009) - Canadian Hydro Developers, Inc. (TSX:KHD) -

3 Months Ended Year Ended
December 31, December 31,
2008 2007 2008 2007
Financial Results (in thousands
of dollars except per share
Revenue 23,578 17,398 80,098 63,757
EBITDA 14,457 10,597 49,771 39,115
Cash flow 7,487 6,687 26,897 23,755
Per share (diluted) 0.05 0.05 0.19 0.18
Net earnings 1,225 5,505 931 8,343
Per share (diluted) 0.01 0.04 0.01 0.06

Property, plant, and equipment
additions 100,904 129,678 401,872 145,923
Prospect development cost
additions 5,427 45,235 24,378 55,737
Working capital(1) 21,766 21,159
Assets 1,410,132 949,914
Unused & available long-term
debt & construction lines
of credit 134,208 246,326
Long-term debt & construction
lines of credit (including
current portion) 835,796 414,756
Shareholders' equity 483,530 481,976
Asset Value(2) 1,767,000 1,440,000

Operating Results
Installed capacity - MW (net) 495.8 363.8
Electricity generation - MWh
(net) 302,104 237,917 1,066,081 921,675
kWh per share (diluted) 2.07 1.76 7.31 6.91
Average price received per
MWh ($) 78 73 75 69
Power generation under
contract (%) 79 70 78 77

(1) Excludes current portion of long-term debt and acquisition facility.
(2) Based on McDaniel & Associates Consultants Ltd. independent evaluation
of the pre-tax future cash flows of the Company's assets, including
operating EcoPower® Centres, projects under or nearing construction
and Dunvegan, discounted at 8%.


- Achieved record power generation of 1,066,081 MWh;

- Achieved commercial operations of phase II at our Melancthon EcoPower® Centre (Melancthon II);

- Progressed well on the construction of our 197.8 MW Wolfe Island Wind Project (Wolfe Island). Melancthon II and Wolfe Island together will double the size of our Company;

- Secured two power purchase agreements in Quebec for a combined 116 MW of wind prospects;

- Received regulatory approvals the construction and operation of our Dunvegan Hydroelectric Prospect (Dunvegan); and

- Welcomed Keith O'Regan as Executive Vice President & Chief Operating Officer.

Revenue, EBITDA, and cash flow, including per share amounts, improved in 2008 and Q4 2008 over the prior year as a result of new EcoPower® Centre additions, higher average prices received, and higher hydroelectric generation. Net earnings, including per share amounts, decreased year over year as a result of higher current and future taxes, and higher write-offs of prospect development costs. Q4 2007 included a large future income tax recovery, which benefited net earnings and per share amounts in the prior year.


McDaniel & Associates Consultants Ltd. (McDaniels) has evaluated our EcoPower® Centres as of January 1, 2009. The purpose in engaging McDaniels is to provide investors and shareholders with third party confirmation of future cash flow estimates. Using McDaniel & Associates' evaluation, the Asset Value was $1,767,000,000 as of January 1, 2009, compared to $1,440,000,000 as of January 1, 2008. The increase in the Asset Value is due primarily to:

- The addition of St. Valentin and New Richmond.

offset partially by:
- Increased capital costs associated with Dunvegan.

McDaniels' made the following assumptions in preparing its evaluation:

- Electricity prices were determined using either a contractually-determined price specific to each EcoPower® Centre or a forecast of the average electricity spot price specific to each of the provinces in which we operate where no contracts are in place or expire;

- The forecast of the average electricity spot price was based on McDaniels' opinion on future natural gas and electricity prices at January 1, 2009;

- Electricity generation from each operating EcoPower® Centre was primarily based on historical annual averages. For EcoPower® Centres without sufficient operating history, generation was based on data provided by the Company, which, in turn, was derived from independent studies;

- We provided estimates of applicable operating costs, which were primarily based on historical annual average costs;

- We provided estimates of sustaining capital, which were based on historical annual average costs;

- Overriding royalties, water rentals, property taxes and lease rentals were estimated based on the applicable contracted or legislated rates;

- We provided capital costs related to planned acquisition and projects either under construction, nearing construction or under development;

- Applicable electricity prices, operating costs, sustaining capital, water rentals and property taxes were escalated at 2% per annum, unless otherwise prescribed by contract or legislation; and

- Discounted cash flows for EcoPower® Centres, projects and prospects assume no terminal value.



The following MD&A, dated February 13, 2009, should be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2008 and 2007 (the Financials). All tabular amounts in the following MD&A are in thousands of dollars, unless otherwise noted, except share and per share amounts. Additional information respecting our Company, including our Annual Information Form, is available on SEDAR at 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 'Advisories'.

The audited consolidated financial statements as at and for the years ended December 31, 2008 and 2007 are currently posted on our website ( until the Annual Report is mailed to registered shareholders in mid-March 2009. The unaudited consolidated statements of earnings and of cash flows for the three months ended December 31, 2008 and 2007 are currently posted on our website as supplemental information.


Revenue and Generation

Quarterly Electricity Generation - by Province and Technology(1)
Q4 2008 Q4 2007 2008 2007
MWh MWh Change MWh MWh Change
British Columbia 49,530 46,070 + 8% 239,310 238,008 + 1%
Alberta 115,800 119,540 - 3% 445,772 419,812 + 6%
Ontario 113,894 67,392 + 69% 304,688 258,940 + 18%
Quebec 22,880 4,915 + 366% 76,311 4,915 +1,453%
Totals 302,104 237,917 + 27% 1,066,081 921,675 + 16%

Hydroelectric 79,309 66,354 + 20% 382,605 367,286 + 4%
Wind 194,113 144,180 + 35% 559,242 430,694 + 30%
Biomass 28,682 27,383 + 5% 124,234 123,695 -%
Totals 302,104 237,917 + 27% 1,066,081 921,675 + 16%
kWh per share(2) 2.07 1.76 + 19% 7.32 6.91 + 6%

(1) Reflecting our net interest.
(2) kWh per share based on diluted weighted average shares outstanding.

Revenue in 2008 increased 26% compared to 2007. We sold 78% of our generation under long-term sales contracts in 2008 (2007 - 77%). We received an average price of $75/MWh in 2008 for electricity from all operations (2007 - $69/MWh). This was the result of:

- The addition of phase II of our Melancthon EcoPower® Centre (Melancthon II) and the Le Nordais EcoPower® Centre (Le Nordais), each of which has a higher contract price than existing EcoPower® Centres; and

- Higher average Pool prices received on our merchant EcoPower® Centres (2008 - $73/MWh; 2007 - $60/MWh).

Revenue in Q4 2008 increased 36% compared to Q4 2007 due primarily to:

- The completion of Melancthon II in November;

- The addition of Le Nordais as discussed above; and

- Higher average prices received, as discussed below.

We sold 79% of our generation under long-term sales contracts in Q4 2008 (Q4 2007 - 70%). The average price we received for electricity from all operations for Q4 2008 was $78/MWh compared to $75/MWh in Q4 2007 due to new EcoPower® Centre additions with long-term contracts at higher prices than our existing operating EcoPower® Centres.

In addition, kWh per share increased 6% in 2008 compared to 2007. This increase was a result of:

- A full year of generation at Le Nordais and the Soderglen EcoPower® Centres (Soderglen);

- The addition of Melancthon II in November; and

- Improved hydroelectric generation in Ontario due to higher water levels than the prior year.

These increases were offset partially by:

- Lower generation at our Melancthon I EcoPower® Centre as a result of 28 days of downtime in June for a substation expansion required to bring phase II online and less windy conditions in 2008 compared to 2007; and

- Lower generation at our Alberta hydroelectric EcoPower® Centres as a result of lower water levels.

In Q4 2008, kWh per share increased 19% as a result of:

- The completion of Melancthon II in November; and

- The addition of Le Nordais as discussed above.

Operating Expenses

Operating expenses increased 31% in 2008 compared to 2007, due to:

- A full year of operations at Le Nordais as well as the maintenance program required at the site in order to optimize performance and improve the availability of the turbines;

- The addition of Melancthon II in November;

- A full year of operations at Soderglen; and

- Increased operating expenses at our Grande Prairie EcoPower® Centre (GPEC) as a result of the increased maintenance work performed in 2008.

Offset partially by:

- Lower operating expenses at our BC and Alberta hydroelectric EcoPower® Centres as a result of lower water flows.

Operating expenses increased 36% in Q4 2008 compared to Q4 2007, due to the reasons discussed above.

On a $/MWh basis, operating expenses increased 7% and 13%, respectively, in Q4 2008 and 2008 compared to the same periods in the prior year primarily as a result of the above factors.

Since achieving commercial operations, GPEC has performed below expectations. In the fourth quarter of 2008, we hired a new plant manager and have formalized a detailed plan to improve the operations and profitability to what we had originally planned. We will expend approximately $4,000,000 in 2009 to upgrade, replace and rebuild certain plant components, including the super heaters and boiler protection equipment, as well as combustion modeling changes and the implementation of revised standard operating procedures. This work is planned for the third quarter of 2009, and as a result, we anticipate improved operating results in the fourth quarter of 2009.

At Le Nordais, as part of our plan on acquisition of this EcoPower® Centre, we implemented a comprehensive maintenance program, focusing primarily on gearbox maintenance and replacement in order to improve the availability of turbines at the site. The objective of this maintenance program is to have at least 111 of the 133 turbines achieving 98% availability by the end of 2009, and all 133 turbines achieving this target in 2010, which is expected to improve generation above the historical long-term average generation of 165,000 MWh.

Gross Margins

Gross margins as a percentage of revenue were similar in 2008 at 69% compared to 70% in 2007. We expect gross margins to improve in 2009 as we execute on our plans for both GPEC and Le Nordais.

Gross margins, as a percentage of revenue, were consistent at 69% for Q4 2008 and Q4 2007.

Interest on Credit Facilities and Credit Facilities

Year ended
(in thousands of dollars Q4 December 31,
except where noted) 2008 2007 Change 2008 2007 Change
Gross interest on credit
facilities 10,688 4,814 + 122% 36,612 18,778 + 95%
Capitalized interest (4,209) (1,082) + 289% (15,656) (3,931) + 298%
Net interest expense on
credit facilities 6,479 3,732 + 73% 20,956 14,847 + 41%
Net interest expense on
credit facilities
per MWh ($/MWh) 21.45 15.69 + 37% 19.66 16.11 + 22%
Weighted average
interest rate on credit
facilities (%) 5.10 5.21 - 2% 5.15 5.12 + 1%
Interest income 100 227 - 56% 612 1,451 - 58%

The increase in interest on credit facilities (excluding capitalized interest) in 2008 and Q4 2008, compared to the same periods in the prior year, was due to higher outstanding corporate debt, as a result of:

- The issuance of the unsecured Series 4 and Series 5 corporate debentures in June 2008, the proceeds of which were used to repay the acquisition facility for Le Nordais, issued in December 2007.

On a $/MWh basis, net interest expense increased in 2008 as we have not yet had the full generation benefit of the Le Nordais acquisition.

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.

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.

Amortization Expense

Amortization expense increased 30% in Q4 2008 from Q4 2007. For the year ended December 31, 2008, it increased 42% from 2007, due to the addition of Soderglen and Le Nordais and the completion of Melancthon II. On a $/MWh basis, amortization expense increased for both the 3 and 12 month periods ended December 31, 2008, as we had not yet had the full generation benefit of the Le Nordais acquisition.

Our wind EcoPower® Centres are amortized on a straight-line basis over a 30 year period, except Le Nordais and Taylor, which are amortized over 26 years and 15 years, respectively. Our biomass and hydroelectric EcoPower® Centres are amortized on a straight-line basis over a 40 year period.

Administration Expense

Year ended
Q4 December 31,
(in thousands of dollars
except where noted) 2008 2007 Change 2008 2007 Change
Gross administration
expense 3,272 2,323 + 41% 11,170 9,278 + 20%
administration expense (1,382) (1,559) - 11% (5,654) (5,171) + 9%
Net administration
expense 1,890 764 + 147% 5,516 4,107 + 34%
Net administration
expense per MWh ($/MWh) 6.26 3.21 + 96% 5.15 4.46 + 15%

Gross administration expense increased 20% in 2008 and 41% in Q4 2008, compared to the same periods in the prior year, due to:

- Moderately higher salary and burden costs associated with the addition of new employees; and

- Increased recruitment costs associated with the addition of the new employees.

On a $/MWh basis, the increase was due to the factors described above.

Stock Compensation Expense

Stock compensation expense increased 11% in 2008 compared to 2007 due to an increased number of stock options vesting in 2008, as compared to 2007. This increase was offset partially by the fact that stock options issued in the current year had a lower per stock option fair value than previous years due to a lower share price.

Stock compensation expense decreased 13% in Q4 2008 from Q4 2007 due to lower per stock option fair value as a result of a lower share price.

Income and Capital Taxes

We have available tax pools of $1,206,315,000 (2007 - $772,100,000) compared to book assets of $1,410,132,000 (2007 - $949,914,000). We do not anticipate paying cash income taxes for several years, other than in respect of the Cowley Ridge EcoPower® Centre, through our wholly owned subsidiary, Cowley Ridge Wind Power Inc.

We are, however, liable for Provincial Capital Taxes in Ontario (OCT) and Quebec (QCT), which comprise the majority of the current tax provision. OCT and QCT in 2008 has increased significantly as a result of our capital build program in Ontario, including Melancthon I, Melancthon II, Wolfe Island, the Yellow Falls Hydroelectric Project (Yellow Falls) and the Royal Road Wind Projects (Royal Road), as well as our expansion into Quebec with Le Nordais. OCT and QCT are scheduled to be eliminated effective July 1, 2010 and January 1, 2011, respectively.

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 in 2008 was $444,000, compared to a future tax recovery of $2,726,000 in 2007. In Q4 2008, the future income tax recovery decreased to $516,000 compared to $4,858,000 in Q4 2007. This is mainly due to a 4% reduction in the corporate federal tax rates effective January 1, 2012, which were enacted on December 17, 2007 and resulted in a large future tax recovery in 2007.

EBITDA, Cash Flow and Net Earnings


EBITDA increased 27% in 2008 and 37% in Q4 2008, compared to the same periods in the prior year, due to:

- Increased revenue from the addition of Soderglen and Le Nordais; and

- The addition of Melancthon II and the other factors discussed above with respect to revenue.

These increases were offset partially by the factors discussed above with respect to operating and administrative expenses.

On a $/MWh basis for the 3 and 12 months ended December 31, 2008, EBITDA increased 7% and 10%, respectively, as a result of the addition of Melancthon II and higher average prices received.

Cash Flow

Cash flow from operations improved 13% for the year ended December 31, 2008 and 12% in Q4 2008 over Q4 2007 due to the same factors as discussed above with respect to EBITDA, offset partially by:

- Increased interest expense, as discussed above; and

- Increased current taxes, associated with the increased capital taxes due to our increased capital investment in Ontario and Quebec.

On a $/MWh basis, cash flow decreased due to the increased interest and tax expenses on a per MWh basis.

Net Earnings

Net earnings decreased 89% in 2008 from 2007 mainly due to:

- Increased amortization, interest, operating and administrative expenses as discussed above;

- Higher current and future taxes as discussed above; and

- Increased development costs written-off during the year.

This was partially offset by increased revenue, as discussed above.

Net earnings decreased 78% in Q4 2008 ($0.01 per share, diluted) compared to 2007 ($0.04 per share, diluted). The change was due to the same factors as discussed above with respect to EBITDA and cash flow from operations, in addition to:

- Increased future taxes, as a reduction in substantively enacted future tax rates occurred in Q4 2007 resulting in a large recovery;

- Increased development cost write-offs; and

- Higher amortization expense due to new EcoPower® Centre additions.

Property, Plant, and Equipment Additions and Prospect Development Costs

(in thousands of
dollars) Q4 2008 Q4 2007 Change 2008 2007 Change
Property, plant, and
equipment additions 100,904 129,673 - 22% 401,872 145,923 + 175%
Prospect development
cost additions 5,427 45,235 - 88% 24,378 55,737 - 56%

Property, plant, and equipment additions for both the three and twelve month periods relate mainly to costs for Melancthon II, which was completed in November 2008, and the continued development of Wolfe Island and the Blue River Hydroelectric Projects (Blue River). Additions of prospect development costs relate primarily to costs for Royal Road, Yellow Falls, Blue River and the Dunvegan Hydroelectric Project (Dunvegan).

From time to time, initial site investigations and project economics do not justify us pursuing certain prospective projects, and accordingly, these costs are written off. During 2008 and Q4 2008, prospect development costs of $1,764,000 and $1,577,000, respectively, were written off (2007 - $442,000; Q4 2007 - $442,000).


The nature of our business requires long lead times from prospect identification through to commissioning of electrical generation facilities. Our investment commitment proceeds in a step-wise fashion through the identification and preparation of our prospects, securing the associated power purchasing contracts, satisfying the lengthy regulatory requirements, and finally constructing the facilities.

Given these long lead times from expenditure through to cash flow generation, it is imperative to have a solid and well funded capital structure. We operate with a minimum equity base of 35% on invested capital and fund the majority of our debt on a basis consistent with the long term asset base - mid-term financing is obtained through the construction phases and then converted into a long term unsecured debenture basis after commissioning.

In early 2007, we embarked upon a significant expansion plan to triple our generating capacity by the end of 2010. Subsequently, we have secured long term power purchase agreements out to 2012. The following table summarizes the investments contemplated by this plan and our current expectations as to the funding thereof.

In June 2008, we issued debentures for total gross proceeds of $75,900,000 and amended our existing credit agreement, adding an additional $312,500,000 of unsecured credit facilities, for a total of $611,000,000.

Credit facilities (including current portion) as at December 31, 2008 were $835,796,000.

As at December 31,
(in thousands of dollars) 2008
Capital expenditure plans through 2012 1,014,120
Spent to date (450,242)
Remaining capital expenditures to be financed 563,878
Financed/to be financed by:
Blue River construction facility 48,900
Wolfe Island construction facility 60,600
Working capital surplus(1) 24,100
Anticipated construction facilities(2) 281,900
Undrawn & available revolving Operating Facility 24,708
Expected to be funded through cash flow from operations 123,670
Difference -

(1) Excluding derivative financial instruments
(2) See following table with project breakdown

The amount expected to be funded from cash flow from operations relates mainly to our New Richmond and St. Valentin Wind Projects with target on-line dates of December 2012.

Our current capital expenditure plans are for the following projects, all of which have power purchase agreements and are either in or nearing construction:

- Wolfe Island;
- Yellow Falls;
- Royal Road;
- Blue River (including Bone, Clemina, and Serpentine Creek);
- English Creek;
- St. Valentin; and
- New Richmond.

The following table outlines the size and timing of the anticipated credit

Anticipated construction Anticipated timing of
(in thousands of dollars) facility size construction facility
Yellow Falls 28,400 Q3 2009
Royal Road 26,000 Q1 2010
New Richmond 123,500 Q4 2011
St. Valentin 104,000 Q4 2011
Total 281,900

Exclusive of any new projects beyond our current capital program, we will require no additional equity financing for our current projects, and will require only $28 million of debt financing in 2009, relating to Yellow Falls.

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 is 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.

We have no requirements to significantly access the debt markets until September 2010 when the Melancthon II construction facility matures. While we anticipate that funds in the debt market will be available at economic interest rates, it is currently not possible to guarantee that these funds will be available when required. With the completion of phase II of Melancthon in 2008 and the expected completion of Wolfe Island in 2009, we expect to have the ability to self-finance a greater portion of our investing activities and expect to become less reliant on external equity financing in the future.

As at December 31, 2008, we had a 63/37 debt/equity mixture (December 31, 2007 - 46/54) compared to a stated target of 65/35. We will move towards our stated target as we draw on existing credit facilities and put in place and draw on future construction facilities for the projects discussed above. We believe that we have the necessary cash flow, working capital and access to capital markets to fulfill any obligations and commitments we make in implementing this expansion plan.



British Columbia

At year-end, we were engaged in the development of the following hydroelectric projects:

- 18.0 MW, $49,000,000 Bone Creek;
- 11.0 MW, $27,000,000 Clemina Creek;
- 9.6 MW, $28,000,000 Serpentine Creek; and
- 5.0 MW, $10,000,000 English Creek.

The targeted completion date for all four B.C. projects is the fourth quarter of 2010. Bone has a 20-year and Clemina, Serpentine and English have 40-year Electricity Purchase Agreements (EPAs) with BC Hydro, for the purchase of electricity and Renewable Energy Certificates (RECs). In addition, we will receive funding under ecoENERGY for Renewable Power program (eRI) for Bone and Clemina, and expect to be eligible for the remaining two projects.

Construction activities were completed for the winter season for Bone and Clemina in October 2008. Since securing EPAs in 2006, construction costs have increased significantly, most particularly in the first eight months of 2008. Recently, we have begun to see a decrease in construction costs due to the current worldwide economic conditions. Should costs continue to decrease in the coming months, we plan to resume construction on Bone and Clemina and commence construction on Serpentine and English in mid-2009. Updated capital cost estimates will be provided at that time. We currently estimate a one-year delay to the target Commercial Operations Date for these projects from October 1, 2009 to October 1, 2010. There is no assurance that construction costs will decrease to economic levels, and this may impact the viability of these projects.


As previously discussed, we completed construction of Melancthon II in 2008. This $284,000,000, 132.0 MW EcoPower® Centre has a 20-year power purchase agreement (RES II Contract) with the Ontario Power Authority (OPA), an agency of the Ontario government, for the purchase of electricity and RECs. On December 22, 2008 we signed a Contribution Agreement with the Government of Canada for eRI funding. The 67.5 MW phase I achieved commercial operations on March 4, 2006 and receives $10 per MWh for 10 years from Natural Resources Canada under the Wind Power Production Incentive. The 132 MW phase II reached commercial operations on November 24, 2008 and will receive a $10 per MWh incentive for 10 years under the eRI program, in accordance with the terms of the agreement. Combined, the two phases are expected to generate 545 GWh per year and is Canada's largest wind installation.

Due to a harsher winter than expected, we anticipate that the 197.8 MW Wolfe Island Wind Project will be in-service by June 30, 2009 (previously - March 31, 2009), at a total expected capital cost of $475 million (previously $450 million), a 6% increase. Because of the worse than normal winter conditions, we have revised our project schedule for the remainder of the winter, reducing the total number of turbines erected each week based on performance to date, and, as a result, increased the targeted capital cost for the project. The project continues to be economic and provide accretive growth to our shareholders, incorporating these changes. Wolfe Island has a 20-year RES II Contract with the OPA for the purchase of electricity and RECs and will receive eRI. Based on winter conditions, construction continues to proceed well at Wolfe Island, with 45 of the 86 turbines fully erected, the laying of the 7.8 kilometre submarine cable completed, all turbines and components on the island, and work underway on the interconnection on the mainland. In December, we completed the federal Environmental Assessment, which is a major milestone in the completion of this 197.8 MW project.

The 18.0 MW, $40,000,000 Royal Road has been awarded two Standard Offer Contracts (SOCs) from the OPA under the Standard Offer Program at $110 per MWh for power generated for 20 years. The target completion date is August 2010. Regulatory approvals and financing are required prior to proceeding with construction.

We continue to work on obtaining permits and approvals to proceed to construction of our 16.0 MW (8.0 MW net to our interest), $71,000,000 ($35,500,000 net to our interest) Yellow Falls. Yellow Falls has a 20-year RES II Contract with the OPA for the purchase of electricity and RECs. Our target completion date for this project is October 2010. Regulatory approvals and financing are required prior to proceeding with construction.


We continue to work on the permitting and development of our 50.0 MW St. Valentin and 66.0 MW New Richmond Wind Projects. The capital costs remain unchanged at $160 million and $190 million, respectively, and the target in-service date of both projects remains December 2012. Turbine supply costs, including delivery have been fixed; these represent over 70% of the capital cost of the projects. St. Valentin and New Richmond have PPA prices of $108.10/MWh and $105.56/MWh (expressed in 2007 dollars), respectively. These PPA prices will escalate 5%, 15% and 80% based on full increases in the copper, steel, and Canadian consumer price indices, respectively, until the date of commercial operations. Thereafter and for the life of the PPAs, the PPA prices escalate at 100% of the change in the Canadian consumer price index. These projects are subject to regulatory approvals and financing. We anticipate financing the equity portion of these projects through internally generated cash flow and financing the debt portion in Q4 2011.

Over the last two years, most particularly in the first eight months of 2008, the industry has been faced with an unprecedented increase in construction costs. Our largest projects, which include Wolfe Island, New Richmond and St. Valentin, have been insulated largely from these cost increases as the wind turbine supply and prices, which represent the majority of the projects' capital costs, were fixed prior to securing long-term power sales contracts. Given the current economic conditions, we have seen construction costs begin to decrease and expect them to continue to decrease in the coming months. We feel this provides us with an opportunity to improve the economic returns of primarily the hydroelectric projects discussed above, which are expected to be completed in 2010. There is no assurance that construction costs will decrease to economic levels, and this may impact the viability of these projects.


In addition to our construction projects, we have an additional 1,525 MW of renewable energy prospects that are in various stages of permitting for construction in the next several years. Near-term prospects are discussed below:


Dunvegan, a 100 MW low-head, run-of-river hydro project located in northwestern Alberta on the Peace River, was subject to a joint federal-provincial panel hearing prior to obtaining approval for construction and operation. The hearing with the Alberta Utilities Commission, the Natural Resources Conservation Board and the Federal Government (the Panel) under the Canadian Environmental Assessment Act, concluded on September 26, 2008 and on December 22, 2008, we received a favourable Panel decision to proceed with the project.

The Panel decision on Dunvegan was a major milestone for us and a culmination of over a decade's work. Once constructed, Dunvegan will generate approximately 600,000 MWh per year of electricity and Renewable Energy Certificates (RECs). In 2009, the focus of our efforts will be on obtaining all permits required to proceed to construction and continuing to work on the detailed design. Due to the current economic climate, it is our intention to proceed with Dunvegan, however, the timing of construction will be dependent upon obtaining equity and debt financing at appropriate rates, finalizing our capital costs and construction schedule and marketing the power and RECs at economic levels on a long-term basis to creditworthy counterparties.

Common shares outstanding: 143,661,223


Forward-Looking Statements

Certain statements contained in this press release, constitute forward-looking statements. These statements relate to future events or our 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. We believe 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 press release should not be unduly relied upon. These statements speak only as of the date of the press release. We do not intend, and do not assume any obligation, to update these forward-looking statements.

Non-GAAP Financial Measures

Included in this press release are references to terms that do not have any meanings prescribed in GAAP and may not be comparable to similar measures presented by other companies, including EBITDA, cash flow, cash flow per share (diluted), MWh, $/MWh, kWh, kWh per share and other per share amounts. All references to cash flow relate to cash flow from operations before changes in non-cash working capital. 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.

Contact Information

  • Canadian Hydro Developers, Inc.
    Investor Relations
    Kathy Boutin, Vice President, Finance
    (403) 298-0256
    Canadian Hydro Developers, Inc.
    Media Relations
    Lindsey Moen, Communications Coordinator
    (403) 802-2099