Canadian Hydro Developers, Inc.
TSX : KHD

Canadian Hydro Developers, Inc.

August 14, 2009 08:30 ET

Canadian Hydro Announces Results for the Second Quarter Ended June 30, 2009

CALGARY, ALBERTA--(Marketwire - Aug. 14, 2009) - Canadian Hydro Developers, Inc. (TSX:KHD)

HIGHLIGHTS

- EBITDA and cash flow per share increased 50% over the prior year;

- Achieved commercial operations at Canada's second largest wind facility, the 197.8 MW Wolfe Island EcoPower® Centre, on June 26, 2009;

- Increased generation, revenue, EBITDA and cash flow due to the addition of Wolfe Island and the 132 MW Melancthon II EcoPower® Centre (Melancthon II). Together, Wolfe Island and Melancthon II more than double the size of our Company;

- Achieved positive operating income at our Grande Prairie EcoPower® Centre (GPEC), an improvement for the six months ended June 30, 2009, exceeding the amount from the entire 2008 calendar year;

- Resumed construction of our 18 MW Bone Creek Hydroelectric Project; and

- Announced the promotion of Kent Brown to Chief Executive Officer and Kathy Boutin to Chief Financial Officer, effective July 1, 2009.



----------------------------------------------------------------------------
Q2 6 Months
Change Change
2009 2008 % 2009 2008 %
----------------------------------------------------------------------------
Financial Results (in
thousands of dollars
except where noted)
Revenue 26,157 19,661 + 33 49,619 39,122 + 27
EBITDA(1) 17,148 11,279 + 52 30,164 23,978 + 26
Cash flow (1) 9,172 5,614 + 63 14,562 13,956 + 4
Per share (diluted) 0.06 0.04 + 50 0.10 0.10 -
Net earnings (loss) 23 2,883 - 99 (2,195) 4,692 - 147
Per share (diluted) 0.00 0.02 - 100 (0.02) 0.03 - 167

Operating Results
Installed capacity
- MW (net) 694 364 + 91 694 364 + 91
Electricity generation
- MWh (net) 354,617 261,377 + 36 642,067 517,844 + 24
kWh per share (diluted) 2.47 1.80 + 37 4.47 3.57 + 25
Average price received
per MWh ($) 74 75 - 1 77 76 + 1
Electrical generation
under contract (%) 86 78 + 10 83 76 + 9

(1) Non-GAAP measures, please refer to 'Advisories' included in the MD&A


For the second quarter ended June 30, 2009, revenue, EBITDA, and cash flow improved over the same period due to:

- The addition of Melancthon II (November 2008) and Wolfe Island (June 2009);

- Improved generation at Melancthon I as a result of substation work completed in 2008, which reduced availability by 28 days in June 2008; and

- Improved generation at GPEC.

These factors were offset partially by:

- Increased interest expense as compared to the prior year as a result of the interest from the Melancthon II construction facility now being expensed;

- Lower pool prices received in Alberta;

- Increased administrative expenses as a result of the Company's growth; and

- Lower foreign exchange gains as a result of lower foreign cash balances on hand.

For the six months ended June 30, 2009, revenue, EBITDA and cash flow improved over the same period in the prior year as a result of the factors described above.

On July 22, 2009, TransAlta Corporation launched an unsolicited offer (the TransAlta offer) to purchase all of the outstanding common shares of Canadian Hydro. The Board of Directors of Canadian Hydro have performed a thorough review and evaluation of the unsolicited TransAlta offer with its independent financial and legal advisors and have, as of the date hereof, concluded that the TransAlta offer is inadequate and not in the best interests of Canadian Hydro and its shareholders. As a result, the Board of Directors unanimously recommended that Canadian Hydro shareholders REJECT THE TRANSALTA OFFER by not tendering their shares. Please refer to our website at www.canhydro.com for current information regarding the unsolicited TransAlta offer.

"As the TransAlta process unfolds, the Canadian Hydro team remains focused on advancing our suite of growth opportunities," said Kent Brown, Chief Executive Officer of Canadian Hydro. "We are at a key inflection point in our Company's 20-year history as we begin to reap the financial rewards of our significant development investments, as seen in our Q2 results. With the completion of Melancthon II and Wolfe Island, we have more than doubled the size of Canadian Hydro in the last eight months and will show quarter over quarter growth throughout the worldwide economic downturn. We are now less reliant on external financing sources and will be able to take on larger projects. Additionally, after much consideration and planning, a key executive transition has been completed with John and Ross Keating transitioning into new roles of Founder and Director, and myself and Kathy Boutin being promoted to Chief Executive Officer and Chief Financial Officer, respectively. The Keatings are pioneers of green energy in Canada, and will remain a valuable source of knowledge and guidance for the Company going forward. While we are now a bigger company, we remain committed to our entrepreneurial roots and to Building a Sustainable Future®, and will continue to realize a strategic advantage through our unique process of design, build, and operate."

Canadian Hydro is focused on Building a Sustainable Future®. We are a developer, owner and operator of 21 EcoPower® Centres totalling net 694 MW of capacity in operation and have an additional 160 MW in or nearing construction and 1,660 MW of prospects under development. Our renewable generation portfolio is diversified across three technologies (water, wind and biomass) in the provinces of British Columbia, Alberta, Ontario, and Quebec. This portfolio is unique in Canada as all facilities are certified, or slated for certification, under Environment Canada's EcoLogo(M) Program.

Common shares outstanding: 143,801,223

MANAGEMENT'S DISCUSSION AND ANALYSIS (MD&A)

Advisories

The following MD&A, dated August 6, 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) and the unaudited interim consolidated financial statements for the three and six months ended June 30, 2009 and 2008. 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 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'.

EXECUTIVE SUMMARY

We completed significant milestones in the execution of our strategic plan during the first six months of 2009. We:

- Achieved commercial operations at our Wolfe Island EcoPower® Centre (Wolfe Island) on June 26, 2009, on-time at a cost of $478 million, which increased our net installed capacity by 40% to 694 MW;

- Promoted Kent Brown to Chief Executive Officer and Kathy Boutin to Chief Financial Officer, and John and Ross Keating transitioned to Founder & Director roles;

- Progressed well on the planned programs under way at our Grande Prairie EcoPower® Centre (GPEC) and Centre EcoPower® Le Nordais (Le Nordais) with the goal of improving operations by the end of 2009;

- Made advances on permitting the 100 MW Dunvegan Hydroelectric Prospect (Dunvegan); and

- Resumed construction on our 18 MW Bone Creek Hydroelectric Project (Bone Creek).

Compared to Q2 2008, revenue, EBITDA and cash flow increased in Q2 2009 due to:

- The addition of phase II of the Melancthon EcoPower® Centre (Melancthon) completed in November 2008 and Wolfe Island; and

- Increased generation at Le Nordais as a result of windier conditions.

Net earnings were lower in Q2 2009 compared to Q2 2008 due to:

- Increased interest expense as a result of the Melancthon II construction facility being charged to earnings rather than project costs as the project was completed in November 2008;

- Increased amortization expense due to commercial operations achieved at Melancthon II and Wolfe Island; and

- Lower foreign exchange gains compared to the prior year as a result of lower foreign cash balances on hand.

Revenue, EBITDA and cash flow improved in the first six months of 2009 over the same period in the prior year due to:

- The addition of phase II of Melancthon in November 2008 and Wolfe Island; and

- Improved generation and operating results at GPEC as a result of the work program initiated in late 2008.

For the six months ended June 30, 2009, net earnings were lower compared to 2008 due to the same factors as discussed above for Q2 2009 as well as lower generation at Melancthon I and II in Q1 2009 as a result of lower than average wind conditions.



RESULTS OF OPERATIONS

Revenue and Generation

Quarterly Electricity Generation - by Province and Technology(1)

----------------------------------------------------------------------------
Q2 6 months
2009 2008 2009 2008
MWh MWh Change MWh MWh Change
----------------------------------------------------------------------------
British Columbia 81,569 80,607 + 1% 86,881 111,936 - 22%
Alberta 105,224 107,144 - 2% 218,165 225,921 - 3%
Ontario 151,145 59,566 + 154% 299,311 138,990 + 115%
Quebec 16,679 14,060 + 19% 37,710 40,997 - 8%
----------------------------------------------------------------------------
Totals 354,617 261,377 + 36% 642,067 517,844 + 24%
----------------------------------------------------------------------------
Hydroelectric 124,935 120,362 + 4% 157,780 174,808 - 10%
Wind 195,522 108,620 + 80% 418,534 281,511 + 49%
Biomass 34,160 32,395 + 5% 65,753 61,525 + 7%
----------------------------------------------------------------------------
Totals 354,617 261,377 + 36% 642,067 517,844 + 24%
----------------------------------------------------------------------------
kWh per share(2) 2.47 1.80 + 37% 4.47 3.57 + 25%
----------------------------------------------------------------------------
(1) Reflecting our net interest.
(2) kWh per share based on diluted weighted average shares outstanding.


Revenue in Q2 2009 increased 33% over Q2 2008 as a result of the following factors:

- The addition of Melancthon II in November 2008 and Wolfe Island in June 2009;

- Improved generation in June compared to the prior year at Melancthon I as the EcoPower® Centre was shutdown for 28 days in June 2008 to allow for a substation expansion; and

- Improved generation at GPEC as a result of the work programs currently underway.

These increases were offset partially by lower generation at our Alberta wind EcoPower® Centres due to lower wind levels than Q2 2008.

For the six months ended June 30, 2009, revenue increased 27% over 2008 as a result of the following factors:

- The addition of Melancthon II in November 2008 and Wolfe Island in June 2009;

- Improved hydroelectric generation in Alberta and Ontario due to higher water levels; and

- Improved generation at GPEC as a result of the work program currently underway;

Offset slightly by:

- Lower generation at our British Columbia hydroelectric EcoPower® Centres due to lower water levels and increased downtime for planned maintenance;

- The inclusion in Q1 2008 of a one-time metering adjustment at our Akolkolex Hydroelectric EcoPower® Centre (Akolkolex) of 21,011 MWh, which benefited generation in Q1 2008; and

- Lower generation at our Alberta and Ontario wind EcoPower® Centres due to lower wind levels than the same period in 2008.

We received an average price of $74/MWh for Q2 2009 and $77/MWh year to date, compared to $75/MWh in Q2 2008 and $76/MWh for the first six months of 2008. These changes are the result of:

- The addition of Melancthon II and Wolfe Island, which have higher contract prices than the average of our other EcoPower® Centres;

Offset by:

- Lower pool prices received by our merchant Alberta plants in Q2 2009 (Q2 2009 - $30/MWh; Q2 2008 - $93/MWh) and for the six months ended June 30 (2009 - $42/MWh; 2008 - $76/MWh) due to lower natural gas prices and lower demand as a result of the current worldwide economic downturn, both of which influence the spot market price in Alberta. On an annual basis, a $10/MWh change in the Alberta pool price impacts earnings and cash flow per share by $0.01.

This decline in pool price was mitigated by the fact that approximately 86% of our total generation was sold pursuant to long-term sales contracts in Q2 2009 (Q2 2008 - 78%) and for the six months ended June 30, 2009, 83% of generation was sold under long-term sales contracts (2008 - 76%).

Operating Expenses

Operating expenses decreased 13% in Q2 2009 compared to Q2 2008, mainly due to the following factors:

- Significantly lower operating expenses at GPEC in Q2 2009 than Q2 2008;

- Lower property taxes in Alberta and British Columbia due to reductions in assessed values and mill rates; and

- Lower land lease payments in Alberta due to lower wind generation and significantly lower pool prices.

These decreases were offset partially by the addition of Melancthon II and Wolfe Island.

On a $/MWh basis, operating expenses decreased 35% in Q2 2009 compared to Q2 2008, primarily as a result of increased generation due to the addition of Melancthon II and Wolfe Island, as well as the above factors.

For the six months ended June 30, 2009, operating expenses increased 7% over 2008 as a result of the addition of Melancthon II and Wolfe Island and planned maintenance completed in Q1 2009 at our British Columbia Hydroelectric and Le Nordais EcoPower® Centres, offset partially by the factors discussed above. On a $/MWh basis, operating expenses decreased 14% for the six months ended June 30, 2009, compared to 2008, primarily as a result of increased generation due to the addition of Melancthon II and Wolfe Island.

Gross Margins

Gross margins, as a percentage of revenue, increased to 75% in Q2 2009 compared to 62% in Q2 2008 due primarily to increased generation and decreased operating expenses, as explained above.

For the six months ended June 30, 2009, gross margins were 73% compared to 68% in 2008 due to the increase in generation discussed above.



Interest on Credit Facilities

----------------------------------------------------------------------------
Q2 6 months
(in thousands of dollars
except where noted) 2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Gross interest on credit
facilities 8,728 8,864 - 2% 17,958 14,543 + 23%
Capitalized interest (1,382) (4,122) - 66% (3,554) (5,377) - 34%
----------------------------------------------------------------------------
Net interest expense on
credit facilities 7,346 4,742 + 55% 14,404 9,166 + 57%
----------------------------------------------------------------------------
Net interest expense on
credit facilities per MWh
($/MWh) 20.72 18.15 + 14% 22.43 17.70 + 27%
----------------------------------------------------------------------------


The increase in net interest expense on credit facilities for Q2 2009 and for the six months ended June 30, 2009 compared to the prior year was due to higher outstanding corporate debt, which increased as a result of the achievement of commercial operations (COD) of Melancthon II and Wolfe Island. Prior to COD, interest was capitalized to the projects.

On a $/MWh basis, net interest expense increased in 2009 as a result of increased debt and lower than average generation at Melancthon in January and February. On an annual basis, we expect this amount to decrease as we receive the generation benefits from Melancthon II and Wolfe Island.

We have a capital intensive business with a multi-year growth horizon. Interest costs incurred as a result of our capital program are capitalized to the project during the construction phase and are part of the estimated capital costs for the project. Capitalized interest associated with construction-in-progress and development prospects decreased due to lower outstanding balances on our credit facilities associated with the projects in or nearing construction, compared to the prior year.

Credit facilities (including current portion) drawn as at June 30, 2009 were $876,165,000 compared to $835,796,000 as at December 31, 2008. The increase was a result of increased draws on our construction facilities, less the usual repayments on certain credit facilities.

Amortization Expense

Amortization expense increased 58% in Q2 2009 from Q2 2008 and 55% for the six months ended June 30, 2009 compared to 2008, due to the addition of Melancthon II and Wolfe Island. On a $/MWh basis, amortization expense increased due to these additions, which have a higher capital cost than our existing plants.

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, and our biomass and hydroelectric EcoPower® Centres are amortized on a straight-line basis over a 40 year period.



Administration Expense

----------------------------------------------------------------------------
Q2 6 months
(in thousands of dollars
except where noted) 2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Gross administration
expenses 3,915 3,152 + 24% 8,157 5,376 + 52%
Capitalized
administration expenses (1,338) (1,917) - 30% (2,573) (2,328) + 11%
----------------------------------------------------------------------------
Net administration
expenses 2,577 1,235 + 109% 5,584 3,048 + 83%
----------------------------------------------------------------------------
Net administration
expenses per MWh ($/MWh) 7.27 4.67 + 56% 8.70 5.88 + 48%
----------------------------------------------------------------------------


Gross administration expense increased 24% in Q2 2009 compared to Q2 2008 and 52% for the six months ended June 30, 2009, compared to 2008. Over the past year, we have become a much larger company and have more than doubled our generating capacity within the last eight months. As a result, administration expenses and staff numbers have increased in order to support that growth.

On a $/MWh basis, net administration expense increased for the three and six month periods in 2009 compared to the prior year due to the reasons explained above.

Stock Compensation Expense

Stock compensation expense increased 78% in Q2 2009 compared to Q2 2008 and 31% for the six months ended June 30, 2009, compared to 2008 due to the issuance of 4,017,200 options in Q2 2009 in accordance with our new comprehensive compensation program. As a result of the new compensation program, effective April 2009, going forward we anticipate issuing between 900,000 and 1,200,000 options per year, with option grants occurring in the second and fourth quarters.

Income and Capital Taxes

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. This subsidiary is fully taxable, but is entitled to recover approximately 175% of cash taxes paid annually (limited to 15% of eligible gross revenue).

We are also liable for Provincial Capital Taxes in Ontario and Quebec, which comprise the majority of the current tax provision. Ontario Capital Tax is scheduled to be eliminated effective July 1, 2010, while Quebec Capital Tax is scheduled to be eliminated effective January 1, 2011.

Future income taxes decreased 111% and 138% for the three and six months ended June 30, 2009, compared to the same periods in the prior year, due to lower earnings before taxes and adjustments to tax pools upon finalization of 2008 annual tax returns. Our effective tax rate of 19% remains unchanged in 2009. As at June 30, 2009, we had available tax pools of $1,285,308,000.

EBITDA, Cash Flow, and Net Earnings (Loss)

EBITDA

EBITDA increased 52% in Q2 2009 compared to Q2 2008 and 26% for the six month period ended June 30, 2009, compared to 2008 due to:

- Increased generation as discussed above; and

- Increased gross margins, as discussed above.

This was offset partially by higher administrative expenses, as previously discussed.

On a $/MWh basis, EBITDA increased as a result of the factors discussed above with respect to gross margins.

Cash Flow

Cash flow increased 63% in Q2 2009 compared to Q2 2008, and 4% for the six month period ended June 30, 2009, compared to 2008 due to:

- Higher EBITDA as discussed above;

Offset partially by:

- Higher interest expense as a result of interest from the Melancthon II construction facility no longer being charged to the project costs; and

- Higher administrative expenses and capital taxes as compared to the prior year.

On a per share basis, cash flow increased 50% in Q2 2009 compared to Q2 2008 due to the reasons above. For the six months ended June 30, 2009, cash flow per share was consistent with 2008. Additionally, the proceeds from our equity issuances in 2005 have been used primarily to finance the equity portion of capital costs related to the construction of Melancthon II, Wolfe Island and our British Columbia Hydroelectric Projects. The benefits of these equity issues will not be fully reflected in our cash flow until a full year of operations has been achieved at these projects.

Net Earnings (Loss)

Net earnings (loss) decreased 99% in Q2 2009 compared to Q2 2008 and 147% for the six months ended June 30, 2009, compared to 2008, mainly as a result of:

- Higher amortization and interest expense as a result of the completion of Melancthon II and Wolfe Island;

- A large foreign exchange gain in Q2 2008 relating to Euros ear-marked for turbine purchases. With the completion of Wolfe Island, we had lower foreign cash balances on hand; and

- Higher stock compensation expense as a result of more options issued in 2009.

These expenses were offset partially by increased gross margins.

On a $/MWh basis, net earnings for both Q2 2009 and the six months ended June 30, 2009, decreased over the prior year.

The proceeds from our equity issuances in 2005 were used to finance the construction of Melancthon II, Wolfe Island, and our British Columbia Hydroelectric Projects. The benefits of these equity issues will not be fully reflected in our net earnings until a full year of operations has been achieved at these projects.



Property, Plant, and Equipment Additions and Prospect Development Costs

----------------------------------------------------------------------------
Q2 6 months
----------------------------------------------------------------------------
(in thousands of dollars) 2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Property, plant, and
equipment additions 13,982 130,222 - 89% 76,363 140,863 - 46%
Prospect development cost
additions 2,719 5,387 - 50% 6,437 7,750 - 17%
----------------------------------------------------------------------------


Property, plant, and equipment additions relate mainly to capital expenditures for Wolfe Island.

Additions to prospect development costs relate primarily to expenditures for Dunvegan, Bone Creek, and the Quebec wind projects.

LIQUIDITY AND CAPITAL RESOURCES

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, to securing the associated power purchase contracts, to satisfying the lengthy regulatory requirements, and finally to 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, consistent with the power purchase agreements we enter into.

Our capital expenditure plans and our current expectations as to the funding thereof are summarized in the table below. We believe we will generate the necessary cash flow and working capital to meet the equity needs of new projects. Subject to conditions in the capital markets at the time, we expect to have adequate access to financing to fulfill all the obligations that may be required to implement this expansion plan.

In June 2008, we issued unsecured 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 (see 'Interest on Credit Facilities').



----------------------------------------------------------------------------
As at June 30
(in thousands of dollars) 2009
----------------------------------------------------------------------------
Capital expenditure plans through 2012 474,100
Spent to date (28,739)
----------------------------------------------------------------------------
Remaining capital expenditures to be financed 445,361
Financed/to be financed by:
Blue River Credit Facility 31,590
Working capital(1) (22,855)
Anticipated credit facilities(2) 281,900
Undrawn & available revolving Operating Facility 46,003
Expected to be funded through cash flow from operations 108,723
----------------------------------------------------------------------------
Difference -
----------------------------------------------------------------------------
(1) Excluding derivative financial instruments assets and liabilities
(2) See following table with project breakdown


Our current capital expenditure plans are for the following projects either
in or nearing construction:

- Yellow Falls;
- Royal Road;
- Bone Creek;
- St. Valentin; and
- New Richmond.

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

----------------------------------------------------------------------------
Anticipated construction Anticipated timing of
(in thousands of dollars) facility size construction facility
----------------------------------------------------------------------------
Project
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 that we may be awarded under the calls for power discussed below, we will require no additional equity financing for our current projects out to 2012, and anticipate requiring only $28 million of debt financing in Q3 2009, relating to the Yellow Falls Hydroelectric Project. With Wolfe Island now completed, we expect to have the ability to finance the equity portion of approximately one, 100 MW project each year from free cash flow.

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. Generally, we 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 employ our cash flow from operations to support our capital expenditure program.

Our revolving Operating Facility matures on August 28, 2009, followed by a six-month non-amortizing term out period, subject to a one year extension upon mutual agreement by ourselves and the lending syndicate. On July 29, 2009, we requested an offer of extension of the Operating Facility term out date for a further period of 364 days from August 29, 2009 to August 28, 2010. While we are confident that the Operating Facility will be renewed prior to its maturity, the Operating Facility is classified within the current portion of our long-term debt until the Operating Facility is extended.

We have no other requirements to access the debt markets until September 2010 when the Melancthon II Construction Facility matures. Based on preliminary discussions with potential lenders and feedback we have received, we believe that we will be able to access the debt markets, as required, to satisfy our maturing obligations.

As at June 30, 2009, we had a 64/36 debt/capital mixture (December 31, 2008 - 63/37) consistent with our stated target of 65/35. We monitor our lending covenants on a continuous basis and, based on our projections, will continue to comply with all externally imposed covenants.

OUTLOOK

Project Updates

Ontario

Wolfe Island

At Wolfe Island, COD was achieved on June 26, 2009 at a total cost of $478 million. The completion of Wolfe Island represents a major milestone in the execution of our strategic plan and has increased our installed capacity by 40% to 694 MW. With the completion of Melancthon II and Wolfe Island, we have successfully doubled the size of our Company within eight months, which is a testament to our team's ability to finance, complete projects and execute on our strategic plan.

Royal Road Wind Projects

We continue to work through the approvals process for the $40 million Royal Road Wind Projects in Ontario. The projects are targeted for completion in August 2010. However, we expect the Ontario Power Authority (OPA) to offer an optional form of contract amendment to provide a one-year extension to the target in-service date. Regulatory approvals and debt financing are required prior to proceeding with construction.

Yellow Falls Hydroelectric Project

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 Hydroelectric Project. Yellow Falls has a 20-year RES II Contract with the OPA for the purchase of electricity and Renewable Energy Certificates (RECs). Our target completion date for this project is October 2010. Regulatory approvals and financing are required prior to proceeding with construction.

British Columbia

Bone, Clemina, Serpentine and English Creek Hydroelectric Projects

Since securing Electricity Purchase Agreements (EPAs) in 2006 with BC Hydro, construction costs have increased significantly. As a result, the project returns for Clemina, Serpentine and English are no longer within our targeted return threshold and as a result, we plan to proceed with construction of the 18 MW Bone Creek Hydroelectric Project and to delay construction at this time for our 11 MW Clemina Creek, 9.6 MW Serpentine Creek and 5 MW English Creek Hydroelectric Projects. Subject to the necessary approvals, we have mutually agreed with BC Hydro to terminate these three EPAs, subject to British Columbia Utilities Commission (BCUC) approval. Subject to eligibility, we plan to either build these projects under the Standing Offer Program in British Columbia or bid them into future BC Hydro calls for clean power. We anticipate that prices under BC Hydro programs will exceed the prices under our terminated EPAs, allowing us to offset any increases in capital costs and achieve project returns within our required threshold. As the projects remain viable, we continue to carry these fully permitted projects on our books at cost.

Bone Creek, which is currently under construction and is the largest of our Blue River hydroelectric projects, has a target completion date of March 31, 2011. At a capital cost estimate of $57 million, the project is expected to generate 73 GWh annually of renewable energy. Bone Creek has a 20-year EPA with BC Hydro under which BC Hydro has the option to extend the length of the EPA term from 21 to 36 years at any time until EPA expiry, subject to BCUC approval. In addition, Bone Creek will receive $10 per megawatt hour for 10 years under the Federal ecoENERGY for Renewable Power program.

Alberta

Dunvegan Hydroelectric Prospect

On April 29, 2009, another significant milestone was achieved when the Dunvegan Hydro Development Act was passed by the Alberta Legislature and came into force. This Act is another step in our permitting and approvals process as it authorizes the Alberta Utilities Commission (AUC) to make an order for the construction and operation of the project. On May 7, 2009, we received AUC approval. We continue to work on obtaining all permits required to proceed to construction, completing the detailed design and developing a marketing strategy for the power. 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. We are actively exploring alternatives with a reputable third party in order to immediately extract value from this world class project in order to accelerate commencement of construction. Dunvegan is currently estimated to cost between $500 and $600 million, however, we plan to update this estimate once detailed design is complete. The remaining permits, long-term power sale contracts and financing are required prior to proceeding to construction.

Quebec

We continue to work on the permitting and development of our 50 MW St. Valentin and our 66 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. The cost and delivery of turbines, which represents over 70% of the capital costs for these projects, have been fixed. 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.

Calls for Power

British Columbia

We submitted a proposal for a 50 MW hydroelectric prospect into BC Hydro's Clean Power Call in November 2008. On July 27, 2009, BCUC issued a ruling rejecting BC Hydro's Long Term Acquisition Plan and, as a result, did not endorse the Clean Power Call. This event may impact the timing and size of contracts awarded. However, indications from the British Columbia government are that BC Hydro will proceed with contract awards under the Clean Power Call.

Ontario Green Energy Act

On February 23, 2009, Ontario Bill 150, the "Green Energy and Green Economy Act" was tabled at the Legislative Assembly of Ontario and received royal assent on May 14, 2009. This act proposes the addition of an advanced renewable tariff that offers renewable energy producers guaranteed access to the grid at a price set by the regulatory authority. Generally, tariff prices are established at a rate that enables developers to cover the cost of their projects and to earn a reasonable return on their investment. The proposed tariff rates would be at a premium to those available under the current Standard Offer Program in Ontario. We continue to monitor this legislation, and view it as having a positive impact on our business. Please refer to our August 6, 2009, Directors' Circular which details the projects in Ontario that we are working on.

New Business

We have purchased land for the 10 MW Napanee and Bath solar facilities, both of which are fully approved for construction. Napanee has a Standard Offer Contract in place with the OPA and Bath is expected to be eligible for a contract with the OPA under the feed-in tariff program. In addition, we have purchased land for a 10 MW solar prospect at Wolfe Island and expect to be able to leverage existing infrastructure at the 198 MW Wolfe Island EcoPower® Centre, which is now in operation. Regulatory approvals for Wolfe Island, equipment supply agreements and financing are required prior to proceeding with any of the foregoing prospects. We are also assessing the viability of installing rooftop solar panels on our operations buildings in Ontario in order to reduce operating costs and further minimize our carbon footprint.



ADDITIONAL DISCLOSURES

Summary of Quarterly Results

The following table sets out selected financial information for each of the
eight most recently completed quarters:

----------------------------------------------------------------------------
(in thousands of dollars, except
per share amounts) Q3 2008 Q4 2008 Q1 2009 Q2 2009
----------------------------------------------------------------------------
Total revenue 17,398 23,578 23,462 26,157
EBITDA 11,336 14,457 13,016 17,148
Cash flow 5,454 7,487 5,390 9,172
Net earnings (loss) (4,986) 1,225 (2,218) 23
Earnings (loss) per share - basic (0.03) 0.01 (0.02) -
Earnings (loss) per share - diluted (0.03) 0.01 (0.02) -
Generation (MWh) 246,133 302,104 287,450 354,617
kWh per share (diluted) 1.69 2.07 2.00 2.47
Average price received ($/MWh) 71 78 82 74
----------------------------------------------------------------------------


----------------------------------------------------------------------------
(in thousands of dollars, except
per share amounts) Q3 2007 Q4 2007 Q1 2008 Q2 2008
----------------------------------------------------------------------------
Total revenue 14,344 17,398 19,461 19,661
EBITDA 7,765 10,597 12,699 11,279
Cash flow 4,161 6,687 8,342 5,614
Net earnings (loss) 162 5,505 1,809 2,883
Earnings (loss) per share - basic - 0.04 0.01 0.02
Earnings (loss) per share - diluted - 0.04 0.01 0.02
Generation (MWh) 212,031 237,917 256,467 261,377
kWh per share (diluted) 1.56 1.76 1.78 1.80
Average price received ($/MWh) 68 73 76 75
----------------------------------------------------------------------------


The changes over the past eight quarters are due primarily to the addition of Le Nordais and Melancthon II, as well as the large non-cash foreign exchange loss in Q3 2008 due to foreign denominated cash on hand ear-marked for turbine payments, and increased operating, interest and amortization expenses, as previously discussed.

Disclosure Controls and Internal Controls and Procedures

As of the end of the period covered by this quarterly report, there have been no changes to our disclosure controls or internal controls over financial reporting since December 31, 2008.

Accounting Changes and Future Accounting Changes

Effective January 1, 2009, the Company adopted Canadian Institute of Chartered Accountants ("CICA") handbook section 3064 - "Goodwill and Intangible Assets" and the CICA Emerging Issues Committee (EIC) Abstract No.173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities" (EIC 173). EIC 173 clarifies how an entity's own credit risk and that of the relevant counterparty should be taken into account in determining the fair value of financial assets and financial liabilities, including derivative instruments. The new guidance did not have any impact on the financial position or earnings of the Company.

The CICA has issued the following handbook sections, which will become effective between 2009 and 2011:

(i) Section 1582 - "Business Combinations" - Section 1582 replaces Section 1581 - "Business Combinations" and provides the Canadian equivalent to International Financial Reporting Standards ("IFRS") 3 - "Business Combinations". This applies to a transaction in which the acquirer obtains control of one or more businesses. Most assets acquired and liabilities assumed, including contingent liabilities that are considered to be improbable, will be measured at fair value. Any interest in the acquiree owned prior to obtaining control will be remeasured at fair value at the acquisition date, eliminating the need for guidance on step acquisitions. Additionally, a bargain purchase will result in recognition of a gain and acquisition costs must be expensed. The Company will adopt this standard on January 1, 2011.

(ii) Section 1601 - "Consolidations" and Section 1602 - "Non-controlling Interests". Section 1601 and Section 1602 replace Section 1600 - "Consolidated Financial Statements". Section 1602 provides the Canadian equivalent to International Accounting Standard 27 - "Consolidated and Separate Financial Statements", for non-controlling interests. The Company will adopt this standard on January 1, 2011.

(iii) In June 2009, the CICA issued amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments will be effective for annual financial statements for fiscal years ending after September 30, 2009. The amendments are consistent with recent amendments to financial instrument disclosure standards in IFRS. The Company will include these additional disclosures in its annual consolidated financial statements for the year ending December 31, 2009.

Effective January 1, 2011, IFRS will replace current Canadian standards and interpretations as Canadian generally accepted accounting principles for publicly accountable enterprises. Accordingly, we will be adopting the new standards effective at this date. IFRS are based on a conceptual framework that is substantially the same as that on which Canadian standards are based and cover many of the same topics and reach similar conclusions on many issues. However, within the various standards there are differences which may impact our accounting practices and balances.

We commenced our IFRS conversion project in 2009 and recognized that the convergence to IFRS may impact a combination of accounting, IT, and business systems. We have engaged a major accounting firm to advise and assist us with identifying accounting treatment differences between IFRS and Canadian GAAP. Our IFRS conversion project consists of three main phases: Project Scoping, Solution Development, and Implementation. We have completed the scoping phase, which involved a high-level preliminary assessment of the differences between IFRS and Canadian GAAP and the potential impact of convergence on other business systems and processes. This assessment has provided insight as to the most significant areas of differences applicable to us, which includes, but is not limited to: property, plant, and equipment, joint ventures, provisions and leases, and financial statement disclosure and presentation.

The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect our reported financial position and results of operations. As we are still in the Solution Development phase of our conversion project, and have not yet selected our accounting policies and IFRS 1 exemptions, we are unable to quantify the impact of IFRS on our financial statements at this time. We continue to monitor standards development as issued by the International Accounting Standards Board and the CICA Accounting Standards Board, as well as regulatory developments as issued by the Canadian Securities Administrators, which may affect the timing and nature of disclosure of our adoption of IFRS. The areas of significance identified above are based on available information and our expectations as of the date of this MD&A and thus, are subject to change.

OFF-BALANCE SHEET ARRANGEMENTS

At June 30, 2009, we have no off-balance sheet arrangements.

TRANSACTIONS WITH RELATED PARTIES

We pay gross overriding royalties ranging from 1% - 2% on electric energy sales on four of our original hydroelectric plants to a company controlled by J. Ross Keating, Founder & Director. During the three and six months ended June 30, 2009, royalties totaling $20,000 (2008 - $19,000) and $29,000 (2008 - $28,000), respectively, were incurred.

FINANCIAL INSTRUMENTS

We have a risk management policy that is approved annually by our Board of Directors. Our general philosophy is to avoid unnecessary risk and to limit, to the extent practicable, any significant risks associated with business activities. We may use from time to time derivative financial instruments to manage or hedge commodity price, interest rate, and foreign currency risks. Use of derivatives on a speculative or non-hedged basis is specifically disallowed. Authorization levels for the execution of derivatives for hedging purposes have been set by our Board of Directors and are reviewed quarterly by our Audit Committee. For the period ended June 30, 2009, we had the following financial instruments in place to manage risk:

Contracts for Differences

We have entered into various Contracts for Differences (CFDs) with other parties whereby the other parties have agreed to pay us a fixed price with a weighted average of $53 per MWh based on the average monthly Pool price for an aggregate of 133,950 MWh per year of electricity, maturing from 2009 to 2024. While the CFDs do not create any obligation for us to physically deliver electricity to other parties, we believe we have sufficient electrical generation that is not subject to contract, to satisfy the CFDs. We are unable to fair value two of the CFDs for an aggregate of 4,150 MWh per year of electricity because the CFD price includes the sale of RECs along with the settlement of the average monthly Pool price. Our assumptions for fair valuing our CFDs, given the ongoing illiquidity of the forward market, assume the actual contract prices contained in the CFDs are the same as the forward prices for years where no forward market exists. At June 30, 2009, the fair value of the CFDs was a liability of $465,000.

Foreign Exchange Contracts

Concurrent with the issuance of the Series 5 debentures, we entered into a cross-currency swap to fix both the principal and interest payments on the Series 5 debentures. The principal amount of $20,000,000 US dollars was fixed at $20,400,000 Canadian dollars and the semi-annual interest payments of $730,800 US dollars were fixed at $734,400 Canadian dollars. At June 30, 2009, the aggregate fair value of all outstanding foreign exchange contracts was an asset of $3,624,000.

Interest Rate Swap Contracts

We have entered into an interest rate swap contract on our Melancthon II and Wolfe Island Construction Facilities, which fix our interest payments at a blended rate of 2.41% per annum plus a stamping fee for an all-in rate of 3.71%. At June 30, 2009, the fair value of all outstanding interest rate swap contracts was a liability of $9,084,000.



OUTSTANDING SHARE DATA

----------------------------------------------------------------------------
As at August 6, 2009
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 143,801,223
Convertible securities:
Options 9,524,950
----------------------------------------------------------------------------
Fully diluted common shares 153,326,173
----------------------------------------------------------------------------
----------------------------------------------------------------------------


ADVISORIES

Forward-Looking Statements

Certain information in this MD&A constitutes "forward-looking information" (within the meaning of applicable Canadian securities laws) regarding the business and affairs of Canadian Hydro Developers, Inc. ("Canadian Hydro"). Such information ("forward-looking statements") is generally identifiable by the terminology used, such as "anticipate", "believe", "intend", "potential", "plan", "expect", "estimate", "budget", "may", "might", "outlook" or other similar words and include statements relating to, or associated with, individual power generation facilities, regions, projects or prospects. Any statements regarding the following are forward-looking statements:

- future commodity prices, power production levels, capital expenditures, sources of funding for Canadian Hydro's capital program and debt levels;

- supply and demand for power, including green power;

- the expected costs to construct the Yellow Falls, Royal Road, New Richmond, St. Valentin, Bone Creek, Clemina Creek, Serpentine Creek and English Creek projects and other potential projects;

- the anticipated availability of skilled laborers;

- Canadian Hydro's estimated general financial performance in future periods;

- any estimate of present value or Canadian Hydro's future net cash flow;

- Canadian Hydro's expectations regarding global capital markets;

- the impact of governmental controls and regulations on Canadian Hydro's operations;

- Canadian Hydro's expectations regarding its competitive advantages, ability to compete successfully and the development potential of its projects and potential projects, including through the use of emerging technologies such as biomass and solar; and

- potential alternative transactions involving Canadian Hydro, including those transactions that may produce superior value to the Shareholders.

Assumptions upon which certain of such forward-looking statements are based include assumptions regarding, among other items:

- future supply of, demand for and market prices for power, exchange rates for the Canadian dollar, wind patterns and run-of-river water volumes;

- Canadian Hydro's ability to market power production successfully to customers;

- availability and pricing of capital equipment and other inputs used in connection with Canadian Hydro's business and projects;

- current and future economic, market and business conditions in Canada or elsewhere in North America;

- Canadian Hydro's ability to obtain qualified staff and equipment in a timely and cost-efficient manner to meet Canadian Hydro's requirements;

- Canadian Hydro's ability to raise capital and generate cash flow to fund existing projects and future prospects;

- the cost of construction for Canadian Hydro's projects, construction schedules and planned start-up dates;

- the regulatory framework representing taxes and environmental matters, including with respect to carbon emissions, in which Canadian Hydro conducts its business; and

- that the TransAlta Offer will not be successful or that an alternative and superior transaction involving Canadian Hydro can be negotiated and concluded.

These assumptions are based on certain factors and events that are not within the control of Canadian Hydro and there is no assurance they will prove to be correct. These statements speak only as of the date of the MD&A. We do not intend, and do not assume any obligation, to update these forward-looking statements.

Non-GAAP Financial Measures

Included in this MD&A 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, gross margins, 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. The following table reconciles EBITDA and cash flow to their nearest prescribed GAAP definition:



3 months ended 6 months ended
June 30 June 30
--------------------------------------
2009 2008 2009 2008
--------------------------------------
Cash flow from operations (19,484) 40,767 15,848 48,132
Less: Changes in non-cash working
capital 28,656 (35,153) (1,286) (34,176)
--------------------------------------
Cash flow 9,172 5,614 14,562 13,956
--------------------------------------
--------------------------------------
Cash flow 9,172 5,614 14,562 13,956
Interest expense 7,346 4,743 14,404 9,167
Interest income (8) (175) (83) (380)
Current tax expense 638 1,097 1,281 1,235
--------------------------------------
EBITDA 17,148 11,279 30,164 23,978
--------------------------------------
--------------------------------------


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

June 30, December 31,
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

ASSETS

CURRENT
Cash 8,311 33,839
Accounts receivable (Note 8) 13,472 31,925
Derivative financial instrument asset (Note 8) 3,624 4,954
Prepaid expenses 3,966 962
----------------------------------------------------------------------------
29,373 71,680

Property, plant, and equipment (Note 3) 1,347,065 1,288,446
Prospect development costs (Note 4) 66,598 50,006

----------------------------------------------------------------------------
TOTAL ASSETS 1,443,036 1,410,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES

CURRENT
Accounts payable and accrued liabilities 33,055 39,085
Derivative financial instrument liability (Note 8) 9,549 12,273
Current portion of long-term debt (Note 6) 14,420 2,364
Taxes payable 1,129 1,177
----------------------------------------------------------------------------
58,153 54,899

Long-term debt (Note 6) 861,745 833,432
Future income taxes 38,701 39,564
----------------------------------------------------------------------------

958,599 927,895
----------------------------------------------------------------------------
COMMITMENTS & CONTINGENCIES (Note 12)
SUBSEQUENT EVENTS (Note 13)

SHAREHOLDERS' EQUITY

Share capital and warrants (Note 7) 451,247 455,066
Contributed surplus (Note 7) 12,027 6,399
Retained earnings 30,085 32,280
----------------------------------------------------------------------------
493,359 493,745
Accumulated other comprehensive loss (Note 5) (8,922) (11,508)
----------------------------------------------------------------------------
484,437 482,237
----------------------------------------------------------------------------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 1,443,036 1,410,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------



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

3 months ended 6 months ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------

Revenue
Electric energy sales 26,043 19,538 49,348 38,813
Revenue rebate 114 123 271 309
----------------------------------------------------------------------------
26,157 19,661 49,619 39,122
----------------------------------------------------------------------------

Expenses (income)
Operating 6,546 7,483 13,550 12,633
Amortization 8,058 5,100 15,675 10,129
Interest on credit facilities 7,346 4,743 14,404 9,167
Administration 2,577 1,235 5,584 3,048
Stock based compensation 1,042 584 1,714 1,306
Reclassification of amounts from other
comprehensive income (Note 5) 1,742 - 1,242 -
Foreign exchange gain (1,626) (5,081) (641) (5,282)
Interest income (8) (175) (83) (380)
Write-off of prospect development
costs (Note 4) - 188 - 188
----------------------------------------------------------------------------
25,677 14,077 51,445 30,809
----------------------------------------------------------------------------

Earnings (loss) before taxes 480 5,584 (1,826) 8,313
----------------------------------------------------------------------------

Tax expense (recovery)
Current 638 1,097 1,281 1,235
Future (181) 1,604 (912) 2,386
----------------------------------------------------------------------------
457 2,701 369 3,621
----------------------------------------------------------------------------

Net earnings (loss) 23 2,883 (2,195) 4,692

Retained earnings, beginning of period 30,062 33,158 32,280 31,349
----------------------------------------------------------------------------

Retained earnings, end of period 30,085 36,041 30,085 36,041
----------------------------------------------------------------------------

Earnings (loss) per share (Note 10)
Basic 0.00 0.02 (0.02) 0.03
Diluted 0.00 0.02 (0.02) 0.03

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited)
(in thousands of dollars)

3 months ended 6 months ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------

Net earnings (loss) 23 2,883 (2,195) 4,692

Other comprehensive gain (loss):
Unrealized (loss) gain on derivative
financial instrument currency hedges,
net of tax (2,316) (2,874) (1,379) 1,108
Unrealized (loss) gain on derivative
financial instrument contracts for
differences (660) (355) 387 (236)
Unrealized gain on derivative
financial instrument interest
rate hedges 2,848 - 2,336 -
Reclassified to net earnings 1,742 - 1,242 -
----------------------------------------------------------------------------
Other comprehensive gain (loss) 1,614 (3,229) 2,586 872

Comprehensive income (loss) 1,637 (346) 391 5,564
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

3 months ended 6 months ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings (loss) 23 2,883 (2,195) 4,692
Adjustments for:
Amortization 8,058 5,100 15,675 10,129
Reclassification of amounts from
other comprehensive income 1,742 - 1,242 -
Stock compensation expense 1,042 584 1,714 1,306
Unrealized foreign exchange gain (1,512) (4,745) (962) (4,745)
Future income tax (recovery) expense (181) 1,604 (912) 2,386
Write-off of prospect development
costs - 188 - 188
----------------------------------------------------------------------------

Cash flow from operations before
changes in non-cash working capital 9,172 5,614 14,562 13,956
Changes in non-cash working capital (28,656) 35,153 1,286 34,176
----------------------------------------------------------------------------
(19,484) 40,767 15,848 48,132
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Credit facility repayments (Note 6) (501) (1,696) (23,990) (2,135)
Credit facility advances (Note 6) 37,000 214,400 65,600 214,400
Acquisition facility repayment - (72,300) - (72,300)
Issue of common shares, net of issue
costs (Note 7) - 213 95 6,297
----------------------------------------------------------------------------
36,499 140,617 41,705 146,262
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Property, plant, and equipment
additions (13,982) (130,222) (76,363) (140,863)
Prospect development costs (2,719) (5,387) (6,437) (7,750)
----------------------------------------------------------------------------
(16,701) (135,609) (82,800) (148,613)
----------------------------------------------------------------------------

----------------------------------------------------------------------------
FOREIGN EXCHANGE ON CASH HELD IN
FOREIGN CURRENCY (231) 4,745 (281) 4,745
----------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH 83 50,520 (25,528) 50,526
CASH, BEGINNING OF PERIOD 8,228 22,791 33,839 22,785
----------------------------------------------------------------------------

CASH, END OF PERIOD 8,311 73,311 8,311 73,311
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental information
Cash interest paid 11,622 8,209 18,865 12,737
Cash income and capital taxes paid 734 111 1,328 111


CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
AS AT AND FOR THE THREE AND SIX MONTH PERIODS ENDED JUNE 30, 2009
(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 for electricity, 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 generally expects interim results for the first and fourth quarters to be higher than those for the second and third.

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

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

2. CHANGE IN ACCOUNTING POLICIES

(a) Accounting Changes

Effective January 1, 2009, the Company adopted Canadian Institute of Chartered Accountants ("CICA") handbook section 3064 - "Goodwill and Intangible Assets", which replaces section 3062 - "Goodwill and Other Intangible Assets". This new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. Effective January 1, 2009, the Company adopted the CICA Emerging Issues Committee (EIC) Abstract No.173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities" (EIC 173). EIC 173 clarifies how an entity's own credit risk and that of the relevant counterparty should be taken into account in determining the fair value of financial assets and financial liabilities, including derivative instruments. The new guidance did not have any impact on the financial position or earnings of the Company.

(b) Future Accounting Pronouncements

The CICA has issued the following handbook sections, which will become effective between 2009 and 2011. The Company is currently in the process of evaluating the requirements of the new standards:

(i) Section 1582 - "Business Combinations" - Section 1582 replaces Section 1581 - "Business Combinations" and provides the Canadian equivalent to International Financial Reporting Standards ("IFRS") 3 - "Business Combinations". This applies to a transaction in which the acquirer obtains control of one or more businesses. Most assets acquired and liabilities assumed, including contingent liabilities that are considered to be improbable, will be measured at fair value. Any interest in the acquiree owned prior to obtaining control will be remeasured at fair value at the acquisition date, eliminating the need for guidance on step acquisitions. Additionally, a bargain purchase will result in recognition of a gain and acquisition costs must be expensed. The Company will adopt this standard on January 1, 2011.

(ii) Section 1601 - "Consolidations" and Section 1602 - "Non-controlling Interests". Section 1601 and Section 1602 replace Section 1600 - "Consolidated Financial Statements". Section 1602 provides the Canadian equivalent to International Accounting Standard 27 - "Consolidated and Separate Financial Statements", for non-controlling interests. The Company will adopt this standard on January 1, 2011.

(iii) Effective January 1, 2011, IFRS will replace current Canadian standards and interpretations as Canadian GAAP for publicly accountable enterprises. Accordingly, the Company will be adopting the new standards effective at this date.

(iv) In June 2009, the CICA issued amendments to CICA Handbook Section 3862 - "Financial Instruments - Disclosures". The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments will be effective for annual financial statements for fiscal years ending after September 30, 2009. The amendments are consistent with recent amendments to financial instrument disclosure standards in IFRS. The Company will include these additional disclosures in its annual consolidated financial statements for the year ending December 31, 2009.

3. PROPERTY, PLANT, AND EQUIPMENT

The major categories of property, plant, and equipment at cost and related accumulated amortization are as follows:



December 31,
June 30, 2009 2008
---------------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
---------------------------------------------------
Generating plants
- operating 1,419,649 (89,993) 1,329,656 856,291
- construction-in-progress 12,817 - 12,817 428,592
Equipment, other 6,632 (2,663) 3,969 2,918
Vehicles 2,273 (1,650) 623 645
---------------------------------------------------

1,441,371 (94,306) 1,347,065 1,288,446
---------------------------------------------------
---------------------------------------------------


The following amounts have been capitalized to property, plant, and
equipment for the 3 and 6 months ended June 30, 2009 and 2008:


3 months ended 6 months ended
June 30 June 30
-------------------------------------
2009 2008 2009 2008
-------------------------------------

Interest costs 1,382 4,122 3,554 4,424
Administrative expenses 605 1,709 1,151 1,754
-------------------------------------
Total 1,987 5,831 4,705 6,178
-------------------------------------
-------------------------------------


As at June 30, 2009, construction-in-progress (CIP) relates to costs associated with the construction of the Bone Creek Hydroelectric Project (2008 - Melancthon II, Wolfe Island Wind Project, and Bone and Clemina Creek). During the three and six months ended June 30, 2009, $nil was moved from Prospect Development Costs to CIP (2008 - $220,668,000) and $11,005,000 was moved from CIP to prospect development costs (2008 - $nil) related to the reclassification of Clemina Creek.

4. PROSPECT DEVELOPMENT COSTS

Prospect development costs are composed of the following:



June 30, December 31,
2009 2008
$ $
------------------------
Dunvegan Hydroelectric Prospect 18,675 16,703
Clemina Creek Hydroelectric Project 11,005 -
Manitoba Wind Prospects 7,687 7,744
Serpentine Creek Hydroelectric Project 6,707 6,066
Royal Road Wind Projects 6,418 6,160
New Richmond and St. Valentin Wind Projects 5,899 5,156
Other Hydroelectric and Wind Prospects 4,574 3,036
Yellow Falls Hydroelectric Project 3,614 3,350
Solar Prospects 1,083 909
English Creek Hydroelectric Project 936 882
------------------------

Total 66,598 50,006
------------------------
------------------------


The following amounts have been capitalized to prospect development costs
for the 3 and 6 months ended June 30, 2009 and 2008:

3 months ended 6 months ended
June 30 June 30
------------------------------------
2009 2008 2009 2008
------------------------------------

Interest costs - - - 953
Administrative expenses 733 208 1,422 574
------------------------------------
Total 733 208 1,422 1,527
------------------------------------
------------------------------------


For the three and six months ended June 30, 2009, the Company wrote off $nil (2008 - $188,000) in costs relating to development prospects that were abandoned during the period.

5. ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCL)

AOCL is composed of the following:



$
---------
Balance, December 31, 2008 (11,508)
Unrealized loss on derivative financial instrument cross-currency
swap, net of tax (1,379)
Unrealized gain on derivative financial instrument interest rate
hedges 2,336
Unrealized gain on derivative financial instrument contracts for
differences (CFDs) 387
Amounts reclassified to net earnings 1,242
---------
Accumulated other comprehensive loss, June 30, 2009 (8,922)
---------
---------


During the three and six months ended June 30, 2009, $1,742,000 and $1,242,000, respectively, were reclassified from AOCL to the statement of earnings, related to the cross-currency swap (Note 8). Notwithstanding future changes in the value of the cross-currency swap described in Note 8, no additional amounts are expected to be reclassified from AOCL to net earnings within the next 12 months.

6. CREDIT FACILITIES

The Company has a revolving Operating Facility with its banking syndicate for a total of $85,000,000. As at June 30, 2009, in addition to the $12,000,000 shown below as drawn, the Company had outstanding letters of credit in the amount of $26,997,000 (December 31, 2008 - $30,292,000) relating primarily to construction activities and security required under long-term sales contracts for electricity.



June 30, December 31,
2009 2008
$ $
------------------------
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 5.690%,
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 5.770%,
12-year term with interest payable semi annually
and no principal repayments until maturity on June
19, 2018, senior unsecured. 121,000 121,000

Series 4 Debentures, bearing interest at 7.027%,
10-year term with interest payable semi annually
and no principal repayments until maturity on June
11, 2018, senior unsecured. 55,500 55,500

Series 5 Debentures, bearing interest at 7.308%,
10-year term with interest payable semi annually
and no principal repayments until maturity on June
11, 2018, senior unsecured, with a principal of
$20,000,000 denominated in US dollars (Note 8). 23,250 24,492

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 EcoPower® Centre,
without recourse to joint venture participants. 35,000 35,000

Melancthon II Credit Facility, bearing interest at
Bankers' Acceptances rates plus a stamping fee of
0.70% per annum, unsecured non-revolving credit
facility with an 18-month drawdown period, which
ended December 27, 2008, followed by a two-year
non-amortizing term out period to September 26,
2010 (Note 8). 184,600 184,600

Wolfe Island Credit Facility, bearing interest at
Bankers' Acceptances rates plus a stamping fee of
1.375% per annum, unsecured non-revolving credit
facility with an 18-month drawdown period, followed
by a two-year non-amortizing term out period to June
11, 2011 (Note 8). 292,500 231,900

Blue River Credit Facility, bearing interest at
Bankers' Acceptances rates plus a stamping fee of
0.70% per annum, unsecured non-revolving credit
facility with a 31-month drawdown period ending
January 27, 2010, followed by a two-year
non-amortizing term out period. - -

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 rates plus a stamping
fee of 1.375% per annum. 12,000 30,000

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. 5,148 5,580

Mortgage, bearing interest at 10.680%, secured by
letters of guarantee. Monthly repayments of principal
are $31,000 plus interest until December 30, 2012. 1,313 1,500

Mortgage, bearing interest at 10.700% and secured by a
letter of guarantee. Monthly repayments of principal
and interest are $84,000 until May 31, 2010. 907 1,350

Promissory note, bearing interest fixed at 6.000%,
secured by a second fixed charge on three of the
Alberta hydroelectric EcoPower® Centres. Monthly
repayments of principal and interest are $19,000
until August 1, 2012 682 769
------------------------

878,900 838,691
Less: Deferred financing costs (2,735) (2,895)
------------------------
876,165 835,796
Less: Current portion of credit facilities (14,420) (2,364)
------------------------
Credit facilities 861,745 833,432
------------------------
------------------------


7. SHARE CAPITAL

(a) Common shares and warrants:

Number of Amount
Shares $
-----------------------
Balance, share capital, December 31, 2008 143,611,223 455,066
Warrants, reclassified to contributed surplus
(Note 7(c)) - (3,967)
Issued on exercise of stock options 50,000 95
Stock compensation on options exercised - 53
-----------------------

Balance, share capital, June 30, 2009 143,661,223 451,247
-----------------------
-----------------------


(b) Stock compensation:

The following table presents the Company's stock option issuances and
expense for the 3 and 6 months ended June 30, 2009 and 2008:

3 months ended 6 months ended
June 30 June 30
-----------------------------------------
2009 2008 2009 2008
-----------------------------------------

Number of options issued 4,017,200 522,500 4,042,400 602,500
Stock based compensation recognized 1,042 584 1,714 1,306
Average fair value per option 0.95 1.90 0.96 1.77
-----------------------------------------


The fair value of options issued for the 3 and 6 months ended June 30, 2009 and 2008 were estimated using the Black-Scholes option-pricing model with the following average assumptions:



3 months ended 6 months ended
June 30 June 30
-------------------------------------
2009 2008 2009 2008
-------------------------------------
Risk free interest rate (%) 1.81 3.32 1.82 3.43
Volatility (%) 39.26 28.72 39.18 28.60
Expected weighted average life (years) 4.0 4.0 4.0 4.0
Annual dividend yield (%) - - - -
Vesting period (years) 3.22 4.0 3.23 4.0
-------------------------------------


(c) Contributed surplus:

June 30 June 30
2009 2008
$ $
------------------------
Balance, beginning of period 6,399 4,299
Stock based compensation 1,714 1,306
Reclassification of expired warrants 3,967 -
Stock compensation on options exercised (53) (306)
------------------------

Balance, end of period 12,027 5,299
------------------------
------------------------


On March 8, 2009, 4,110,900 warrants valued at $3,967,000 relating to the acquisition of GW Power Corporation on March 8, 2007 expired without exercise. The corresponding value was reclassified from share capital to contributed surplus.

(d) Stock options:

The following table summarizes information about stock options outstanding at June 30, 2009:



Range of Weighted Average
Exercise Prices Number Outstanding Exercise Price
----------------------------------------------------------------------------
$1.00 to $3.00 4,480,650 $ 2.56
$3.00 to $5.00 1,187,500 $ 3.84
$5.00 to $7.00 4,315,000 $ 5.90
----------------------------------------------------
9,983,150 $ 4.16
----------------------------------------------------
----------------------------------------------------


8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Categories of Financial Assets and Liabilities

Under GAAP, 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 disposed of. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability (other than costs attributable to instruments classified as held for trading) are added to the cost of the instrument at its initial carrying amount.

The Company has made the following classifications:

- Cash and cash equivalents and derivative financial instrument assets and liabilities are classified as financial assets and liabilities held for trading and are measured on the balance sheet at fair value;

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

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

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximates their fair value at June 30, 2009 and 2008 due to their short-term nature. The Company is exposed to credit related losses, which are minimized as the majority of sales are made under contracts with provincial governmental agencies and large utility customers with extensive operations in British Columbia, Alberta, Ontario, and Quebec. No reclassifications or derecognition of financial instruments occurred in the period.

The Company's credit facilities, as described in Note 6, are comprised of senior unsecured debentures, secured debentures, construction facilities, an operating facility, mortgages and a promissory note and, as such, the Company is exposed to interest rate risk. The Company mitigates this risk by either fixing the interest rates upon the inception of the debt or through interest rate swaps. The fair values of the debentures approximate their book values, based on the Company's current creditworthiness and prevailing market interest rates.

Credit Risk, Liquidity Risk, Market Risk, and Interest Rate Risk

The Company has limited exposure to credit risk, as the majority of its sales contracts are with governments and large utility customers with extensive operations in British Columbia, Alberta, Ontario, and Quebec, and the Company's cash is held with major Canadian financial institutions. Historically, the Company has not had collection issues associated with its receivables and the aging of receivables is reviewed on a regular basis to ensure the timely collection of amounts owing to the Company. At June 30, 2009, the aging of the Company's receivables is as follows:



June 30
2009
$
---------

Current receivables 13,472
Receivables between 60 - 120 days -
Receivables greater than 120 days -
---------
13,472
Less: Impairment allowance -
---------
Receivables, end of period 13,472
---------
---------


The Company manages its credit risk by entering into sales agreements with creditworthy parties and through regular review of accounts receivable. The maximum exposure to credit risk is represented by the net carrying amount of these financial assets. This risk management strategy is unchanged from the prior year.

The Company manages its liquidity risk associated with its financial liabilities (primarily those described in Note 6) through the use of cash flow generated from operations, combined with strategic use of long term corporate debentures and issuance of additional equity, as required to meet the capital requirements of maturing financial liabilities. The contractual maturities of the Company's long term financial liabilities are disclosed in Note 6, and remaining financial liabilities, consisting of accounts payable, are expected to be realized within one year. As disclosed in Note 9, the Company is in compliance with all financial covenants relating to its financial liabilities as at June 30, 2009. This risk management strategy is unchanged from the prior year.

As disclosed in Note 6, the Company has four credit facilities, which have variable interest rate risks: the Operating Facility and the three credit facilities (Melancthon II, Wolfe Island, and Blue River). These facilities have interest rates based on the Bankers' Acceptances rates, plus a stamping fee ranging from 0.70% to 1.375% per annum. Due to these variable rates, the Company is exposed to interest rate risk. This risk has been mitigated to the greatest extent possible through the interest rate swap described below. The Company also manages this interest rate risk through the issuance of fixed rate, long term debentures which are used to replace the credit facilities upon completion of the project. This risk management strategy is unchanged from the prior year.

The Company's financial instruments that are exposed to market risk are: CFDs, the cross-currency swap, and the interest rate swap, which are impacted by changes in the forward price of electricity in Alberta, the Canadian/US dollar exchange rate, and the Bankers' Acceptances rates respectively. The objective of these financial instruments is to provide a degree of certainty over the future cash flows of the Company and protect the Company from fluctuating exchange rates and commodity prices. These instruments are managed through a periodic review by senior management, during which the value of entering into such contracts is assessed. The Company's financial instrument activities are governed by its risk management policy, as approved by the Board of Directors on an annual basis. Based upon the remaining payments at June 30, 2009, a 1% change in the forward electricity prices would result in a $18,000 impact to AOCL, a 1% change in the Canadian/US dollar exchange rate would result in an impact of $351,000 to AOCL, and a 1% change in the Bankers' Acceptances rates would result in an impact of $2,000 to AOCL. This risk management strategy is unchanged from the prior year.



Derivative Instruments and Hedging Activities

June 30 December 31
2009 2008
$ $
------------------------
Derivative Financial Instrument Assets

On June 11, 2008, concurrent with the issuance of the
Series 5 debentures described in Note 6, the Company
entered into a cross-currency swap to fix both the
principal and interest payments on the Series 5
debentures, which are denominated in US dollars,
into Canadian dollars. The principal amount of
$20,000,000 US was fixed at $20,400,000 Canadian and
the semi-annual interest payments of $730,800 US were
fixed at $734,400 Canadian. After giving effect to
the cross-currency swap, the principal amounts of the
Series 4 and 5 Debentures are fixed at $75,900,000
Canadian with an interest rate of 7.073% per annum. 3,624 4,954
------------------------
3,624 4,954
------------------------
------------------------

Derivative Financial Instrument Liabilities

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 $53 per MWh to the Company
based on the average monthly Alberta Power Pool
("Pool") price for an aggregate of 133,950 MWh per
year of electricity, maturing from 2009 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 in future periods
where no forward market exists. 465 852

On August 28 and December 16, 2008, the Company
entered into interest rate swaps to fix the interest
rate on the Bankers' Acceptances amounts under the
Wolfe Island and Melancthon II construction facilities
from a variable interest rate based upon the Bankers'
Acceptances rates to a fixed rate of 2.41% per annum
plus a stamping fee. 9,084 11,421
------------------------
9,549 12,273
------------------------
------------------------


As at June 30, 2009, the Company does not have any outstanding contracts or financial instruments with embedded derivatives that require bifurcation.

9. CAPITAL DISCLOSURES

The Company's stated objective when managing capital (comprised of the Company's debt and shareholders' equity) is to utilize an appropriate amount of leverage to ensure that the Company is able to carry out its strategic plans and objectives. The Company's debt ratio is measured against a targeted debt to capital ratio of 65/35, which the Company believes is an appropriate mix given the current economic conditions in Canada, the Company's growth phase, and the long-term nature of the Company's assets. The Company plans to meet the targeted ratio through the issuance of additional financings, as required to fund the Company's development projects.

The Company's current debt/capital mixture is calculated as follows:



June 30 December 31
2009 2008
$ $
--------------------------

Total debt, including current portion of credit
facilities 876,165 835,796
Shareholders' equity 484,437 482,237
--------------------------
Total capital 1,360,602 1,318,033
--------------------------
--------------------------

Debt to capital mixture, end of period 64/36 63/37
--------------------------
--------------------------


Changes from December 31, 2008 relate primarily to draws on construction facilities described in Note 6, offset slightly by the repayment of credit facilities, in accordance with the original agreements, as well as changes to shareholders' equity relating to current period earnings and the exercise of stock options, described in Note 7.

In accordance with the Company's various lending agreements, the Company is required to meet specific capital requirements. As at June 30, 2009, the Company was in compliance with all externally imposed capital requirements, which consist of the following covenants in accordance with the Company's borrowing agreements:

- Debt to total capitalization ratio - the Company cannot exceed a debt to total capitalization ratio of 0.65:1. Total capitalization is defined as long term debt (including current portion of credit facilities and derivative financial instrument liabilities) plus shareholders' equity, which includes AOCL.

- Interest service coverage ratio - the Company shall not have an interest service coverage ratio below 2.50:1. Interest service coverage is calculated by dividing EBITDA (defined as net income, plus depreciation, income taxes, interest expense net of interest income, stock compensation expense and non-cash foreign exchange and prospect development cost write offs) by interest expense, on a rolling four quarter basis. Both EBITDA and interest expense are annualized for new EcoPower® Centre additions.

- Maintenance covenant - the Company must not have outstanding secured indebtedness exceeding 20% of its asset base, defined as net assets plus accumulated amortization.

The following table presents the contractual maturities of the Company's financial liabilities, including interest payments, to maturity:



Carrying Contractual 2009 2010 2011 2012 -
Amount Cash Flows onwards
$ $ $ $ $ $
------------------------------------------------------
Credit facilities 876,165 1,056,148 15,300 228,796 320,499 491,553
Accounts payable and
accrued liabilities 33,055 33,055 33,055 - - -
Taxes payable 1,129 1,129 1,129 - - -
------------------------------------------------------
Total 910,349 1,090,332 49,484 228,796 320,499 491,553
------------------------------------------------------
------------------------------------------------------


Historically, the Company has re-financed its debt obligations through the issuance of private placement corporate debentures.

10. EARNINGS PER SHARE

The following table shows the effect of dilutive securities on the weighted average common shares outstanding, as at June 30:



3 months ended June 30 6 months ended June 30
2009 2008 2009 2008
-------------------------------------------------
Basic weighted average
shares outstanding 143,661,223 143,413,228 143,659,013 143,304,327
Effect of dilutive
securities:
Options 262,386 1,712,507 - 1,820,312
-------------------------------------------------
Diluted weighted average
shares 143,923,609 145,125,735 143,659,013 145,124,639
-------------------------------------------------
-------------------------------------------------


For the three months ended June 30, 2009, securities totaling nil have been excluded from the calculation as they were anti-dilutive. For the six months ended June 30, 2009, securities totaling 480,099 have been excluded from the calculation as they were anti-dilutive.

11. SEGMENTED INFORMATION

Effective January 1, 2008, the Company has identified the following operating segments: Wind, Hydro, and Biomass. These have been identified based upon the nature of operations and technology used in the generation of electricity. The Company analyzes the performance of its operating segments based on their gross margin, which is defined as revenue, less operating expenses.



For the 3 months ended June 30, 2009
-----------------------------------------
Wind Hydro Biomass Total
$ $ $ $
-----------------------------------------
Revenue 16,401 7,272 2,484 26,157
Operating expenses 3,381 1,109 2,056 6,546
-----------------------------------------
Gross margin 13,020 6,163 428 19,611
-----------------------------------------
-----------------------------------------

Additions to operating plants 482,727 730 443 483,900
Net book value of operating plants 1,135,440 126,973 67,243 1,329,656


For the 3 months ended June 30, 2008
-----------------------------------------
Wind Hydro Biomass Total
$ $ $ $
-----------------------------------------
Revenue 9,677 8,057 1,927 19,661
Operating expenses 2,288 2,397 2,798 7,483
-----------------------------------------
Gross margin 7,389 5,660 (871) 12,178
-----------------------------------------
-----------------------------------------

Additions to operating plants 70 17 67 154
Net book value of operating plants 380,983 128,200 66,754 575,937


For the 6 months ended June 30, 2009
-----------------------------------------
Wind Hydro Biomass Total
$ $ $ $
-----------------------------------------
Revenue 35,183 9,510 4,926 49,619
Operating expenses 6,605 2,731 4,214 13,550
-----------------------------------------
Gross margin 28,578 6,779 712 36,069
-----------------------------------------
-----------------------------------------

Additions to operating plants 486,041 868 712 487,621
Net book value of operating plants 1,135,440 126,973 67,243 1,329,656


For the 6 months ended June 30, 2008
-----------------------------------------
Wind Hydro Biomass Total
$ $ $ $
-----------------------------------------
Revenue 23,432 11,474 4,216 39,122
Operating expenses 4,769 3,141 4,723 12,633
-----------------------------------------
Gross margin 18,663 8,333 (507) 26,489
-----------------------------------------
-----------------------------------------

Additions to operating plants 164 (3) 240 401
Net book value of operating plants 380,983 128,200 66,754 575,937


The following table reconciles the additions and net book values of property, plant, and equipment shown above to the Company's financial statements as at and for the 3 months ended June 30, 2009 and 2008:



For the 3 months ended June 30, 2009
---------------------------------------------------
CIP and
general
Wind Hydro Biomass corporate Total
$ $ $ assets $ $
---------------------------------------------------
Additions to operating
plants 4,727 730 443 8,082 13,982
Net book value 1,135,440 126,973 67,243 17,409 1,347,065
---------------------------------------------------


For the 3 months ended June 30, 2008
---------------------------------------------------
CIP and
general
Wind Hydro Biomass corporate Total
$ $ $ assets $ $
---------------------------------------------------
Additions to operating plants 272 160 264 3,324 4,020
Net book value 384,376 129,099 67,245 215,659 796,379
---------------------------------------------------


12. COMMITMENTS AND CONTINGENCIES

In the ordinary course of constructing new projects, the Company routinely enters into contracts for goods and services. As at June 30, 2009, the Company has committed approximately $36,455,000 for goods and services for Dunvegan, Royal Road, and the British Columbia Hydroelectric projects, which will be expended between 2009 and 2010.

On April 1, 2004, the Company entered into a new 25 year lease agreement (the "Lease") with Ontario Power Generation ("OPG") for the 6.6 MW Ragged Chute Hydroelectric Plant (the "Plant") commencing September 30, 2004. Under the Lease, the Company has agreed to repair the weir at the Plant to the highest minimum standard required by law by November 30, 2008. However, due to force majeure events, the Company did not complete the work and is currently working with the OPG to amend the Lease to extend this date into 2009. The repairs are estimated to cost $4,000,000, of which $3,094,000 has been spent as at June 30, 2009. Upon expiry of the Lease and payment of $6,600,000 by OPG to the Company, the Company will provide OPG with vacant possession of the plant. As the property upon which the Lease is located is owned by the Crown, the Ontario Ministry of Natural Resources has granted consent to the Lease.

13. TRANSACTIONS WITH RELATED PARTIES

The Company pays gross overriding royalties ranging from 1% - 2% on electric energy sales on four of its original hydroelectric plants to a company controlled by a Founder & Director. During the three and six months ended June 30, 2009, royalties totaling $20,000 (2008 - $19,000) and $29,000 (2008 - $28,000), respectively, were incurred.

14. SUBSEQUENT EVENTS

On July 22, 2009, the Company received an unsolicited take-over bid from TransAlta Corporation (the TransAlta offer), requesting that shareholders tender their common shares for cash consideration of $4.55 per share. The TransAlta offer is open until August 27, 2009. After a thorough review and evaluation of the TransAlta offer and after consultation with its financial and legal advisors, the Board of Directors determined that the TransAlta offer was financially inadequate and was not in the best interests of the Company's shareholders. The Board of Directors therefore recommended on July 23, 2009 that the Company's shareholders reject the offer and not tender their shares. The Company formally responded by issuing a Directors' Circular dated August 6, 2009, recommending that shareholders reject the TransAlta offer.

On July 29, 2009, the Company requested an offer of extension of the Operating Facility term out date for a further period of 364 days from August 29, 2009 to August 28, 2010. The Operating Facility is subject to one year extensions upon the mutual agreement of the Company and the lending syndicate.

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

Contact Information

  • Canadian Hydro Developers, Inc.
    Investor Relations
    Kathy Boutin, Chief Financial Officer
    (403) 298-0256
    Email: kboutin@canhydro.com
    or
    Canadian Hydro Developers, Inc.
    Media Relations
    Lindsey Moen, Communications Coordinator
    (403) 802-2099
    Email: lmoen@canhydro.com
    Website: www.canhydro.com