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(R) 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(R) 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(R) 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.
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Q2 6 Months
Change Change
2009 2008 % 2009 2008 %
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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(R),
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(R). We are a
developer, owner and operator of 21 EcoPower(R) 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(R) 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(R) Centre (GPEC) and Centre EcoPower(R) 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(R) 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
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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%
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Totals 354,617 261,377 + 36% 642,067 517,844 + 24%
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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%
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Totals 354,617 261,377 + 36% 642,067 517,844 + 24%
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kWh per share(2) 2.47 1.80 + 37% 4.47 3.57 + 25%
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(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(R) 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(R) 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(R) 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(R) Centre (Akolkolex) of 21,011 MWh, which benefited
generation in Q1 2008; and
- Lower generation at our Alberta and Ontario wind EcoPower(R) 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(R) 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(R) Centres, offset partially by the factors discussed above. On
a $/MWh basis, operating expenses decreased 14% for the six months ended June
30, 2009, compared to 2008, primarily as a result of increased generation due to
the addition of Melancthon II and Wolfe Island.
Gross Margins
Gross margins, as a percentage of revenue, increased to 75% in Q2 2009 compared
to 62% in Q2 2008 due primarily to increased generation and decreased operating
expenses, as explained above.
For the six months ended June 30, 2009, gross margins were 73% compared to 68%
in 2008 due to the increase in generation discussed above.
Interest on Credit Facilities
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Q2 6 months
(in thousands of dollars
except where noted) 2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Gross interest on credit
facilities 8,728 8,864 - 2% 17,958 14,543 + 23%
Capitalized interest (1,382) (4,122) - 66% (3,554) (5,377) - 34%
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Net interest expense on
credit facilities 7,346 4,742 + 55% 14,404 9,166 + 57%
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Net interest expense on
credit facilities per MWh
($/MWh) 20.72 18.15 + 14% 22.43 17.70 + 27%
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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 $/MWh basis, amortization expense increased due to
these additions, which have a higher capital cost than our existing plants.
Our wind EcoPower(R) Centres are amortized on a straight-line basis over a 30
year period, except Le Nordais and Taylor, which are amortized over 26 years and
15 years, respectively, and our biomass and hydroelectric EcoPower(R) Centres
are amortized on a straight-line basis over a 40 year period.
Administration Expense
----------------------------------------------------------------------------
Q2 6 months
(in thousands of dollars
except where noted) 2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Gross administration
expenses 3,915 3,152 + 24% 8,157 5,376 + 52%
Capitalized
administration expenses (1,338) (1,917) - 30% (2,573) (2,328) + 11%
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Net administration
expenses 2,577 1,235 + 109% 5,584 3,048 + 83%
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Net administration
expenses per MWh ($/MWh) 7.27 4.67 + 56% 8.70 5.88 + 48%
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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(R) 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%
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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').
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As at June 30
(in thousands of dollars) 2009
----------------------------------------------------------------------------
Capital expenditure plans through 2012 474,100
Spent to date (28,739)
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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
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Difference -
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(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
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Total 281,900
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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(R) 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(R) 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(R) 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(R) 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.
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