Canadian Hydro Developers, Inc. (TSX:KHD) -
HIGHLIGHTS
- Increased generation, revenue, and EBITDA due to the addition of the 132 MW
Melancthon II EcoPower(R) Centre (Melancthon II) and higher average electricity
prices received;
- Erected all 86 turbines and began the commissioning process at our 197.8 MW
Wolfe Island Wind Project, which is expected to be commercially operational by
June 30, 2009, on-time and on-budget;
- Achieved positive operating income at our Grande Prairie EcoPower(R) Centre
(GPEC), an improvement of 324% in Q1 2009 over the 2008 year; and
- Progressed well on the planned capital programs to improve operations at GPEC
and Centre EcoPower(R) Le Nordais (Le Nordais).
----------------------------------------------------------------------------
Q1 Change
2009 2008 %
----------------------------------------------------------------------------
Financial Results (in thousands
of dollars except where noted)
Revenue 23,462 19,461 + 21
EBITDA 13,016 12,699 + 2
Cash flow 5,390 8,342 - 35
Per share (diluted) 0.04 0.06 - 33
Net earnings (loss) (2,218) 1,809 - 223
Per share (diluted) (0.02) 0.01 - 300
Operating Results
Installed capacity - MW (net) 496 364 + 36
Electricity generation - MWh (net) 287,450 256,467 + 12
kWh per share (diluted) 2.00 1.78 + 12
Average price received per MWh ($) 82 76 + 8
Electrical generation under contract (%) 79 73 + 8
----------------------------------------------------------------------------
For the quarter ended March 31, 2009, revenue and EBITDA improved over the same
period in the prior year due to:
- The addition of Melancthon II in November 2008; and
- Improved generation at GPEC.
These factors were offset partially by:
- Lower gross margins (70% versus 74%) mainly due to unseasonably low wind
conditions in Ontario and increased Hydro One line outages, which impacted
generation at the Melancthon EcoPower(R) Centre. No additional line outages are
planned in 2009. Generation in April 2009 was 29% above the long-term average.
"The first quarter of 2009 was an exciting one for Canadian Hydro as we began to
reap the benefit of the completion of Melancthon II in 2008 and continued to
successfully execute on our strategic plan," said John Keating, CEO of Canadian
Hydro. "Along with the completion of Melancthon II in late 2008, the imminent
completion of Wolfe Island will more than double the size of Canadian Hydro.
Combined with the anticipated benefits from the programs aimed at increasing
efficiency currently underway at GPEC and Le Nordais, we are continuing to
benefit from our unique and proven strategy of design, build, and operate. This
has allowed us to continue to grow our Company at a significant rate despite the
global economic turmoil of the past year."
Canadian Hydro is focused on Building a Sustainable Future(R). We are a
developer, owner and operator of 20 EcoPower(R) Centres totalling net 496 MW of
capacity in operation and have an additional 383 MW in or nearing construction
and 1,525 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: 143,661,223
MANAGEMENT'S DISCUSSION AND ANALYSIS (MD&A)
Advisories
The following MD&A, dated May 7, 2009, should be read in conjunction with the
audited consolidated financial statements as at and for the years ended December
31, 2008 and 2007 (the Financials). All tabular amounts in the following MD&A
are in thousands of dollars, unless otherwise noted, except share and per share
amounts. Additional information respecting our Company, including our Annual
Information Form, is available on SEDAR at 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 quarter of 2009. We:
- Approached completion of our Wolfe Island Wind Project (Wolfe Island), which
is anticipated to achieve commercial operations by June 30, 2009, on time and on
budget and will increase our net installed capacity by 40% to 694 MW;
- 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; and
- In Alberta, continued to work on permitting the 100 MW Dunvegan Hydroelectric
Prospect (Dunvegan).
Revenue and EBITDA, including per share amounts, improved in the first quarter
of 2009 over the same period in the prior year due to:
- The addition of phase II of the Melancthon EcoPower(R) Centre (Melancthon)
completed in November 2008; and
- Improved generation and operating results at GPEC as a result of the work
program initiated in late 2008.
Cash flow and net earnings, including per share amounts, were lower in the first
quarter of 2009 over the same period in the prior year due to:
- Lower gross margins (70% vs. 74%) as a result of:
- Unseasonably low winds in Ontario and increased Hydro One line outages
resulting in lower than normal generation at Melancthon. Generation in April
2009 was 29% above the long-term average;
- Lower water levels and increased maintenance at our BC hydroelectric
EcoPower(R) Centres;
- Continued planned work to improve performance at Le Nordais and GPEC; and
- Increased interest expense as a result of the Melancthon II construction
facility being charged to earnings rather than project costs, as a result of the
project being completed in November 2008.
RESULTS OF OPERATIONS
Revenue and Generation
Quarterly Electricity Generation - by Province and Technology(1)
----------------------------------------------------------------------------
Q1
2009 2008
MWh MWh Change
----------------------------------------------------------------------------
British Columbia 5,312 31,328 - 83
Alberta 112,941 118,777 - 5
Ontario 148,166 79,424 + 87
Quebec 21,031 26,938 - 22
----------------------------------------------------------------------------
Totals 287,450 256,467 + 12
----------------------------------------------------------------------------
Hydroelectric 32,845 54,446 - 40
Wind 223,011 172,892 + 29
Biomass 31,594 29,129 + 8
----------------------------------------------------------------------------
Totals 287,450 256,467 + 12
----------------------------------------------------------------------------
kWh per share(2) 2.00 1.78 + 12
----------------------------------------------------------------------------
(1) Reflecting our net interest.
(2) kWh per share based on diluted weighted average shares outstanding.
Revenue in Q1 2009 increased 21% over the prior year as a result of the
following factors:
- The addition of Melancthon II in November 2008;
- Improved hydroelectric generation in Ontario due to higher water flows than Q1
2008; and
- Improved generation at GPEC as a result of the work program currently underway;
Offset partially by:
- Lower generation at our BC 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;
- Lower generation at Melancthon as a result of unseasonably low wind conditions
and an increased number of Hydro One line outages. No additional line outages
are planned by Hydro One in 2009;
- Lower generation at our Alberta wind EcoPower(R) Centres due to lower wind
levels than Q1 2008; and
- Lower generation at Le Nordais due to the work program currently underway,
which is expected to be completed by year end.
Generation decreased from Q4 2008 as a result of lower wind generation in
Ontario and lower hydroelectric generation in British Columbia. At Akolkolex, we
completed significant required planned maintenance and capital upgrades
including the installation of new runners, which were required as part of the
normal life cycle of the facility. As a result of these repairs, Akolkolex had
minimal generation for the quarter. Akolkolex is back on-line as of May 7, 2009,
in advance of spring freshet, the highest generating period in the year.
We have received an average price of $82/MWh for Q1 2009, compared to $76/MWh
for 2008. This was the result of the addition of Melancthon II, which has a
higher contract price than the average of our other EcoPower(R) Centres. This
was offset by lower pool prices received by our merchant Alberta plants in Q1
2009 (Q1 2009 - $52/MWh, Q1 2008 - $77/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. This decline in pool price was
mitigated by the fact that approximately 79% of our generation was sold pursuant
to long-term sales contracts in Q1 2009 (Q1 2008 - 73%).
Operating Expenses
Operating expenses increased 35% in Q1 2009 compared to Q1 2008, mainly due
to the following factors:
- The addition of Melancthon II;
- Work at Le Nordais and GPEC in order to optimize performance and improve the
availability of the EcoPower(R) Centres; and
- Increased planned maintenance expenditures at our BC hydroelectric EcoPower(R)
Centres.
On a $/MWh basis, operating expenses increased in Q1 2009 primarily as a result
of the above factors.
Gross Margins
Gross margins, as a percentage of revenue, decreased for Q1 2009 to 70% from 74%
in Q1 2008 due primarily to the increase in operating expenses described above.
This decrease was also impacted by the lower than normal generation at
Melancthon during the quarter, as many of our operating costs are fixed and do
not have a directly proportional relationship with generation.
Interest on Credit Facilities and Credit Facilities
----------------------------------------------------------------------------
(in thousands of dollars Q1 Change
except where noted) 2009 2008 %
----------------------------------------------------------------------------
Gross interest on credit facilities 9,230 5,679 + 63
Capitalized interest (2,172) (1,255) + 73
----------------------------------------------------------------------------
Net interest expense on credit
facilities 7,058 4,424 + 60
----------------------------------------------------------------------------
Net interest expense on credit
facilities per MWh ($/MWh) 24.55 17.25 + 42
----------------------------------------------------------------------------
Interest income 75 205 - 63
----------------------------------------------------------------------------
The increase in net interest expense on credit facilities in 2009 was due to
higher outstanding corporate debt, which increased a result of the achievement
of commercial operations (COD) of Melancthon II. Prior to COD, interest was
capitalized to the project.
On a $/MWh basis, net interest expense increased in 2009 as a result of the
increase in corporate debt and lower than expected generation.
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 increased due to higher outstanding balances on our credit
facilities associated with the projects in or nearing construction.
Credit facilities (including current portion) drawn as at March 31, 2009 were
$841,408,000 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 52% in Q1 2009 from Q1 2008 due to the addition
of Melancthon II. On a $/MWh basis, amortization expense increased for the 3
month period as a result of lower than expected generation at Melancthon.
Our wind EcoPower(R) Centres are amortized on a straight-line basis over a 30
year period, except Le Nordais and Taylor, which are amortized over 26 years and
15 years, respectively, and our biomass and hydroelectric EcoPower(R) Centres
are amortized on a straight-line basis over a 40 year period.
Administration Expense
----------------------------------------------------------------------------
(in thousands of dollars Q1 Change
except where noted) 2009 2008 (%)
----------------------------------------------------------------------------
Gross administration expenses 4,243 2,224 + 91
Capitalized administration expenses (1,236) (411) + 201
----------------------------------------------------------------------------
Net administration expenses 3,007 1,813 + 66
----------------------------------------------------------------------------
Net administration expense per MWh
($/MWh) 10.48 7.02 + 49
----------------------------------------------------------------------------
Gross administration expense increased 91% in Q1 2009 from Q1 2008. Over the
past year, we have become a much larger company and are on the verge of doubling
our installed capacity. As a result, administration expenses and staff numbers
have increased as well.
On a $/MWh basis, net administration expense increased for the 3 month period
due to the reasons explained above. Additionally, capitalized administration
costs associated with construction-in-progress and prospect development costs
increased in association with our increased construction and development
activity.
Stock Compensation Expense
Stock compensation expense decreased 7% in Q1 2009 from Q1 2008 due to a lower
fair value per option as a result of a lower share price, which impacts the
calculation of the fair value per option.
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 will be
eliminated effective July 1, 2010, while Quebec Capital Tax will be eliminated
effective January 1, 2011.
Future income taxes decreased 221% due to lower earnings before taxes. Our
effective tax rate remains unchanged at 21% in 2009.
EBITDA, Cash Flow, and Net Earnings
EBITDA
In Q1 2009, EBITDA increased 2% compared to Q1 2008 due to:
- Increased generation as a result of the Melancthon II addition; and
- Higher prices received.
This was offset partially by:
- lower than expected generation from Melancthon and our BC hydroelectric
EcoPower(R) Centres; and
- higher administrative expenses, as discussed above.
On a $/MWh basis, EBITDA decreased as a result of the factors discussed above
with respect to operating expenses.
Cash Flow
Cash flow in Q1 2009 decreased 35% from Q1 2008 as a result of:
- Lower gross margins due to lower than expected generation from Melancthon and
our BC hydroelectric EcoPower(R) Centres and higher administrative expenses;
- Higher interest expenses as a result of interest from the Melancthon
construction facility no longer being charged to the project costs; and
- Higher administrative and capital taxes as compared to the prior year.
On a per share basis, cash flow decreased 33% in Q1 2009 from Q1 2008 due to the
above. 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, our B.C. Hydroelectric Projects and Wolfe Island.
The benefits of these equity issues will not be fully reflected in our cash flow
until a full year of operations at these projects.
Net Earnings
Net earnings, on an absolute basis, decreased 223% in Q1 2009 compared to Q1
2008, mainly as a result of:
- Lower gross margins mainly due to lower than expected generation from
Melancthon and our BC hydroelectric EcoPower(R) Centres and higher
administrative expenses, as discussed above;
- Higher interest expenses as a result of interest from the Melancthon
construction facility no longer being charged to the project costs; and
- Higher amortization expense as a result of the addition of Melancthon II.
These expenses were offset partially by a future income tax recovery due to
lower taxable income. Accordingly, on a $/MWh basis, net earnings decreased over
the prior year.
The proceeds from our equity issuances in 2005 are being used to finance the
construction of Melancthon II, Wolfe Island, and the B.C. Hydroelectric
Projects. The benefits of these equity issues will not be fully reflected in our
net earnings until a full year of operations at these projects
Property, Plant, and Equipment Additions and Prospect Development Costs
----------------------------------------------------------------------------
(in thousands of dollars) Q1 2009 Q1 2008 Change
----------------------------------------------------------------------------
Property, plant, and equipment additions 47,417 4,441 + 968%
Prospect development cost additions 4,004 12,150 - 67%
----------------------------------------------------------------------------
Property, plant, and equipment additions relate mainly to capital expenditures
for the $475,000,000 Wolfe Island Wind Project.
Additions of prospect development costs relate primarily to expenditures for
Dunvegan.
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.
In early 2007, we embarked upon a significant expansion plan to more than double
our generating capacity by the end of 2010. The table below summarizes the
investments contemplated by this plan and our current expectations as to the
funding thereof. 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 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 and Credit Facilities').
----------------------------------------------------------------------------
(in thousands of dollars) As at March 31 2009
----------------------------------------------------------------------------
Capital expenditure plans through 2012 1,014,120
Spent to date (503,285)
----------------------------------------------------------------------------
Remaining capital expenditures to be financed 510,835
Financed/to be financed by:
Blue River construction facilities 48,900
Wolfe Island construction facility 32,000
Working capital(1) (24,887)
Anticipated construction facilities(2) 281,900
Undrawn & available revolving Operating Facility 54,914
Expected to be funded through cash flow from operations 118,008
----------------------------------------------------------------------------
Difference -
----------------------------------------------------------------------------
(1) Excluding derivative financial instrument 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:
- Wolfe Island;
- Yellow Falls;
- Royal Road;
- Blue River (including Bone, Clemina, and Serpentine Creeks);
- English Creek;
- St. Valentin; and
- New Richmond.
The following table outlines the size and timing of the anticipated credit
facilities:
----------------------------------------------------------------------------
Anticipated Anticipated timing
construction of construction
(in thousands of dollars) facility size facility
----------------------------------------------------------------------------
Project
Yellow Falls 28,400 Q3 2009
Royal Road 26,000 Q1 2010
New Richmond 123,500 Q4 2011
St. Valentin 104,000 Q4 2011
----------------------------------------------------------------------------
Total 281,900
----------------------------------------------------------------------------
Exclusive of any new projects that we may be awarded under the calls for power
discussed below, we will require no additional equity financing for our current
projects, and will require only $28 million of debt financing in 2009, relating
to the Yellow Falls Hydroelectric Project. With the upcoming completion of Wolfe
Island, 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.
We have no requirements to significantly access the debt markets until September
2010 when the Melancthon II Construction Facility matures. While we anticipate
that funds in the debt market will be available at economic interest rates, it
is currently not possible to guarantee that these funds will be available when
required.
As at March 31, 2009, we had a 64/36 debt/capital mixture (December 31, 2008 -
63/37) compared to a stated target of 65/35. We will move towards our stated
target as we draw on existing credit facilities and put in place and draw on
future construction facilities for the projects discussed above. We 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 Wind Project
At Wolfe Island, construction has reached its final stages with all 86 turbines
erected, the substation constructed and operational, and the commissioning of
turbines well underway. 10 of the 86 turbines are currently providing power to
the grid. The anticipated capital costs and in-service date remain unchanged at
$475 million and June 30, 2009, respectively. The completion of Wolfe Island
represents a major milestone and will increase our installed capacity by 40% to
694 MW. With the completion of Melancthon II and Wolfe Island, we will have
successfully doubled the size of our Company within 8 months, which is a
testament to our ability to 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 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
At March 31, 2009, we were engaged in the development of the following
hydroelectric projects:
- 18.0 MW, $49,000,000 Bone Creek;
- 11.0 MW, $27,000,000 Clemina Creek;
- 9.6 MW, $28,000,000 Serpentine Creek; and
- 5.0 MW, $10,000,000 English Creek.
The targeted completion date for all four B.C. projects is the fourth quarter of
2010. Bone has a 20-year and Clemina, Serpentine and English have 40-year
Electricity Purchase Agreements (EPAs) with BC Hydro, for the purchase of
electricity and RECs. In addition, we will receive funding under ecoENERGY for
Renewable Power program (eRI) for Bone, Clemina and Serpentine, and expect to be
eligible for English Creek. Construction activities were completed for the
winter season for Bone and Clemina in October 2008. Since securing EPAs in 2006,
construction costs have increased significantly. Recently, we have begun to see
a decrease in construction costs due to the current worldwide economic
conditions. We are currently in the process of obtaining construction cost
estimates and we will provide an update on these projects in Q2 2009. We
currently estimate a one-year delay to the target commercial operations date for
these projects from October 1, 2009 to October 1, 2010. There is no assurance
that construction costs will decrease to economic levels, and this may impact
the viability of these projects.
Alberta
Dunvegan Hydroelectric Project
On April 29, 2009, we achieved another significant milestone at Dunvegan when
the Dunvegan Hydro Development Act came into force under Alberta legislature.
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. The AUC can now approve applications
previously filed. 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. With the upcoming completion of Wolfe Island, we
expect to have the ability to finance the equity portion of approximately one
100 MW project each year from free cash flow. As a result, due to current market
conditions, we may choose to proceed slowly with Dunvegan, using our free cash
flow as opposed to issuing equity at a higher cost of capital than we have
historically achieved. 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. Turbine supply, including cost and delivery
have been fixed, which represents over 70% of the capital costs. 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
B.C.
We submitted a proposal for a 50 MW hydroelectric prospect into BC Hydro's Clean
Power Call, in November 2008. Contracts under this Clean Power Call are
anticipated to be awarded in June of 2009.
Ontario Green Energy Act
On February 23, 2009, Ontario Bill 150 "Green Energy and Green Economy Act" was
tabled at the Legislative Assembly of Ontario. 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.
New Business
The solar energy market is one which we continue to monitor and assess on a
regular basis. As previously disclosed, we have entered into a Standard Offer
Contract (SOC) for one 10 MW solar project in Ontario and will work on a second
10 MW contract under the proposed Ontario Green Energy Act's Feed in Tariff
Program. In recent months, we have seen a decrease in the cost of solar panels
world wide, which is improving the economics of this technology. In addition, we
are working on the development of a tracking system to improve the anticipated
output of the solar panels. We feel this is an area where our expertise and
proven track record in project identification, construction, and operation will
allow us to be a market leader in this market segment, provided that the
underlying economics of the projects justify our entrance into the market.
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) Q2 2008 Q3 2008 Q4 2008 Q1 2009
----------------------------------------------------------------------------
Total revenue 19,661 17,398 23,578 23,462
EBITDA 11,279 11,336 14,457 13,016
Cash flow 5,614 5,454 7,487 5,390
Net earnings (loss) 2,883 (4,986) 1,225 (2,218)
Earnings (loss) per share - basic 0.02 (0.03) 0.01 (0.02)
Earnings (loss) per share - diluted 0.02 (0.03) 0.01 (0.02)
Generation (MWh) 261,377 246,133 302,104 287,450
kWh per share (diluted) 1.80 1.69 2.07 2.00
Average price received ($/MWh) 75 71 78 82
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(in thousands of dollars,
except per share amounts) Q2 2007 Q3 2007 Q4 2007 Q1 2008
----------------------------------------------------------------------------
Total revenue 17,277 14,344 17,398 19,461
EBITDA 12,216 7,765 10,597 12,699
Cash flow 7,762 4,161 6,687 8,342
Net earnings (loss) 1,771 162 5,505 1,809
Earnings (loss) per share - basic 0.01 - 0.04 0.01
Earnings (loss) per share - diluted 0.01 - 0.04 0.01
Generation (MWh) 271,429 212,031 237,917 256,467
kWh per share (diluted) 2.01 1.56 1.76 1.78
Average price received ($/MWh) 64 68 73 76
----------------------------------------------------------------------------
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, 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, 2008, the Company adopted Canadian Institute of Chartered
Accountants ("CICA") handbook section 3064 - "Goodwill and Intangible Assets".
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
Effective January 1, 2011, International Financial Reporting Standards (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. IFRSs
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.
Currently, we are working to assess the accounting policy choices available
under IFRS (including application on a prospective or retroactive basis for
certain policies), the impact of the conversion to IFRS on the internal controls
and financial reporting procedures, and have commenced training for financial
reporting and accounting staff.
OFF-BALANCE SHEET ARRANGEMENTS
At March 31, 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, President, Operations & Development, and a director. During the three
months ended March 31, 2009, royalties totaling $9,000 (2007 - $12,000) 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 March 31, 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, which 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
January 1, 2007, the fair value of these contracts of $206,000 was recorded on
the consolidated balance sheet as a derivative financial liability, with the
loss recorded as Other Comprehensive Income (OCI). At March 31, 2009, the fair
value of the CFDs was an asset of $195,000.
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 March 31, 2009, the
aggregate fair value of all outstanding foreign exchange contracts was an asset
of $5,913,000.
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 March 31, 2009, the fair value of all outstanding interest rate swap
contracts was a liability of $11,933,000.
OUTSTANDING SHARE DATA
----------------------------------------------------------------------------
As at May 7, 2009
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 143,661,223
Convertible securities:
Options 9,387,200
----------------------------------------------------------------------------
Fully diluted common shares 153,048,423
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ADVISORIES
Forward-Looking Statements
Certain statements contained in this MD&A, constitute forward-looking
statements. These statements relate to future events or our future performance.
All statements other than statements of historical fact may be forward-looking
statements. Forward-looking statements are often, but not always, identified by
the use of words such as "seek", "anticipate", "plan", "continue", "estimate",
"expect, "may", "will", "project", "predict", "potential", "targeting",
"intend", "could", "might", "should", "believe" and similar expressions. These
statements involve known and unknown risks, uncertainties and other factors that
may cause actual results or events to differ materially from those anticipated
in such forward-looking statements, including, but not limited to, changes in
construction schedules, weather, water flows, reservoir levels on irrigation
works, wind resources and Pool prices. We believe that the expectations
reflected in those forward-looking statements are reasonable but no assurance
can be given that these expectations will prove to be correct and such
forward-looking statements included in this MD&A should not be unduly relied
upon. 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.
CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED BALANCE SHEETS (Unaudited)
(in thousands of dollars)
March 31, December 31,
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
CURRENT
Cash 8,228 33,839
Accounts receivable (Note 8) 14,650 31,925
Derivative financial instrument asset (Note 8) 6,108 4,954
Prepaid expenses 1,664 962
----------------------------------------------------------------------------
30,650 71,680
Property, plant, and equipment (Note 3) 1,336,776 1,288,446
Prospect development costs (Note 4) 53,567 50,006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TOTAL ASSETS 1,420,993 1,410,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
CURRENT
Accounts payable and accrued liabilities 45,793 39,085
Derivative financial instrument liability (Note 8) 11,933 12,273
Current portion of long-term debt (Note 6) 2,389 2,364
Taxes payable 1,247 1,177
----------------------------------------------------------------------------
61,362 54,899
Long-term debt (Note 6) 839,019 833,432
Future income taxes 38,854 39,564
----------------------------------------------------------------------------
939,235 927,895
----------------------------------------------------------------------------
COMMITMENTS & CONTINGENCIES (Note 12)
SHAREHOLDERS' EQUITY
Share capital and warrants (Note 7) 451,247 455,066
Contributed surplus (Note 7) 10,985 6,399
Retained earnings 30,062 32,280
----------------------------------------------------------------------------
492,294 493,745
Accumulated other comprehensive loss (Note 5) (10,536) (11,508)
----------------------------------------------------------------------------
481,758 482,237
----------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 1,420,993 1,410,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements
CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF (LOSS) EARNINGS AND RETAINED EARNINGS (Unaudited)
(in thousands of dollars except per share amounts)
3 months ended March 31
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
Electric energy sales 23,305 19,275
Revenue rebate 157 186
----------------------------------------------------------------------------
23,462 19,461
----------------------------------------------------------------------------
Expenses (income)
Operating 7,004 5,150
Amortization 7,617 5,029
Interest on credit facilities 7,058 4,424
Administration 3,007 1,813
Foreign exchange loss (gain) 985 (201)
Stock based compensation 672 722
Interest income (75) (205)
Reclassification of amounts from other
comprehensive income (Note 5) (500) -
----------------------------------------------------------------------------
25,768 16,732
----------------------------------------------------------------------------
(Loss) earnings before taxes (2,306) 2,729
----------------------------------------------------------------------------
Tax (recovery) expense
Current and capital 643 138
Future (731) 782
----------------------------------------------------------------------------
(88) 920
----------------------------------------------------------------------------
Net (loss) earnings (2,218) 1,809
Retained earnings, beginning of period 32,280 31,349
----------------------------------------------------------------------------
Retained earnings, end of period 30,062 33,158
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Loss) earnings per share (Note 10)
Basic (0.02) 0.01
Diluted (0.02) 0.01
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Unaudited)
(in thousands of dollars except per share amounts)
3 months ended March 31
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (loss) earnings (2,218) 1,809
Other comprehensive gain (loss):
Unrealized gain on derivative financial
instrument currency hedges, net of tax 937 3,982
Unrealized gain on derivative financial
instrument contracts for differences 1,047 119
Unrealized loss on derivative financial
instrument interest rate hedges (512) -
Reclassified to net earnings (500) -
----------------------------------------------------------------------------
Other comprehensive gain 972 4,101
Comprehensive (loss) income (1,246) 5,910
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements
CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands of dollars)
3 months ended March 31
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net (loss) earnings (2,218) 1,809
Adjustments for:
Amortization 7,617 5,029
Future income tax (recovery) expense (731) 782
Stock based compensation 672 722
Reclassification of amounts from other
comprehensive income (500) -
Unrealized foreign exchange losses 550 -
----------------------------------------------------------------------------
Cash flow from operations before changes
in non-cash working capital 5,390 8,342
Changes in non-cash working capital 15,264 2,610
----------------------------------------------------------------------------
20,654 10,952
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Credit facility repayments (Note 6) (23,489) (439)
Credit facility advances (Note 6) 28,600 -
Issue of common shares, net of issue costs (Note 7) 95 6,084
----------------------------------------------------------------------------
5,206 5,645
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Property, plant, and equipment additions (47,417) (4,441)
Prospect development costs (4,004) (12,150)
----------------------------------------------------------------------------
(51,421) (16,591)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FOREIGN EXCHANGE ON CASH HELD IN FOREIGN CURRENCY (50) -
----------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH (25,611) 6
CASH, BEGINNING OF PERIOD 33,839 22,785
----------------------------------------------------------------------------
CASH, END OF PERIOD 8,228 22,791
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplemental information
Cash interest paid 7,243 4,528
Cash income and capital taxes paid 594 -
See accompanying Notes to the Consolidated Financial Statements
CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 second and fourth quarters to be higher than those for the first
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.
(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.
3. PROPERTY, PLANT, AND EQUIPMENT
The major categories of property, plant, and equipment at cost and related
accumulated amortization are as follows:
March 31, 2009 December 31, 2008
---------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
---------------------------------------------
Generating plants
- operating 935,746 82,232 853,514 856,291
- construction-in-progress 479,969 - 479,969 428,592
Equipment, other 5,241 2,171 3,070 2,918
Vehicles 2,101 1,878 223 645
---------------------------------------------
1,423,057 86,281 1,336,776 1,288,446
---------------------------------------------
---------------------------------------------
The following amounts have been capitalized to property, plant, and
equipment for the 3 months ended March 31, 2009 and 2008:
2009 2008
------------------------
Interest costs 2,172 302
Administrative expenses 547 46
------------------------
Total 2,719 348
------------------------
------------------------
As at March 31, 2009, construction-in-progress (CIP) relates to costs associated
with the construction of the Wolfe Island Wind Project, and the Bone and Clemina
Creek Hydroelectric Projects (2008 - Melancthon II). During the 3 months ended
March 31, 2009, $nil was moved from Prospect Development Costs to CIP (Q1 2008 -
$nil).
4. PROSPECT DEVELOPMENT COSTS
Prospect development costs are comprised of the following:
March 31, December 31,
2009 2008
$ $
------------------------
Dunvegan Hydroelectric Prospect 17,950 16,703
Manitoba Wind Prospects 7,310 7,744
British Columbia Hydroelectric Projects 6,875 6,066
Royal Road Wind Projects 6,345 6,160
New Richmond and St. Valentin Wind Projects 5,721 5,156
Other Hydroelectric and Wind Prospects 4,923 3,918
Yellow Falls Hydroelectric Project 3,483 3,350
Solar Prospects 960 909
------------------------
Total 53,567 50,006
------------------------
------------------------
The following amounts have been capitalized to prospect development costs
for the 3 months ended March 31, 2009 and 2008:
2009 2008
------------------------
------------------------
Interest costs - 953
Administrative expenses 689 365
------------------------
Total 689 1,318
------------------------
------------------------
For the 3 months ended March 31, 2009, the Company wrote off $nil (2008 -
$nil) in costs relating to development prospects that were abandoned during
the period.
5. ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCL)
AOCL is comprised of the following:
$
---------
Balance, December 31, 2008 (11,508)
Unrealized gain on derivative financial instrument cross-currency
swap, net of tax 937
Unrealized loss on derivative financial instrument interest rate
hedges (512)
Unrealized gain on derivative financial instrument contracts for
differences (CFDs) 1,047
Amounts reclassified to net earnings (500)
---------
Accumulated other comprehensive loss, March 31, 2009 (10,536)
---------
---------
During the 3 months ended March 31, 2009, $500,000 was 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 March 31, 2009, in addition to the $7,000,000 shown
below as drawn, the Company had outstanding letters of credit in the amount of
$23,086,000 (December 31, 2008 - $30,292,000) relating primarily to construction
activities and security required under long-term sales contracts for
electricity.
March 31, 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). 24,992 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 Construction 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 Construction 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 ending the earlier of 3 months
post commercial operations and September
12, 2009, followed by a two-year non-amortizing
term out period (Note 8). 260,500 231,900
Blue River Construction 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. 7,000 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. 5,367 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. 1,406 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. 1,132 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 725 769
------------------------
844,222 838,691
Less: Deferred financing costs (2,814) (2,895)
------------------------
841,408 835,796
Less: Current portion of credit facilities (2,389) (2,364)
------------------------
Credit facilities 839,019 833,432
------------------------
------------------------
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, March 31, 2009 143,661,223 451,247
----------------------------
----------------------------
(b) Stock compensation:
The following table presents the Company's stock option issuances and
expense for the 3 months ended March 31, 2009 and 2008:
2009 2008
----------------------------
Number of options issued 25,000 55,000
Stock based compensation recognized $ 672 $ 722
Average fair value per option $ 1.08 $ 1.58
----------------------------
----------------------------
The fair value of options issued for the 3 months ended March 31, 2009 and
2008 were estimated using the Black-Scholes option-pricing model with the
following assumptions:
2009 2008
----------------------------
Risk free interest rate (%) 1.52 3.51
Volatility (%) 37.93 28.26
Expected weighted average life (years) 4.0 4.0
Annual dividend yield (%) 0.0 0.0
Vesting period (years) 4.0 4.0
----------------------------
----------------------------
(c) Contributed surplus:
March 31 March 31
2009 2008
$ $
-------------------------
Balance, beginning of the period 6,399 4,299
Stock based compensation 672 722
Reclassification of expired warrants 3,967 -
Stock compensation on options exercised (53) (181)
-------------------------
Balance, end of period 10,985 4,840
-------------------------
-------------------------
During the quarter, 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.
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 are added to the cost of the instrument at its initial
carrying amount.
The Company has made the following classifications:
- Cash and cash equivalents are classified as financial assets 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 March 31, 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 March 31, 2009, the aging of the
Company's receivables is as follows:
March 31
2009
$
----------
Current receivables 14,602
Receivables between 60 - 120 days 48
Receivables greater than 120 days -
----------
14,650
Less: Impairment allowance -
----------
Receivables, end of period 14,650
----------
----------
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 March 31, 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 construction
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 March 31, 2009, a 1%
change in the forward electricity prices would result in a $27,000 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 $1,000 to AOCL. This risk management strategy is
unchanged from the prior year.
Derivative Instruments and Hedging Activities
March 31 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. 5,913 4,954
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. 195 (852)
----------------------
6,108 4,102
----------------------
----------------------
Derivative Financial Instrument Liabilities
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. 11,933 11,421
----------------------
11,933 11,421
----------------------
----------------------
As at March 31, 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:
March 31 December 31
2009 2008
$ $
---------------------------
Total debt, including current portion of credit
facilities 841,408 835,796
Shareholders' equity 481,758 482,237
---------------------------
Total capital 1,323,166 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 March 31, 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 841,408 1,024,590 20,544 223,024 287,727 493,295
Accounts payable and
accrued
liabilities 45,793 45,793 45,793 - - -
Taxes payable 1,247 1,247 1,247 - - -
-----------------------------------------------------
Total 888,448 1,071,630 67,584 223,024 287,727 493,295
-----------------------------------------------------
-----------------------------------------------------
Historically, the Company has re-financed its debt obligations through the
issuance of corporate debentures.
10. EARNINGS PER SHARE
The following table shows the effect of dilutive securities on the weighted
average common shares outstanding, as at March 31:
2009 2008
----------------------------
Basic weighted average shares outstanding 143,656,779 142,001,305
Effect of dilutive securities:
Options - 2,048,281
----------------------------
Diluted weighted average shares 143,656,779 144,049,586
----------------------------
----------------------------
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 March 31, 2009
---------------------------------------
Wind Hydro Biomass Total
$ $ $ $
---------------------------------------
Revenue 18,782 2,238 2,442 23,462
Operating expenses 3,223 1,623 2,158 7,004
---------------------------------------
Gross margin 15,559 615 284 16,458
---------------------------------------
---------------------------------------
Additions to operating plants 3,402 151 1,031 4,584
Net book value of operating plants 656,856 129,481 67,177 853,514
For the 3 months ended March 31, 2008
---------------------------------------
Wind Hydro Biomass Total
$ $ $ $
---------------------------------------
Revenue 13,755 3,417 2,289 19,461
Operating expenses 2,481 744 1,925 5,150
---------------------------------------
Gross margin 11,274 2,673 364 14,311
---------------------------------------
---------------------------------------
Additions to operating plants 272 160 264 696
Net book value of operating plants 384,376 129,099 67,245 580,720
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 March 31, 2009 and 2008:
For the 3 months ended March 31, 2009
---------------------------------------------------
Wind Hydro Biomass CIP and general Total
$ $ $ corporate assets $ $
---------------------------------------------------
Additions to operating
plants 3,402 151 1,031 42,833 47,417
Net book value 656,856 129,481 67,177 483,262 1,336,776
---------------------------------------------------
For the 3 months ended March 31, 2008
---------------------------------------------------
Wind Hydro Biomass CIP and general Total
$ $ $ corporate 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 March 31, 2009, the Company
has committed approximately $52,405,000 for goods and services for Wolfe Island,
Dunvegan, Royal Road, and the B.C. 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 will 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 $2,988,000 has been spent as at March 31,
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 the President who is also a director. During the three months
ended March 31, 2009, royalties totaling $9,000 (2008 - $12,000) were incurred.
Open Gold Corp. (TSXV:OPG)
과거 데이터 주식 차트
부터 5월(5) 2024 으로 6월(6) 2024
Open Gold Corp. (TSXV:OPG)
과거 데이터 주식 차트
부터 6월(6) 2023 으로 6월(6) 2024
