Canadian Hydro Developers, Inc. (TSX:KHD)
HIGHLIGHTS
- Increased revenue both quarterly and year-to-date due to new plant additions;
- Progressed well on the construction of the Melancthon II Wind Project, and the
Bone Creek and Clemina Creek Hydroelectric Projects;
- Formally concluded the provincial environmental approval process at Wolfe
Island, allowing pre-servicing work to commence in July and construction to
start shortly thereafter;
- Closed an additional $312.5 million in credit facilities, adding 5 new banks
to our lending syndicate;
- Closed private placement of the Series 4 and Series 5 debentures, for total
gross proceeds of $75.9 million;
- Hired Keith O'Regan as the new Executive Vice-President and Chief Operating
Officer; and
- Awarded two power purchase agreements in Quebec for a combined 116 MW.
----------------------------------------------------------------------------
Q2 6 Months
Change Change
2008 2007 % 2008 2007 %
----------------------------------------------------------------------------
Financial Results (in thousands
of dollars except where noted)
Revenue 19,661 17,277 + 14% 39,122 32,015 + 22%
EBITDA 11,279 12,216 - 8% 23,978 20,753 + 16%
Cash flow from
operations, before changes
in non-cash working
capital 5,614 7,762 - 28% 13,956 12,907 + 8%
Per share (diluted) 0.04 0.06 - 33% 0.10 0.10 -
Net earnings 2,883 1,771 + 63% 4,692 2,676 + 75%
Per share (diluted) 0.02 0.01 +100% 0.03 0.02 + 50%
Operating Results
Installed capacity - MWh (net) 364 264 + 38% 364 264 + 38%
Electricity generation - MWh
(net) 261,377 271,429 - 4% 517,844 471,727 + 10%
kWh per share (diluted) 1.80 2.01 - 10% 3.57 3.62 - 1%
Average price received per
MWh ($) 75 64 + 17% 76 68 + 12%
Electrical generation under
contract (%) 78 80 - 3% 76 80 - 5%
Net earnings improved in Q2 2008 compared to Q2 2007 due to a foreign exchange
gain on a Euro-denominated cash balance ear-marked for turbine payments and
higher power prices. Our combined hydro and wind operations performed as
expected, despite our Melancthon I Wind Plant being down for 28 days in the
quarter. This was in order to expand the substation for the construction of our
Melancthon II Wind Project. A major planned turnaround at our Grande Prairie
EcoPower(R) Centre resulted in quarter over quarter lower revenue and higher
operating costs. This reduced overall EBITDA and cash flow from operations in Q2
2008 compared to Q2 2007.
For the six months ended June 30, 2008, financial results improved over the same
period in the prior year due to the same factors as discussed above, with the
exception of generation. Notwithstanding the downtime discussed above,
generation increased over the prior year as a result of a full period of
generation from the Soderglen and Le Nordais Wind Plants, acquired in March and
December 2007, respectively.
"The second quarter of 2008 included some major milestones for Canadian Hydro
with the breaking of ground at Wolfe Island and Blue River, erecting turbines at
Melancthon II, and closing significant financings," said John Keating, CEO of
Canadian Hydro. "Our balance sheet assets now exceed one billion dollars, which
is a testament to the growth of our Company and the continued execution of our
strategic plan. Our focus in the next several quarters is the successful
execution and completion of our close to $1 billion in major construction
projects, as well as improving operations at our biomass plant."
Canadian Hydro is focused on Building a Sustainable Future(R). We are a
developer, owner and operator of 20 power generation facilities totalling net
364 MW of capacity in operation and have an additional 517 MW in or nearing
construction and 1,632 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 under
Environment Canada's EcoLogo(M) Program.
Common shares outstanding: 143,488,723
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
Advisories
The following MD&A, dated August 5, 2008 (with the exception of the 'Outstanding
Share Data', which is dated August 14, 2008), should be read in conjunction with
the audited consolidated financial statements as at and for the years ended
December 31, 2007 and 2006 (the "Financials") and related Notes. 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'. References to Notes herein are in relation to the
unaudited consolidated financial statements as at and for the three and six
months ended June 30, 2008.
RESULTS OF OPERATIONS
Revenue and Generation
Quarterly Electricity Generation - by Province and Technology(1)
----------------------------------------------------------------------------
Q2 6 months
2008 2007 2008 2007
MWh MWh Change MWh MWh Change
----------------------------------------------------------------------------
British Columbia 80,607 94,627 - 15% 111,936 123,832 - 10%
Alberta 107,144 112,789 - 5% 225,921 198,591 + 14%
Ontario 59,566 64,013 - 7% 138,990 149,304 - 7%
Quebec 14,060 - +100% 40,997 - +100%
----------------------------------------------------------------------------
Totals 261,377 271,429 - 4% 517,844 471,727 + 10%
----------------------------------------------------------------------------
Hydroelectric 120,362 141,559 - 15% 174,808 196,459 - 11%
Wind 108,620 95,202 + 14% 281,511 212,556 + 32%
Biomass 32,395 34,668 - 7% 61,525 62,712 - 2%
----------------------------------------------------------------------------
Totals 261,377 271,429 - 4% 517,844 471,727 + 10%
----------------------------------------------------------------------------
kWh per share(2) 1.80 2.01 - 10% 3.57 3.62 - 1%
----------------------------------------------------------------------------
(1) Reflecting our net interest.
(2) kWh per share based on diluted weighted average shares outstanding.
Revenue in Q2 2008 increased 14% over Q2 2007 to $19,661,000 on generation of
261,377 MWh, compared to revenue of $17,277,000 on generation of 271,429 MWh in
Q2 2007. This increase was a result of higher pool prices in Alberta combined
with higher average contract prices as a result of the addition of the Le
Nordais Wind Plant ("Le Nordais"). This was offset partially by lower quarter
over quarter generation at the following plants due to:
- Extended downtime for the annual turnaround maintenance at our Grande Prairie
EcoPower(R) Centre ("GPEC") (see 'Operating Expenses' below);
- Spring runoff commencing about one month later than normal at our British
Columbia hydroelectric plants;
- A late spring in Alberta that resulted in lower irrigation demands, causing
our Alberta hydroelectric plants to come online a full month later than normal;
and
- The Melancthon I Wind Plant ("Melancthon I") being down for 28 days in June
due to substation expansion for the Melancthon II Wind Project ("Melancthon
II"). Based on the long term average generation of Melancthon I, this downtime
resulted in approximately 6,275 MWh of lost generation.
For the six months ended June 30, 2008, revenue increased by 22% to $39,122,000
from $32,015,000 in 2007 as a result of higher average prices received, as well
as increased generation primarily due to the addition of Le Nordais and a full
six months of generation from the Soderglen Wind Plant ("Soderglen"), which was
acquired in March 2007. This increased generation was offset slightly by lower
production at Melancthon I, GPEC, and the Alberta hydroelectric plants, as
discussed above.
We have received an average price of $76/MWh for the year-to-date, compared to
$68/MWh for 2007. This was the result of the addition of Le Nordais, which has a
higher contract price than the average of our existing plants, and a higher pool
price received by our merchant Alberta plants. Approximately 78% of our
generation was sold pursuant to long-term sales contracts in Q2 2008 (Q2 2007 -
80%) and for the year-to-date, we have sold 76% under long-term sales contracts,
compared to 80% in 2007. Alberta Power Pool ("Pool") prices received in Q2 2008
($93/MWh) were significantly higher than Q2 2007 ($43/MWh).
Operating Expenses
Operating expenses increased 47% in Q2 2008 to $7,483,000 compared to $5,077,000
in Q2 2007, mainly due to the annual turnaround maintenance at GPEC. This year's
maintenance program included tasks which are on a 2 to 3 year cycle, as well as
new projects to stabilize operations and improve the availability and
profitability of the plant. Approximately $400,000 of additional costs were
incurred as a result of this program, in addition to lower revenue due to plant
downtime. We anticipate GPEC to perform consistent with 2007 for the rest of the
year (generation of approximately 60,000 MWh). We are currently working on a
detailed plan to improve operations and profitability at GPEC to what we had
originally planned.
For the six months ended June 30, 2008, operating expenses have increased 27% to
$12,633,000 from $9,965,000 in 2007 as a result of the factors discussed above,
as well as a full six months of operations at Soderglen and Le Nordais. On a
$/MWh basis, operating expenses increased in Q2 2008 primarily as a result of
the increased maintenance at GPEC, as well as lower generation in Q2 2008
compared to Q2 2007, as explained above.
Gross Margins
Gross margins (revenue less operating expenses) decreased slightly in Q2 2008 to
$12,178,000 from $12,200,000 in Q2 2007 due to lower generation and increased
operating expenses, as discussed above. As a percentage of revenue, gross
margins decreased for Q2 2008 to 62% from 71% in Q2 2007 due primarily to the
lower gross margins at GPEC as a result of the extended downtime for the annual
turnaround maintenance.
For the six months ended June 30, 2008, gross margins have increased 20% to
$26,489,000 in 2008, from $22,050,000 in 2007 as a result of a full six months
of operations at Soderglen and the addition of Le Nordais, combined with higher
average prices received. As a percentage of revenue, gross margins decreased for
the six month period to 67%, as compared to 69% in 2007, due primarily to GPEC
as discussed above.
Interest on Credit Facilities, Credit Facilities and Interest Income
----------------------------------------------------------------------------
(in thousands of dollars except Q2 6 months
where noted) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Gross interest on credit
facilities 8,864 4,678 + 89% 14,543 9,264 + 57%
Capitalized interest 4,122 950 + 334% 5,377 1,899 + 183%
----------------------------------------------------------------------------
Net interest expense on credit
facilities 4,742 3,728 + 27% 9,166 7,365 + 24%
----------------------------------------------------------------------------
Net interest expense on credit
facilities per MWh
($/MWh) 18.14 13.73 + 32% 17.70 15.62 + 13%
----------------------------------------------------------------------------
Interest income 175 179 + 2% 380 636 - 40%
----------------------------------------------------------------------------
The increase in net interest on credit facilities (excluding capitalized
interest) for both Q2 and the six months ended June 30, 2008 was due to higher
outstanding corporate debt, mainly due to the acquisition facility, which we
closed in December 2007 for our acquisition of Le Nordais, and subsequently
repaid in June 2008 from the proceeds of the Series 4 and Series 5 Debentures
which closed on June 11, 2008 for total gross proceeds of $75,900,000. The
Series 4 Debentures have a 10-year term maturing on June 11, 2018, and bear an
interest rate of 7.027% per annum, with interest paid semi-annually. The Series
5 Debentures have a 10-year term maturing on June 11, 2018, and bear an interest
rate of 7.308% per annum, with interest paid semi-annually. As described in Note
8, on June 6, 2008, we entered into a cross-currency swap to fix both the
principal repayment and the semi-annual interest payments on the Series 5
Debentures. The principal amount of $20,000,000 US dollars was fixed at
$20,400,000 Canadian dollars. The semi-annual interest payments of 7.308% per
annum were fixed into Canadian dollars at rate of 7.200% per annum. After giving
effect to the cross-currency swap, the principal amounts of the Series 4 and
Series 5 Debentures are fixed at $75,900,000 Canadian dollars with an interest
rate of 7.073% per annum.
On June 12, 2008 we amended our existing credit agreement, adding an additional
$312,500,000 of unsecured credit facilities, for a total of $611,000,000. The
amended credit facility includes the $233,500,000 in the aggregate of
construction facilities for Melancthon II and the Blue River Hydroelectric
Projects ("Blue River"), a $292,500,000 construction facility for the Wolfe
Island Wind Project ("Wolfe Island"), and an $85,000,000 Operating Facility. The
terms of the Melancthon II and Blue River construction facilities remain
unchanged with 18-month and 31-month drawdown periods, respectively, followed by
a two-year non-amortizing term out period, bearing interest at Bankers'
Acceptances rates plus a stamping fee of 0.70% per annum. The Wolfe Island
construction facility has a 15-month drawdown period followed by a two-year
non-amortizing term out period. Both the Wolfe Island construction facility and
the Operating Facility bear interest at Bankers' Acceptances rates plus a
stamping fee of 1.375% per annum.
On a $/MWh basis, net interest expense increased for both the 3 and 6 month
periods as we have not yet had the full generation benefit of the Le Nordais
acquisition, combined with lower generation in Q2 2008 compared to Q2 2007, as
explained above. 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 June 30, 2008 were
$554,746,000 compared to $414,756,000 as at December 31, 2007. The increase was
a result of the issuance of the Series 4 and Series 5 Debentures and increased
draws on our Melancthon II construction facility and Operating Facility, offset
slightly by regular repayments on certain credit facilities.
Amortization Expense
Amortization expense increased 28% in Q2 2008 to $5,100,000 from $3,989,000 in
Q2 2007, and for the six months ended June 30, 2008 increased 41% to $10,129,000
from $7,181,000 in 2007, due in both cases to the addition of Soderglen and Le
Nordais in March and December 2007, respectively. Our wind plants are amortized
on a straight-line basis over a 30 year period, except Le Nordais and Taylor
Wind, which are amortized over 26 years and 15 years, respectively, and our
biomass and hydroelectric plants are amortized on a straight-line basis over a
40 year period. On a $/MWh basis, amortization expense increased for both the 3
and 6 month periods as we have not yet had the full generation benefit of the Le
Nordais acquisition, combined with lower generation in Q2 2008 compared to Q2
2007, as explained above.
Administration Expense
Administration expense increased 80% in Q2 2008 to $1,235,000 from $688,000 in
Q2 2007, due to moderately higher salary costs with the addition of new
employees in 2008, as well as increased costs associated with the recruitment
and hiring of these new employees, and timing differences on certain bonus
accruals.
For the six months ended June 30, 2008 administration expense increased 34% to
$3,048,000 from $2,274,000 in 2007, as a result of the increased staff as
discussed above.
On a $/MWh basis, administration expense increased for both the 3 and 6 month
periods as we have not yet had the full generation benefit of the Le Nordais
acquisition, as well as lower generation in Q2 2008 compared to Q2 2007, as
explained above.
Capitalized administration costs associated with construction-in-progress and
prospect development costs in Q2 2008 were $1,917,000 (Q2 2007 - $1,594,000) and
for the six months ended June 30, 2008 were $2,328,000 (2007 - $2,204,000)
associated with our continued construction and development activity.
Stock Compensation Expense
Stock compensation expense increased 4% in Q2 2008 to $584,000 from $561,000 in
Q2 2007, due to additional options issued, offset by lower fair value per option
as a result of lower volatility in our share price, which impacts the fair value
per option.
For the six months ended June 30, 2008 stock compensation expense increased 26%
to $1,306,000 from $1,039,000 in 2007, as a result of the factors discussed
above.
Taxes
We do not anticipate paying cash income taxes for several years, other than in
respect of the Cowley Ridge Wind Plant, 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) in accordance with the Revenue Rebate Regulation of the
Alberta Small Power Research and Development Act. This Regulation will apply
until the associated power sale agreements expire in 2013 (9.0 MW) and 2014 (9.9
MW). 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 January 1, 2009, while Quebec Capital Tax rates are
being reduced from 0.36% of paid up capital in 2008 to 0.12% in 2010.
Future income tax expense was $1,604,000 in Q2 2008 (Q2 2007 - $1,484,000) and
$2,386,000 for the six months ended June 30, 2008 (2007 - $2,097,000). The
increase in 2008 is due to higher earnings before taxes, offset partially by
lower future tax rates as compared to the prior year.
EBITDA, Cash Flow from Operations, and Net Earnings
EBITDA
In Q2 2008, EBITDA of $11,279,000 decreased 8% compared to $12,216,000 in Q2
2007, due primarily to lower gross margins at GPEC, as well as higher
administrative expenses, as discussed previously, offset partially by the
addition of Le Nordais, higher pool prices received in Alberta, and the realized
portion of the foreign exchange gain in the period. On a $/MWh basis, EBITDA in
Q2 2008 was consistent with the prior year.
For the six months ended June 30, 2008 EBITDA increased 16% to $23,978,000 from
$20,753,000 in 2007 due to higher pool prices received in Alberta, higher gross
margins from the addition of Soderglen and Le Nordais, and the realized portion
of the foreign exchange gain, offset partially by lower gross margins at GPEC,
and increased administrative expenses, as discussed above.
Cash Flow from Operations
Cash flow from operations in Q2 2008 of $5,614,000 decreased 28% over Q2 2007 at
$7,762,000 as a result of lower gross margins at GPEC and higher interest
expense and current taxes. On a $/MWh basis, cash flow decreased in Q2 2008
compared to the prior year as a result of the same factors, in addition to lower
generation as previously discussed. On a per share basis, cash flow decreased
33% in Q2 2008 to $0.04 per share from $0.06 in Q2 2007 due to the above and the
dilution of the additional shares issued through our bought-deal equity
financing completed in December 2007 and the exercise of the over-allotment
option in January 2008, for which we have not yet had the full benefit to cash
flow.
For the six months ended June 30, 2008, cash flow from operations increased 8%
on an absolute basis, and on a $/MWh basis, to $13,956,000 from $12,907,000 in
2007, due to the same factors as discussed above with respect to EBITDA. For the
six months ended June 30, 2008, cash flow per share was consistent with 2007 at
$0.10 per share due to more shares outstanding in 2008 compared to 2007 as
discussed above. Additionally, 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, and as a result, the full benefit of the
financings have not yet been reflected in our net earnings or cash flow from
operations.
Net Earnings
Net earnings, on an absolute basis, increased 63% in Q2 2008 to $2,883,000
compared to $1,771,000 in Q2 2007, and for the six months ended June 30, 2008,
net earnings increased 75% to $4,692,000 from $2,676,000 in 2007, as a result of
increased revenue and the foreign exchange gain from the Euros ear-marked for
turbine payments, offset partially by the factors discussed above with respect
to EBITDA and cash flow from operations as well as increased future taxes.
Accordingly, on a $/MWh basis, net earnings improved over the prior year.
On a per share basis, these absolute increases were offset partially by
additional shares outstanding due to the bought deal equity financing completed
in December 2007, and the exercise of the over-allotment option in January 2008,
resulting in earnings per share of $0.02 in Q2 2008 compared to $0.01 in Q2
2007. 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, and as a result, the benefit of the financings have not yet been
reflected in our net earnings or cash flow from operations.
Property, Plant, and Equipment Additions and Prospect Development Costs
----------------------------------------------------------------------------
Q2 6 months
----------------------------------------------------------------------------
(in thousands of dollars) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Property, plant, and
equipment additions 130,222 4,912 +2,551% 140,863 11,773 +1,096%
Prospect development cost
additions 5,387 3,538 + 52% 7,750 7,139 + 9%
----------------------------------------------------------------------------
Property, plant, and equipment additions relate mainly to costs for Wolfe Island
including initial wind turbine payments, the B.C. hydroelectric projects, and
Melancthon II, which are currently under or nearing construction. Additions of
prospect development costs relate primarily to expenditures for the Dunvegan
Hydroelectric Prospect ("Dunvegan").
From time to time, initial site investigations and project economics do not
justify us pursuing certain prospects, and as such, these costs are written off.
During Q2 2008 and for the six months ended June 30, 2008, prospect development
costs of $188,000 were written off (2007 - $nil).
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 2007 Q4 2007 Q1 2008 Q2 2008
----------------------------------------------------------------------------
Total revenue 14,344 17,398 19,461 19,661
Net earnings 162 5,505 1,809 2,883
Earnings per share - basic - 0.04 0.01 0.02
Earnings per share - diluted - 0.04 0.01 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(in thousands of dollars, except per
share amounts) Q3 2006 Q4 2006 Q1 2007 Q2 2007
----------------------------------------------------------------------------
Total revenue 11,729 13,060 14,738 17,277
Net earnings 292 3,328 905 1,771
Earnings per share - basic - 0.03 0.01 0.01
Earnings per share - diluted - 0.03 0.01 0.01
----------------------------------------------------------------------------
The changes over the past eight quarters are due primarily to the addition of
Soderglen and Le Nordais, acquired in Q1 2007 and Q4 2007, respectively, as well
as the large foreign exchange gain offset partially by GPEC, as discussed above.
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 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.
In early 2007, we embarked upon a significant expansion plan to triple 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 have the necessary cash flow, working capital and
access to capital markets to fulfill any obligations and commitments we make in
implementing this expansion plan.
In June 2008, we issued the Series 4 and Series 5 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, Credit Facilities and Interest
Income').
----------------------------------------------------------------------------
As at June 30,
(in thousands of dollars except where noted) 2008
----------------------------------------------------------------------------
Capital expenditure plans through 2012 1,274,120
Spent to date (450,373)
----------------------------------------------------------------------------
Remaining capital expenditures to be financed 823,747
Financed/to be financed by:
Melancthon II and Blue River construction facilities 120,000
Wolfe Island construction facility 292,500
Working capital surplus(1) 37,024
Anticipated construction facilities 302,700
Undrawn & available revolving Operating Facility 5,436
----------------------------------------------------------------------------
Difference (66,087)
----------------------------------------------------------------------------
(1) Excluding derivative financial instrument asset
The difference is expected to be funded through cash flow from operations.
Our current capital expenditure plans are for: Melancthon II, Wolfe Island,
Island Falls, Royal Road, Blue River, English Creek, St. Valentin, and New
Richmond projects, which are either in or nearing construction. The construction
facilities we have placed and anticipate placing for these projects are,
generally, based on 65% of the capital costs of these projects. Our ability to
debt finance these projects are predicated on our BBB (Stable) investment grade
credit rating. We, generally, cannot draw on construction credit facilities
until we have expended 35% of the capital costs of a project, using our equity
to pay for this. If timing differences exist between when the costs are expended
and the construction facilities are in place, we will employ our cash flow from
operations to support our capital expenditure program. With the addition of
Royal Road, St. Valentin, and New Richmond, we will require additional capital,
as shown in the previous table. Depending on the timing of expenditures, we plan
to fund this capital requirement through cash flow from operations.
In December 2007, we closed a public offering of common shares on a bought-deal
basis through a syndicate of underwriters (the "Underwriters") for the issue of
8,800,000 common shares at a price of $6.25 per share for gross proceeds of
$55,000,000 ($52,195,000 net of share issue costs). Included in the public
offering was an over-allotment option of $5,500,000 ($5,280,000 net of share
issue costs), which was fully exercised by the Underwriters in January 2008. The
proceeds from the over-allotment were used for general corporate purposes.
As at June 30, 2008, we had a 53/47 debt/equity mixture (December 31, 2007 -
46/54) compared to a stated target of 65/35. We will move towards our stated
target as we draw on existing credit facilities and put in place and draw on
future construction facilities for the projects discussed above.
OUTLOOK
Key Management
People are our most critical non-capital resource. Having the right people in
the right places at the right time, with the right resources, is one of our key
priorities to achieve our strategic plan. As such, to build on this benchmark
strength, we hired Keith O'Regan into the role of Executive Vice-President and
Chief Operating Officer in the second quarter. Keith has a diverse and strong
background of leading people, and successfully growing and developing high
performing business operations. Keith's valuable leadership skills and focus on
operational excellence will help us achieve our strategic plan.
Project Updates
Ontario
Construction is proceeding well at Melancthon II, with no change to the
projected capital cost of $285 million or to the anticipated in-service date of
November 30, 2008. As at August 5, 2008 we have erected 34 of the 88 turbines,
completed the necessary expansion work at the Melancthon I substation to
accommodate the additional turbines, and continue to work towards the completion
of this project.
At Wolfe Island, in June 2008, we completed the provincial environmental
approval process, clearing our way to proceed with construction, subject to any
other permits and approvals required. We now have a $292,500,000 construction
credit facility in place, and have begun pre-servicing activities such as access
roads, lay down areas, and transmission line transitions. Anticipated capital
costs and in-service date remain unchanged at $450,000,000 and March 31, 2009,
respectively.
We continue to work through the approvals process for the $71 million ($35.5
million net to our interest) Island Falls Hydroelectric Project and the $40
million Royal Road Wind Projects in Ontario. The projects are targeted for
completion by October 2009 and August 2010, respectively. Construction will
commence once approvals and debt financing are in place. Wind turbines and
related equipment have been ordered for the Royal Road Wind Projects, consisting
of 12, 1.5 MW GE turbines for these 2, 9 MW projects.
British Columbia
Approvals and financing are complete for the $49 million Bone and $27 million
Clemina Creek Hydroelectric Projects, and construction commenced in June 2008
with site clearing and preliminary work. The $22 million Serpentine and $10
million English Creek Hydroelectric Projects are nearly through the approvals
process and construction is expected to follow thereafter. All B.C.
hydroelectric projects are anticipated to be operational by the fourth quarter
of 2009.
Alberta
We continue to pursue the development of Dunvegan. In June, we were granted
permits and began a summer fieldwork investigation program, focusing on
geotechnical and seismic data gathering for the purpose of detailed engineering
design. On July 16th, three panel members were appointed to a joint
federal-provincial panel established to review the project for the approval of
construction and operation of the project. We anticipate a hearing and
regulatory decision for approval of construction and operation in 2008.
Regulatory approvals, long-term power sales contracts and financing are required
prior to construction commencing.
Quebec
On May 5, 2008, we were awarded two, 20 year Electricity Supply Contracts
("PPAs") from Hydro-Quebec Distribution ("HQD") for our 50 MW St. Valentin ("St.
Valentin") and our 66 MW New Richmond ("New Richmond") Wind Projects through our
Venterre joint venture. St. Valentin is expected to generate 143,900 MWh per
year of power at an estimated capital cost of $160 million, including
capitalized interest. Approximately 72% of the capital costs are fixed,
including turbine supply agreements. New Richmond is expected to generate
178,700 MWh per year of power at an estimated capital cost of $190 million,
including capitalized interest. Approximately 79% of the capital costs are
fixed, including turbine supply agreements. St. Valentin and New Richmond have
PPA prices of $108.10/MWh and $105.56/MWh (expressed in 2007 dollars),
respectively. These PPA prices will escalate 5%, 15% and 80% based on full
increases in the copper, steel, and Canadian consumer price indices,
respectively, until the date of commercial operations. Thereafter and for the
life of the PPAs, the PPA prices escalate 100% for the change in the Canadian
consumer price index.
The target internal rate of return for both of these projects on a pre-tax,
unlevered basis is 11%. This clearly demonstrates that we can compete in an
increasingly competitive marketplace without sacrificing returns. The target
in-service date of both projects is December 2012, and is subject to regulatory
approvals and financing.
Upcoming Calls for Power
B.C. and Ontario
We expect to bid up to 55 MW of our 260 MW of B.C. hydroelectric prospects into
BC Hydro's call for power, which was announced in June 2008, with submissions
due in late November 2008 and contracts anticipated to be awarded in the second
quarter of 2009. In addition, we plan to submit up to 70 MW of wind prospects
into the Ontario Power Authority's request for up to 500 MW of renewable energy
supply, announced in the second quarter with submissions due in October 2008,
and contracts anticipated to be awarded in December 2008.
New Business
The solar energy market is one which we continue to monitor and assess on a
regular basis. As a result of the Ontario Power Authority's Standard Offer
Contract ("SOC") for solar energy projects offering a significant premium over
existing prices ($420/MWh), combined with improving costs in the photovoltaic
cell market, we have begun to review the economics of a solar project. As a
result of these factors, we have entered into an SOC for a 10 MW solar project,
at no cost to us to enter into or walk away from the SOC. We view this as a free
option as we continue to assess the economic viability of the project. We feel
that 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
Financial Position
The following chart outlines significant changes in our consolidated balance
sheet from December 31, 2007 to June 30, 2008:
----------------------------------------------------------------------------
Increase Explanation
(Decrease)
$
----------------------------------------------------------------------------
Cash and cash 50,526 The increase is a result of financings
equivalents completed in the quarter and the
settlement of Euro forward contracts
ear-marked for turbine payments.
Property, plant, and 221,213 The increase is a result of Wolfe Island
equipment and Blue River projects being
reclassified as construction-in-
progress from development costs, as
well as increased expenditures on these
projects, offset slightly by increased
amortization.
Prospect development (82,917) The decrease is due to the change in
costs classification of Wolfe Island and the
Blue River projects to construction-in-
progress.
Accounts payable 33,080 The increase in accounts payable is a
result of the increase in construction
activity at Melancthon II and Wolfe
Island.
Acquisition facility (72,300) The decrease is a result of the payment
of the acquisition facility with the
proceeds from the Series 4 and 5
Debentures.
Credit facilities 212,265 The increase is a result of financings
completed in the quarter, including
the issuance of the Series 4 and Series
5 Debentures, and increased drawings on
existing credit facilities.
Share capital 6,672 The increase is due to the exercise of
the over-allotment option of the
December 2007 private placement, as
well as the issuance of shares from the
exercise of stock options.
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 and internal controls over financial
reporting since year end. Based on this evaluation, we have concluded that the
design of these controls and procedures continues to be appropriate.
Accounting Changes and Future Accounting Changes
Effective January 1, 2008, we adopted Canadian Institute of Chartered
Accountants ("CICA") handbook sections 3862 - "Financial Instruments
Disclosures", section 3863 - "Financial Instruments Presentations", and section
1535 - "Capital Disclosures", which are required to be adopted for fiscal years
beginning on or after October 1, 2007. The impact of these changes is
exclusively disclosure related, as described in Notes 2, 8 and 9 of the
unaudited interim financial statements as at and for the period ended June 30,
2008.
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 the training requirements for financial
reporting and accounting staff.
OFF-BALANCE SHEET ARRANGEMENTS
At June 30, 2008, 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 six
months ended June 30, 2008, royalties totaling $28,000 (2007 - $24,000) 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 year ended June 30, 2008, 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 from January 1, 2008, maturing
from 2008 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 OCI. At June 30, 2008,
the fair value of the CFDs was a liability of $1,460,000.
Foreign Exchange Contracts
We have entered into various foreign exchange contracts, expiring in 2008, which
fix our Euro payments under wind turbine purchase contracts in Canadian dollars.
The aggregate remaining amount of Euro purchases is EUR 21,349,000, which is
fixed at a blended average rate of 1.4677 for an aggregate Canadian dollar
amount of $31,334,000. Additionally, on June 11, 2008, 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 were 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, 2008, the aggregate fair value of all
outstanding foreign exchange contracts was an asset of $628,000.
Outstanding Share Data
----------------------------------------------------------------------------
As at August 14, 2008
(Unaudited)
----------------------------------------------------------------------------
Basic common shares 143,488,723
Convertible securities:
Warrants 4,110,900
Options 6,306,250
----------------------------------------------------------------------------
Fully diluted common shares 153,905,873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 from operations,
cash flow from operations per share (diluted), MWh, $/MWh, kWh, kWh per share,
and other per share amounts. All references to cash flow from operations relate
to cash flow from operations before changes in non-cash working capital. 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)
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 73,311 22,785
Accounts receivable 10,442 11,897
Derivative financial instrument asset (Note 8) 931 -
Prepaid expenses 1,597 568
----------------------------------------------------------------------------
86,281 35,250
Property, plant, and equipment (Note 3) 1,018,600 797,387
Prospect development costs (Note 4) 34,360 117,277
----------------------------------------------------------------------------
TOTAL ASSETS 1,139,241 949,914
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities 45,164 12,084
Current portion of credit facilities (Note 6) 2,191 2,825
Derivative financial instrument liability (Note 8) 1,763 1,703
Taxes payable 973 304
Acquisition facility (Note 6) - 72,300
----------------------------------------------------------------------------
50,091 89,216
Credit facilities (Note 6) 552,530 339,631
Future income taxes 41,408 39,091
----------------------------------------------------------------------------
644,029 467,938
----------------------------------------------------------------------------
Commitments and contingencies (Note 12)
SHAREHOLDERS' EQUITY
Share capital (Note 7) 454,703 448,031
Contributed surplus (Note 7) 5,299 4,299
Retained earnings 36,041 31,349
----------------------------------------------------------------------------
496,043 483,679
Accumulated other comprehensive loss (Note 5) (831) (1,703)
----------------------------------------------------------------------------
495,212 481,976
----------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 1,139,241 949,914
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (Unaudited)
(in thousands of dollars except per share amounts)
3 months ended 6 months ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
Electric energy sales 19,538 17,154 38,813 31,733
Revenue rebate 123 123 309 282
----------------------------------------------------------------------------
19,661 17,277 39,122 32,015
----------------------------------------------------------------------------
Expenses (income)
Operating 7,483 5,077 12,633 9,965
Amortization 5,100 3,989 10,129 7,181
Interest on credit facilities 4,743 3,728 9,167 7,365
Administration 1,235 688 3,048 2,274
Stock based compensation 584 561 1,306 1,039
Write-off of prospect development
costs (Note 4) 188 - 188 -
Interest income (175) (179) (380) (636)
Foreign exchange gain (5,081) (704) (5,282) (714)
Gain on derivative financial
instrument - (43) - (349)
----------------------------------------------------------------------------
14,077 13,117 30,809 26,125
----------------------------------------------------------------------------
Earnings before taxes 5,584 4,160 8,313 5,890
----------------------------------------------------------------------------
Tax expense
Current 1,097 905 1,235 1,117
Future 1,604 1,484 2,386 2,097
----------------------------------------------------------------------------
2,701 2,389 3,621 3,214
----------------------------------------------------------------------------
Net earnings 2,883 1,771 4,692 2,676
Retained earnings, beginning of period 33,158 23,793 31,349 22,888
----------------------------------------------------------------------------
Transitional adjustment - 118 - 118
Adjusted retained earnings, beginning
of period 33,158 23,911 31,349 23,006
----------------------------------------------------------------------------
Retained earnings, end of period 36,041 25,682 36,041 25,682
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share (Note 10)
Basic 0.02 0.01 0.03 0.02
Diluted 0.02 0.01 0.03 0.02
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Unaudited)
(in thousands of dollars except per share amounts)
3 months ended 6 months ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings 2,883 1,771 4,692 2,676
Other comprehensive (loss) gain:
Unrealized (loss) gain on derivative
financial instrument currency hedges (2,874) (13,374) 1,108 (10,321)
Unrealized loss on derivative
financial instrument contracts
for differences (355) (226) (236) (1,244)
Reclassification of deferred credit - (43) - (86)
----------------------------------------------------------------------------
Other comprehensive (loss) gain (3,229) (13,643) 872 (11,651)
Comprehensive (loss) income (346) (11,872) 5,564 (8,975)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CANADIAN HYDRO DEVELOPERS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands of dollars)
3 months ended 6 months ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings 2,883 1,771 4,692 2,676
Adjustments for:
Amortization 5,100 3,989 10,129 7,181
Future income tax expense 1,604 1,484 2,386 2,097
Stock compensation expense 584 561 1,306 1,039
Write-off of prospect development
costs 188 - 188 -
Unrealized foreign exchange gain (4,745) - (4,745) -
Gain on derivative financial
instrument - (43) - (86)
----------------------------------------------------------------------------
Cash flow from operations before
changes in non-cash working capital 5,614 7,762 13,956 12,907
Changes in non-cash working capital 35,153 832 34,176 6,717
----------------------------------------------------------------------------
40,767 8,594 48,132 19,624
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Credit facility repayments (Note 6) (1,696) (494) (2,135) (977)
Credit facility advances (Note 6) 214,400 - 214,400 -
Acquisition facility repayment
(Note 6) (72,300) - (72,300) -
Issue of common shares, net of issue
costs (Note 7) 213 715 6,297 652
140,617 221 146,262 (325)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Property, plant, and equipment
additions (130,222) (4,912) (140,863) (11,773)
Prospect development costs (5,387) (3,538) (7,750) (7,139)
Working capital deficit assumed on
acquisition - - - (13,423)
----------------------------------------------------------------------------
(135,609) (8,450) (148,613) (32,335)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FOREIGN EXCHANGE ON CASH HELD IN
FOREIGN CURRENCY 4,745 - 4,745 -
----------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 45,775 365 45,781 (13,036)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 22,791 48,268 22,785 61,669
----------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF
PERIOD 73,311 48,633 73,311 48,633
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplemental information
Cash interest paid 8,209 5,356 12,737 8,743
Cash income and capital taxes paid 111 872 111 1,054
See accompanying Notes to the Consolidated Financial Statements
CANADIAN HYDRO DEVELOPERS, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2008 (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.
These accounting policies used in the preparation of these interim consolidated
financial statements conform to those used in the Company's most recent annual
consolidated financial statements, except as noted below.
2. CHANGE IN ACCOUNTING POLICIES
Effective January 1, 2008, the Company adopted Canadian Institute of Chartered
Accountants ("CICA") handbook section 3862 - "Financial Instruments
Disclosures", section 3863 - "Financial Instruments Presentations", and section
1535 - "Capital Disclosures", which are required to be adopted for fiscal years
beginning on or after October 1, 2007. The changes as a result of the adoption
of these sections are as follows:
(i) Section 1535 - Under this section, the Company is required to disclose
information that enables users of the financial statements to evaluate the
Company's objectives, policies, and process for managing capital. These
disclosures have been included in Note 9.
(ii) Sections 3862 and 3863 - Under these sections, the Company is required to
disclose information that enables users of the financial statements to evaluate
the significance of financial instruments for its financial position and
performance, as well as the nature and extent of the risks arising from
financial instruments to which the Company is exposed at the balance sheet date.
These disclosures have been included in Note 8.
3. PROPERTY, PLANT, AND EQUIPMENT
The major categories of property, plant, and equipment at cost and related
accumulated amortization are as follows:
June 30, 2008 December 31, 2007
------------------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
$ $ $ $
------------------------------------------------------
Generating plants
- operating 639,604 (63,667) 575,937 585,359
- construction-in-
progress 439,300 - 439,300 208,886
Equipment, other 4,786 (1,923) 2,863 2,670
Vehicles 1,647 (1,147) 500 472
------------------------------------------------------
1,085,337 (66,737) 1,018,600 797,387
------------------------------------------------------
------------------------------------------------------
For the 3 months ended June 30, 2008, interest costs of $4,122,000 (3 months
ended June 30, 2007 - $559,000) and administration expenses of $1,709,000 (3
months ended June 30, 2007 - $831,000) associated with construction-in-progress
have been capitalized during construction. For the 6 months ended June 30, 2008,
interest costs of $4,424,000 (6 months ended June 30, 2007 - $1,118,000) and
administration expenses of $1,754,000 (6 months ended June 30, 2007 - $646,000)
associated with the construction-in-progress have been capitalized during
construction. In 2008 and 2007, construction-in-progress relates to costs
associated with the construction of the Melancthon II Wind Project, the Wolfe
Island Wind Project, and the Bone and Clemina Creek Hydroelectric Projects (2007
- Melancthon II). During the 3 months ended June 30, 2008, $220,688,000 was
moved from Prospect Development Costs to construction-in-progress for the Wolfe
Island Wind Project and the Bone and Clemina Creek Hydroelectric Projects.
4. PROSPECT DEVELOPMENT COSTS
Prospect development costs are comprised of the following:
June 30, 2008 December 31, 2007
$ $
---------------------------------
Hydroelectric and other prospects 12,042 14,184
Wind prospects 11,992 94,344
Dunvegan Hydroelectric Prospect 10,326 8,749
---------------------------------
Total 34,360 117,277
---------------------------------
---------------------------------
For the 3 months ended June 30, 2008, interest costs of $nil (June 30, 2007 -
$391,000) and administration expenses of $208,000 (June 30, 2007 - $948,000)
associated with prospect development costs have been capitalized for projects
leading up to construction. For the 6 months ended June 30, 2008, interest costs
of $953,000 (June 30, 2007 - $781,000) and administration expenses of $574,000
(June 30, 2007 - $1,373,000) associated with prospect development costs have
been capitalized for projects leading up to construction. The wind prospect
development costs relate to over 1,127 MW of optioned land for wind prospects
located primarily throughout Manitoba and Ontario. Included in hydroelectric
prospects is $2,939,000 (December 31, 2007 - $2,672,000) in costs related to the
development of the Island Falls Hydroelectric Project and $8,075,000 (December
31, 2007 - $9,267,000) in costs related to the development of run-of-river
hydroelectric projects in B.C. During the 3 months ended June 30, 2008, all
development costs relating to Wolfe Island and the Bone and Clemina Creek
Hydroelectric Projects were transferred to construction-in-progress in Property,
Plant, and Equipment.
The Company continues to pursue the development of the Dunvegan Hydroelectric
Prospect. The Company anticipates a hearing and regulatory decision for approval
of construction and operation in 2008. Regulatory approvals, long-term power
sales contracts and financing are required prior to proceeding. Should the
Company not be successful in obtaining regulatory approvals, the prospect would
likely be abandoned and the related prospect development costs would be written
off.
For the 3 and 6 months ended June 30, 2008, the Company wrote off $188,000 (2007
- $nil) in costs relating to development prospects that were abandoned during
the quarter.
5. ACCUMULATED OTHER COMPREHENSIVE INCOME ("AOCI")
AOCI, including transition amounts, is comprised of the following:
$
----------
Balance, December 31, 2007 (1,703)
Unrealized gain on derivative financial instrument foreign
currency hedges 1,411
Unrealized loss on derivative financial instrument cross-currency
swap (303)
Unrealized loss on derivative financial instrument contracts
for differences (236)
----------
Accumulated other comprehensive (loss) income, June 30, 2008 (831)
----------
----------
6. CREDIT FACILITIES
On June 10, 2008 the Company closed a private placement issuance of $75,900,000
in unsecured corporate debentures with a 10-year term, maturing on June 11,
2018, bearing interest at a combined rate of 7.073% per annum (the
"Debentures"). The Debentures are comprised of Series 4 unsecured corporate
debentures in the amount of $55,500,000 (the "Series 4 Debentures"), and Series
5 unsecured corporate debentures in the amount of US$20,000,000 (the "Series 5
Debentures"). The Series 4 Debentures have a 10-year term maturing on June 11,
2018, and bear an interest rate of 7.027% per annum, with interest paid
semi-annually. The Series 5 Debentures have a 10-year term maturing on June 11,
2018, and bear an interest rate of 7.308% per annum, with interest paid
semi-annually. As described in Note 8, on June 6, 2008, the Company entered into
a cross-currency swap to fix both the principal repayment and the semi-annual
interest payments on the Series 5 Debentures. The principal amount of
$20,000,000 US dollars was fixed at $20,400,000 Canadian dollars. The
semi-annual interest payments of 7.308% per annum were fixed into Canadian
dollars at rate of 7.200% per annum. After giving effect to the cross-currency
swap, the principal amounts of the Debentures are fixed at $75,900,000 Canadian
dollars with an interest rate of 7.073% per annum.
On June 12, the Company amended its existing credit agreement, adding an
additional $312,500,000 of unsecured credit facilities, for a total of
$611,000,000. Prior to this, the Company's $370,800,000 credit facility
consisted of $233,500,000 in the aggregate of construction credit facilities for
Melancthon II, and certain Blue River Hydroelectric Projects ("Blue River"), a
$72,300,000 acquisition facility for the Le Nordais Wind Plant (the "Acquisition
Facility"), and a revolving operating facility (the "Operating Facility") of
$65,000,000. The amended credit facility includes the $233,500,000 in the
aggregate of construction facilities for Melancthon II and Blue River, a
$292,500,000 construction facility for Wolfe Island, and an $85,000,000
Operating Facility. On June 12, 2008, the Le Nordais Acquisition Facility was
repaid with the proceeds from the issuance of the Company's Debentures. The
terms of the Melancthon II and Blue River construction facilities remain
unchanged with 18-month and 31-month drawdown periods, respectively, followed by
a two-year non-amortizing term out period, bearing interest at Bankers'
Acceptances rates plus a stamping fee of 0.70% per annum. The Wolfe Island
construction facility has a 15-month drawdown period followed by a two-year
non-amortizing term out period. Both the Wolfe Island construction facility and
the Operating Facility bear interest at Bankers' Acceptances rates plus a
stamping fee of 1.375% per annum.
As described above, the Company has a revolving Operating Facility with its
banking syndicate for a total of $85,000,000. As at June 30, 2008, in addition
to the amount shown below as drawn, the Company had outstanding letters of
credit in the amount of $24,564,000 (December 31, 2007 - $22,174,000) relating
primarily to construction activities and security required under long-term sales
contracts for electricity.
June 30, December 31,
2008 2007
$ $
------------------------
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 -
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, with the
principal and interest payments fixed in
Canadian dollars through a cross-currency swap
(Note 8) 20,400 -
Pingston Debt, bearing interest at 5.281%, 10-year
term with interest payable semi-annually and
no principal repayments until maturity on February
11, 2015, secured by the Pingston
Hydroelectric Plant, without recourse to joint
venture participants 35,000 35,000
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, followed by a two-year non-
amortizing term out period 113,500 30,000
Operating Facility, 364-day revolving credit
facility, with a six month non-amortizing term out
period, extendable for one year periods annually by
mutual agreement of the Company and its
Lenders, bears interest at Bankers' Acceptances rates
plus a stamping fee of 1.375% per annu 55,000 -
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 5,990 6,379
Mortgage, bearing interest at 10.700% and secured by
letter of guarantee. Monthly repayments of
principal and interest are $84,000 until May 31,
2010 1,755 2,140
Mortgage, bearing interest at 10.680%, secured by
letters of guarantee. Monthly repayments of
principal are $31,000 plus interest until December
30, 2012 1,688 1,875
Promissory note, bearing interest fixed at 6.000%,
secured by a second fixed charge on three of
the Alberta hydroelectric plants. Monthly repayments
of principal and interest are $19,000 until
August 1, 2012 842 930
Acquisition Facility, bearing interest at the Bankers'
Acceptances rates plus a stamping fee of 0.85% per
annum, unsecured non-revolving credit facility
maturing on June 12, 2008 - 72,300
Note payable to a Canadian private company, assumed
on the acquisition of Le Nordais,
unsecured, bearing no interest, maturing on June 16,
2008 - 678
Deferred financing costs (2,954) (2,546)
------------------------
554,721 414,756
Less: Acquisition facility - (72,300)
Less: Current portion of credit facilities (2,191) (2,825)
------------------------
Credit facilities 552,530 339,631
------------------------
------------------------
7. SHARE CAPITAL
(a) Common shares and warrants:
Number of Amount
Shares $
----------------------------
Balance, common shares, December 31, 2007 141,834,973 444,064
Balance, warrants, December 31, 2007 (Note 7(b)) - 3,967
Issue of common shares 880,000 5,500
Share issue costs, net of tax effect of $69 - (195)
Issued on exercise of stock options 773,750 1,061
Stock compensation on options exercised - 306
----------------------------
Balance, June 30, 2008 143,488,723 454,703
----------------------------
----------------------------
On January 8, 2008, the Company closed the sale of 880,000 common shares at an
issue price of $6.25 per common share for aggregate gross cash proceeds of
$5,500,000 ($5,280,000 net of share issue costs). The common shares were issued
pursuant to the exercise by the underwriters of the over-allotment option
related to the equity financing closed in December 2007.
(b) Warrants:
Number of Amount
Warrants $
----------------------------
Balance, December 31, 2007 and June 30, 2008 4,110,900 3,967
----------------------------
----------------------------
The warrants issued have an exercise price of $7.00, and expire on March 8,
2009. These warrants have been allocated a fair value of $3,967,000, which was
calculated using the Black-Scholes pricing model.
(c) Stock compensation:
Using the fair value method of accounting for stock options issued to employees
on or after January 1, 2003, the Company recognized $584,000 for Q2 2008 (Q2
2007 - $561,000) and $1,306,000 for the 6 months ended June 30, 2008 (2007 -
$1,039,000) of compensation expense in the consolidated statement of earnings,
with a corresponding increase recorded to contributed surplus in the
consolidated balance sheet as at June 30, 2008. The Company issued 522,500
options in Q2 2008 (Q2 2007 - 820,000) and 602,500 options for the 6 months
ended June 30, 2008 (2007 - 1,185,000). The weighted average fair value of
options granted during Q2 2008 was $1.90 per share (Q2 2007 - $2.16 per share),
which was estimated using the Black-Scholes option-pricing model, assuming a
risk free interest rate of 3.32% (Q2 2007 - 4.55%), expected volatility of
28.72% (Q2 2007 - 34.45%), expected weighted average life of 4.0 years (Q2 2007
- 4.0 years), no annual dividends paid, vesting equally over 4 years. The
weighted average fair value of options granted during the 6 months ended June
30, 2008 was $1.77 per share (2007 - $2.11 per share), assuming a risk free
interest rate of 3.43% (2007 - 4.03%), expected volatility of 28.60% (2007 -
33.17%), expected weighted average life of 4.0 years (2007 - 4.0 years), and no
annual dividends paid.
(d) Contributed surplus:
June 30, June 30,
2008 2007
----------------------------
Balance, beginning of the period 4,299 2,186
Stock based compensation 1,306 1,039
Stock compensation on options exercised (306) (81)
----------------------------
Balance, end of period 5,299 3,144
----------------------------
----------------------------
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 periodical 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.
As at the transition date of January 1, 2007, the Company recorded an $118,000
increase in retained earnings with a corresponding decrease in the credit
facilities liability as a result of applying the effective interest rate method
to the Company's debentures. In addition, on transition date, the deferred
financing costs, previously recorded in other long-term assets, were netted
against the credit facilities liability. As the Company records debt accretion
of the deferred financing costs over the remaining term to maturity of the
debentures, these costs will be charged to income as interest expense with a
corresponding increase to the credit facilities liability.
The carrying value of cash and cash equivalents, accounts receivable, accounts
payable and accrued liabilities approximates their fair value at June 30, 2008
and 2007 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 credit worthiness and prevailing market interest rates.
Derivative Instruments and Hedging Activities
Derivative instruments are utilized by the Company to manage market risk against
the volatility in commodity prices, foreign exchange rates and interest rate
exposures. The Company's policy is not to utilize derivative instruments for
speculative purposes. The Company may choose to designate derivative instruments
as hedges.
All hedges are documented at inception including information such as the hedging
relationship, the risk management objective and strategy, the method of
assessing effectiveness and the method of accounting for the hedging
relationship. Hedge effectiveness is reassessed on a quarterly basis. All
derivative instruments are recorded on the balance sheet at fair value either in
accounts receivable, derivative financial asset or liability, accounts payable
and accrued liabilities, or other long-term liabilities. Derivative financial
instruments that do not qualify for hedge accounting are classified as held for
trading and are recognized on the balance sheet and measured at fair value, with
gains and losses on these instruments recorded in gain or loss on derivative
financial instruments in the consolidated statement of earnings in the period
they occur. Derivative financial instruments that have been designated and
qualify for hedge accounting have been classified as fair value or cash flow
hedges. For fair value hedges, the gains and losses arising from adjusting the
derivative to its fair value are recognized immediately in earnings along with
the gain or loss on the hedged item. For cash flow and foreign currency hedges,
the effective portion of the gains and losses is recorded in other comprehensive
income until the hedged transaction is recognized in earnings. For any hedging
relationship that has been determined to be ineffective, hedge accounting is
discontinued on a prospective basis.
The Company has entered into various foreign exchange contracts, expiring in
2008, which fix the Company's Euro payments under wind turbine purchase
contracts in Canadian dollars. The aggregate initial amount of Euro purchases
was _118,452,960, which is fixed at a rate of 1.4677 for an aggregate Canadian
dollar amount of $173,853,409. As at June 30, 2008 the remaining payments
totaled _21,349,080, or $31,344,035 Canadian dollars. As at January 1, 2007, the
fair value of all outstanding foreign exchange contracts of $7,894,000 was
recorded on the consolidated balance sheet as a derivative financial asset, with
the gain recorded in OCI. The fair value of the derivative asset as at June 30,
2008 was $931,000. From time to time, the Company may carry cash denominated in
foreign currencies which may give rise to foreign exchange gains and losses as a
result of fluctuations in exchange rates with the Canadian dollar.
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 from January 1, 2008, maturing from 2008 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. At
January 1, 2007, the fair value of these contracts of $206,000 was recorded on
the consolidated balance sheet as a derivative financial liability, with the
loss recorded as OCI. At June 30, 2008, the fair value of the derivative
liability was $1,460,000.
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 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, 2008, the fair value of the swap of $303,000 was
recorded on the consolidated balance sheet as a derivative financial liability,
with the loss recorded in OCI.
As at June 30, 2008, the Company does not have any outstanding contracts or
financial instruments with embedded derivatives that require bifurcation.
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 are reviewed on a regular basis to ensure the timely
collection of amounts owing to the Company. At June 30, 2008, the aging of the
Company's receivables is as follows:
June 30, 2008
----------------------------
Current receivables 9,483
Receivables greater than 60 - 120 days 959
Receivables greater than 120 days -
----------------------------
10,442
Less: Impairment allowance -
----------------------------
Receivables, end of period 10,442
----------------------------
----------------------------
The Company manages its credit risk by entering into sales agreements with
credit worthy parties and through regular review of accounts receivable. The
maximum exposure to credit risk is represented by the net carrying amount of
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, 2008.
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. Based on the balance outstanding at June 30,
2008, a 1% increase, on an absolute basis, in the Bankers' Acceptance rate would
result in additional interest expense, on an annual basis, of approximately
$1,700,000. The Company 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: foreign
currency hedges, CFDs, and the cross-currency swap, which are impacted by
changes in the Canadian dollar/Euro exchange rate, the forward price of
electricity in Alberta, and the Canadian/US dollar exchange rate, 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 instruments
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,
2008, a 1% change in the Canadian dollar/Euro blended forward exchange rate,
over the timing of the payments to be made by the Company, would result in a
$1,001,000 impact to AOCI, a 1% change in the forward electricity prices would
result in a $30,000 impact to AOCI, and a 1% change in the Canadian/US dollar
exchange rate would result in an impact of $180,000 to AOCI. This risk
management strategy is unchanged from the prior year.
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 success of this is monitored through comparison to a
targeted debt to equity 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/equity mixture is calculated as follows:
June 30, December 31,
2008 2007
$ $
----------------------------
Total debt, including current portion of credit
facilities 554,721 414,756
Shareholders' equity 495,212 481,976
----------------------------
Total debt and equity 1,049,933 896,732
Debt to equity mixture, end of period 53/47 46/54
----------------------------
----------------------------
Changes from December 31, 2007 relate primarily to issuance of new debt
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, the issuance of common shares 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, 2008, the Company
was in compliance with all externally imposed capital requirements, which
consist of covenants in accordance with the Company's borrowing agreements.
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 6 Months
ended June 30, ended June 30,
2008 2007 2008 2007
--------------------------------------------------
Basic weighted average
shares outstanding 143,413,228 132,462,020 143,304,327 127,658,641
Effect of dilutive
securities:
Options 1,712,507 2,799,503 1,820,312 2,768,260
--------------------------------------------------
Diluted weighted average
shares 145,125,735 135,261,523 145,124,639 130,426,901
--------------------------------------------------
--------------------------------------------------
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. As
previous internal management reporting had been prepared on a plant by plant
basis, rather than by operating segment, comparative information is not readily
available and not presented below. The Company analyzes the performance of its
operating segments based on their gross margin, which is defined as revenue,
less operating expenses.
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
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
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 6 months ended June 30:
2008
$
---------------
Additions to operating plants above 401
Additions to property, plant and equipment relating to
construction-in-progress and
general corporate assets 140,462
---------------
Total additions to property, plant, and equipment 140,863
---------------
Net book value of operating plants 575,937
Net book value of property, plant and equipment relating to
construction-in-progress
and general corporate assets 442,663
---------------
Total net book value of property, plant, and equipment 1,018,600
---------------
---------------
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, 2008, the Company
has committed approximately $175,972,000 for goods and services for Melancthon
II, Wolfe Island, Royal Road, and the B.C. Hydro projects, which will be
expended between 2008 and 2012.
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 June 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. The Company is currently amending
the Lease to extend this date. The repairs are estimated to cost $4,000,000, of
which $1,399,000 has been spent as at June 30, 2008. 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 our original hydroelectric plants to a company
controlled by the President who is also a director. During the six months ended
June 30, 2008, royalties totaling $28,000 (2007 - $24,000) were incurred.
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