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Site C Clean Energy Project
Rebuttal Evidence
With Respect to the Submissions of Clean Energy Association of British Columbia
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page i
Table of Contents
1 Introduction ........................................................................................................ 1 2 Cost of Capital and IPP Risk Assumptions ......................................................... 3
1.1 Cost of Capital .......................................................................................... 3 1.2 IPP Risk Assumptions ............................................................................... 6
3 Financial Evaluation Periods .............................................................................. 8 4 Wind Turbine Costs .......................................................................................... 10 5 Cost of Supporting Intermittent Run-of-River and Wind ................................... 11 6 Construction Inflation and Project Cost Estimate ............................................. 14
List of Appendices
Appendix A Copy of Manulife Financial Slide Presentation
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 1
1 Introduction 1
On 25 November 2013 Clean Energy Association of British Columbia (CEABC) filed a 2
written submission entitled “Submission to the Site C Joint Review Panel” (CEABC 3
Submission) on the topic of Independent Power Producer (IPP) alternatives to the Site 4
C Clean Energy Project (Project).1 Mr. Kariya, Executive Director of CEABC made an 5
oral presentation on 10 December 2013 which largely summarized the CEABC 6
Submission, although the accompanying slides included some new evidence.2 By letter 7
dated 3 December 2013,3 BC Hydro sought leave pursuant to section 5.10 of the Public 8
Hearing Procedures to file written rebuttal evidence to the CEABC Submission. 9
BC Hydro provides the following Rebuttal Evidence pursuant to counsel for the Joint 10
Review Panel’s (JRP) e-mail dated 6 December 2013 conveying that the JRP had 11
acceded to BC Hydro’s request.4 12
CEABC’s essential contention is that clean or renewable IPP energy projects are lower 13
cost than the Project. The CEABC Submission at page 1 quotes a cost of 14
$3,000-4,000 per kilowatt (/kW) versus over $7,000/kW for the Project. The 15
representation of costs and the rationales for those costs is inappropriate. CEABC 16
compares installed costs per kW for resources with essentially no dependable capacity 17
to resources with dependable capacity, and concludes that IPP clean or renewable 18
resources are cost-effective by evaluating them on an installed (nameplate) capacity5 19
basis. The installed capacity of intermittent clean or renewable resources such as 20
run-of-river and wind is significantly higher than the amount of dependable capacity 21
such resources can actually provide. For example, BC Hydro currently has contracts 22
(called Electricity Purchase Agreements or EPAs) for run-of-river projects which have 23
1 Canadian Environmental Assessment Agency Registry Number (CEAR) #1782. 2 A copy of the slides is found at CEAR #2092; for example, the slides contained new evidence on Demand Side
Management. 3 Letter of Mr. Feldberg, Fasken Martineau, page 7; CEAR #2006. 4 CEAR #2023. 5 Installed or nameplate capacity is the maximum rating of generator equipment identified by the manufacturer
under specified conditions. Dependable capacity is the amount of megawatts a generator can reliably produce when required, assuming all units are in service. Factors external to a generator affect its dependable capacity. For example, for run-of-river resources with no storage, streamflow conditions can restrict the dependable capacity.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 2
an installed capacity of 2,200 megawatts (MW) but which are expected to deliver about 1
200 MW of capacity BC Hydro can rely on.6 2
The appropriate comparison is on an energy basis as shown in the Unit Energy Cost 3
(UEC) Block Analysis in Tables 14-16 in the Evidentiary Update.7 Overall, BC Hydro 4
has emphasized that the primary approach to evaluation of resource cost-effectiveness 5
is through the System Optimizer Present Value (PV) Portfolio modelling analysis 6
because among other things it captures most of the economical dispatch value (for 7
dispatchable resources such as the Project or natural gas-fired generation) which 8
provides value to BC Hydro’s customers and is a point of differentiation of the Project 9
from intermittent clean or renewable resources such as wind and run-of-river. 10
CEABC also points to various cost, evaluation and risk factors that it claims have been 11
misrepresented. However, the arguments for the claims are in large part based on one 12
IPP project and the CEABC Submission discussion of risk allocation is inconsistent with 13
CEABC’s argument concerning project financing costs. 14
The remainder of BC Hydro’s Rebuttal Evidence is organized to follow the structure of 15
the CEABC Submission as follows: 16
• Part 2 provides BC Hydro’s response to CEABC’s assertions in section 1 of the 17
CEABC Submission that IPPs have the same or similar cost of capital as 18
BC Hydro, and the transfer of risk to IPPs; 19
• Part 3 addresses CEABC’s contentions in section 2 of the CEABC Submission 20
concerning the financial evaluation periods of the Project and IPP alternatives; 21
• Part 4 sets out BC Hydro’s reply to the wind turbine cost comments contained in 22
section 3 of the CEABC Submission; 23
• Part 5 contains BC Hydro’s response to CEABC Submission section 4 regarding 24
the cost of supporting intermittent IPP run-of-river and wind resources; and 25
6 The 200 MW figure is based on the Effective Load Carrying Capability (ELCC), which as described in
section 5.2.1.2 of the Environmental Impact Statement (EIS) is used by BC Hydro to represent the capacity contribution of intermittent clean or renewable IPP resources such as wind and run-of-river during winter peak events. The ELCC method may overstate the capacity contribution of these intermittent clean or renewable resources on their own.
7 CEAR #1574.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 3
• Part 6 concludes this Rebuttal Evidence by addressing section 5 of the CEABC 1
Submission, which pertains to the Project cost estimate. 2
2 Cost of Capital and IPP Risk Assumptions 3
2.1 Cost of Capital 4
CEABC contends that IPPs have the same or similar cost of capital as BC Hydro and 5
suggests that the following financial assumptions should be used to evaluate IPP 6
projects: 7
• 4.45% 40 year debt issuance; 8
• 10-15% before tax Return on Equity (ROE); 9
• 80% or better debt; and 10
• 5-6% real pre-tax Weighted Average Cost of Capital (WACC). 11
The financial assumptions proposed by CEABC were derived from a single run-of-river 12
project example, Kwagis Power Limited Partnership’s8 Kokish Run-of-River project 13
(KPL Project), with a firm energy output of about 180 gigawatt hours (GWh) per year. 14
In response to the JRP’s request for a report or letter on the WACC for IPP capital 15
projects, CEABC in Undertaking #129 provided additional investor presentation material 16
from the KPL Project. BC Hydro’s concern with the CEABC submissions is twofold: 17
1) the selected project is not representative of British Columbia’s (B.C.) IPP industry as 18
a whole; and 2) the recent transaction is not reflective of what BC Hydro can expect 19
from IPP bids over the next 20-30 years. 20
In this section of the Rebuttal Evidence BC Hydro reviews the debt costs, equity costs 21
and the overall project cost assessment. 22
8 Kwagis Power Limited Partnership is a limited partnership between Brookfield Renewable Power (Brookfield) and
Namgis First Nation. 9 CEAR #2202.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 4
Debt Costs 1
The 4.45% debt for the KPL project was rated A (low) by Dominion Bond Rating Service 2
(DBRS) at the time of issue through a private placement in October 2012. To compare, 3
BC Hydro completed AAA priced debt issues at 3.25% for 30 years during the same 4
time period. The low recent financing costs for both Brookfield and BC Hydro are not the 5
basis on which BC Hydro undertook the Portfolio PV modelling analysis. The 5% real 6
WACC for BC Hydro and 7% real WACC for IPPs are based on an economic outlook of 7
available financing over the next 20-30 years. The debt rates available over the past 18 8
months are unlikely to be available over the longer term. As shown in BC Hydro’s 9
response to JRP Information Request (IR) 27B,10 BC Hydro would expect its longer 10
term debt costs to be in the order of 4.8% which is above BC Hydro’s current debt 11
costs. 12
While BC Hydro is anticipating debt costs will rise in the future, it still expects that the 13
cost differential between BC Hydro debt and developer debt will remain at current 14
levels. Further, based on past experience with acquisition processes, rating agencies 15
and investor firms, BC Hydro does not accept the KPL Project’s debt rating of A (low) as 16
being representative of the IPP industry in general. Without examining the loan 17
documentation of the KPL Project, it is difficult to comment on exactly what factors 18
contributed to the KPL Project achieving a higher debt rating from DBRS than other 19
typical IPP transactions. BC Hydro’s expects that the typical IPP transaction would be 20
structured to achieve a BBB debt rating and be priced approximately 200 basis points 21
higher than BC Hydro’s AAA priced cost of debt. 22
A Manulife Financial presentation “Financing Renewable Power” presented at the 23
24 February 2012 Hatch Renewable Power Symposium provides their perspective of 24
renewable project financing. On Slide 20, the project pricing is given as a 300 to 25
350 basis point spread above Government of Canada bond yields. BC Hydro’s debt is 26
priced typically at a premium of 75 basis points compared to Government of Canada 27
debt. Hence, the difference between IPP project debt and BC Hydro’s debt cost would 28
10 CEAR #1624.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 5
be in the range of 225-275 basis points. A copy of the Manulife Financial presentation 1
slides is found at Attachment A to this Rebuttal Evidence. 2
CEABC points out that the recent change in BC Hydro’s WACC is an indication of 3
another risk that BC Hydro faces over the life of the Project. While financing costs can 4
change over the life of the project, BC Hydro has the same ability to issue long-term 5
debt as projects are built. However, this does demonstrate another reason why IPP debt 6
costs are frequently higher than BC Hydro’s cost. At the time of bidding their projects 7
into acquisition processes, the majority of IPPs have not completed their financing. The 8
IPP would be expected to price in a conservative margin on its anticipated debt costs to 9
ensure that they can deliver the project profitably. Further, once actual financing costs 10
are known after EPA awards by BC Hydro and all approvals have been obtained, the 11
debt costs may be lower than the bid values, but there is no mechanism to allow 12
ratepayers to benefit from the lower cost. Rather, this becomes an additional margin for 13
the developer. 14
Equity Costs 15
In terms of equity costs, it is BC Hydro’s experience that IPPs anticipate a higher return 16
on equity than public utilities which is attributed to the risks that the IPPs absorb. 17
BC Hydro identified in the 2006 Integrated Electricity Plan/Long-Term Acquisition Plan 18
(LTAP) proceeding before the British Columbia Utilities Commission that expected 19
returns to IPPs were 12-15% after-tax ROE. Similarly, in the 21 June 2012 “Analysis of 20
Electricity Purchase Agreement Terms” undertaken for BC Hydro by Navigant 21
Consultants, page 20 shows that the economic modelling was done based upon a 13% 22
after-tax equity Internal Rate of Return.11 The Navigant work was done in consultation 23
with CEABC and IPP representatives. This is substantially different than the 10-15% 24
before-tax ROE asserted by CEABC. 25
11 Document located on BC Hydro’s website at
https://www.bchydro.com/content/dam/hydro/medialib/internet/documents/planning_regulatory/acquiring_power/2012q3/navigant_financial_analysis.pdf.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 6
WACC 1
The WACC for a particular IPP is a function of the debt to equity ratio that can be 2
achieved together with the debt cost and ROE. While merchant generation will 3
frequently be seen with a 60/40 debt to equity ratio, it is likely that with a utility backed 4
contract that IPPs would be able to leverage their projects to a greater extent. For 5
BC Hydro, a 70/30 debt to equity ratio is assumed to be in-line with other similar utilities. 6
BC Hydro does expect that a certain subset of IPPs will be capable of achieving 7
increased leverage ratios as high as 80/20 debt to equity ratio. However, BC Hydro also 8
expects that any increase in leverage would have a corresponding increase in cost such 9
as more expensive debt pricing, insurance premiums and guarantees. 10
Depending upon the assumptions made, the WACC for the ‘typical’ IPP could be in the 11
range of 1-2% or up to 4% higher than BC Hydro. In the analysis, BC Hydro assumed a 12
2% differential. BC Hydro undertook a sensitivity analysis using a 1% cost of capital 13
differential between BC Hydro and IPPs. Please refer to section 4.2 of the Evidentiary 14
Update. 15
It is a difficult task to assess the costs of IPP development as suppliers are unwilling to 16
share commercially sensitive information. As a result, BC Hydro has in the past 17
compared its Resource Options Report (ROR) resource characterization and financial 18
assumptions with the results of the most recent broadly-based clean or renewable 19
power acquisition process. The last assessment that was undertaken as part of the 20
2008 LTAP concluded that a block of 5,000 GWh of IPP projects would be about 21
$124/MWh ($F2008, or $129/MWh in $F2010 using a 2.1% Consumer Price Index 22
escalation) adjusted to the Lower Mainland. The actual results of the 2009 Clean Power 23
Call were a weighted-average adjusted firm energy price of $124.3/MWh ($F2010). 24
BC Hydro believes its assessment of resource costs are a reasonable basis on which to 25
undertaken portfolio analysis. 26
2.2 IPP Risk Assumptions 27
The CEABC Submission at page 2 contends that BC Hydro’s cost of capital assessment 28
does not factor in the differences in risk allocation between IPP EPAs and the Project, 29
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 7
and that “[l]enders assess these risks and the terms of borrowing including interest rate 1
and the allowable debt to equity ratio are adjusted accordingly”. BC Hydro finds this 2
view of risk allocation inconsistent with CEABC’s declaration on page 1 of its 3
submission that “[t]he cost of BCH and IPP capital are the same”. If IPPs were taking on 4
significant risks in project development, then their costs of financing would need to 5
reflect this. It is BC Hydro’s view that IPPs take on some but not all of the project risks, 6
and that debt costs reflect both the project to be delivered with associated risks and the 7
proponent’s overall reputation as a project developer. 8
Typical risks transferred to IPPs through EPAs are development (including project 9
delays), financing costs, operating costs and anticipated First Nations and community 10
costs. However, BC Hydro pays for this risk transfer through a premium included by 11
IPPs in their pricing to account for the risks that they are assuming. BC Hydro bears the 12
cost of that premium regardless of whether or not the risk factors materialize. BC Hydro 13
expects that IPPs will have included within their bid prices and project development 14
contingency factors to ensure that they can deliver their product and receive a fair return 15
for the risks absorbed. There is no mechanism to reclaim those premiums should the 16
risks not materialize. It must also be recognized that BC Hydro included appropriate 17
contingencies in the Project cost estimate to accommodate the known and unknown 18
cost risks of the Project; refer to Part 6 below. 19
BC Hydro worked to support the development of the Clean Energy sector in accordance 20
with the Clean Energy Act12 British Columbia’s energy objectives 2(i) [encourage 21
communities to reduce greenhouse gas emissions], 2(j) [encourage the use of 22
biomass], 2(k) [foster the development of First Nations communities through 23
development of clean or renewable resources] and 2(l) [encourage economic 24
development]. In addition, as clean energy projects are developed, they involve First 25
Nations and communities, provide economic benefits and once they have progressed to 26
EPA award, there are significant pressures and expectations that the projects proceed. 27
These expectations result in less risk transfer than might be anticipated. 28
12 S.B.C 2010, c.22.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 8
While BC Hydro assumes that IPP developers have taken into account their costs and 1
perceived risks in coming up with their bid prices, BC Hydro does not accept that bid 2
prices can be categorized as ‘all in’ prices for the following reasons: 3
• IPP projects are subject to attrition, with EPAs being terminated for various 4
reasons such as unexpected cost increases, financing obstacles and permitting 5
difficulties. BC Hydro makes an allowance for attrition by awarding a greater 6
number of EPAs than are required and must absorb the risk of more or less 7
projects completing and delivering energy. For the F2006 Call for Tenders 8
(F2006 Call) and the 2009 Clean Power Call, a 30% attrition factor was assumed. 9
The current attrition rate is approximately 55% for the F2006 Call (excluding the 10
two coal-fired projects) and approximately 35% for the 2009 Clean Power Call; and 11
• IPPs periodically request EPA amendments after power acquisition processes 12
have been completed, including uplifts to EPA energy prices and delays in the 13
Commercial Operating Date. 14
Both the attrition rate and the request for EPA amendments show that IPPs have 15
experienced unanticipated development cost increases and project delays, indicating 16
that in fact not all costs and/or risks have been captured in IPP bids. What appears to 17
be at risk is the development work; however, if project costs, permits, First Nations or 18
community costs or financing costs become uneconomic for the developer, they will 19
either seek EPA amendments or stop developing the project. There is significant risk 20
remaining with BC Hydro with respect to delivering electricity to customers. 21
3 Financial Evaluation Periods 22
The CEABC Submission at page 3 advances that BC Hydro should not use the average 23
length of IPP EPAs for the financial evaluation period of IPP resources. CEABC 24
maintains that the economic life of the technology itself should be used. Nevertheless, 25
CEABC concludes that if BC Hydro were willing to accept longer-term contracts, EPA 26
terms would “promptly increase to the 40 to 70 years level depending on the project, 27
essentially project life, and levelized costs would fall proportionately”. 28
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 9
CEABC’s comments on IPP financial evaluation periods focus almost exclusively on 1
run-of-river IPP resources. For example, at page 3 CEABC maintains that “IPP 2
hydroelectric projects last as long as those built by [BC Hydro] …”. Further, at page 4 3
CEABC discusses the maximum 40-year term for Conditional Water Licences, a B.C. 4
government agency approval required for run-of-river resources but not for other IPP 5
resources such as wind and biomass. 6
The Project is expected to have a life of more than 100 years; however, for the EIS 7
economic evaluation an economic planning life of 70 years is used. Section 5.5.2 of the 8
EIS sets out the economic life for three resources - wind (20 years), run-of-river 9
(40 years due to Water License maximum terms) and bioenergy resources (10-25 years 10
due to fuel supply uncertainty and economic life) - which have been bid into BC Hydro 11
power acquisition processes and some of which make up the clean or renewable 12
energy resources in the Portfolio PV modelling analysis.13 13
As set out in Table 14 of the Evidentiary Update, the Clean Generation Block is 14
composed mainly of wind resources – about 94% – as they were largely the lowest cost 15
energy resources in the portfolios. Similarly, the Clean Generation Portfolio modelled 16
with System Optimizer has about 95% wind resources for the first 5,000 GWh. In 17
contrast, no run-of-river resources were picked up in the Block Analysis for the Clean 18
Energy Block or in the Portfolio PV modelling analysis for the Clean Energy Generation 19
portfolio for the first 5,000 GWh. 20
BC Hydro’s 2010 ROR found that the expected life of wind projects is about 20 to 21
25 years; refer to section 5.5.2.2 of the EIS. As noted in section 5.4.1.1 of the EIS, the 22
IPP community had input into the development of the 2010 ROR, including through a 23
wind-specific engagement process. The findings of the 2010 ROR align with BC Hydro’s 24
experience in the F2006 Call and 2009 Clean Power Call: 25
13 BC Hydro’s Clean Generation Block and Clean + Thermal Generation Blocks include only wind and municipal
solid waste resource options.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 10
• The three successful wind projects in BC Hydro’s F2006 Call bid in contract terms 1
of between 20 to 25 years, although they had the option of bidding up to 2
40 years;14 3
• The six successful wind projects in BC Hydro’s Clean Power Call bid in contract 4
terms of between 20 to 25 years, although they had the option of bidding up to 5
40 years.15 6
Though of lesser significance because biomass makes up a smaller portion of the 7
Blocks and Portfolio PV modelling, BC Hydro notes that for its two recent biomass 8
power acquisition processes – the Bioenergy Call Phase I Request for Proposals (RFP) 9
and the Bioenergy Call Phase II RFP – proponents were permitted to select an EPA 10
term of between five to 30 years.16 These EPA terms reflect the fact that excess wood 11
fibre originating from the mountain pine beetle epidemic was available during the 12
2009-2012 timeframe of the two biomass RFPs, but will decline significantly through the 13
end of the next decade. The maximum 30 year biomass EPA term is also consistent 14
with the expected life of a thermal-based facility. 15
4 Wind Turbine Costs 16
The CEABC Submission at page 4 argues that BC Hydro’s 15% reduction of wind 17
turbine prices from the original assumption used in the 2010 ROR for purposes of both 18
the EIS and the November 2013 Integrated Resource Plan (IRP) should probably be 19
further reduced to reflect the drop in wind turbine prices of about 20% to 30% that 20
occurred between the peak of wind turbine prices in 2009 and January 2013. 21
As noted in section 5.4.1.2 of the EIS, the decline in wind turbine prices since 2009 22
coincided with the downturn in the global economic situation, signaling a shift from a 23
seller’s market to a buyer’s market. Current wind turbine prices are forecasted to persist 24
14 Bear Mountain Wind Park – 25-year EPA term; Mount Hays Wind Farm– 25-year EPA term; Dokie Wind Project –
20-year EPA term. 15 Four Finavera wind projects (Bullmoose, Meikle, Tumbler Ridge and Wildmare) – each with a 25-year EPA term;
Quality Wind Project – 25-year EPA term; and Knob Hill Wind – 20-year EPA term. 16 The maximum term under the Bioenergy Call Phase I RFP was 20 years; the maximum term under the Bioenergy
Phase II RFP was 30 years. One of the two Bioenergy Phase II RFP successful proponents, Pratt & Whitney Power Systems on behalf of West Fraser Timber Company, opted for a 20-year EPA term even though it had the option to bidding in a 30-year EPA term.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 11
through 2015, but it is uncertain if turbine prices will remain low in the long-term. While 1
improved efficiencies in the manufacturing process, continued technical advancements 2
and potential competition from Chinese turbine manufacturers may help keep turbine 3
prices low in the future, it is noted that wind technology is becoming a mature 4
technology and a resurgence in wind turbine demand, resulting in supply chain 5
pressures similar to those observed between 2004 and 2009, could counter the cost 6
reductions and increase wind turbine prices. BC Hydro’s 15% wind turbine price 7
reduction was made in light of these uncertainties and based on discussions with 8
manufacturers. 9
BC Hydro notes that while turbines are the largest cost component of wind resources, 10
there is no evidence of a reduction in the cost of land and transmission required for wind 11
resources; increases in such costs may partially offset the gains in turbine costs. In 12
other words, the percentage change in wind turbine costs alone does not create the 13
same percentage change in the overall cost of a wind project. 14
5 Cost of Supporting Intermittent Run-of-River and Wind 15
Intermittent resources such as wind and run-of-river provide little dependable capacity. 16
Indeed, the 2009 Clean Power Call resulted in the award of 25 EPAs for 17
3,266 GWh/year of firm energy from largely wind and run-of-river resources with only 18
9 MW of dependable capacity. 19
The CEABC Submission raises two points concerning natural gas-fired generation as a 20
source of required backup capacity for IPP run-of-river and wind resources. First, at 21
pages 5 and 6 CEABC speculates the Clean Energy Act’s 93% clean or renewable 22
objective may be changed sometime in the future, and points to the British Columbia’s 23
Energy Objective Regulation17 as a possible basis for this conjecture. The British 24
Columbia’s Energy Objective Regulation modifies the 93% clean or renewable objective 25
by providing that electricity to serve liquefied natural gas (LNG) demand is not included 26
in the 93% clean or renewable objective. BC Hydro draws the opposite inference – the 27
B.C. Government treats the 93% clean or renewable objective as a hard constraint, and 28
17 B.C. Reg. 234/2012.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 12
therefore saw the need to specifically carve out LNG demand from the constraint. This 1
planning assumption was confirmed with the approval of the November 2013 IRP on 2
26 November 2013. This matter will be further addressed in the written closing comment 3
phase of the public hearing. 4
Second, CEABC questions BC Hydro’s treatment of existing natural gas-fired 5
generation facilities in its system as part of BC Hydro’s estimate of the space available 6
for developing new natural gas-fired generation. CEABC reproduces Table 5.33 of the 7
EIS and makes two arguments: 8
1. EPAs for the two largest existing natural gas-fired generation facilities18 – the 9
120 MW McMahon Cogeneration Plant and the 275 MW Island Generation Plant 10
(ICG) – are set to expire on or before 2023, and if the EPAs are not renewed the 11
amount of space for developing new natural gas-fired generation will increase. 12
Consistent with section 9.2.4.2 of the November 2013 IRP,19 BC Hydro exercised 13
its option to extend the EPA term beyond 2023 for McMahon Cogeneration Plant. 14
BC Hydro conservatively assumed that all non-run-of-river and non-biomass EPAs 15
will be renewed,20 including the ICG EPA, and incorporated those renewals into 16
the resource stack prior to determining the need for the Project; 17
2. ICG can be dispatched, and therefore BC Hydro should not treat ICG in its stack as 18
a base-load facility even though ICG is a Combined Cycle Gas Turbine facility 19
(CCGT), so that the amount of existing natural gas-fired generation can be reduced 20
and thus the space available for developing new natural gas-fired generation 21
increased. BC Hydro’s treatment of ICG as a base-load CCGT is not new; 22
BC Hydro has treated ICG in this manner in its resource stack since it was 23
commissioned in 2002. Furthermore, CEABC’s reference to CCGTs in other 24
jurisdictions has little relevance to BC Hydro’s situation. BC Hydro develops plans 25
18 The other two existing natural gas-fired facilities are Fort Nelson Generating Station and the small Prince Rupert
Generating Station; refer to section 5.5.2.8, page 5-54 of the EIS. 19 A copy of the November 2013 IRP is found at CEAR #2101. 20 As set out in section 2.1.1 of the Evidentiary Update (CEAR #1574), for planning purposes BC Hydro assumes
that approximately 50% of bioenergy EPAs will be renewed, about 75% of the run-of-river EPAs that are up for renewal in the next five years are renewed, and the renewal of all other EPAs. These EPA renewal planning assumptions results in about 4,700 GWh/year of firm energy in F2024 and about 6,400 GWh/year of firm energy in F2033.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 13
to meet its customer’s load requirements from a variety of sources and the only 1
reason ICG would not be required to run is if the market is available and economic 2
to displace it. Consistent with section 6.2.2 of the November 2013 IRP, BC Hydro 3
is planning on ICG to operate at a 90% capacity factor if needed and still be able to 4
meet the Clean Energy Act 93% clean or renewable objective. 5
At page 7, the CEABC Submission appears to question the use of average water 6
conditions for the Project and other BC Hydro Heritage hydroelectric resources, and 7
critical water conditions for IPP resources. As explained in section 5.2.1.2 of the EIS 8
and expanded upon in section 1.2.2.1 of the November 2013 IRP, for BC Hydro’s 9
Heritage hydroelectric resources, which include the Project if the Project proceeds,21 10
section 3 of the B.C. Electricity Self-Sufficiency Regulation22 requires that BC Hydro 11
achieve self-sufficiency by 2016 and each year after that assuming that the Heritage 12
hydroelectric resources are capable of producing no more than they can produce under 13
“average water conditions”. In addition, subsections 1(1) and 1(2) of Amended Special 14
Direction No. 10 to the British Columbia Utilities Commission23 mandate that BC Hydro 15
use the average water capability of its Heritage hydroelectric resources for assessing 16
the needs of new resources. However, these two regulations are silent with respect to 17
the treatment of IPP energy output and accordingly BC Hydro uses its energy planning 18
criterion, which is described in detail in section 1.2.2 of the November 2013 IRP and is 19
summarized here. 20
Contrary to the CEABC Submission, “critical water conditions” are not used for all “IPP 21
assets”, and in particular are not used for wind resources. For IPPs, energy reliance is 22
determined by the application of self-sufficiency and firm energy requirements as 23
follows: 24
• For IPP wind resources, BC Hydro has relied upon average energy production for 25
firm energy contribution since the annual variability measured to date is much 26
lower than and appears to be independent of hydro inflows; 27
21 As a result of the definition of “heritage assets” set out in section 1, and Schedule 1, of the Clean Energy Act,
supra, note 12. 22 B.C. Reg. 315/2010 as amended by B.C. Reg. 16/2012. 23 B.C. Reg. 245/2006, as amended by B.C. Reg. 17/2012.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 14
• For thermal projects under contract to BC Hydro through EPAs, contractual firm 1
energy commitments (where available) are relied upon for firm energy contributions 2
since such EPAs would not typically contain significant non-firm energy due to 3
higher fuel certainty. For thermal projects that do not have contractual firm 4
commitments, their average energy production is relied upon for firm energy 5
contribution; 6
• It is only for IPP hydroelectric resources that BC Hydro uses an assessment of the 7
firm energy contribution to the system under critical water conditions (the most 8
adverse sequence of stream flows occurring within the 60-year period between 9
October 1940 and September 2000). With the degree of market back-up 10
established in the Heritage hydro reliance and further restricted by the 11
self-sufficiency requirement, IPP non-firm energy does not meet BC Hydro's 12
energy planning criterion and is not relied on to meet customer demand. In the 13
energy load-resource balances in Part 2 of the Evidentiary Update and section 5.2 14
of the EIS, BC Hydro’s assessment of firm energy contributions from IPPs is 15
calculated using the Heritage hydroelectric system for back-up. Therefore, to treat 16
the IPP run-of-river non-firm energy as firm energy BC Hydro would need to rely on 17
market purchases which would not meet the definition of self-sufficiency set out in 18
subsection 6(2) of the Clean Energy Act. 19
6 Construction Inflation and Project Cost Estimate 20
CEABC references “media reports” at page 7 of the CEABC Submission to advance 21
arguments concerning the scale of potential LNG development in B.C., and to argue 22
that the Project has greater exposure to civil construction and engineering work force 23
competition than wind IPPs, which CEABC states has a “lower risk because the turbines 24
and towers which generally account for about 60% of a project are manufactured 25
outside of” B.C. CEABC also makes some comments concerning natural gas-fired 26
generating resources such as CCGTs and Simple Cycle Gas Turbines (SCGTs). 27
BC Hydro agrees that wind projects have a different risk profile than does the Project. 28
Wind projects are less exposed to the B.C. construction market. However, this does not 29
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 15
necessarily mean that wind projects have a lower risk of cost overruns; for example, 1
wind projects are more exposed to the global demand for wind power. Natural gas-fired 2
generating resources are more similar to LNG export terminals (e.g., requirements for 3
tanks, piping, high precision machining for compressors, pipefitting/steam fitting, and so 4
on) than they are to the Project, and therefore would likely face the same sort of cost 5
pressures as LNG export terminals. 6
BC Hydro has set out the steps underpinning the Project cost estimate preparation in 7
the EIS, Volume 1, Appendix F, Part 1,24 the 4 June 2013 “Technical Memo: Project 8
Costs”25 and BC Hydro’s response to JRP IR 77-A.26 The Project cost estimate 9
incorporates knowledge gained from work implemented at other BC Hydro facilities, and 10
appropriate contingencies to accommodate the known and unknown cost risks of the 11
Project. The risk that the Project cost estimate will prove to be incorrect has been 12
reduced through: 13
• Clearly defining the scope of Project including a detailed cost analysis. The 14
construction costs were prepared by estimators with significant recent experience 15
in the construction of hydro-electric generation facilities. As a result, the cost 16
estimate is a Class 3 according to the definition of the Association for the 17
Advancement of Cost Engineering. The level of project definition for many of the 18
major components of the Project exceeds the guidelines for a Class 3 estimate of 19
10-40% definition; 20
• Using reasonably conservative assumptions for market conditions and design 21
assumptions. BC Hydro assumptions regarding commodity prices, labour prices, 22
and other major cost drivers were made based on conservative values rather than 23
expected market conditions. In addition, when there was uncertainty regarding 24
design assumptions BC Hydro provided costs based on the design option which 25
would result in the highest project cost; 26
24 CEAR #421. 25 CEAR #1459. 26 CEAR #1645.
Rebuttal Evidence With Respect to the Submissions of
Clean Energy Association of British Columbia
Site C Clean Energy Project
Page 16
• Undertaking a Monte Carlo analysis of Project capital costs as part of validation 1
work on the Project cost estimate. Based on this analysis, the Project cost estimate 2
would be between a P70 and a P75;27 3
• Including contingency of $730 million in real dollars, which is 18% of direct 4
construction costs. The contingency was estimated using a Monte Carlo analysis 5
for each work package, based on how well the scope/schedule was defined for 6
each work package as well as uncertainty in market conditions; 7
• Retaining a third party expert, KPMG, to provide a due diligence review of the 8
Project cost estimate. KPMG concluded that the methodologies and assumptions 9
used in the Project cost estimate were appropriate. 10
BC Hydro reviewed a total of 774 capital projects (over $1 million) completed by 11
BC Hydro in the last five years. The result is a cost of $11 million over the original 12
expected of $3.3 billion, or within 0.34% of original expected amount. Of these projects, 13
63% were completed for costs less than the expected amount.28 14
27 Draft Transcript, Volume 4, 12 December 2013, page 108, lines 19-25 (uncertified version). 28 Draft Transcript, Volume 4, 12 December 2013, page 106, lines 13-18 (uncertified version).
Site C Clean Energy Project
Rebuttal Evidence
With Respect to the Submissions of Clean Energy Association of British Columbia
Appendix A
Copy of Manulife Financial Slide Presentation
DIV
ISIO
N
Hat
ch R
enew
able
Pow
er S
ympo
sium
Fina
ncin
g Re
new
able
Pow
er
Febr
uary
24,
201
2
Rich
ard
Lee,
Man
agin
g D
irect
or –
Pro
ject
Fin
ance
INV
ES
TM
EN
T D
IVIS
ION
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 1 of 22
DIV
ISIO
N
Pres
enta
tion
Topi
cs:
2 INV
ES
TM
EN
T D
IVIS
ION
Pr
ojec
t Fin
ance
101
Pr
ofile
: Man
ulife
Fin
anci
al a
nd P
roje
ct F
inan
ce G
roup
Pr
icin
g an
d Tr
ansa
ctio
n Si
ze G
uide
lines
Q
uest
ions
& A
nsw
ers
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 2 of 22
DIV
ISIO
N
Proj
ect F
inan
ce 1
01
3
INV
ES
TM
EN
T D
IVIS
ION
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 3 of 22
DIV
ISIO
N
Proj
ect F
inan
ce D
efin
ed
4 INV
ES
TM
EN
T D
IVIS
ION
Pr
ojec
t fin
anci
ng is
a w
ay to
fina
nce
long
term
infr
astr
uctu
re p
roje
cts
(lega
lly a
nd e
cono
mic
ally
) ba
sed
on r
elia
bilit
y of
futu
re c
ash
flow
s as
opp
osed
to
the
bala
nce
shee
t of
the
Spon
sor.
It
is d
epen
dent
on:
•Th
e ab
ility
of t
he s
pons
ors
to c
onst
ruct
the
Pro
ject
on
time
and
on b
udge
t;
•Th
e ab
ility
of t
he P
roje
ct t
o op
erat
e at
out
put a
nd e
ffic
ienc
y le
vels
as
proj
ecte
d;
•Th
e st
reng
th a
nd in
tegr
ity o
f con
trac
ts a
nd a
bilit
y of
cou
nter
part
ies
to m
eet
oblig
atio
ns
unde
r the
con
trac
ts; a
nd
•Th
e ab
ility
to w
ithst
and
reso
urce
inpu
t, o
pera
ting
and
econ
omic
ris
ks.
Li
mite
d or
non
-rec
ours
e to
spo
nsor
s
•Le
nder
s’ o
nly
reco
urse
(in
the
even
t of d
efau
lt an
d re
aliz
atio
n) is
to ta
ke o
ver
the
Proj
ect.
•Le
nder
s re
ly o
n fu
ture
pro
ject
cas
h flo
w fo
r de
bt s
ervi
ce
Pr
ojec
t as
sets
typi
cally
hav
e lit
tle v
alue
exc
ept a
s on
-goi
ng b
usin
ess
with
con
trac
ts in
tact
.
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 4 of 22
DIV
ISIO
N
Proj
ect F
inan
cing
vs.
Cor
pora
te F
inan
cing
5 INV
ES
TM
EN
T D
IVIS
ION
Pr
ojec
t Fin
anci
ng:
•Non
-rec
ours
e to
Spo
nsor
•Mar
ket c
an p
rovi
de 2
0+ y
ear
term
•No
refin
anci
ng ri
sk
•75
to 8
5% d
ebt l
ever
age
•15
to 2
5% o
wne
rs e
quity
•Lon
g te
rm c
apita
l mar
ket
in C
anad
a is
re
lativ
ely
thin
•Hig
her c
ost t
han
issu
ing
corp
orat
e bo
nds
Corp
orat
e Fi
nanc
ing:
•Diff
icul
t to
acce
ss p
ublic
bon
d m
arke
t on
a
sing
le p
roje
ct b
asis
•Mar
ket o
nly
avai
labl
e to
larg
e co
rpor
ate
issu
ers •But
less
cos
tly to
com
pani
es th
at
do h
ave
acce
ss
•Sec
onda
ry m
arke
t liq
uidi
ty fu
rthe
r re
duce
s in
tere
st c
ost
•Les
s on
erou
s do
cum
enta
tion
and
due
dilig
ence
than
pro
ject
fina
ncin
g
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 5 of 22
DIV
ISIO
N
Typi
cal O
wne
rshi
p an
d Fi
nanc
ing
Stru
ctur
e
6 INV
ES
TM
EN
T D
IVIS
ION
Spon
sor(
s)
Borr
ower
- (S
peci
al P
urpo
se
Vehi
cle,
usu
ally
an
LP)
Phys
ical
Fac
ility
•Po
wer
Pur
chas
e A
gree
men
t w
ith p
rovi
ncia
l util
ity
•Co
nstr
uctio
n /
Equi
pmen
t Su
pply
Con
trac
t(s)
•La
nd le
ases
, lic
ense
s, r
ight
of
way
agr
eem
ents
•O
ther
mat
eria
l agr
eem
ents
•In
sura
nce
•Pr
ojec
t ban
k ac
coun
ts
•Pe
rmits
, lic
ense
s an
d ot
her
appr
oval
s
•O
ther
pro
ject
ass
ets
Loan
(7
5% to
85%
of
tota
l ca
pita
l cos
t)
Oth
er P
roje
ct
Ass
ets
Equi
ty
Key
Proj
ect
Agr
eem
ents
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 6 of 22
DIV
ISIO
N
7
Lend
ers’
Sec
urity
Le
nder
s’ s
ecur
ity g
ener
ally
con
sist
s of
100
% o
f the
ass
ets
of th
e Bo
rrow
er p
lus
a pl
edge
by
the
Spon
sor
of th
e sh
ares
/par
tner
ship
uni
ts in
Bor
row
er.
St
ruct
ure
is ri
ng fe
nced
and
is b
ankr
uptc
y re
mot
e, t
here
by m
akin
g it
easi
er in
the
even
t th
e Le
nder
s ar
e ev
er r
equi
red
to “
step
in”.
•Bo
rrow
er is
spe
cial
pur
pose
ent
ity a
nd c
anno
t eng
age
in a
bus
ines
s ot
her
than
bui
ldin
g an
d op
erat
ing
the
Proj
ect.
•Lo
an is
non
-rec
ours
e to
Spo
nsor
.
Sp
onso
r’s
finan
cial
risk
is li
mite
d to
its
equi
ty c
ontr
ibut
ion
in B
orro
wer
and
righ
t to
futu
re
bene
fits
from
Pro
ject
.
•Cr
edit
eval
uatio
n is
larg
ely
abou
t Pro
ject
’s m
erits
and
less
so
abou
t Spo
nsor
’s
finan
cial
sta
tus.
INV
ES
TM
EN
T D
IVIS
ION
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 7 of 22
DIV
ISIO
N
Und
erly
ing
Proj
ect A
gree
men
ts (T
ypic
al)
8 INV
ES
TM
EN
T D
IVIS
ION
Pow
er P
urch
ase
Agr
eem
ent (
“PPA
”)
Cred
it A
gree
men
t
Cons
truc
tion
Cont
ract
or a
nd/o
r Eq
uipm
ent S
uppl
ier
Ass
ignm
ent &
Ack
now
ledg
emen
t
A
gree
men
t
Cons
truc
tion
Cont
ract
and
/or
Equi
pmen
t Su
pply
Con
trac
t
Firs
t Nat
ion(
s)
Land
Ow
ner(
s)
Land
Lea
ses
(if
app
licab
le)
Borr
ower
Lend
ers
Util
ity
Ass
ignm
ent &
Ack
now
ledg
emen
t
A
gree
men
t
Impa
ct B
enef
it A
gree
men
t (“I
BA”)
(if
app
licab
le)
Fina
ncin
g A
gree
men
ts:
•Cre
dit A
gree
men
t •A
ssig
nmen
t and
Ack
now
ledg
emen
t A
gree
men
t •C
onst
ruct
ion
Escr
ow A
ccou
nts
Agr
eem
ent (
betw
een
Age
nt, E
scro
w
Age
nt a
nd B
orro
wer
)
Proj
ect A
gree
men
ts:
•PPA
•C
onst
ruct
ion
Cont
ract
s •I
BA
•Lan
d Le
ases
•P
erm
its
•Wat
er li
cens
es
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 8 of 22
DIV
ISIO
N
Key
Proj
ect R
isks
to C
onsi
der
and
thei
r Miti
gant
s
9 INV
ES
TM
EN
T D
IVIS
ION
Co
nstr
uctio
n co
mpl
etio
n ri
sk:
•Co
st, s
ched
ule
and
faci
lity
perf
orm
ance
Re
venu
e ri
sk:
•Po
wer
out
put
•El
ectr
icity
rate
•Co
ntra
ct te
rmin
atio
n ri
sk
Fu
el s
uppl
y an
d/or
cos
t ris
k:
•Re
new
able
reso
urce
•N
atur
al g
as p
rici
ng a
nd s
uppl
y
O
pera
ting
risk
:
•O
pera
ting
cost
con
trol
•M
aint
enan
ce
In
tere
st ra
te r
isk
Fo
rce
maj
eure
ris
k
O
ther
risk
s
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 9 of 22
DIV
ISIO
N
Who
Pro
vide
s Pr
ojec
t Deb
t
10 IN
VE
ST
ME
NT
DIV
ISIO
N
Li
fe in
sura
nce
com
pani
es (a
nd to
an
exte
nt, p
ensi
on fu
nds)
:
•20
to 4
0-ye
ar t
erm
to m
atch
EPA
/PPA
term
.
•Po
wer
gen
erat
ion
prov
ides
idea
l mat
ch fo
r lo
ng te
rm li
abili
ties
(i.e.
life
insu
ranc
e an
d an
nuiti
es)
D
omes
tic C
anad
ian
Bank
s:
•Li
mite
d to
10-
year
ter
m (m
axim
um)
•Pu
nitiv
e “m
ini p
erm
” st
ruct
ure
Co
rpor
ate
Bond
Mar
ket:
•O
nly
avai
labl
e to
larg
e is
suer
s (e
g. T
rans
Cana
da, E
nbri
dge,
Tra
nsA
lta, e
tc.)
Eu
rope
an (a
nd Ja
pane
se) B
anks
:
•U
sed
to p
rovi
de 1
8-ye
ar t
erm
fina
ncin
g
•W
ith c
risi
s in
Eur
ope,
man
y ha
ve o
r ar
e sc
alin
g ba
ck o
r sh
uttin
g do
wn
Cana
dian
ope
ratio
ns
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 10 of 22
DIV
ISIO
N
Type
s of
Pro
ject
s Fi
nanc
ed
11 IN
VE
ST
ME
NT
DIV
ISIO
N
Rene
wab
le:
•H
ydro
elec
tric
•W
ind
•So
lar
•Bi
omas
s
•La
ndfil
l Gas
/Bio
gas
•Bi
ofue
ls
Non
-ren
ewab
le:
•N
atur
al G
as
Prov
en te
chno
logy
wit
h lo
ng h
isto
ry
Rela
tive
ly n
ew te
chno
logy
Pre
ferr
ed
Less
Pre
ferr
ed
√
(Str
ong)
√
√
√
√
√
√
√
√
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 11 of 22
DIV
ISIO
N
Prof
ile o
f Man
ulife
and
Pro
ject
Fin
ance
Gro
up
12 IN
VE
ST
ME
NT
DIV
ISIO
N
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 12 of 22
DIV
ISIO
N
Man
ulife
Fin
anci
al -
Inve
stm
ents
13 IN
VE
ST
ME
NT
DIV
ISIO
N
Man
ulife
Fin
anci
al
Corp
orat
ion
(“M
FC”)
Cana
dian
Inve
stm
ents
U
.S. I
nves
tmen
ts
Man
ulife
Ass
et
Man
agem
ent
Man
ulife
Cap
ital
Asi
a In
vest
men
ts
Fund
M
anag
emen
t Ti
mbe
r &
Agr
icul
ture
M
FC is
Can
ada’
s la
rges
t life
insu
ranc
e co
mpa
ny
O
ver
45,0
00 e
mpl
oyee
s an
d ag
ents
and
a n
etw
ork
of d
istr
ibut
ion
part
ners
in 2
1 co
untr
ies
and
terr
itori
es w
orld
wid
e.
M
arke
t Cap
italiz
atio
n of
~C$
21Bn
(as
at F
eb 2
, 201
2), w
ith T
otal
Ass
ets
of ~
C$45
5Bn
Cr
edit
ratin
gs: A
- (S&
P); A
(hig
h) (D
BRS)
; A- (
Fitc
h)
Li
sted
on
the
TSX,
NYS
E &
SEH
K
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 13 of 22
DIV
ISIO
N
Prof
ile –
Man
ulife
Cap
ital
14 IN
VE
ST
ME
NT
DIV
ISIO
N
M
anul
ife C
apita
l han
dles
pri
vate
equ
ity a
nd p
roje
ct fi
nanc
e in
vest
men
ts in
Can
ada.
Man
ulife
Cap
ital
Priv
ate
Equi
ty
Mez
zani
ne d
ebt
and
equi
ty
inve
stm
ents
in
num
erou
s co
mpa
nies
and
fu
nds
NA
L Re
sour
ce
Man
agem
ent
(Man
ager
of N
AL
Ener
gy C
orp.
)
Oil
and
Gas
A
sset
s
20M
W B
ear
Hyd
ro
Proj
ect (
B.C.
)
31M
W L
ong
Lake
H
ydro
Pro
ject
(B.C
.)
19M
W W
hite
Riv
er
Hyd
ro P
roje
ct
(Ont
ario
)
Oth
ers
unde
r de
velo
pmen
t
Regi
onal
Pow
er
Corp
. Pr
ojec
t Fin
ance
Infr
astr
uctu
re
Equi
ty
Proj
ect
Deb
t Fi
nanc
ing
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 14 of 22
DIV
ISIO
N
Proj
ect F
inan
ce (D
ebt)
at M
anul
ife
15 IN
VE
ST
ME
NT
DIV
ISIO
N
Fuel
Sou
rce
Tota
l Inv
estm
ent
%W
ind
1,48
4,62
0,00
0$
64.7
%H
ydro
395,
300,
000
$
17.2
%G
as F
ired
290,
500,
000
$
12.7
%N
ucle
ar85
,000
,000
$
3.
7%G
eoth
erm
al26
,900
,000
$
1.
2%Bi
omas
s/Bi
ogas
10,7
00,0
00$
0.5%
Coal
-Fir
ed-
$
0.0%
Sola
r/O
ther
Ren
ewab
les
-$
0.
0%
Oth
er-
$
0.0%
2,29
3,02
0,00
0$
100.
0%
Man
ulif
e's
Pow
er P
roje
ct F
inan
ce P
ortf
olio
(Jan
uary
201
2)
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 15 of 22
DIV
ISIO
N
Past
Fin
anci
ng T
rans
actio
ns
16 IN
VE
ST
ME
NT
DIV
ISIO
N
Arra
nger
and
Sol
e Le
nder
Arra
nger
and
Sol
e Le
nder
Lead
Arr
ange
rLe
ad A
rran
ger
Lam
eque
Win
d Po
wer
LP
Long
Lak
e Hy
dro
LP /
Prem
ier
Pow
er C
orp.
Win
dsta
r En
ergy
, LLC
Mon
t Lou
is W
ind
LP
45 M
W W
ind
Farm
31 M
W R
un-o
f-riv
er H
ydro
120
MW
Win
d Fa
rm10
0.5
MW
Win
d Fa
rm
$70
mill
ion
Seni
or D
ebt
$148
.4 m
illio
n Se
nior
Deb
t and
$19.
2 m
illio
n Su
bord
inat
ed D
ebt
US$2
04 m
illio
n Se
nior
Deb
t$1
40.5
mill
ion
Seni
or D
ebt a
nd
Lette
r of
Gua
rant
ee F
acili
ty
Jan-
2012
Jul-2
011
Dec-
2010
Nov-
2010
Lead
Arr
ange
rAr
rang
er a
nd S
ole
Lend
erLe
ad A
rran
ger
Lead
Arr
ange
r
Poin
te-A
ux-R
oche
s W
ind
Inc.
Bear
Hyd
ro L
PBo
rale
x En
ergy
Hol
ding
s LP
Rale
igh
Win
d Po
wer
Par
tner
ship
48.6
MW
Win
d Fa
rm20
MW
Run
-of-r
iver
Hyd
ro9
x 10
MW
Win
d Fa
rms
78 M
W W
ind
Farm
$117
mill
ion
Seni
or D
ebt
$79.
2 m
illio
n Se
nior
Deb
t and
$8.5
mill
ion
Subo
rdin
ated
Deb
t$1
94.5
mill
ion
Seni
or D
ebt a
nd
Lette
r of
Gua
rant
ee F
acili
ty$1
79 m
illio
n Se
nior
Deb
t and
G
uara
ntee
Fac
ility
Sep-
2010
Sep-
2010
Feb-
2010
Jan-
2010
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 16 of 22
DIV
ISIO
N
Past
Fin
anci
ng T
rans
actio
ns
17 IN
VE
ST
ME
NT
DIV
ISIO
N Le
ad A
rran
ger
Arra
nger
& S
ole
Lend
erAr
rang
er &
Sol
e Le
nder
Lead
Arr
ange
r
Doki
e G
ener
al P
artn
ersh
ipAI
M H
arro
w W
ind
Farm
LP
RMSE
nerg
y Da
lhou
sie
Mou
ntai
n Br
uce
Pow
er A
LP
144
MW
Win
d Fa
rm39
.6 M
W W
ind
Farm
51 M
W W
ind
Farm
3,00
0 M
W N
ucle
ar G
ener
atio
n
$175
mill
ion
Seni
or D
ebt
$82
mill
ion
Seni
or D
ebt
$88.
5 m
illio
n Se
nior
Deb
t$2
00 m
illio
n Se
nior
Deb
t
Dec-
2009
Oct
-200
9Fe
b-20
09Se
p-20
08
Part
icip
ant
Lead
Arr
ange
rPa
rtic
ipan
tPa
rtic
ipan
t
Buffa
lo G
ap II
I Hol
ding
s LL
CSa
int U
lric
Sai
nt L
eand
re W
ind
Hack
berr
y W
ind
LLC
East
Win
dsor
Cog
ener
atio
n LP
170
MW
Win
d Fa
rm12
7.5
MW
Win
d Fa
rm16
5.6
MW
Win
d Fa
rm84
MW
NG
Cog
en
$35.
8 m
illio
n Cl
ass
A Eq
uity
$208
mill
ion
Seni
or D
ebt
$50
mill
ion
Seni
or D
ebt
$179
mill
ion
Seni
or D
ebt
and
Lette
r of
Gua
rant
ee F
acili
ty
Jul-2
008
May
-200
8De
c-20
07No
v-20
07
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 17 of 22
DIV
ISIO
N
Past
Fin
anci
ng T
rans
actio
ns
18 IN
VE
ST
ME
NT
DIV
ISIO
N
Co-L
ead
Arra
nger
Part
icip
ant
Co-L
ead
Arra
nger
Part
icip
ant
Toba
Mon
tros
e G
PNo
ble
Envi
ronm
enta
l Pow
er,
LLC
Thor
old
Coge
n LP
Gre
enfie
ld E
nerg
y Ce
ntre
LP
196
MW
Run
-of-R
iver
Hyd
ro3
Win
d Fa
rms
tota
ling
282
MW
265
MW
NG
Cog
en10
05 M
W N
G C
ombi
ned
Cycl
e
$470
mill
ion
Seni
or D
ebt
US$5
61.5
mill
ion
Seni
or D
ebt
$484
mill
ion
Seni
or &
Jun
ior
Debt
$648
mill
ion
Seni
or D
ebt
Nov-
2007
Oct
-200
7Au
g-20
07Ju
l-200
7
Sole
Lon
g Te
rm L
ende
rAr
rang
er &
Sol
e Le
nder
Part
icip
ant
Arra
nger
& S
ole
Lend
er
Whi
rlw
ind
Ener
gy C
ente
rW
est C
ape
Win
d En
ergy
Inc.
Fent
on P
ower
Par
tner
s I,
LLC
Norw
ay W
ind
Ener
gy L
P60
MW
Win
d Fa
rm20
MW
Win
d Fa
rm20
6 M
W W
ind
Farm
9 M
W W
ind
Farm
US$5
0 m
illio
n Se
nior
Deb
t$2
4 m
illio
n Se
nior
& J
unio
r De
btUS
$301
mill
ion
Seni
or D
ebt
$14
mill
ion
Seni
or &
Jun
ior
Debt
Mar
-200
7De
c-20
06De
c-20
06Se
p-20
06
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 18 of 22
DIV
ISIO
N
Pric
ing
and
Tran
sact
ion
Size
Gui
delin
es
19 IN
VE
ST
ME
NT
DIV
ISIO
N
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 19 of 22
DIV
ISIO
N
Pric
ing
and
Tran
sact
ion
Size
20 IN
VE
ST
ME
NT
DIV
ISIO
N
Lo
ng te
rm fi
nanc
ing
is p
rice
d of
f Gov
ernm
ent
of C
anad
a (“
GO
C”)
bon
d yi
elds
.
•Cu
rren
t pri
cing
rang
e is
3.0
% to
3.5
% a
bove
ave
rage
life
GO
C yi
eld
U
sual
ly th
e tr
ansa
ctio
n is
pri
ced
at C
losi
ng o
f tra
nsac
tion
base
d on
GO
C yi
eld
at th
at ti
me.
Cr
edit
spre
ad is
det
erm
ined
by
cred
it ri
sk a
nd c
orpo
rate
bon
d yi
elds
.
M
anul
ife w
ill c
onsi
der
finan
cing
s of
$50
MM
(min
imum
) up
to $
400M
M.
•U
p to
$80
MM
to $
100M
M, f
inan
cing
will
be
by M
anul
ife a
s so
le le
nder
.
•A
bove
$80
MM
to $
100M
M, M
anul
ife w
ill s
yndi
cate
to o
ther
lend
ers.
For
20-y
ear
Fina
ncin
g Fo
r 40
-yea
r Fi
nanc
ing
Aver
age
Life
Est
imat
e
GO
C Yi
eld
(cur
rent
)
Cred
it Sp
read
~12
year
s
~2.0
%
3.0
– 3.
5%
~30
year
s
~2.5
%
3.0
– 3.
5%
Tota
l All-
in R
ate
5.0
– 5.
5%
5.5
– 6.
0%
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 20 of 22
DIV
ISIO
N
His
tori
cal P
rici
ng
21 IN
VE
ST
ME
NT
DIV
ISIO
N
Not
e: R
ates
are
an
appr
oxim
atio
n
10.0
0%
9.00
%
8.00
% I I
7.00
% /+-------~--~~~~~--~----~----------------------------------------------; ___
____
__
, ;"
"
........
I ;
' I
/ ~
6.00%
~+-------------------~------------~~L---~~~~----~#-~~~~~~
r--+/--------~\
I I
\ I
\ I
\
5.00%
~+-------------------~1 --
----
----
----
----
----
----
----
----
----
----
----
----
-,1---
----
----
-~
4.00
%
3.00
%
2.00
%
1.00
%
I I
I I
I I
I I
: I I I I , '
, '
I '
I ',
I
+---~------~~--------------------------------------------------------~~~~~~
~ .....
... ___
_ ~,,'
/ ;
.,·-'
-G
ov'
t o
f Can
ada
-10
Yr
Bon
d -
Ma
nu
life
Ben
chm
ark
PF
Rat
e
1m M
anul
ife
Fin
anci
al
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 21 of 22
DIV
ISIO
N
Que
stio
ns &
Ans
wer
s
22 IN
VE
ST
ME
NT
DIV
ISIO
N
Appendix A
Site C Clean Energy Project - Rebuttal Evidence With Respect to the Submissions of CEABC
Page 22 of 22