iaac-aeic.gc.ca · installed or nameplate capacity is the maximum rating of generator equipment...

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


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




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.




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.




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.




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.




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.

https://www.bchydro.com/content/dam/hydro/medialib/internet/documents/planning_regulatory/acquiring_power/2012q3/navigant_financial_analysis.pdf

https://www.bchydro.com/content/dam/hydro/medialib/internet/documents/planning_regulatory/acquiring_power/2012q3/navigant_financial_analysis.pdf




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




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.




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




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.




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.




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.




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.




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.




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




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.




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).


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

http://www.nunukphotos.com/Industry-photos/solar-power-plant�

http://www.nunukphotos.com/Industry-photos/solar-power-plant�

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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


Page 21 of 22

DIV

ISIO

N

Que

stio

ns &

Ans

wer

s

22 IN

VE

ST

ME

NT

DIV

ISIO

N

Appendix A


Page 22 of 22

iaac-aeic.gc.ca · installed or nameplate capacity is the maximum rating of generator equipment...

Documents