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200 – 2006 West 10th Avenue

Vancouver, BC V6J 2B3

www.wcel.org

tel: 604.684.7378

fax: 604.684.1312

toll free: 1.800.330.WCEL (in BC)

email: [email protected]

November 25, 2013

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Courtney Trevis Brian Murphy Panel Co-Manager Panel Co-Manager Site C Review Panel Secretariat Site C Review Panel Secretariat Canadian Environmental Assessment Agency Environmental Assessment Office 160 Elgin Street, 22nd floor 2n floor, 836 Yates Street Ottawa, ON K1A 0H3 Victoria, BC V8W 9V1 Re: Site C Clean Energy Project, CEAA Ref # 63919 – Submission of Expert Report

Dear Sir/Madam:

Please find enclosed the expert report of Dr. Marvin Shaffer, prepared on behalf of and submitted by the Peace Valley Environment Association (PVEA), an Interested Party and Participant in the environmental assessment of the proposed Site C Project. Also enclosed are Dr. Shaffer’s résumé and list of assignments current to November, 2013.

We are grateful to the Panel for granting PVEA an extension to file Dr. Shaffer’s report by November 29. Due to a concerted final effort, we are pleased to be able to file the report today.

Please feel free to contact me if you have any questions.

Sincerely,

Anna Johnston Staff Counsel, West Coast Environmental Law

smithj

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<original signed by>

200 – 2006 West 10th Avenue

Vancouver, BC V6J 2B3

www.wcel.org

tel: 604.684.7378

fax: 604.684.1312

toll free: 1.800.330.WCEL (in BC)

email: [email protected]

November 26, 2013

Via email Via email

Courtney Trevis Sean Moore Panel Co-Manager Panel Co-Manager Site C Review Panel Secretariat Site C Review Panel Secretariat Canadian Environmental Assessment Agency Environmental Assessment Office 160 Elgin Street, 22nd floor 2n floor, 836 Yates Street Ottawa, ON K1A 0H3 Victoria, BC V8W 9V1 [email protected] [email protected]

Re: Site C Clean Energy Project, CEAA Ref # 63919 – Amended Expert Report and Clarification

Dear Sir/Madam:

Please find enclosed an amended expert report of Dr. Marvin Shaffer, prepared on behalf of and submitted by the Peace Valley Environment Association (PVEA). The amendments correct two typos in the fourth bullet on page 3 of the report submitted November 25.

Also, we understand that some PVEA members may be submitting Registration Forms that state PVEA in the “Organization” Field: for example, Hearing Document No 1767, “Written Submission of Denise Gardiner”.

To clarify, as a registered Society, PVEA is represented only by individuals authorized to make decisions on its behalf. For the purposes of the environmental assessment of the Site C Clean Energy Project, unless it states otherwise, PVEA is represented by West Coast Environmental Law, counsel Timothy Howard and PVEA coordinator Andrea Morison.

While PVEA does not dispute the right of individuals, including its members, to participate in the environmental assessment of the Site C Clean Energy Project, it wishes to clarify that any information submitted by individuals other than those authorized to represent it are submissions on those individuals’ behalf, not PVEA’s. PVEA requests that the Panel not consider submissions by Ms. Gardiner or any other individuals to be a PVEA submission unless PVEA explicitly communicates otherwise to it.

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Please feel free to contact me if you require clarification on this or any other matters.

Sincerely,

Anna Johnston Staff Counsel, West Coast Environmental Law //enclosure

SmithJ

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<original signed by>

Assessment of the Need for and Alternatives to the Site C Project

Prepared at the Request of: Peace Valley Environmental Association

for submission to the: CEAA and BCEAO Joint Review Panel

by:

Dr. Marvin Shaffer Marvin Shaffer & Associates Ltd.

November 25, 2013

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Executive Summary

• The purpose of this submission is to present an independent assessment of BC Hydro’s analysis and conclusions with respect to the need and justification for the Site C project.

• BC Hydro is forecasting shortfalls in energy supply starting in 2027 without LNG and between 2021 and 2024 with LNG. It is forecasting shortfalls of peak generating capacity by 2020.

• Contributing to the forecast shortfalls is a major market failure in the pricing

of electricity, with rates in the industrial sector less than half the marginal cost of new supply. BC Hydro is in effect inducing new mining and oil and gas load with the offer of low cost power that it does not have, giving rise to more load growth than what would be economically efficient – where the value of the use exceeds the cost it entails.

• The key factor underlying the forecast shortfalls is the elimination of the

existing gas-‐fired Burrard Thermal plant as a source of back-‐up energy and peak generating capacity. Traditionally the Burrard plant has been used to backstop or ‘firm up’ non-‐firm hydro and spot market supplies – low cost sources of supply that very cost-‐effectively defer the need for new resources.

• The elimination of Burrard as a source of back-‐up energy and peak capacity

was forced on BC Hydro by the government without any supporting economic, environmental or other analysis and despite the recommendations of the BC Utilities Commission, the positions of all intervenors except for the Independent Power Producers Association (IPPBC) at the 2008 Long Term Acquisition Plan (LTAP) hearing, and even BC Hydro itself.

• Had BC Hydro been able to recognize the back-‐up role of Burrard, together

with the spot market allowance it traditionally assumed, its latest LRB analysis (without LNG) would show no shortfall of energy until 2033 and no shortfall of capacity until 2029 (the same year capacity shortfalls would have to be addressed even with the Site C project). Were BC Hydro to assume the back-‐up capability of Burrard recommended by the BC Utilities Commission plus the market allowance implicit in its current planning on the basis of average water conditions, its latest LRB analysis (without LNG) would show no shortfall of energy until beyond 2033.

• The need for new resources that BC Hydro has identified to meet non-‐LNG

requirements is a need to replace what was lost with the elimination of Burrard. As for LNG, BC Hydro has stated that because of the unique requirements of that load, it could better be served by north coast supply. BC Hydro is not proposing, nor has it provided any analysis supporting the development of Site C to meet potential LNG requirements.

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• BC Hydro compared Site C with two alternatives: a clean portfolio and a clean

plus thermal portfolio, the latter including the development of single cycle gas turbines (SCGTs) to meet capacity requirements. It concluded Site C is preferable based on its environmental attributes and employment impacts as well as its cost advantage. In fact BC Hydro’s preference for Site C is based solely on its cost analysis, as BC Hydro did not assess the significance of the different environmental attributes nor did it analyze the economic net benefits (or costs) that the employment impacts may entail.

• BC Hydro’s estimated cost advantage for Site C is less in comparison with the

clean plus thermal portfolio than the clean portfolio. The SCGTs in the clean plus thermal portfolio provide relatively low cost capacity that can be strategically located to minimize transmission requirements, and low cost energy when used to meet peak loads. The estimated cost advantage of Site C compared to the clean plus thermal portfolio BC Hydro analyzed is relatively small and dependent on some key assumptions.

• BC Hydro did not consider in its analysis the role that SCGTs could play in

backstopping greater use of non-‐firm and spot market supplies – in other words, they did not consider how SCGTs could replace what was lost with the elimination of Burrard.

• The SCGTs in BC Hydro’s clean plus thermal portfolio have the potential to

back up some 3700 GWh of non-‐firm and spot market supply, deferring the need for new sources of energy supply until 2033. Such an SCGT ‘thermal back-‐up’ strategy would be far more cost-‐effective than what BC Hydro analyzed, and would be far less costly than the Site C project that BC Hydro is proposing. The cost advantage of the SCGT strategy could be $1 billion or more.

• BC Hydro is constrained by the self-‐sufficiency and clean requirements in the

Clean Energy Act. However, it is not clear that this SCGT strategy would contravene those requirements. The SCGTs would give BC Hydro the firm capability to meet requirements with BC resources. At the same time, the expected displacement of SCGT generation by non-‐firm and spot supplies, would enable BC Hydro to satisfy the clean restriction on thermal generation in B.C. Nor would the displacement simply necessarily mean more thermal generation outside B.C. Much of the spot market supply would be from freshet hydro surplus in the Pacific Northwest as well as the increasing amount of wind generation in neighbouring jurisdictions that is surplus to requirements when produced.

• In conclusion:

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There would be no need for new supply had BC Hydro not eliminated Burrard as a source of back-up energy and dependable capacity. BC Hydro’s conclusion that Site C is the preferred source to meet the need is due to the restrictive nature of the clean plus thermal portfolio it analyzed. A strategy of using the back-up capability of SCGTs to restore much of the combined thermal back-up / market allowance that was lost with the elimination of Burrard would be a far more cost-effective strategy than the development of Site C in the foreseeable future.

There is not a need and justification for Site C as proposed by BC Hydro.

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1.0 Introduction In its Environmental Impact Assessment of the Site C project, including the Evidentiary update, BC Hydro has argued that the proposed project is needed and justified. It states that there is a need “based on the updated load-resource balance (LRB) analysis even after taking into account the DSM target and without taking into account the potential demand from LNG”.1 And it concludes based on its analysis of alternative portfolios capable of meeting the forecast need that the proposed project is justified – that it provides “the best combination of financial, technical, environmental and economic attributes”.2 The purpose of this submission is to present an independent assessment of BC Hydro’s analysis and conclusions regarding need and justification. Specifically, this submission addresses the following questions and issues:

• What are the key factors underlying BC Hydro’s forecast of LRB shortfalls in both energy and capacity?

• What are the key factors underlying BC Hydro’s conclusion that Site C is the preferred alternative to meet its forecast need?

• Is there an alternative strategy that would be more cost-‐effective or otherwise preferable than the development of Site C?

The overriding issue this submission addresses is whether there is in fact a need and justification for the Site C project as proposed by BC Hydro. The submission has been prepared by Dr. Marvin Shaffer of Marvin Shaffer & Associates Ltd. at the request of the Peace Valley Environmental Association (PVEA). Dr. Shaffer is a consulting economist and adjunct professor in the public policy program at Simon Fraser University.3 He has appeared as an expert witness on numerous occasions before the BC Utilities Commission on BC Hydro resource plan and other matters, and before other regulatory bodies and environmental assessment panels, including panels established under the Canadian Environmental Assessment Act. The analysis and conclusions in this submission are those of Dr. Shaffer and were not in any way influenced by the views and positions of the PVEA.

1 BC Hydro, Site C Clean Energy Project Evidentiary Update, September 13, 2013, p.3. 2 Ibid., p.4. 3 Dr. Shaffer’s resume can be found at: http://www.sfu.ca/mpp/marvinshaffer/resume/

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2.0 Need for New Supply

2.1 BC Hydro’s LRB Forecast BC Hydro’s LRB forecast for energy is based on comparisons of its forecast of annual requirements with its estimated annual firm supply. The requirements forecast starts with projections of residential, commercial and industrial load growth before demand side management (DSM) and then considers the system requirements after planned DSM measures and targets are taken into account. Estimated firm supply includes the capability of BC Hydro’s hydro electric generating plants under average water conditions; the firm potential output of its thermal plants (excluding the Burrard generating station); and the firm supply from its IPP contract purchases, including expected renewal as well as existing and committed purchases. BC Hydro’s LRB forecast for capacity is based on comparisons of its forecast of peak demand with its dependable peak generating capacity, including provision for forced outage or other contingency-‐related reserve margins. The LRB forecasts after taking planned DSM into account are developed with and without new LNG requirements. In its Evidentiary Update BC Hydro reported that without new LNG requirements it will have shortfalls of energy supply starting in 2027 and shortfalls of peak generating capacity starting in 2020.4 With LNG it would have energy shortfalls starting in 2021 to 2024 depending on the magnitude of the LNG requirements, and capacity shortfalls starting in 2020.5

2.2 Underlying Factors

BC Hydro’s 2012 requirements forecast indicates load growth in all sectors.6 For the residential and commercial sectors the growth is due largely to increased population (number of accounts) and economic activity. In the industrial sector the load growth is due to the forecast sharp increase in mining and oil and gas industry requirements. Increased mining and oil and gas industry requirements constitute the largest rate of growth for the entire system over the 2014-‐2024 period. Contributing to the load growth in all sectors, but particularly with the electric-‐intensive mining and oil and gas industry, is what economists term a market failure in the pricing of electricity. Electricity rates are based on BC Hydro’s average cost of supply, which is dominated by its low cost heritage hydro resources. As a result, the energy rate (the rate charged per MWh of use) for the industrial sector (the transmission level customers) currently averages less than $40/MWh.7 BC Hydro’s

4 BC Hydro, Site C Clean Energy Project Evidentiary Update, Tables 5 and 6, pp. 12-‐13. 5 Ibid., Tables 7 and 8, pp. 15-‐16. 6 BC Hydro, Draft Integrated Resource Plan, Chapter 2, section 2.2. 7 Current rates are set out in: https://www.bchydro.com/accounts-‐billing/customer-‐service-‐business/business-‐rates-‐overview/business-‐rates-‐prices.html

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most recent estimate of the marginal cost of new energy supply, by comparison, is $85-‐$100/MWh.8 It is the marginal cost of new electricity supply that reflects the cost BC Hydro will incur if, as it argues, it will have to increase supply to meet increased requirements. The fact that rates in the industrial sector are less than half the marginal cost of supply means that new loads are heavily subsidized – they pay less than half the cost consequences they add to the system. And that in turn contributes to more load growth than what economists would consider economically efficient, where the value of the electricity use equals or exceeds the costs it entails. The DSM that BC Hydro takes into account in developing its LRB estimates assumes a continuation of its long-‐term target of 7800 GWh by 2021. This DSM is based primarily on incentive and other programs aimed at encouraging customers to use less electricity. However, except for the existing stepped rate structures, BC Hydro’s DSM strategy does not address the major market failure in the pricing of electricity. Indeed, BC Hydro specifically ruled out consideration of DSM strategies that address this market failure because of its concerns about government and customer acceptance as well as uncertainty about its effects.9 The market failure in the pricing of electricity and the failure of planned DSM measures to address that (beyond the current stepped rate structure) is an important factor underlying BC Hydro’s forecast of future requirements and its determination of ‘need’. In effect BC Hydro is attracting new electric-‐intensive industry and other new demand with the offer of low cost power that it does not have available for sale. It is creating a ‘need’ that BC Hydro is arguing has to be met with high cost new sources of supply. On the supply side, a key factor underlying BC Hydro’s determination of need is its elimination of the existing natural gas-‐fired Burrard Thermal plant as a source of back-‐up energy capability and, after 2017, as a source of dependable peak generating capacity. Prior to the 2008 Long Term Acquisition Plan (LTAP) hearing when BC Hydro raised the issue of what capability it should assume for Burrard, BC Hydro assumed an energy capability of 6100 GWh and 900 MW of capacity from Burrard.10 For many years, BC Hydro has not intended nor in fact operated Burrard at its 6100 GWh energy capability. Annual production since 2001 has been less than 1000 GWh per year; in most years considerably so.11 It planned on the potential for a high level of production, however, in order that it could reliably take greater advantage of – 8 BC Hydro, Draft Integrated Resource Plan, Chapter 8, p.8-‐50. 9 Ibid., Chapter 3, pp. 3-‐86 to 3-‐87. 10 BC Utilities Commission, In the Matter of BC Hydro and the 2006 Integrated Electricity Plan and Long Term Acquisition Plan, May 11, 2007, p 69. 11 BC Utilities Commission, In the Matter of BC Hydro and an Application for Approval of the 2008 Long Term Acquisition Plan, Decision, July 27, 2009, p.90.

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essentially backstop or “firm up” – non-‐firm hydro as well as low cost spot market supply. When water conditions were favourable, non-‐firm energy was used in lieu of Burrard operation to meet requirements. If there were no non-‐firm and in any event, low cost spot market supply, when available, could opportunistically be acquired and used to meet requirements in lieu of Burrard. This use of non-‐firm and spot market supply was very economic because it enabled BC Hydro to defer the need for costly new sources of supply. The non-‐firm and spot market energy are typically very low cost sources of supply, and with the thermal back up they can reliably be used because if non-‐firm energy were not available and spot market supply were restricted or not attractively priced, requirements could still be with the back-‐up thermal supply. In addition to assuming 6100 GWh of back-‐up capability at Burrard, BC Hydro historically assumed a firm ability to acquire up to 2500 GWh of spot market energy to meet requirements.12 In total, it assumed a combined Burrard thermal back-‐up plus market allowance of 8600 GWh when assessing whether or when new resources were required. In its current assessment of the need for Site C, BC Hydro has assumed that it can acquire up to 4100 GWh of spot market energy to meet its requirements. It effectively made this assumption by basing its hydro supply on average as opposed to critical water conditions (4100 GWh being the difference between average and critical or firm hydro supply).13 However, because it has eliminated Burrard as a potential source of supply, it has assumed no ability to ‘firm up’ potential non-‐firm or rely on more spot market supply beyond 4100 GWh. BC Hydro’s current market allowance of 4100 GWh is 4500 GWh less than the 8600 GWh thermal back-‐up/ market allowance it used to assume. The elimination of Burrard as a source of supply was forced on BC Hydro by the government’s Clean Energy Act and related regulation – legislative direction not supported by the BC Utilities Commission, all intervenors except for IPPBC at the 2008 LTAP hearing, and not even by BC Hydro itself.14 The BC Utilities Commission concluded that with sustaining capital and O&M, the Burrard Thermal plant could provide 900 MW of peak generating capacity and at least 5000 GWh of energy in its traditional role as a back-‐up to the hydro system.15

12 BC Utilities Commission, In the Matter of BC Hydro and the 2006 Integrated Electricity Plan and Long Term Acquisition Plan, May 11, 2007, p 57. 13 BC Hydro, Site C Clean Energy Project Evidentiary Update, Figure 1, p.18. 14 BC Hydro recommended in the 2008 LTAP hearing that Burrard should be maintained to provide 900 MW of capacity and 3000 GWh of back-‐up energy capability. 15 BC Utilities Commission, In the Matter of BC Hydro and an Application for Approval of the 2008 Long Term Acquisition Plan, Decision, July 27, 2009, pp.113-‐116.

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Had BC Hydro been allowed to continue to recognize the historic role of Burrard and retain a combined thermal back-‐up plus market allowance of 8600 GWh, the load resource balance would be very different. As shown in Table 1, instead of energy shortfalls starting in 2027, there would be no forecast shortfall for non-‐LNG requirements until 2033, the last year of BC Hydro’s planning period. And if BC Hydro were allowed to recognize a thermal back-‐up/market allowance equal to 9100 GWh – the sum of the 4100 GWh BC Hydro assumes it can acquire in the market plus the 5000 GWh of Burrard back-‐up capability the BCUC recommended in its 2008 LTAP decision, there would be no shortfall until beyond 2033.

Table 1 Energy Load Resource Balance

without LNG -shortfalls in GWh-

(surpluses shown in parentheses)

Year BCH Current Market Allowance:

4100 GWh16

Historic Thermal Back-up / Market

Allowance: 8600 GWh

BCH Current Mkt Allowance plus

BCUC Burrard Rec.: 9100 GWh

F2017 (5000) (9500) (10000) F2018 (3700) (8200) (8700) F2019 (2800) (7300) (7800) F2020 (2400) (6900) (7400) F2021 (2200) (6700) (7200) F2022 (1800) (6300) (6800) F2023 (1100) (5600) (6100) F2024 (700) (5200) (5700) F2025 (300) (4800) (5300) F2026 (300) (4800) (5300) F2027 200 (4300) (4800) F2028 900 (3600) (4100) F2029 1800 (2700) (3200) F2030 2600 (1900) (2400) F2031 3300 (1200) (1700) F2032 4200 (300) (800) F2033 4900 400 (100)

16 BC Hydro LRB estimates in BC Hydro, Site C Clean Energy Project Evidentiary Update, Table 5, pp. 12-‐13.

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With respect to peak requirements, as shown in Table 2, if BC Hydro had been able to recognize the peak generating capacity that the Burrard thermal plant could provide, there would be no shortfalls of capacity in the 2020-‐2024 period that BC Hydro is currently forecasting, and no need for additional capacity to meet peak loads (without LNG) until 2029. That is the same year in which new capacity would be required even with the development of Site C.

Table 2

Capacity Load Resource Balance Without LNG

-shortfalls in MW- (surpluses shown in parentheses)

Year BC Hydro Forecast without

Burrard17 Forecast with Burrard

F2017 (250) (1150) F2018 (100) (1000) F2019 -‐-‐ (900) F2020 100 (800) F2021 100 (800) F2022 150 (750) F2023 300 (600) F2024 400 (500) F2025 500 (400) F2026 550 (350) F2027 700 (200) F2028 850 (50) F2029 1000 100 F2030 1150 250 F2031 1350 450 F2032 1550 650 F2033 1750 850

2.3 Conclusion with Respect to Need There is a need for new supply based on BC Hydro’s forecasts of requirements and estimates of supply. That need is in part a reflection of the market failure in the pricing of electricity and the economically inefficient load growth that can cause. Primarily, however, it is due to the elimination of Burrard as a source of back-‐up energy and dependable peak generating capacity. Eliminating Burrard was not done

17 Ibid., Table 6, p.13.

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for technical, economic or well-‐documented environmental reasons, nor was it recommended by the BCUC or broadly supported. It was a directive imposed by government without any supporting analysis or justification. Eliminating Burrard has greatly reduced BC Hydro’s ability to reliably and cost-‐effectively take advantage of non-‐firm supply and low cost spot market supplies to meet requirements. The need for new supply at least with respect to non-‐LNG loads is basically a need to replace what was lost by the elimination of Burrard. As for LNG, BC Hydro has indicated there is a great deal of uncertainty regarding what amount of electricity it may be called upon to supply. However, because of transmission constraints between Prince George and the North Coast, BC Hydro is not proposing to build a project like Site C to meet LNG loads. As it stated in its Evidentiary Update: “BC Hydro believes that the unique requirements of potential LNG customers may be better served by north coast supply”.18

18 Ibid., p.8.

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3.0 Site C versus Alternatives 3.1 BC Hydro’s Analysis Based on a technical and economic screening of potential resources, and subject to the constraints in the Clean Energy Act, BC Hydro developed two portfolios that could serve as alternatives to its proposed Site C project: (i) a clean energy portfolio consisting of wind and municipal solid waste energy resources combined with additions of generating capacity at Revelstoke and GMS, plus additional Power Smart initiatives to reduce capacity requirements; and (ii) a clean plus thermal portfolio consisting of a similar mix of wind and municipal solid waste energy resources, combined with additional generating capacity at Revelstoke and new capacity from single cycle gas thermal (SCGT) plants. In a variant of the clean plus thermal portfolio, there is additional generating capacity at GMS and a smaller amount from SCGTs.19 BC Hydro compared Site C with these two alternatives in terms of their present value system costs, environmental attributes and economic impacts. It concluded that Site C was preferred as it offered lower present value system costs, greater economic development and employment impacts, and comparatively low GHG emissions.20 Under BC Hydro’s base case set of assumptions, the magnitude of the cost advantage of Site C if developed as proposed for 2024, was relatively small compared to the clean plus thermal portfolio ($150 million in present value). It was greater when compared to the clean portfolio ($630 million). The cost advantage of Site C in both cases was greater if the in-‐service date was delayed until 2026.21 3.2 Underlying Factors While BC Hydro states that the preference for Site C is based on its environmental attributes and employment impacts as well cost advantage, it did not provide an assessment of relative significance of the different environmental attributes, nor did it provide any assessment or analysis of the net benefits of the employment impacts. Given the widely held expectation of shortages of construction and skilled trade workers in the province22 and the competing demands from other projects, it is not clear there would be any significant net benefit from the employment impacts that Site C would generate (indeed there could be a cost because of the added pressure it

19 Ibid., Tables 14, 15 and 16, pp. 34-‐36. 20 Ibid., Tables 12, 17 and 18, pp. 31-‐39. 21 Ibid., Figure 2 and Table 12, pp.30-‐31. 22 See, e.g., WorkBC, BC Labour Market Conditions, 2010-2020, which forecasts shortages of workers province-‐wide by 2016 and sooner on a regional basis.

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would bring to labour markets in the province).23 The preference for Site C in BC Hydro’s analysis derives solely from its estimated lower system cost. The lower net system cost is due to the significantly lower unit cost of energy that BC Hydro estimated for Site C as compared to the renewable energy resources in the alternative portfolios. The output from Site C also is higher in value than what the renewables offer, providing dependable capacity as well as energy plus the ability to shape production into higher valued seasons and time periods. In BC Hydro’s base case analysis these advantages outweigh Site C’s disadvantages – its high capital cost and large size relative to the annual load growth it will serve. In the initial years much of Site C’s output will be surplus to requirements and sold at forecast market prices far less than its unit energy cost. The main advantage of the alternative portfolios is that the resources can be brought into service in smaller increments, matched better to load growth. The sensitivity case results confirm these advantages and disadvantages of Site C. The smaller the gap that needs to be filled and the lower forecast market prices, the greater is the cost of the lumpiness and the less favoured is Site C compared to the alternatives. For similar reasons, the earlier the in-‐service date for Site C the less of a cost advantage does it exhibit. Also, though not shown in BC Hydro’s results, the higher the assumed discount rate the less favoured would Site C be. By the same token, the greater the gap, the higher forecast market prices, the later its in-‐service date and the lower the discount rate, the more favoured would Site C be.24 The cost advantage of Site C is most pronounced relative to the clean portfolio. Its cost advantage relative to the clean plus thermal portfolio is much less, and dependent on the LRB gap, market price, capital cost and in-‐service date assumptions BC Hydro used in the analysis. The SCGTs in the clean plus thermal portfolio offer capacity that is competitive in cost and can be strategically located to reduce transmission requirements and expenditures. They also offer much lower cost energy compared to the renewables they would displace, even with the GHG offset costs that were included. In its analysis, BC Hydro assumed that the SCGTs would be operating to meet peak requirements, with a resulting capacity factor of approximately 18%. The 588 MW of SCGT capacity in the clean plus thermal portfolio would produce 924 GWh of

23 It is well understood by economists that economic impacts (as BC Hydro estimated for its portfolio analysis) do not in themselves constitute economic benefits. Economic benefits depend on the origin and opportunity cost of those hired as a result of any project. In tight labour markets, a large percentage of the workers may come from outside the jurisdiction and the opportunity costs of those hired can be very high. See P. Grady and R. Muller, “On the Use and Misuse of Input-‐Output Based Impact Analysis in Evaluation”, Canadian Journal of Program Evaluation, Vol. 3, No. 2, 1968 for a discussion of the fundamental difference between impact and benefit-‐cost analysis. 24 BC Hydro, Site C Clean Energy Project Evidentiary Update, Table 24, p.48.

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energy at an estimated energy cost almost half that of the renewables and roughly three quarter that of Site C.25 What BC Hydro did not consider in its analysis is the role that the SCGTs could play in backing up non-‐firm energy and spot market supplies. In other words, they did not consider how the SCGTs could replace what was lost with the elimination of Burrard. While one would not expect SCGTs to operate at higher capacity factors than needed to meet peak requirements, they could in practice do so if and when required. And just like Burrard, their ability to do so would provide a physical back-‐up to non-‐firm or spot market supplies. At a 90% capacity factor,26 the 588 MW of SCGT capacity in the clean plus thermal alternative would have the potential to produce 4635 GWh – or some 3700 GWh more than what BC Hydro assumed would be generated for peak operations. That 3700 GWh is an indication of the energy back-‐up potential the SCGTs offer. Recognizing 3700 GWh of back-‐up potential would enable BC Hydro to increase its thermal back-‐up/market allowance from 4100 GWh to 7800 GWh, an amount closer to what it assumed in the past. Had BC Hydro taken that into account in its analysis, it would have greatly reduced the need for additional supply. Indeed, the SCGTs, both in what they might produce on-‐peak and the thermal back-‐up /market allowance they enable, would eliminate BC Hydro’s forecast shortfalls of energy (without LNG) until 2033. And the SCGTs plus the development of additional capacity at Revelstoke would eliminate BC Hydro’s forecast shortfalls of capacity (without LNG) until 2029, the same as what Site C would do. Such an SCGT ‘thermal back-‐up’ strategy would effectively address the primary reason for the forecast shortfalls – the elimination of Burrard. It would be far better than the clean plus thermal portfolio BC Hydro analyzed because it would enable BC Hydro to take greater advantage of the potentially large amount of non-‐firm supply27 as well as low cost spot market energy. And, as with Burrard, it could do so with no physical supply risk. Had BC Hydro analyzed this strategy, with the SCGT energy capability reflected in a larger thermal back-‐up/ market allowance, it would almost certainly have found it

25 Ibid., Table 15, p.35. 26 The North American Electric Reliability Corporation Generation Availability Report, 2009 indicates availability rates for SCGT-‐size thermal plants in the 90-‐92% range over the 2004 to 2008 period. The link to that report can be found at: http://www.nerc.com/pa/RAPA/gads/Pages/default.aspx 27 Historical water flow records indicate that BC Hydro’s own generating plants could produce up as much as 12,000 GWh in excess of its firm hydro supply. In the Evidentiary Update BC Hydro reports that with climate change the amount of non-‐firm from BC Hydro’s plants may increase. In addition, BC Hydro estimates that the non-‐firm energy from IPPs under contract by 2017 will average some 2100 GWh per year (Draft Integrated Resource Plan, p.2-‐24).

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to be more cost effective than Site C under a wide range of assumptions. Replacing the back-‐up function of Burrard would essentially eliminate the need for Site C and the major capital expenditures it entails within the planning period. The system studies with and without different amounts of back-‐up energy at Burrard that BC Hydro undertook for the 2008 LTAP suggest that the cost advantage of this SCGT strategy could be in excess of $1 billion.28 The difference in the unit cost of Site C and the non-‐firm or spot market purchases the SCGT thermal back-‐up strategy enable would also suggest potential savings of that order of magnitude or more.29 BC Hydro is constrained by the self-‐sufficiency and 93% clean requirement in the Clean Energy Act. However, as BC Hydro itself noted there is some ambiguity as to the interpretation of these requirements.30 One could argue that this SCGT thermal back-‐up strategy does satisfy these constraints. BC Hydro would have the firm capability to meet its forecast requirements with BC resources, satisfying the self-‐sufficiency requirement. At the same time, it would not expect to operate the thermal plants as much as their capability because of the expected availability of non-‐firm plus spot market supply that could economically displace the thermal production. In terms of what BC Hydro would expect to generate in the province, it could satisfy the 93% clean requirements.31 BC Hydro rejected this interpretation of the requirements, based on its assessment of the intention of the Act. However, it is not clear there is a legal imperative to do so. At a minimum, before BC Hydro embarks on a plan that could result in $1 billion or more in additional system costs, it should seek explicit direction on this matter, making very clear why ratepayers and arguably the general public interest would best be served by an interpretation that would permit BC Hydro to cost-‐effectively use the thermal back-‐up capability of SCGTs to replace what was in lost with the elimination of Burrard.

28 BC Utilities Commission, In the Matter of BC Hydro and an Application for Approval of the 2008 Long Term Acquisition Plan, Decision, July 27, 2009, Table 5-‐8, p.108. 29 BC Hydro’s market forecasts suggest that the cost saving from using non-‐firm and spot supplies as opposed to a new source like Site C could be in the order of $50/MWh. The 3700 GWh of non-‐firm and/or spot supply that the SCGTs could back-‐up could therefore offer a saving of some $185 million per year. As well this SCGT back-‐up strategy would avoid the cost of the lumpiness of Site C – the losses that would be incurred on the supply Site C generates in excess of requirements. While system studies are required to confirm the exact magnitude of the saving it is clear they could be considerable. 30 BC Hydro, Draft Integrated Resource Plan, Chapter 6. pp. 6-‐6 to 6-‐8. 31 Nor should it be assumed that this strategy would simply increase thermal production outside British Columbia. Much of the lowest cost spot supply comes from renewable resources – the very large amount of surplus freshet hydro power typically available in the U.S. Pacific Northwest in the spring time and the increasing amount of surplus wind energy that is generated in neighbouring jurisdictions when high wind events coincide with light load hour periods or for other reasons is surplus to requirements.

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3.3 Conclusion with Respect to Alternatives BC Hydro’s analysis indicates that Site C would be more cost-‐effective than the clean and clean plus thermal portfolio alternatives it examined. However, Site C is not more cost-‐effective than the much better alternative of using SCGTs to restore the thermal back-‐up capability that BC Hydro lost with the elimination of Burrard. Non-‐firm and opportunistically acquired spot market supplies are far less costly than Site C or any new sources of supply. Strategies that enable BC Hydro to take better advantage of those low cost sources, which if anything are expected to be increasingly available with the development of wind and other intermittent resources, offer a much more cost-‐effective way to meet requirements. Provided the SCGT thermal back-‐up strategy is in fact consistent with the provisions of the Clean Energy Act, as arguably it should be, it could be $1 billion or more less costly than what BC Hydro has proposed with its Site C development plan to meet forecast non-‐LNG requirements. As for LNG, as noted earlier, BC Hydro believes that these requirements, should it be called upon to supply them, would better be met by north coast supply. BC Hydro is not proposing to build Site C to meet LNG requirements, nor did its alternatives analysis address the relative advantages of different portfolios and strategies for that. If BC Hydro decides that in fact it wants to develop Site C not because it is the most cost effective way to meet non-‐LNG requirements (which it isn’t) but rather because it can best accommodate potential LNG demands, a new set of issues need to be addressed (including transmission requirements, pricing, and the risk to BC Hydro and ratepayers of stranded assets). As well, analyses comparing a much broader set of alternatives would need to be undertaken.

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4.0 Concluding Remarks

1. The need for new supply is policy driven – it is a direct result of the elimination of the Burrard plant as a source of back-‐up energy and capacity. The government would be well-‐advised to reconsider the elimination of Burrard as a source of back-‐up energy given the very significant consequences that has, and particularly since it is directly counter to the recommendation of the BCUC and the positions taken by all intervenors except IPPBC at the 2008 LTAP hearing.

2. Government would be well-‐advised to consider the very serious market failure in the pricing of electricity, most significantly in the industrial sector, and the effect it has in encouraging economically inefficient load growth.

3. Site C is not the preferred way to meet the LRB shortfalls (without LNG) that

BC Hydro has forecast. A more cost-‐effective strategy is to replace what was lost with the elimination of Burrard with the energy backup capability from new SCGTs.

4. It is important to note that BC Hydro is not proposing to build Site C to

supply new LNG requirements, should they emerge, nor has BC Hydro supplied the portfolio analysis that would support such a position.

5. If there is ambiguity about the interpretation of the restrictions imposed by

the Clean Energy Act, BC Hydro should seek clarification from government (and possibly reconsideration of the restrictions themselves), and in the process clearly inform government of the cost and other implications of a position that would preclude the cost-‐effective use of the energy back-‐up capability of SCGTs.

6. In summary, with regard to the key questions this report has attempted to address: There would be no need for new supply had BC Hydro not eliminated Burrard as a source of back-up energy and dependable capacity. BC Hydro’s conclusion that Site C is the preferred source to meet the need is due to the restrictive nature of the clean plus thermal portfolio it analyzed. A strategy of using the back-up capability of SCGTs to restore much of the combined thermal back-up / market allowance that was lost with the elimination of Burrard would be a far more cost-effective strategy than the development of Site C in the foreseeable future.

There is not a need and justification for Site C as proposed by BC Hydro.

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