Affidavit #1 of Harry Swain by sagelegal

This is the 1st Affidavit of Harry Sheldon Swain in this case and was made on 31/Jan/2018 No. 18 0247 Victoria Registry

In the Supreme Court of British Columbia BETWEEN: WEST MOBERLY FIRST NATIONS, and ROLAND WILLSON ON HIS OWN BEHALF AND ON BEHALF OF ALL OTHER WEST MOBERLY FIRST NATIONS BENEFICIARIES OF TREATY NO. 8 PLAINTIFFS AND: HER MAJESTY THE QUEEN IN RIGHT OF THE PROVINCE OF BRITISH COLUMBIA, THE ATTORNEY GENERAL OF CANADA, and BRITISH COLUMBIA HYDRO AND POWER AUTHORITY

DEFENDANTS

AFFIDAVIT #1 OF HARRY SHELDON SWAIN I, Harry Sheldon Swain, of 838 Pemberton Road, in the City of Victoria in the Province of British Columbia, Associate Fellow at the Centre for Global Studies, University of Victoria, make oath and say as follows: 1.

I was the chair of the Joint Review Panel ("JRP" or "Panel") on the British Columbia

Hydro and Power Authority's proposed Site C Clean Energy Project (the "Project"). I have personal knowledge of the facts and matters in this Affidavit, except where stated to be on information and belief, in which case I verily believe them to be true. Part A: Expert Report 2.

I was retained by Sage Legal, counsel for the Plaintiffs in this Action, to prepare

an expert report setting out my opinion regarding: (a) the need for the Project, and alternatives to the Project;

-2-

(b)

the limitations placed by the provincial and federal governments on the Panel's terms of reference, and how any such limitations may have affected

the Panel's ability to reach conclusions regarding the effects of the Project on the need for the project or potential alternatives;

(c)

the reasons why the Panel recommended subjecting the project to scrutiny by the BC Utilities Commission (the "BCUC");

(d)

the decision by the provincial government in December 2014 to proceed with the Project without any BCUC review;

(e)

the decision of the provincial government in 2017 to commence a BCUC inquiry,

and

my view regarding the appropriateness of the terms of

reference issued in respect of the inquiry; and

(f)

whether the process followed and conclusions reached by the BCUC were reasonable in light of the inquiry's terms of reference.

Attached to my affidavit as Exhibit "A" is my expert report in response to these

instructions (the "Expert Report"). I hold the opinions expressed in my Expert Report and adopt the Expert Report as my evidence in this proceeding. A copy of my curriculum vitae is included in my Expert Report as Schedule "B". 4.

I certify that I am aware of my duty as an expert witness to assist the court and not

to be an advocate for any party.

I further certify that I have made my Expert Report in

conformity with this duty and will, if called on to give oral or written testimon y, give that testimony in conformity with this duty.

My Expert Report is based on my experience and expertise in the energy sector

and specific experience and expertise with respect to electrical power generation, distribution and markets.

- 3 -

Joint Review Panel Report 6.

My Expert Report is also based, in part, on my personal experiences as the chair

of the JRP. The Panel was established by the federal Minister of the Environm ent and the British Columbia Minister of Environment. Attached to this Affidavit as Exhibit "B" is a

copy of the Site C Clean Energy Project Environmental Impact Stateme nt Guidelines , issued by the Minister of Environment of Canada and the Executive Director of the Environmental Assessment Office of British Columbia on September 5, 2012. 7.

Attached as Exhibit "C" to this affidavit is a copy of the Report of the Joint Review

Panel, Site C Clean Energy Project, of May 1, 2014.

I was one of the authors of this

report (the "Report"). The final Report was published on May 1 , 2014 with no dissenting statements.

The entire text was a consensus of the three panelists.

The Panel then

ceased work and was kept in reserve until the publication of the governm ents' decisions

in late 2014 in case either government needed to ask for clarification on any matter in the

Report. No clarifications were requested. The BCUC Inquiry 8.

My Expert Report also addresses the BCUC's Inquiry Respecting Site C.

In 2017, the new provincial government referred the Project to the BCUC for review

by way of Order of the Lieutenant Governor in Council No. 244, dated August 02, 2017. A copy of this order, including the terms of reference for the British Columbia Utilities Commission Inquiry Respecting Site C, is attached as Exhibit "D" to this Affidavit. 10.

participated

the

review

process

providing

two

submissions

the

Commission.

11.

On November 1, 2017, the BCUC released its final report regarding its review of

the Project, the British Columbia Utilities Commission Inquiry Respecting Site C's Final

Report to the Government of British Columbia. A copy of this report is attached as Exhibit "E" to this Affidavit.

-4 -

Documents Relied on in Formulating My Expert Report 12.

The documents I reviewed and relied on in producing my Expert Report include

those identified in the footnotes of my Expert Report. I also relied on my experience with, and knowledge of, the record before the JRP, which is maintained online and made publicly

available

the

Canadian

Environmental

Assessment

Agency

http://www.ceaa.gc.ca/050/documents-eng.cfm?evaluation=63919, as well as my review of documents made publicly available during my participation in the BCUC Inquiry Respecting

Site

which

remain

available

online

through

the

BCUC

website,

http://www.sitecinquiry.com. I have also reviewed:

(a)

A letter from the Deputy Minister, Ministry of Energy, Mines and Petroleu m Resources, and the Deputy Minister, Ministry of Finance to Mr. David

Morton, Chair of the BCUC, dated November 15, 2017, a copy of which is attached as Exhibit "F" to this Affidavit; and

(b)

A letter from Mr. David Morton, Chair of the BCUC to the Deputy Minister, Ministry of Energy,

Mines and Petroleum Resources, and the Deputy

Minister, Ministry of Finance, dated November 23, 201 7, a copy of which is attached as Exhibit "G" to this Affidavit. 13.

Except where otherwise stated or implied, I assume that the facts and opinions

provided in the documents that I have relied on in my Expert Report accurately reflect the facts and opinions stated therein as those authors understand them.

14.

I swear this Affidavit in respect of the Plaintiffs' application for an injunctio n in this

proceeding.

SWORN f0R-ARF4RMEB)~BEFORE ME at Vancouver, British Columbia, on 31/Jan/2018.

A eoinmissidner for Affidavits for British'Columbia

SONYA A. MORGAN Barrister and Solicitor

) ) ) ) ) ) )

Harry Sheldon Swain

This is Exhibit

" /"7 " referred to In the

affidavit

St/dcyn

sworn before me at V>c?hy\ Q

this^M

day of AaroafU

, 20 1^2

'"2^^J

A ComnTissionerYor t^ktf^rfffdavits Within British Columbia

SONYA A. MORGAN Barrister and Solicitor

EXPERT REPORT

Harry Swain January 31, 2018

-2Part One: Qualifications 1.

In 1977-79, I worked in the federal Department of Energy , Mines and Resources

as Canada's first Senior Advisor for Renewable Energy and then as Director General for Electricity,

Coal,

Uranium

and Nuclear Energy. While there

I co-authored the first

assessment of Canada's renewable energy prospects,1 and assiste d in chartering the Lower Churchill Development Corporation, a company whose purpose was to develop

hydroelectric projects in Labrador. 2.

In 1980 I served as British Columbia's Assistant Deputy Minister for Energy

Policy, assisting in preparing the original legislation establis hing the British Columbia Utilities Commission. As Deputy Minister of the federal Depart ment of Indian Affairs and Northern Development in

1987-92, I had general responsibility for the provision of

electricity on Indian Reserves, and for settling the grievan ces of Manitoba First Nations regarding the flooding of their reserves by Manitoba Hydro. These and other matters are referenced in my curriculum vitae, a copy of which is attache d to as Schedule "A" to this Expert Report.

I was one of the authors of the Joint Review Panel on the Site C Clean Energy

Project (the "Panel" or "JRP")'s Report of the Joint Review Panel, Site C Clean Energy

Project, of May 1, 2014 (the "Report").2 Save for direct quotes from the Report, the views in this Expert Report are my own, not those of the Panel. The direct quotes are not necessarily the views of the sponsoring governments, or the British Columbia Hydro and Power Authority ("BC Hydro" or the "Proponent"). Part Two: Joint Review Panel Report 4.

The Terms of Reference of the Panel were contained in an Amended Agreement

to Conduct a Cooperative Environmental Assessment, includin g the Establishment of a

Joint Review Panel, of the Site C Clean Energy Project between the Minister of the

Environment, Canada, and the Minister of the Environment, British Columbia of August 3, 2012, published at pages 326-41 of the Report.

1 H. Swain, R. Overend and T, Ledwell, "Canada's renewable energy prospects," Solar Energy.

23(1979)459-70

2 A copy of the Report is available online at http://www.ceaa.qc.ca/050 /documents/p6391 9/991 73E.pdf.

- 3A. Limitations on the ability of the JRP to reach conclusions or recommendations relevant to West Moberly First Nations Overview

There

were

both

practical

and

policy

obstacles

reaching

unequivocal

conclusions relevant to West Moberly First Nations. The framing of BC's public policy, within which all analyses had to be conducted, meant that a number of electricity supply alternatives less damaging to the Peace River First Nations could not be considered. The

Environmental

Impact

Statement

("EIS")

Guidelines

were

deficient

some

important ways, meaning that the EIS contained little relevant analysis on certain topics,

notably cumulative, or province-wide economic, effects. As to practical matters, there was no assessment of electricity demand beyond that prepared by BC Hydro, nor any searching third-party investigation of the reliability of BC Hydro's load forecasts . The time and resources available to the JRP, together with the capacity of BC Hydro to produce

paper

(18,000

pages

the

Amended

EIS

alone)

and

the

process

requirements, meant that the Report was produced under considerable time pressure. Policy and Practical Limitations 6.

The production and analysis of the EIS was constrained by established public

policy. Government policy statements and especially policy embodied in statute and regulation guided both the Proponent and the Panel. Practically, this meant that BC government restrictions in the Clean Energy Act, SBC 2010, c 22 ("C/ean Energy Act') ruled out a number of sources of supply which would have lessened or avoided the impacts on the interests of the West Moberly First Nations. Prohibited sources included:

(a)

The

Columbia

River

Entitlement,

resource

paid

for years

ago and

available to BC under treaty with the United States, was and is equal to

half the incremental power generated in the US Columbia River system by reason of the Canadian storage made available under the Treaty and amounting to approximately the production of Site C in a typical year

(discussed below). The reason this source could not be counted as part of

-4-

BC's base supply was that it was foreign,3 an odd stance in a province that lives by trade.

(b)

Nuclear energy, the sole available resource that has fewer greenhouse

gas

emissions

than

hydroelectricity,

source

not

associated

with

methylmercury in fish, and one which if built would not likely be on the

lower Peace River.4

(c)

Wind, solar, geothermal, run-of-river or tidal energy developed by, rather than

purchased

by,

Hydro,

these

sources

being

reserved

for

Independent Power Producers (IPPs).

(d)

Burrard Thermal, an existing 900 MW gas-fired power plant (s. 13) which could have produced energy, especially at peak periods, more cheaply

than other sources.5

(e)

Despite s. 17 of the Clean Energy Act, the use of "smart meters" and a

"smart grid" for the management of available supply. Later ministerial directives prohibited time-of-use pricing for residential and commercial

customers, despite the known positive effects this could have on demand and despite the billion-dollar expenditure on smart meters by BC Hydro. 7.

In addition, certain procedural limitations were imposed on the Panel. The Panel

consisted of three members, and were assisted by about half a dozen researchers seconded from the two governments. Over eight months, the Panel examined about 18,000 pages of studies done or commissioned by BC Hydro, several thousand pages of intervenor submissions, held hearings in northeast BC and wrote and delivered its Report. The Panel had been promised expert assistance but when it said it wanted to hire a consultant in utility finance and economics, the Panel was told by CEAA that it would be required to develop a statement of qualifications, a statement of work to be done, to advertise this on MERX, and to select the cheapest compliant bidder following a formal evaluation of bids and interviews with candidates. As this would have taken

3 Clean Energy Act, ss. 2(a) and 6(2) 4 Ibid., s. 2(o). 5 Ibid. , s. 13

-5several months, the Panel was forced to perform its economic analysis with internal resources.

Amongst the Panel members and research assistants, I was the only one

with relevant economic training.

The effect of these restrictions, together with the generous load forecasts of BC

Hydro, meant that pressure mounted from all sides to build Site C. Disallow ing the Columbia River Entitlement as part of BC's core supply, reserving all new non-Site C alternatives to the

IPP sector while making

Hydro the judge of whether their

proposals were economic, prohibiting demand management through the use of alreadyinstalled "Smart Meters", and prohibiting the use of the existing Burrard Thermal plant even for peak days all conduced to narrow the choice to Site C, with its heavy load of consequences for the West Moberly First Nations.

These

alternatives

would

have

required

disregarding

two

of the

legislated

objectives.6 The objective of cheaper rates would have been ensured by building less expensive supply alternatives, or by using demand management measure s, on an as-

needed basis rather than decades ahead of need. The objective of switching customers from

carbonaceous

hydroelectric energy

sources

contradicted

the

objective

cheaper rates by choosing electricity alternatives that were much more expensive than natural gas. I conclude that the effect of BC energy policy was to bias choices toward a

Project whose effects were disproportionately concentrated on the West Moberly First Nations.

tf. JHP findings with respect to the need for the Project "The Panel rejects, as a governing purpose, the maximization of the hydraulic potential

of the Peace River. "7 10.

BC Hydro justified the need for the Project in terms of three purposes: "(1) to

cost-effectively meet BC Hydro's forecast need for energy and capacity, (2) to meet forecast need in alignment with the provincial policy objectives of the Clean Energy Act and relevant B.C. Government policy statements, and (3) to cost-effe ctively maximize

the development of the hydroelectric potential of the Site C Flood Reserve which was

6 See ss. 2 and 6 of the Clean Energy Act. JRP Report, p. 272

-6-

established in 1957."8 The Panel rejected the last of these on the grounds that there was no legislative statement of this 1950's 'Two Rivers Policy' and that if accepted it would so tilt the scales in favour of Site C as an alternative to meeting the valid first two objectives as to render the entire JRP approach unnecessary. The Two Rivers Policy was simply an attempt to bias the analysis in favour of BC Hydro's preferred conclusion. "The Panel concludes that the Project must rest on its main claimsâ&#x20AC;&#x201D; that it would supply electricity that B.C. customers would need and would pay for at a lower combination of cash and external costs than any alternativeâ&#x20AC;&#x201D; and not on regiona l economic benefits ,"9 11.

BC Hydro argued that the Project would provide a suite of benefits to labour,

businesses,

First

Nations

municipalities

and

even,

surprisingly,

the

regional

environment. The view of the Panel was that these were for the most part simply geographical

displacements,

and

not

net

benefits.

different

suite

but

not

inconsequential suite of effects would have been felt if $7.9 billion was spent elsewhere, or not taken from ratepayers and spent at all. The 'local benefits ' argument is frequently

used by governments and project developers who want to create local enthusiasm and political support for a development regardless of the fact that those benefits will have to be paid for by others, with little net effect.

"The Panel cannot conclude on the likely accuracy of Project cost estimates because it

does not have the information, time, or resources. This affects all further calculations of unit costs, revenue requirements and rates. 12.

"10

In the view of the Panel, the real assessment of economic costs and benefits lay

with BC Hydro's first two statements of purpose noted above. A project passing these tests would have sufficient economic advantages over all alternat ives that it would pay its own costs and provide enough left over to compensate environmental and First Nations cost bearers for their losses. But there was no indepen dent analysis of the

claimed costs, only an attestation by KPMG, BC Hydro's auditors , that best practices had been used. This led to the Panel's recommendation that key economic aspects be

referred to the

BCUC for detailed investigation

3 JRP Report, p. 271 9 JRP Report, p. 279 10 JRP Report, p. 280

by the sole public body with the

-7mandate, experience and expertise to do so. We were somew hat suspicious at the time that BC Hydro's experience with building large dams dated from the 1980s, and that there were few employees who had relevant experience, but this qualitative worry

manifested itself only in the conclusion above.11 In the event, our fears have been realized. The current estimate of the cost of the completed project is 35 percent more than the $7.9 billion promise of 2013, and there is more than six years to go to completion. The point is important, as the Panel's qualified conclusions about the relative attractiveness of the Project rested on cost estimates that have not been met. As with load forecasts, better work by BC Hydro would not have led to a decision to build SiteC.

"The

Panel

concludes

that

Hydro's

forecasting

techniques

are

sound,

but

uncertainties necessarily proliferate in long-term forecasts ,"12 13.

This conclusion was based on assurances that BC Hydro's load forecasting

methods were consistent with industry standards, and had been approved by BCUC in

2008. It was also based on the description of these method s in the EIS. My current opinion, based on another four years of experience and time for analysis, is that this statement was too generous, and that the Panel's concern about the effect of price on demand - see below - should have carried greater weight. My presentation to the

BCUC Inquiry on October 14, 2017 summarizes this concern and gives illustrative calculations of why this should be so. 13

14.

BC Hydro's demand forecasts are persistently and systematically wrong.14 The

Panel did not have the expertise, time, or testimony to challen ge BC Hydro's methods. I

11 B.C., Manitoba, Quebec and Newfoundland are currently all engaged in large hydroelectric developments. Only Quebec has had continuous experience over decades of building such projects. Hydro Quebec is the only company performing within time and on budget. 12 JRP Report, p. 285

13 Harry Swain, "Testimony to BC Utilities Commission on Site C," 14 Oct. 2017. Commission document F-36-2, http://www.sitecinquirv.com/wp-content/uploads/2017/10/0Q62 1 F362 SwainH SiteC Submissions.pdf

14 BC Utilities Commission, "Site C - Alternative Resource Options and Load Forecast Assessment," 8 September 2017. Commission document A9. http://www.sitecinquiry.com /wpcontent/uploads/201 7/1 0/00700 A-9 Site-C-lnquiry Deloitte-LLP-lnde pendent-Report-No2.pdf . R. Hendriks, P. Raphals and K. Bakker, "Reassessing the need for Site C," Program for Water Governance, University of BC, April 17; online as BCUC Commission documen t F-106-1 at http://www.sitecinquirv.com/wp-content/uploads/2017/08/DQC 900127 F106-1 Proqram-on-WaterGovernance

University-of-British-ColumbiaUBC Site-C-Submission Redacte d.pdf Figs. 1-9, pp. 16-25.

-8wish we had had the benefit of the later work of Deloitte or the UBC Program on Water

Governance in 2013-14. BC Hydro's flawed load forecasting was more central to the Site C decision than I appreciated at the time. There is no reason now to believe that much new power, if any, will be required in the next 20 to 30 years.

"The Panel concludes that it is unlikely that the transmission and liquefaction energy

requirements of the new liquefied natural gas industry will be satisfied by any source except natural gas itself, and thus that BC Hydro's Integrated Resource Plan sensitivity

scenario of 'Low Liquefied Natural Gas' forecast is most likely correct Z'15 15.

The Panel regarded the forecast allowances for LNG skeptic ally. No other LNG

plants in the world used grid electricity for compression and liquefaction, and no BC

projects were near final investment decisions.16 Successful LNG plays around the world were based for the most part on associated gas without local uses, not on greenfield

operations, as was being proposed for northeastern BC. Neverth eless, the exploration, tracking, water use and landscape fragmentation caused by the development of the Montney Formation and its condensate-rich gas was acceler ated by LNG feasibility work, with concomitant effects on West Moberly interests.

"The Panel concludes that basing a $7.9 billion Project on a 20-year demand forecast without an explicit scenario of prices is not good practice. Electricity prices will strongly

affect demand, including Liquefied Natural Gas facility demand . 16.

Âť 17

Demand is driven by prices, and thus load forecasts should be as well. We

calculated an implicit price elasticity from BC Hydro load forecas ts, but it was combined with the impact of DSM (demand-side management) measur es in a way that made it difficult to untangle the separate effects. In any case, calcula ting long-term elasticity of

demand (and cross-elasticity with respect to natural gas, which has proven plentiful and cheap) requires a forecast of rates, which BC Hydro did not provide but which a competent utility and board must require. An elasticity-base d load forecast requires

modelling and computational capacity which was beyond the capacity of the Panel.

15 JRP Report, p. 286 16 JRP Report, p. 286 17 JRP Report, p. 287

-9"The Panel concludes that the demand-side management yield ought to at least keep up with the growth in gross demand, and therefore the potentia l savings from 2026 to

2033 may be understated.

Using BC Hydro's price elasticity of demand of -0.57,

accepting BC Hydro's forecast of gross demand, and positing a real price increase of 50

percent from 2014 to 2033, the Panel concludes that net demand in 2033 is likely to be about 65 terawatt hours. The Panel concludes that demand manage ment does not appear to command the same degree of analytic effort as does new supply. 17.

Âť 18

BC Hydro tends to believe that only DSM - specific expenditures by the company

to induce or require lower energy consumption - are effective. They underrate the effect of price on consumer behaviour, usually allowing market price signals and responses to their expenditures to overlap, with the latter being much the more important. But price elasticity is highly important, and with the increases in rates which can be foreseen from their present debt and deferral accounts and a continuing capital expenditure budget,

substantial real rate increases are inevitable. This can be expecte d to depress the demand for power to the point where the only market for margina l supply additions is

the US spot market.19 Site C will be a mostly stranded asset for many years. If BC Hydro's load forecasting had taken account of normal market respons es, especially for its residential and commercial demand, the case for the need for the Project could not have been made.

"The Panel concludes that the Proponent has not fully demons trated the need for the Project on the timetable set forth.

18.

â&#x20AC;˘â&#x20AC;˘ 20

In the face of load forecasts that were not of investment grade and plausible

demand scenarios requiring much less power, the Panel's conclus ion was inescapable. BC Hydro did not, and still has not, made a case for building any new power for many

years. The date for new power requirements keeps receding, and as noted below, there are numerous less expensive alternatives. The fact that constru ction began in 2015 meant that no time was allowed to go beyond consultation with First Nations to a deeper exploration of treaty rights. 18 JRP Report, p. 291 19 Alberta is not a market. Site C power would be roughly twice the price of Alberta's gas-fired systems

even without the cost of the necessary new transmission lines.

20 JRP Report, p. 306

- 10C. JRP findings on alternatives to the Project 19.

Hydro

defined

their portfolios of alternatives

resource

development

opportunities capable of producing 1,100 MW of capacity and 5,100 GWh of energy the same as the output from Site C. But these numbers were unrelated to the demand side of their load forecast. Nevertheless all alternatives were required to produce this output. A more logical way of addressing the problem would have been to array supply and DSM alternatives in terms of what each could contribute at a given price. A rational way of meeting some posited - or experienced - demand would be to commission the

cheapest sources first, up to the desired level of production. Since all alternatives were quantitatively smaller than Site C, there would have been an opportu nity to use cheaper

sources to follow the market and thus avoid the planned large losses of Site C in its early years.

"The Panel concludes that B.C. will need new energy and capacit y at some point. Site C would be the least expensive of the alternatives ,

and its cost advantages would

increase with the passing decades as inflation makes alternat ives more costly.

20.

"21

This statement was based on a $7.9 billion dollar cost for Site C, a cost which

has increased by 35 per cent in the first 2.5 (of a scheduled eight) years of construction. As well, the cost of alternatives has declined dramatically in the last four years. It is no longer true that Site C would be the least expensive alternative. The conclusion that its cost advantages would increase over time was based on the Panel's assumption that the Project would be financed over a period of time normal in the utility business - say,

30 years. We did not contemplate a 70-year term or an all-debt structure. I do not believe that BC Hydro can forecast the continuation of present low rates four to six decades into the future. These changed circumstances have not stopped BC Hydro

from repeatedly quoting the conclusion above.22 "The Panel concludes that methodological problems in the weighin g and comparison of

alternatives

render unitized

energy

costs

only

generally reliable

guide

21 JRP Report, p. 305 22 BC Hydro, "BC Hydro responds to Dan Levin of The New York Times," News , 13 December 2016 ; Dave Conway (Community Relations Manager, Site C Clean Energy Project, BC Hydro), "Site C presents better long-term value of British Columbians," Business in Vancouv er, 15-21 November 2016, p. 33

-11 investment. The Panel is more confident about the ranking of BC Hydro's projects, or

independent

power

producers'

projects ,

demand

side

management

projects

considered as separate lists. Uncosted attributes such as the ability to follow ioad, oeopraphical diversity , or the ability to assist with the integration of intermittent sources need

analytical

attention.

The

Panel concludes

that

number of supply

alternatives are competitive with Site C on a standard financial analysis , although in the

long term. Site C would produce less expensive power than any alternat ive." 23 21.

Today, I would stress that "long term" means the period beyond the Project's

amortization. I would further say that the work not done, to the detriment of First Nations' interests, included an assessment of the costs of various new technologies and their probable trajectories over the next several years. The speed of technological change has taken many large institutions by surprise. Had the Panel been able to engage its own experts, both new evidence and a challenge to BC Hydro assumptions

would have been possible. The absence of a practical capability to engage such people meant that practical alternatives that would have had much less, even zero, impact on the rights and interests of West Moberly and Prophet River First Nations did not get a fair hearing.

"The Panel concludes that a failure to pursue research over the last 30 years into B.C.'s geothermal resources has left BC Hydro without information about a resource that BC Hydro

thinks may offer up

700 megawatts of firm

economic power with low

environmental costs. " 24 22.

Sometimes alternatives had been taken off the table by BC Hydro derelictions. In

1983, when faced by BCUC with the same conclusion the JRP reached ("not on the

timetable set forth"),25

Hydro was

advised to

investigate the

possibilities of

geothermal energy. A modest amount of work was done in the Coast Range Mountains but shortly

abandoned.

recent years,

Hydro

has eschewed

research

and

23 JRP Report, p. 298 24 JRP Report, p. 299 25 "The evidence does not demonstrate that construction must or should start immediately or that Site C is the only or best feasible source of supply..." B.C. Utilities Commission, Site C Report, Report and Recommendations to the Lieutenant Governor-in-Council, May 1983; available at

https://www.sitecproiect.com/sites/default/files/1983050Q%20Report%20and%20Reco

o%20the%20Lieutenant%20Governor%20in%2QCouncil%20-%20BCH.pdf.

mmendations%20t

This excellent report is an

example of the quality of work that can be done by an alert and diligent regulator.

- 12-

development entirely, as being, in its view, inappropriate for its role. The consequence was that BC Hydro's EIS stated that there was perhaps 700 MW of firm power available at prices

at or below

characterized

it could

Site C,

but since the

resource

had

not

considered

available

possibility.

not been

adequately

The

Canadian

Geothermal Association vigorously disputed this conclusion, and more recently has

come forward with concrete proposals,26 but the effect of Site C will be to put off for many years any new call for IPP power.

"The

Panel

concludes

that

analytic

efforts

quantify

the

potential

benefits

geographic diversity and climate-induced changes to hydrolo gy could allow a better characterization of important resources.

23.

" 27

BC Hydro presented detailed estimates of the costs of allowab le alternatives, but

their work on Site C was much more thorough than their work on DSM or on the renewable options that were reserved by policy to IPPs. In any event, the Panel had no

capacity to challenge any of this work and all parties had to rely on it. 24.

The principal alternatives for increasing supply or moderating demand can be

grouped as follows:

(a)

Conservation, substitution, demand-side management (DSM). These were all approved under the Clean Energy Act. For a generation-ori ented utility, these were unfashionable alternatives, and appeared not to garner the same level of analysis as supply alternatives.

(b)

Thermal (gas-fired, oil-fired, coal or nuclear,

all of which were either

prohibited or disfavoured by public policy in BC). The outrigh t prohibition of nuclear alternatives, and the strong discouragement of carbonaceous sources in the Clean Energy Act removed options that might have reduced pressures on First Nations interests. Putting nuclear aside on grounds of public acceptability, small amounts of gas used for peaking power could have put off the date for large new generation capacity for years. But the

Clean Energy Act prohibited the operation of Burrard Therma l, a large 26 CanGEA, BCUC documents F-66-3 and F-66-4, Oct. 14 and 18, 2017 27 JRP Report, p. 300

- 13existing plant near load centre. It discouraged new uses for gas, despite the governmental

enthusiasm for liquefying that gas

and

shipping

abroad for burning.

(c)

Hydroelectricity

(including

big

dams,

the

Columbia

smaller run-of-river operations, micro hydro).

River

Entitlement,

Here, the major problem

was that the prohibition against counting BC's share of the downstream

benefits of the Columbia River Treaty meant that a large source - about

1,300 MW and 4,100 GWh, 28 versus Site C's 1,100 MW and 5,100 GWh which

had

acquired

at the cost of flooded valleys on the upper

Columbia System, was assumed to be unreliable. In fact, it is available under a treaty with the United States, normally a reliable partner. The treaty may be denounced by either side with ten years' notice: a highly unlikely event, in my opinion, because of the great benefits this historic

investment confers on both countries, but in any case the ten-yea r clause was inserted so that there would be plenty of time to construct alternatives if need be. As it stands, the BC government instantly sells its entitlement back to the US at spot market prices, which are generally less than a third

of the cost of Site C power.

(d)

Tidal: A convincing case was made that this resource is not econom ic, or technologically mature enough, to be considered.

(e)

Geothermal: As noted, this may be a highly attractive source in economic, environmental,

and

First

Nations'

concerns,

but

was

left

out

consideration because neither BC Hydro nor its owner took the advice of the BC Utilities Commission in 1983.

(f)

Wind:

Hydro saw opportunities for wind power and included it in

portfolios of alternative means to generate 5,100 GWh a year. Their costs

28 Cathy Eichenberger, BC Ministry of Energy, Mines and Mineral Developm ent, personal communication.

The downstream benefits vary with precipitation and are currently under negotiation, with the US side claiming they are worth a lot less money after 2024.

- 14-

estimates were high at the time and are even more so now.29 It would now appear

that

wind

alone

could

accommodate

all

BC's

marginal

requirements for decades at prices much less than Site C. BC Hydro was concerned about integrating an intermittent resource, but admitted that the

very large existing storage capacity in its reservoirs was underu tilized.

(g)

Solar photovoltaic:

Cost

and

the

same

concern

about integration

intermittent sources led BC Hydro to add rather arbitrary additio ns to their assumed price for solar. In addition they attributed a higher cost of capital to the solar, wind, and run-of-river IPPs, and ignored the fact that IPPs would

pay taxes.

Here,

perhaps more obviously than elsewhere,

Hydro's assessment methodology produced results biased in favour of Site C.

25.

All supply alternatives save Site C and DSM were prohibi ted by policy from

exploitation by BC Hydro. They were reserved for IPPs on grounds of their assumed

greater efficiency. BC Hydro became their sole, and not always enthusiastic, consumer. What in my opinion is a cultural or institutional preference for large-scale hydro in BC Hydro was reinforced by the policy of the British Columbia government. 26.

In brief, BC Hydro did not favour run-of-river IPP projects, whose modest scale

would have made them suitable for First Nations' develop ment, on grounds of cost and seasonal intermittency; nor wind on grounds of unrelia bility; nor solar on grounds of

diurnal intermittency and seasonal variation. Storage, other than that represented by the large quantities of water behind dams on the Columb ia and Peace systems, was thought

hopelessly

straightforward

expensive,

although

integration of much

that

existing

storage

more renewable energy,

would

allow

the

so that the relatively

inexpensive wind and solar options could be added to assure d supply. 27.

The JRP missed one point which should have been obviou s to BC Hydro, namely

that IPP contract renewals could be expected to be less expensive than the initial contracts. Most such projects can be expected to substa ntially amortize their capital

29 The median of 42 wind bids in Xcel's Colorado solicitation was US$1 8. 1 0/MWh for industrial (42,000 MW) quantities of electricity, which raised eyebrows througho ut the industry.

- 15costs in an initial contract, but the equipment will typically have a longer operation al life.

Lowering the presently very high costs of IPP power30 would moderate somewhat the pressure on rates while still seeing a flow of taxes to all levels of government.

Part 2: The BCUC Inquiry of 201 7 28.

Before the JRP was created, the BC government decided not to refer the Project

to the BCUC by exempting it from the BCUC's review through s. 7 of the Clean Energy Act , s. 7(1 )(d).

29.

The

arguments.

Panel decided to pay special attention to the economic and financial It was

frustrated,

noted

above,

by the

inability

hire

specialist

assistance.

30.

At the conclusion of its work, the Panel felt more strongly than ever that the

Project should be referred to the BCUC, at least for certain parts of the analysis that the panel was unable to perform. In the JRP Report, the Panel recommended that if the

Project should proceed, "a first step should be the referral of Project costs and hence unit energy costs and revenue requirements to the BC Utilities Commission for detailed

examination."31 In addition, the Panel recommended that, "if Ministers are inclined to proceed, they may wish to consider referring the load forecast and demand side

management plan details to the BC Utilities Commission."32 These recommendations

were rejected.33 31.

In 2015 and 2017, new governments were elected in Ottawa and BC. The new

federal government did

not propose to

reopen

issues concluded

by the

government. In BC, the new government similarly declined to rescind the 2014 decision approving the

Project,

opting

instead for a three-month study of a subset of the

economic issues it raised while not slowing construction.

On August 2, 2017, the

provincial government by Order-in-Council 244, tasked the BC Utilities Commiss ion with

a review to be delivered by November 1 , 2017.

30 $88.90/MWh for the most recent fiscal year. BC Hydro, Annual Service Plan Report 2016/17, p. 24 31 JRP Report, p. 280 32 JRP Report, p. 306 33 B.C Environmental Assessment Office, "EAO Executive Director's Response to the Joint Review Panel Report for BC Hydro's Site C Clean Energy Project," n.d. [Dec. 2014], pp 14, 15

- 1632.

The Terms of Reference of the review were highly restricti ve. The Commission

had to accept as the basis for its analysis the load forecas t of BC Hydro. Since that forecast seemed to require new generation, the Commission was required to assess alternatives to Site C. Those alternatives had to be within the scope of the Clean Energy Act. And since the most sensitive point for the provincial govern ment was the effect on rates

the

Commission

was

supposed to make an

assessment of the effects of

alternatives on what ratepayers would face in their monthly bills, both before and after the next election. It had to provide a preliminary report in six weeks, hold truncated public hearings, and deliver a final report in 12 weeks. The BCUC was asked, in other words, to focus on a subset of financial questions, leaving aside First Nations' and environmental concerns, as well as the overall justification of the Project in terms of its economic costs and benefits.

33.

This was a poisoned chalice. If the future held less demand than posited by BC

Hydro's discredited forecasts, then the question of alternatives was moot. But the Terms of Reference made it clear that BCUC had to devote a substan tial part of its available staff time to the analysis of alternatives that might not be required at all, or for a very long time.

34.

The Terms of Reference did not allow for a rigorous analysi s of the financial and

economic issues posed by Site C. They focused the Commi ssion on costs, not needs. They did not allow the Commission to examine BC Hydro's suspect load forecast. 35.

urged

the

Commission

to take

expansive

view of its

mandate.

submission on August 28, 2017, I argued that the Commission should not solely rely on

BC Hydro's forecast of peak capacity demand and energy demand .34 In the event, the Commission limited its analysis to the low bound of BC Hydro's forecast range which was already too high. Their report and reasoning made it clear that, unfettered, they would have adopted a lower forecast.

34 Swain, H. BCUC F-36-1 , 28 August 2017

- 1736.

A remarkable 28 pages of its final report conce rns environmental, social, and

First Nations issues it was instructed to ignore.35 37.

Subsequent to the delivery of the BCUC Repor t on Nov. 1, 2017, two provincial

deputy ministers signed

letter raising questions about the

BCUC

analysis

and

results,36 to which the BCUC responded.37 In my view, the deputies' letter exhibited prejudice and a bias towards completion of Site C. 38.

In the event, and directly as a result of its limited terms of reference, the BCUC

inquiry produced an equivocal result that allowe d the provincial government to conclude that, even though the Project was economicall y loss-making, the assumed but incorrect requirement to pay off the sunk costs immediatel y would be an unbearable burden for ratepayers, and so the Project should continue.

Date:

31/Jan/2018

Harry Sheldon Swain

35 BC Utilities Commission, Inquiry Respecting Site C: Final Report to the Government of British Columbia, November 1, 2017, pp. 10-37

36 D. Nikolejsin and L. Wanamaker, letter to D. Morton , 15 November 2017; 37 D. Morton, letter and enclosure to D. Nikolejsin and L. Wanamaker, 23 November 2017

- 18-

Schedule "A" January 2018

Harry Sheldon SWAIN Address:

838 Pemberton Road, Victoria, B.C. V8S 3R4, Canada

Phone: 250-370-0001

E-mail: swainh@telus.nct Born:

26 July 1942, Prince Rupert, B.C. Canadian citizen

Experience:

President, Trimbelle Limited, July 1998; continued as Trimbelle Investmen ts Limited, 2008; Partner, Sussex Circle, September 1998-2002 Current:

President, Trimbelle Investments Limited Associate Fellow, Centre for Global Studies, University of Victoria Board member and Vice-President, Foundation for the Victoria Symphony Past:

Board member, Treasurer and President, Victoria Symphony Society, 2008-15 Chair, Joint Review Panel, Site C, 2013-14 Advisory Board, Toronto Addiction Rehabilitation Centre

Advisory Board, School of Public Administration, University of Victoria Director, Pacific Climate Impacts Consortium Advisory Board, Pacific Marine Analysis and Research Association Audit, and Evaluation and Performance Measurement Committees, Departmen t of Indian Affairs and Northern Development Subcommittee on Public Inquiries, Committee on Judicial Independence, Canadian Judicial Council Partner, Sussex Circle Inc. Chair, Research Advisory Panel, Walkerton Inquiry, Ontario, 2000-02 Chair, Expert Panel on water and wastewater infrastructure, Ontario,

2005 Chair, Expert Panel on safe drinking water for First Nations, Canada, 2006 Fellow and Governor, Royal Canadian Geographical Society Management Board member, Canadian Geographic Enterprises Board member, Canadian Bank Note Limited Board member, Nikron Technologies Inc. Board member and Audit Committee Chair, OSIFA Board member, OMEIFA Board member, Ontario Infrastructure Projects Corp. Chair, Canadian Biosciences Commercialization Institute Member, Founders Network Editorial Board, Isuma Senior Managing Director, Corporate and Investment Banking, SG Canada, March 1998 Director, Hambros Bank Ltd., Sept. 1996, CEO, Hambros Canada Inc., and Representative of Hambros Bank Limited in Canada, April 1997 Directorships: Hambros Bank Limited (U.K.), Hambros Canada Inc., Strategic Value Corp., Bonham & Co HFM (UK) Ltd., 1996-98; Hambros Tower Hill Holdings Ltd. 1996-98 Special Advisor to the Minister of Finance, Ottawa, October 1995; on secondment to the Bank of Montreal, Toronto, January 1996

- 19 -

Deputy Minister, Department of Industry, Ottawa, September 1992

Directorships: Business Development Bank of Canada, Public Policy Forum, Canadian Tourism Commission, Communications Research Centre Deputy Minister, Department of Indian Affairs and Northern Developme nt, Ottawa, October 1987

Assistant Secretary to the Cabinet for Economic and Regional Development Policy, Privy Council Office, May 1985 Assistant Deputy Minister (Plans), Department of Regional Industrial Expansion, Ottawa, August 1984

Director, Industry, Trade and Technology, January 1981; Deputy Secretary (Projects), May 1982; Deputy Secretary (Operations), November 1982, Ministry of State for Economic (and Regional) Development, Ottawa, January 1981

President, H.S. Swain and Co. Ltd., Sidney, B.C., September 1980 Assistant Deputy Minister (Energy), B.C. Ministry of Energy, Mines and Petroleum Resources, Victoria, January 1980 Senior Advisor, Renewable Energy Resources; Director General, Electrical Coal Uranium and Nuclear Energy; Energy Mines and Resources Canada, Ottawa, January 1977

Executive, Temporary Assignment Pool, Treasury Board Secretariat; on loan to Department of Regional Economic Expansion as Co-Chairman, Intergovernmental Waterfront Committee, Halifax; and in Policy and Coordination Branch, Ottawa, January 1976 Project Leader and Research Scholar, Urban and Regional Systems Project, International Institute

for Applied Systems Analysis, Laxenburg, Austria, January 1974 Director, External Research, Ministry of State for Urban Affairs, Ottawa, May 1971 Assistant Professor, Department of Geography, University of British Columbia, Vancouver, September 1970

Lecturer, Department of Geography, and Lecturer in Geography at Scarborough College,

University ofToronto, September 1968 Education:

Partners Directors and Officers Examination, Canadian Securities Institute, 1997

University of Victoria, 1997: LL.D Cambridge University, 1969-70: postdoctoral fellow, St. Catharine's College

University of Minnesota, 1964-68: graduate student in urban geography; collateral study in economics, statistics and sociology; M.A. 1967, PhD 1970 University of British Columbia, 1960-64: honours in geography; collateral study in economics and architecture; B.A. (Hons.) 1964

-20Publications Books, monographs, etc.:

With Cotton Mather, St. Croix border country, Pierce County Geographical Society, Prescott, Wisconsin, 1968 Reviewed by W.F. ZeLinsky, Annals AAG, Dec. 1970 802-3; by Pierce F. Lewis, Geogr. Rev, 1970, 159-61; and by Earl Chapin, St. Paul Pioneer Press Central place networks, doctoral dissertation, University of Minnesota, 1970, 379pp. (Ed.), National settlement strategies east and west, ILASA CP 75-3, 1975 (Ed., with Ross D. MacKinnon), Issues in the management of urban systems, IL\SA CP 75-4, 1975

(Ed.), The IIASA project on urban and regional systems, IIASA SR 75-1, 1975 (Ed., with Martyn Cordey-Hayes and Ross D. MacKinnon), special issue of Environment and Planning A, 7:7, papers from December 1974 conference on national systems and strategies, ILASA, October 1975 With J.K. Stager, Canada North: journey to the High Arctic, Rutgers University Press, 1992 With Fred Lazar and Jim Pine, Watertight: the case for change in Ontario's water and wastewater sector, report of the water strategy expert panel, Queen's Printer, Toronto, July 2005

With Stan Louttit and Steve E. Hrudey, Report of the expert panel on safe drinking water for First Nations, Canada, Indian Affairs and Northern Developm ent, Ottawa, November 2006 Oka: a political crisis and its legacy, Vancouver: Douglas & Mclntyre, 2010. ISBN 978-1-55365429-2.

Excerpted in The Citizen, Ottawa, 19 September 2010, A8 Donner Prize runner-up for 2010.

With James Mattison and Jocelyne Beaudet, Report of the Joint Review Panel on the Site C Clean Energy Project, Canadian Environmental Assessment Agency, Ottawa, and BC Environmental Assessment Office, Victoria, May 2014 Articles:

with Peter P. Waller, "Changing patterns of oil transportation and refining in West Germany," Economic Geography 43:2 (1967) 143-56 With J. Parlour and M. Ulrich, "System, secretariat, and spatial scale," Ministry of State for Urban Affairs DP 1, 28 May 1971, Ottawa With J. V. Minghi and D. Rumley, "The Vancouver civic election of 1970: a preliminary report," 97 114 m R. Leigh, ed., Contemporary geography: western viewpoints, vol. 12 of B.C. Geographical Series, Vancouver, 1972

"Information requirements for urban research and policy," Canadia n Surveyor, 26:5 (1972) 484-7 "Research for the urban future," 22"d International Geograp hical Congress, Montreal, 15 August 1972

With Allan O'Brien, "Some avenues for urban systems analysis," in M. Rousselot, ed., Proc. IIASA planning conference on urban and regional systems, IIASA38, Laxenburg, 1973, 23-5 and 163-8

38 International Institute for Applied Systems Analysis, Laxenbur g, Austria

-21 -

"Models of national settlement systems: comments on two papers by Cordey-Hayes," IIASA WP 74-

31, August 1974

"IIASA holdings of materials on national settlement systems and policies," IIASA WP 74-47, September 1974

"Solar option: the cost of land," IIASA WP 75-15, Feb. 1975 "Revised 1975 program: management of urban and regional systems," IIASA URB-1, February 1975

"Evaluating growth proposals," IIASA WP 75-33, April 1975 With John Casti, "Catastrophe theory and urban processes," IIASA RM 75-14, April 1975 Reprinted in J. Cea, ed., "Optimization techniques: Proc. 7th IFIP Conf., Nice, Sept., 1975," Lecture notes in computet science, 40 (1976) 388-406, SpringerVerlag, Berlin

With Claire de Narbonne, "French urban research institutions," IIASA RM 75-19, May 1975; rev. as "Urban research institutions in France,' October 1975

With Peter Hall and Niles Hansen, "Urban systems: a comparat ive analysis of structure, change and public policy," IIASA RM 75-35, July 1975 With Peter Hall and Niles Hansen, "Status and future directions of the Comparative Urban Regions study: a summary of workshop conclusions, IIASA RM 75-59, November 1975

With William C. Clark, "Hypotheticality, resilience and option foreclosure," IIASA WP 75-

80, July

1975

With Malcolm I. Logan, "Urban systems: a policy perspective," Environment and Planning A, 7:7 (1975) 743-55 Translated and reprinted in Mitteilungen des Oesterreichisches Institut fuer Raumplanung, Vienna With R. Overend and T.A. Ledwell, 'Canadian renewable energy prospects," Solar Energy 23 (1979) 459-70

"The Halifax-Dartmouth Waterfront project," in W.T. Perks and I.M. Robinson, eds., Urban and regional planning in a federal state: the Canadian experien ce, McGraw-Hill, New York, 1979, 271-81 "Temptation of corruption," Ethics in civil service, 128-37, National School of Public Administration, Warsaw, 1996 With Tim Garrard, "Resourcing the federal effort in investme nt promotion: Investment Partnerships Canada in light of international practices," Sussex Circle, Ottawa, June 2000 "Privatization in Canada and lessons for Russia," chapter 3 in A. Radygin, R. Entov, G. Malginov, Y. Gritsun, V. Bondarev, O. Prerdeina, H. Swain and T. Goodfello w, Transformation of ownership relationship: comparative analysis of the Russian regions and the general problems of the emergence of the new system of ownership rights in Russia, Institute for Economy in Transition, Moscow, 2001; also published in Russian With D. R. O'Connor, chapters 3, 5-8 and 15 of Report of the Walkerton Inquiry Part 2, Queen's

Printer, Toronto, May 2002

-22With J. Carruthers, K. Minden and C. Urban, "Corporate governanc e and accountability in Canada,"

section 5, pp. 137-74 in A. Radygin et a!, The problems of corporate governance in Russia and its regions, Institute for Economy in Transition, Moscow, 2002; also published in Russian

With Harvey Schipper and Gale Murray, "Moving forward, looking forward: a new path for Canada's health care system," The Change Foundation, Toronto, October 2003

"A strategy for safe drinking water," in S.E. Hrudey, ed., Drinking water safety: a total quality management approach, Institute for Risk Research, Universit y of Waterloo, 2003, 83; also www.ittneram.ca

"Canadian corporate bankruptcy: law and public policy," Ch. 7 in A.D. Radygin, A.E. Gontmakher, M.G. Kuzyk, I.V. Mezheraups, H. Swain, Yu. V. Simachov, N.A. Shmeleva and R.M. Entov, The institution of bankruptcy: development, problems, areas of reforming, CEPRA, Institute for Economy in Transition, Moscow, 2005. In Russian as HHCTHTYT EAHKPOTCTBA

With Ian D. Clark, "Distinguishing the real from the surreal in management reform: suggestions for beleaguered admuiistrators in the government of Canada," Canadian Public Administration, 48:4, pp. 453-476, winter 2005 In Russian in 3KOHOMtiuecKaH nontiTHKa, November 2006 "Mixed ownership companies in Canada," Institute for the Economy in Transition, Moscow, 2007

With Emma Sharkey, "Climate change and water users in B.C.," Pacific Climate Impacts Consortium, Centre for Global Studies, University of Victoria, August 2007 "Setting die scene: the challenge of climate change," Working Paper, Local Government Institute, School of Public Administration, University of Victoria, October 2007 With C.L. Abbott, K.E. Bennett, K. Campbell and T.Q. Murdock, "Forest pest and climate change symposium," Dunsmuir Lodge, Pacific Climate Impacts Consortiu m, Victoria, 14-15 October 2007 "Drinking water and wastewater: a primer," Policy Options, July-August 2009, 26-30

"Negotiating Treaty Land Entitlement in Saskatchewan," in Tasha Hubbard and Marilyn Poitras, The Land is Everything, Office of the Treaty Commiss ioner of Saskatchewan, 2014, 68-84

With Ian D. Clark, "Program Evaluation and Aboriginal Affairs: a history and a thought experiment," pp. 51-69 in E. Parson, ed., A Fine Balance, McGill-Queens University Press, 2015 With James Baillie, "Tsilhqot'in Nation v. British Columbia: aboriginal title and section 35," Canadian Business Law Journal, 56 (March 2015) 264-79 "Paths to reconciliation in a post-Tsilhqot'in world," Canadia n Business Law Journal, 58:3 Pec. 2016) 313-24 With Menaka Pai and Plarvey Schipper, "Putting people first: critical reforms for Canada's health care system," Health Care in Canada, 37:2, 3(2016): 13-31 "Site C: Complete, mothball or abandon?" Submission F44-1, BC Utilities Commission Inquiry

into Site C, 28 August 2017 "Testimony to the BC Utilities Commission," Vancouver, 14 October 2017

SITE C CLEAN ENERGY PROJECT ENVIRONMENTAL IMPACT STATEMENT GUIDELINES SEPTEMBER 5, 2012

Pursuant to the British Columbia Environmental Assessment Act and the Canadian Environmental Assessment Act

This is Exhibit "

' rsfarred to in the

nn SiQfr-ih

affidavit of

sworn before me at V \ GiCTH Q. , ^ this

day of CYq/ULCm'U , 20

A Commissioner for taKigg^Arfidavits Within British Columbia

SONYA A. MORGAN Barrister and Solicitor

is*a

British Columbia

Canada

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

TABLE OF CONTENTS TABLE OF CONTENTS

PREFACE TO THE ENVIRONMENTAL IMPACT STATEMENT GUIDELINES ACKNOWLEDGEMENTS

AUTHORSHIP

EXECUTIVE SUMMARY

ABBREVIATIONS AND ACRONYMS DEFINITIONS

Introduction

1.1 Guiding Principles 1.2 Purpose of the Environmental Impact Statement 1.3 Presentation and Organization of the EIS

XV XVI

1 1 1

1 3

Proponent Description

Project Overview 3.1

Project Governance Process

3.1.1

Scheduling

3.2

Project Location

3.3

Project Components and Activities Dam and Generating Station

3.3.1

3.3.1.1 3.3.1.2

Spillways

3.3.3

Reservoir

3.3.4

Transmission Line to Peace Canyon Access Roads and Rail

3.3.5 3.3.7

3.3.8 3.3.9 3.3.10 3.3.11 3.4

7 8

Earthfill Dam Generating Station

3.3.2

3.3.6

XIV

XVII

VOLUME 1 - INTRODUCTION, PROJECT PLANNING, AND DESCRIPTION

XII XIII

TABLE OF CONCORDANCE

Highway 29 Realignment Quarried and Excavated Construction Materials Worker Accommodation Construction Phase Activities Operations Phase Activities Decommissioning Activities References

8 9

9 9 10 10 10 10

10 11 14 14 14

Need for, Purpose of, Alternatives to, and Alternative Means of Carrying Out the

Project

4.1

Need for and Purpose of the Project

4.1.1

Need for the Project

4.1.2

Purpose of the Project

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

4.2

Alternatives to the Project Alternative Means of Carrying Out the Project References

4.3 4.4

Project Benefits.. 5.1

References

Assessment Process

15 16 16 16 18 18

6.1 6.2

Provincial Agencies, Departments and Organizations The Federal Authorities

6.3

6.4

Co-operative Review Process Permitting

6.5

References

Information Distribution and Consultation Public Information Distribution and Consultation

7.1 .1

7.1

7.1.2 7.2

7.2.1 7.2.2 7.3

7.3.1 7.3.2 7.4

Pre-panel Review Stage Construction Communication

19 20

Aboriginal Group Information Distribution and Consultation Pre-Panel Review Stage Construction Communication

Government Agency Information Distribution and Consultation Pre-Panel Review Stage

Construction Communication References

21 21 22 22

VOLUME 2 - ASSESSMENT METHODOLOGY AND ENVIRONMENTAL EFFECTS ASSESSMENT

Effects Assessment Methodology 8.1

Overview

8.2

Technical Studies and Planning

8.3

Selection of Valued Components

Identification of Candidate Valued Components - Step 1 Project Interaction Identification - Step 2 Selection of Valued Components - Step 3 Assessment Boundaries

8.3.1 8.3.2

8.3.3 8.4

26 28 28

8.4.1

Spatial Boundaries

8.4.2

Temporal Boundaries

8.5

8.5.1

Effects Assessment Methods Baseline Conditions

8.5.2

Analysis of Effects

8.5.2.1 8.5.2.2 8.5.2.3 8.5.2.4

8.5.3

Description of Potential Adverse Effects on Valued Components Identification of Mitigation Measures Characterizing Residual Effects Significance of Residual Effects Cumulative Effects Assessment

29 30 30 31

31 32 33 34

8.5.3.1

Spatial and Temporal Boundaries

8.5.3.2

The Project Inclusion List

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

8.5.3.3 8.6 9

Analysis of Cumulative Effects

References

Environmental Background .. Previous Developments

9.1

9.2

Land

9.2.1 9.2.2 9.3

9.3.1 9.3.2 9.3.3 9.3.4 9.3.5 9.3.6 9.4

Geology, Terrain and Soils Land Status, Tenure, and Project Requirements. Water Surface Water Regime Water Quality Groundwater Regime Thermal and Ice Regime Fluvial Geomorphology and Sediment Transport Methylmercury Air

9.4.1

Micro-Climate

9.4.2

Air Quality

9.4.3 9.5 9.6 10 10.1

Fish and Fish Habitat Effects Assessment Valued Component Scoping and Rationale

10.2

Fish and Fish Habitat

10.2.1 10.2.2 10.2.3 10.2.4 10.2.5 10.3 11 1 1.1

Noise and Vibration Electric and Magnetic Fields References

Fish and Fish Habitat Spatial Boundaries Fish and Fish Habitat Temporal Boundaries Fish and Fish Habitat Baseline Potential Effects of the Project and Proposed Mitigation Summary of Residual Effects on Fish and Fish Habitat . References

Vegetation and Ecological Communities Effects Assessment Valued Component Scoping and Rationale

11.2

Vegetation and Ecological Communities 1 1 .2.1 Vegetation and Ecological Communities Spatial Boundaries .... 1 1 .2.2 Vegetation and Ecological Communities Temporal Boundaries 1 1 .2.3 Vegetation and Ecological Communities Baseline 11.2.3.1 Rare and Sensitive Ecological Communities 11.2.3.2 Rare Plants

36 36 37 37 37 37 40 40

40 42 43 43 45 46 46 46 47 48 49 49

49 50 50 50 51 51 52

53 53 53

53 54 54

54 55 55

56 Potential Effects of the Project and Proposed Mitigation 56 1 1 .2.5 Summary of Residual Effects on Vegetation and Ecological Communities... 57 1 1 .3 References 57

11.2.4

12.1

Wildlife Resources Effects Assessment Valued Component Scoping and Rationale

12.2 12.2.1

Wildlife Resources Wildlife Resources Spatial Boundaries...

57 58 59

iii

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

12.2.2 12.2.3

Wildlife Resources Temporal Boundaries Wildlife Resources Baseline

12.2.3.1 12.2.3.2

Butterflies and Dragonflies Amphibians and Reptiles

12.2.3.3

12.2.3.5

Migratory Birds Non-Migratory Game Birds Raptors

12.2.3.6

Bats

12.2.3.7

Furbearers

12.2.3.8

Ungulates

12.2.3.4

12.2.3.9

Large Carnivores 12.2.4 Potential Effects of the Project and Proposed Mitigation 12.2.5 Summary of Residual Effects on Wildlife Resources 12.3 References

60 61

61 62 62 62

Greenhouse Gases Effects Assessment Valued Component Scoping and Rationale Greenhouse Gases 13.2.1 Greenhouse Gases Spatial Boundaries 13.2.2 Greenhouse Gases Temporal Boundaries

13.2.3 13.2.4

13.1 13.2

Greenhouse Gases Baseline Potential Effects of the Project and Proposed Mitigation 13.2.5 Summary of Residual Effects for Greenhouse Gas 13.3 References

63 63 64 64

65 65

VOLUME 3 - ECONOMIC AND LAND AND RESOURCE USE EFFECTS ASSESSMENT 66 14

Economic Effects Assessment

14.1 14.2 14.2.1 14.2.2

14.2.3 14.2.4 14.2.5

Valued Component Scoping and Rationale Local Government Revenue

Potential Effects of the Project and Proposed Mitigation Summary of Residual Effects on Local Government Revenue

Labour Market 14.3.1 Labour Market Spatial Boundaries 14.3.2 Labour Market Temporal Boundaries 14.3.3 Labour Market Baseline 14.3.4 Potential Effects of the Project and Proposed Mitigation 14.3.5 Summary of Residual Effects on Labour Market 14.4 Regional Economic Development 14.4.2 14.4.3 14.4.4

14.4.5 14.5

Local Government Revenue Spatial Boundaries Local Government Revenue Temporal Boundaries Local Government Revenue Baseline

14.3

14.4.1

Regional Economic Development Spatial Boundaries Regional Economic Development Temporal Boundaries Regional Economic Development Baseline Potential Effects of the Project and Proposed Mitigation

Summary of Residual Effects on Regional Economic Development References

67 67 68 68 68

68 68 69 69 70 70 70 70 70 71 71

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

15.1 15.2

Traditional Lands and Resource Use Effects Assessment Valued Component Scoping and Rationale

71 72

Current Use of Lands and Resources for Traditional Purposes 15.2.1 Current Use of Lands and Resources for Traditional Purposes Spatial

Boundaries

15.2.2

Current Use of Lands and Resources for Traditional Purposes Temporal

Boundaries

15.2.3 15.2.4 1 5.2.5

Current Use of Lands and Resources for Traditional Purposes Baseline Potential Effects of the Project and Proposed Mitigation Summary of Residual Effects for Current Use of Lands and Resources for

Traditional Purposes

15.3 16

16.1

References

Land and Resource Use Effects Assessment Valued Component Scoping and Rationale

16.2

16.2.1 16.2.2 16.2.3 16.2.4 16.2.5 16.3

Agriculture

Agriculture Spatial Boundaries Agriculture Temporal Boundaries Agriculture Baseline Potential Effects of the Project and Proposed Mitigation Summary of Residual Effects on Agriculture Forestry

16.3.1 16.3.2

Forestry Spatial Boundaries Forestry Temporal Boundaries 16.3.3 Forestry Baseline 16.3.4 Potential Effects of the Project and Proposed Mitigation 16.3.5 Summary of Residual Effects on Forestry 16.4 Oil, Gas and Energy 16.4.1 Oil, Gas and Energy Spatial Boundaries

74 74 74 74

75 77 77

77 77 78 79

79 79 79

79 80

80 80 80

16.4.2

16.4.3 16.4.4

Oil, Gas and Energy Temporal Boundaries Oil, Gas and Energy Baseline Potential Effects of the Project and Proposed Mitigation 16.4.5 Summary of Residual Effects on Oil and Gas 16.5 Minerals and Aggregates 16.5.1 Minerals and Aggregates Spatial Boundaries 16.5.2 Minerals and Aggregates Temporal Boundaries 16.5.3

Minerals and Aggregates Baseline 16.5.4 Potential Effects of the Project and Proposed Mitigation 16.5.5 Summary of Residual Effects on Minerals and Aggregates 16.6 Harvest of Fish and Wildlife Resources 16.6.1 Harvest of Fish and Wildlife Resources Spatial Boundaries

16.6.2 16.6.3 16.6.4 16.6.5 16.7

16.7.1 16.7.2

Harvest of Fish and Wildlife Resources Temporal Boundaries Harvest of Fish and Wildlife Resources Baseline Potential Effects of the Project and Proposed Mitigation Summary of Residual Effects on Harvest of Fish and Wildlife Resources .... Outdoor Recreation and Tourism

Outdoor Recreation and Tourism Spatial Boundaries .... Outdoor Recreation and Tourism Temporal Boundaries

81 81 81 81 82 82 82 83 83 83 83

83 84

85 85

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

16.7.3

Outdoor Recreation and Tourism Baseline Potential Effects of the Project and Proposed Mitigation 16.7.5 Summary of Residual Effects on Outdoor Recreation and Tourism 16.8 Navigation 16.7.4

86 86

16.8.1

Navigation Spatial Boundaries

16.8.2

Navigation Temporal Boundaries

16.8.3 16.8.4

Navigation Baseline Potential Effects of the Project and Proposed Mitigation 16.8.5 Summary of Residual Effects on Navigation 16.9 Visual Resources 16.9.1 Visual Resources Spatial Boundaries 16.9.2 16.9.3

Visual Resources Temporal Boundaries Visual Resources Baseline

16.9.4 Potential Effects of the Project and Proposed Mitigation 16.9.5 Summary of Residual Effects on Visual Resources 16.10 References VOLUME 4 - SOCIAL, HERITAGE, AND HEALTH EFFECTS ASSESSMENT.. 17

85 86

Social Effects Assessment Valued Component Scoping and Rationale 17.2 Population and Demographics 17.2.1 Population and Demographics Spatial Boundaries 17.2.2 Population and Demographics Temporal Boundaries 17.2.3 Population and Demographics Baseline 17.2.4 Potential Effects of the Project and Proposed Mitigation 17.2.5 Summary of Residual Effects on Population and Demographics 17.3 Housing

17.1

17.3.1 17.3.2

Housing Spatial Boundaries Housing Temporal Boundaries

17.3.3

Housing Baseline 17.3.4 Potential Effects of the Project and Proposed Mitigation 1 7.3.5 Summary of Residual Effects on Housing 1 7.4 Community Infrastructure and Services 17.4.1 17.4.2 17.4.3 17.4.4

1 7.4.5 17.5

Community Infrastructure and Services Spatial Boundaries Community Infrastructure and Services Temporal Boundaries .. Community Infrastructure and Services Baseline Potential Effects of the Project and Proposed Mitigation

Transportation Spatial Boundaries Transportation Temporal Boundaries 17.5.3 Transportation Baseline 17.5.4 Potential Effects of the Project and Proposed Mitigation 1 7.5.5 Summary of Residual Effects on T ransportation 17.6 References

18.1

87 88 88 88 88

88 89 90 90 91 91

91 92 92

93 93 93 94 94 94

94 94 94 95

95 95 95 95

Summary of Residual Effects on Community Infrastructure and Services .... 96 Transportation

17.5.1 17.5.2

Heritage Resources Effects Assessment Valued Component Scoping and Rationale

96 96 97 97 97 98 98 98

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

18.2

Heritage Resources

18.2.1

18.2.2

Heritage Resources Spatial Boundaries Heritage Resources Temporal Boundaries

18.2.3

99 99 99

Heritage Resources Baseline 18.2.4 Potential Effects of the Project and Proposed Mitigation 18.2.5 Summary of Residual Effects on Heritage Resources.... 18.3 References

100

Health Effects Assessment Valued Component Scoping and Rationale 19.2 Human Health 19.2.1 Human Health Spatial Boundaries

101

19.1

19.2.2 19.2.3

Human Health Temporal Boundaries Human Health Baseline

19.2.4

Potential Effects of the Project and Proposed Mitigation 19.2.5 Summary Residual Effects on Human Health 19.3 References

99 100 101 101 102 102 102 102

102 103 103

VOLUME 5 - ASSERTED OR ESTABLISHED ABORIGINAL RIGHTS AND TREATY RIGHTS, ABORIGINAL INTERESTS AND INFORMATION, ENVIRONMENTAL MANAGEMENT PLANS, AND FEDERAL INFORMATION REQUIREMENTS

104

Asserted or Established Aboriginal Rights and Treaty Rights, Aboriginal Interests and Information Requirements 20.1 Aboriginal Groups 20.2 Aboriginal Groups Background Information

104 104

105

20.3 20.4

Asserted or Established Aboriginal Rights and Treaty Rights Aboriginal Accommodation

106

20.5

Outstanding Aboriginal Issues Other Interests of Aboriginal Groups

106 107

20.8

Aboriginal Consultation and Engagement Aboriginal Summary

20.9

References

107

20.6 20.7

21 21.1 22 22.1 23

23.1 23.2

106 107 107

Summary of Proposed Environmental Management Plans References

108

Compliance Reporting

110

References Requirements for the Federal Environmental Assessment Effect of the Environment on the Project

110

110 111

112

Potential Accidents and Malfunctions Cumulative Environmental Effects

113 114

23.5

Capacity of Renewable Resources Requirements of any Follow-up Program

23.6

References

115

23.3 23.4

Summary of Potential Residual Effects of the Project

114 114

115

vii

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

Complete Lists of Mitigation and Follow-up Measures

116

Conclusion

116

EIS Guidelines References

116

Appendices

122

List of Tables The tables listed below are found in these EIS Guidelines. Table 8.1

Example of an interactions matrix used to screen project interactions

Table 8.2

Spatial boundary descriptors

Table 8.3

Residual effects characterization

Table 8.4

Summary of assessment of potential significant residual adverse effects

Table 9.1

The Proponent proposes to use the following hydraulic models to predict potential changes in surface water hydrology

Table 10.1

Fish and fish habitat valued component rationale

Table 10.2

Fish and fish habitat assessment areas

Table 11.1

Vegetation and ecological communities valued component rationale

Table 11.2

Vegetation and ecological communities assessment areas

Table 12.1

Wildlife resources valued component rationale

Table 12.2

Wildlife resource assessment areas

Table 13.1

Greenhouse gases valued component rationale

Table 13.2

Greenhouse gases assessment areas

Table 14.1

Economic conditions valued components rationale

Table 14.2

Local government revenue assessment areas

Table 14.3

Labour market assessment areas

Table 14.4

Regional economic development assessment areas

Table 15.1

Current use of lands and resources for traditional purposes valued component rationale

Table 15.2

Current use of lands and resources for traditional purposes assessment areas

Table 16.1

Land and resource use valued components rationale

Table 16.2

Agriculture assessment areas

Table 16.3

Forestry assessment areas

viii

Site C Clean Energy Project Environmental Impact Statement Guidelines Table of Contents

Table 16.4

Oil, gas and energy assessment areas

Table 16.5

Mineral and aggregates assessment areas

Table 16.6

Harvest of fish and wildlife resources assessment areas

Table 16.7

Outdoor recreation and tourism assessment areas

Table 16.8

Navigation assessment areas

Table 16.9

Visual resources assessment areas

Table 16.10

Proposed visual resources receptor sites

Table 17.1

Social valued components rationale

Table 17.2

Population and demographics assessment areas

Table 17.3

Housing assessment areas

Table 17.4

Community infrastructure and services assessment areas

Table 17.5

Transportation assessment areas

Table 18.1

Heritage resources valued component rationale

Table 18.2

Heritage resources assessment areas

Table 19.1

Human health valued component rationale

101

Table 19.2

Human health assessment areas

102

Table 23.1

Federal requirements effects assessment concordance table

111

Table 24.1

Summary of assessment of potential environmental effects ..

115

List of Figures The figures listed below are found in these EIS Guidelines. Figure 3.1

Site C project location

Figure 8.1

Conceptual representation of the environmental assessment process

Figure 8.2

Decision process for the selection of valued components

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A Corffmission^r for takm§^ifMivifs Within British Columbia

SONYAA MORGAN Barrister ®nd Solicitor

REPORT OF THE JOINT REVIEW PANEL SITE C CLEAN ENERGY PROJECT BC HYDRO MAY 1,2014

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REPORT OF THE JOINT REVIEW PANEL

SITE C CLEAN ENERGY PROJECT B.C. HYDRO AND POWER AUTHORITY

BRITISH COLUMBIA

MAY, 2014

Report of the Joint Review Panel - Site C Clean Energy Project

Published under the authority of the federal Minister of the Environment, Government of Canada and the B.C. Minister of Environment, Government of British Columbia

May 2014

PDF:

Cat. No.: En106-127/2014E-PDF

ISBN:

978-1-100-23631-5

ยง Her Majesty the Queen in Right of Canada

This report was written and transmitted in English. This report has been translated into French.

Copies are available on request from:

Canadian Environmental Assessment Agency

British Columbia Environmental Assessment Office

22nd floor, 160 Elgin Street, Ottawa ON K1A 0H3 Canada

836 Yates Street, 2nd Floor, Victoria BC V8W 9V1 Canada

Email: info@ceaa-acee.gc.ca

Email: eaoinfo@gov.bc.ca

Telephone: 1-866-582-1884

Electronic version is available at: www.eao.gov.bc.ca

Electronic version is available at www.ceaa-acee.gc.ca

Site C Clean Energy Project

Joint Review Panel Report

The Panel would like to acknowledge the technical and logistic support of its joint federal-provincial

Secretariat: Courtney Trevis and Brian Murphy (Panel co-Managers); Catherine Bailey-Jourdain, Philip Seeto, Christine Levicki, Daniel Martineau and Sean Moore (Project Analysts); Lucille Jamault (Project Communications); Joanne Smith (Registry Support); Brian J. Wallace, QC (Legal Counsel); and Judith Brand (Editor).

The Panel is solely responsible for the content of this Report.

iii

Site C Clean Energy Project

Joint Review Panel Report

SUMMARY In August 2013, the federal and provincial governments named a Joint Review Panel to examine and to hold a public hearing on BC Hydro's proposed Site C Clean Energy Project, a third hydroelectric facility to be built on the Peace River, near Fort St. John. This is the report of the Panel's assessment of the Project, which the governments are required to publish. The

Panel was mandated to inquire into the environmental, economic, social, health, and heritage effects of the Project and their significance, to examine proposals for the mitigation of adverse effects, and to record assertions of Project effects on the Aboriginal rights and treaty rights of the affected First Nations and Metis peoples. Any large industrial project carries with it some costs that are not captured in a narrowly economic analysis. The question is whether the benefits from the project outweigh those costs. It is in the nature of a public hearing process that the advocates for each side speak as forcefully as they can, and that there would appear to be no middle ground. The Panel's

mandate required it to weigh both sides, and to present a balance sheet, accounting for its associated recommendations, to allow elected provincial and federal governments to determine if the benefits justify the costs. The decision on whether the Project proceeds is made by elected officials, not by the Panel. The benefits are clear. Despite high initial costs, and some uncertainty about when the power would be needed, the Project would provide a large and long-term increment of firm energy and

capacity at a price that would benefit future generations. It would do this in a way that would produce a vastly smaller burden of greenhouse gases than any alternative save nuclear power, which B.C. has prohibited. The Project would improve the foundation for the integration of other renewable, low-carbon energy sources as the need arises. The Project would also entail a number of local and regional economic benefits, though many of these would be transfers from other parts of the province or country. Among them would be opportunities for jobs and small businesses of all kinds, including those accruing to Aboriginal people.

There are other economic considerations. The scale of the Project means that, if built on BC Hydro's timetable, substantial financial losses would accrue for several years, accentuating the intergenerational pay-now, benefit-later effect. Energy conservation and end-user efficiencies have not been pressed as hard as possible in BC Hydro's analyses. There are alternative sources of power available at similar or somewhat higher costs, notably geothermal power. These sources, being individually smaller than Site C, would allow supply to better follow demand, obviating most of the early-year losses of Site C. Beyond that, the policy constraints that the B.C. government has imposed on BC Hydro have made some other alternatives unavailable. There are other costs, however, and questions of where they fall. Replacing a portion of the Peace River with an 83-kilometre reservoir would cause significant adverse effects on fish and fish habitat, and a number of birds and bats, smaller vertebrate and invertebrate species, rare plants, and sensitive ecosystems. The Project would significantly affect the current use of land and resources for traditional purposes by Aboriginal peoples, and the effect of that on Aboriginal rights and treaty rights generally will have to be weighed by governments. It would not, however, significantly affect the harvest of fish and wildlife by non-Aboriginal people. It would end agriculture on the Peace Valley bottom lands, and while that would not be significant in the context of B.C. or western Canadian agricultural production, it would highly impact the farmers who would bear the loss. The Project would inundate a number of valuable paleontological, archaeological, and historic sites. It would have modest effects on health, which could be mitigated, although the health effects of methylmercury on people who eat the reservoir fish

Site C Clean Energy Project

Joint Review Panel Report

require more analysis to be sure. For most users, outdoor recreation and tourism, transportation, and navigation would also experience effects but not significant effects. Because of the significant adverse effects identified on some renewable resource valued components in

the long-term, there would be diminished biodiversity and reduced capacity of renewable resources, should the Project proceed. The Project would not have any measureable effect on the Peace-Athabasca Delta. Risks and associated environmental effects due to potential accidents and malfunctions have been appropriately mitigated by BC Hydro through project design and planned project management.

There would be the usual health and social risks common to boom towns. The low local unemployment rate would mean that most of the Project workers would come from other parts of the province and Canada. However, increased local demand would mean that a broader range of goods and services would become available to all residents of Fort St. John. The local economic upside would largely provide the resources to deal with possible problems, including those related to health, education, and housing, especially if the arrangements BC Hydro is willing to make with local authorities can be concluded. The Peace River region has been and is currently undergoing enormous stress from resource development. In this context, the Panel has determined that the Project, combined with past, present and reasonably foreseeable future projects would result in significant cumulative effects on fish, vegetation and ecological communities, wildlife, current use of lands and resources for traditional purposes, and heritage. In some cases, these effects are already significant, even without the Project.

BC Hydro proposed a suite of mitigation measures which the Panel accepts. The Panel arrived at its own conclusions about the impact of the proposed Project and made recommendations in consequence. The Panel evaluated all proposals by participants and believes that the ones carried forward here represent a complete and practical list. For ease of reference, the Panel's specific conclusions are in shaded text boxes in each of the chapters, followed by any necessary recommendations. A complete list of the Panel's conclusions and recommendations to be taken into account under section 5 of the Canadian Environmental Assessment Act, 2012 is in Appendix 1.

Harry Swain Jocelyne Beaudet James Mattison

Site C Clean Energy Project

Joint Review Panel Report

CONTENTS Introduction

The Environmental Assessment Process

1. 1

The Legislative Framework for the Review

1.2

Stages of the Review Process

1.3

BC Hydro's Environmental Assessment Methods.

1.4

The Joint Review Panel Stage

1.5

Panel Report and Government Decision Process

Project Description

2. 7

Project Background..

2. 2

Project Components.

2.3

Project Phases

Aquatic Environment

3. 7

Hydrology

3.2

Thermal and Ice Regime

3.3

Fluvial Geomorphology and Sediment Transport

3.4

Groundwater Regime

3. 5

Water Quality

3. 6

Mobilization and Fate of Mercury

3. 7

Peace Athabasca Delta

Fish and Fish Habitat

4. 1

Proponent's Methodology

4. 2

Assessment of Fish and Fish Habitat

4.3

Mitigation Measures

4.4

Cumulative Effects Assessment.

Vegetation and Ecological Communities

5. 7

Proponent's Methodology

5.2

At-Risk and Sensitive Ecological Communities

5. 3

Rare Plants.

5.4

Plants of Interest to Aboriginal Groups

5.5

Cumulative Effects Assessment

Site C Clean Energy Project

Wildlife Resources

Joint Review Panel Report

6. 1

Proponent's Methodology

6.2

Species at Risk

6.3

Migratory Birds

6.4

Ungulates

6.5

Cumulative Effects Assessment.

Current Use of Lands and Resources for Traditional Purposes

7. 1

Proponent's Methodology

7.2

Changes in Fishing Opportunities and Practices

7.3

Changes in Hunting and Non-Tenured and Subsistence Trapping Opportunities and Practices ... 103

7.4

Changes in Other Traditional Uses of the Land.

109

7.5

Cumulative Effects Assessment

113

Asserted or Established Aboriginal Rights and Treaty Rights 8. 1

Affected Aboriginal Groups

Land and Resource Use

123

128

9. 1

Other Harvest of Fish and Wildlife Resources

128

9. 2

Agriculture.

145

9. 3

Effects on Other Resource Industries

150

9.4

Transportation

153

9.5

Air Navigation

159

9. 6

Water Navigation

160

9.7

Outdoor Recreation and Tourism.

172

Community Life

182

10. 1

Population and Demographics

182

10.2

Housing

185

10.3

Community Infrastructure and Services

188

10.4

Employment, Labour Markets and Local Residents.

193

10.5

Local Government Revenue

196

10.6

Regional Economic Development.

198

Human Health

11.1

Ambient Air Quality.

202

vii

Site C Clean Energy Project

Joint Review Panel Report

11.2

Potable and Recreational Water Quality.

208

11.3

Noise and Vibration

211

11.4

Electric and Magnetic Fields

217

11.5

Methylmercury in Fish

219

11.6

Other Participant Views Related to Human Health

224

11.7

Panel's Overall Analysis on Human Health

225

Heritage Resources ..

227

12.1

Physical Heritage .

227

12.2

Cultural Heritage..

234

12.3

Visual Resources.

238

Environmental Protection and Management

241

13.1

GHG Emissions

.241

13.2

Effects of the Environment on the Project

243

13.3

Accidents and Malfunctions

249

13.4

Cumulative Effects Assessment.

.254

13.5

Capacity of Renewable Resources

262

13.6

Environmental Management Plans, Follow-up and Monitoring

266

Project Purpose, Cost, and Benefits

271

14.1

Purpose of the Proposal

271

14.2

Project Benefits

272

14.3

Project Costs

279

Need for and Alternatives to the Project

282

15.1

Demand

282

15.2

Demand Moderation.

287

15.3

Supply: Energy

291

15.4

Supply: Capacity

296

15.5

Policy Constraints on Supply

300

15.6

Panel's Overall Analysis on Need for the Project

305

Panel's Reflections

307

Appendix 1

List of Panel's Conclusions and Recommendations

310

Appendix 2

Agreement and Panel Terms of Reference

326

viii

PROVINCE OF BRITISH COLUMBIA

ORDER OF THE LIEUTENANT GOVERNOR IN COUNCIL Order in Council No.

244

, Approved and Ordered

August 02,2017

Lieutenant Governor Executive Council Chambers, Victoria

On the recommendation of the undersigned, the Lieutenant Governor, by and with the advice and consent of the Executive Council, orders that the attached order, British Columbia Utilities Commission Inquiry Respecting Site C, is made.

This is Exhibit "

" referred to in the

affidavit of VWrU 7WgVlcA A sworn before me aiPVifWW, & this 3>l^day of JfxAua T"?

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A Commissionerfor takingAfMaws Within British Columbia

SONYA A. MORGAN Barrister and Solicitor

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General

Presiding Member of the Executive Council

(This pari isfor administrative purposes only and Is notpart ofthe Order,)

Authority under which Order is made:

Act and section:

Utilities Commission Act, R.S.B.C, 1996, c. 473, s. 5

Other: 040148786

page 1 of 3

British Columbia Utilities Commission Inquiry Respecting Site c

Definitions

In this order:

"Act" means the Utilities Commission Act; "Site C project" means the authority's project to construct a third dam and hydroelectric generating station, including related transmission facilities, on the Peace River to add 1 100 megawatts of firm capacity and 5 100 gigawatt hours of annual energy to the authority's system. Referral to commission

By this order, the Lieutenant Governor in Council, under section 5 (1) of the Act, requests that the commission advise the Lieutenant Governor in Council respecting the Site C project in accordance with the terms of reference set out in section 3 of this order.

Terms of reference

The terms of reference in accordance with which the commission must inquire into the matter referred to it by section 2 are as follows: (a) the commission must advise on the implications of (i) completing the Site C project by 2024, as currently planned,

(ii) suspending the Site C project, while maintaining the option to resume construction until 2024, and

(iii) terminating construction and remediating the site; (b) more specifically, the commission must provide responses to the following questions: (i) After the commission has made an assessment of the authority's expenditures on the Site C project to date, is the commission of the view that the authority is, respecting the project, currently on time

and within the proposed budget of $8,335 billion (which excludes million project reserve established and held by the

the $440

province)?

(ii) What are the costs to ratepayers of suspending the Site C project, while maintaining the option to resume construction until 2024, and what are the potential mechanisms to recover those costs?

(iii) What are the costs to ratepayers of terminating the Site C project, and what are the potential mechanisms to recover those costs? (iv) Given the energy objectives set out in the Clean Energy Act, what, if any, other portfolio of commercially feasible generating projects

and

demand-side management initiatives could provide similar benefits (including firming; shaping; storage; grid reliability; and

maintenance or reduction of 2016/17 page 2 of 3

greenhouse gas emission

levels) to ratepayers at similar or lower unit energy cost as the Site

C project? (c) in making applicable determinations respecting the matters referred to in paragraphs (a) and (b), the commission must use the forecast of peak capacity demand and energy demand submitted in July 2016 as part of the

authority's Revenue Requirements Application, and must require the authority to report on

(i) developments since that forecast was prepared that will impact demand in the short, medium and longer terms, and (ii) other factors that could reasonably be expected to influence demand from the expected case toward the high load or the low load case;

(d) the commission must consult interested parties respecting the matters referred to in paragraphs (a) and (b); (e) in carrying out its inquiry, the commission must be guided by the understanding that the inquiry is not a reconsideration of decisions made in the environmental assessment process or by statutory decision makers or the courts;

(0 the commission may obtain expert advice on any subject related to the inquiry and may exercise any of its powers under the Act in order to carry out the inquiry in accordance with these terms of reference; (g) the

commission must submit to the minister administration of the Hydro and Power Authority Act

charged

with

the

(i) a preliminary report outlining progress to date and preliminary findings by September 20, 2017, and

(ii) a

final report, including the results consultations, by November 1, 2017.

page 3 of 3

the

commission's

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Suite 410, 900 Howe Street

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Commission Secretary

Vancouver, BC Canada V6Z 2N3

British Columbia

Commission.Secretary@bcuc.com

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1.800.663.1385

Utilities Commission

bcuc.com

604.660.1102

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November 1, 2017 BCUC Inquiry Respecting Site C

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Sent via eFile

The Honourable Michelle Mungall, M.L.A. Minister of Energy, Mines and Petroleum Resources Parliament Buildings PO Box 9060 Stn Gov't Victoria, BC V8W 9E2

EMPR.Minister@gov.bc.ca

Re:

British Columbia Hydro and Power Authority - British Columbia Utilities Commission Inquiry Respecting Site C - Project No. 1598922 - Final Report

Dear Minister:

In accordance with Order in Council No. 244 dated August 2, 2017, the British Columbia Utilities Commission hereby submits its Final Report with respect to the Site C Inquiry.

Sincerely,

Original signed by:

Patrick Wruck Commission Secretary

This is Exhibit ' E Y

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SOMYA A. MORGAN Rammer and Solicitor

55604 | Site C Inquiry - Final Report

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About the BCUC Who we are

The British Columbia Utilities Commission (BCUC) is an independent

regulatory agency of the Government of British Columbia that operates

under and administers the Utilities Commission Act. The BCUC is

quasi-judicial and makes legally binding rulings.

What we do

The BCUC's primary responsibility is

the regulation of BC's energy utilities. In addition to setting rates, the BCUC regulates all franchises, privileges, and concession agreements granted to public utilities. It is our mission to ensure that ratepayers receive safe, reliable and non-discriminatory energy services

at fair rates from the utilities we regulate, while also providing utilities the opportunity to earn a fair return on their capital investments.

«•«••• • • «••••* • MM • •

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bcuc British Columbia Utilities Commission

This report was prepared in response to Order-in-Council No. 244 for the Honourable Michelle Mungall, Minister of Energy, Mines and Petroleum Resources.

British Columbia Utilities Commission Suite 410, 900 Howe Street Vancouver, BC Canada V6Z 2N3 Before:

Phone: 604.660.4700 BC Toll-free: 1.800.663.1385 Fax: 604.660.1102

David M. Morton, Panel Chair and Commissioner

Dennis A. Cote, Commissioner Karen A. Keilty, Commissioner

Richard I. Mason, Commissioner

Email: commission.secretary@bcuc.com

bcuc.com

ERRATA

Report errata

1.1

Math Error regarding Mid C price forecasts used in the Site C Calculator

Issue

The Mid C price forecasts used in the Site C unit energy cost UEC Calculator are in real terms and should have been inflated to nominal terms.

Commission comments The Panel confirms that the graph upon which the Mid C price forecasts were derived are in real F$2018 and therefore should be inflated to nominal. In the alternative portfolio spreadsheets, these same price forecasts were inflated to nominal. By correcting the Mid C price forecasts to nominal in the Site C UEC calculator, we find that the rate impact

(NPV) from Site C under the low load case is $336 million lower, at $2,852 million instead of $3,188. Under the mid load case, the rate impact from Site C is $68 million, at $3,901 million instead of $3,969 million. There is no impact on the high load case as there is no surplus energy in that scenario.

Formulas issues regarding the Commission Illustrative Alternative Portfolio

1.2

Issues

In the "Energy & capacity gap" sheet, the text box pointing to cell R42 says "Assumes ramp up at 800 GWh/yr" but the ramp up did not occur in the cells to the right of R42. This should be corrected to include the 800 GWh/yr ramp up for the years F2037 to F2041.

In the "Low LF - portfolio" sheet, the cells titled "(capacity) gap to fill" beginning at Y28 and ending at CB28 contain equal values of 1145 MW but the corresponding values in row 33 of the "Energy &

capacity gap" sheet are 985 MW (i.e., Site C gross capacity less 14% planning reserve). This should be corrected so that the values in both sheets are the same and the correct value is 985 MW. 3.

Pursuant to the change made according to #2 above, a further change is required to cells AJ31 to CB31 of the "Low LF - portfolio" sheet, all of which have the hard number of -629.96 MW rather the cell difference formula which appears in the adjacent AI31 cell and would yield a result of -470 MW.

Pursuant to the changes according to #1 to 3, there is no need for capacity from industrial curtailment in F2039 and F2040 and the in-service date for the first wind project (PC 18) can be delayed by one year from F2039 to F2040.

Commission comments The Panel confirms that the issues outlined above need to be corrected. By correcting them, we find that the

rate impact (NPV) from the Illustrative Alternative Portfolio under the low load case is $87 million lower, at $3,147 million instead of $3,234. There is no impact on the mid and high load cases as the issues affected only the low load case.

Site C Inquiry | Final Report

lof 11

ERRATA

The tables and figure in the Executive Summary would read correctly as follows:

Corrected Table on p. 7 of the Executive Summary: Rate Impact ($ million) Scenario

A. Illustrative

B. Site C

Alternative

Unit Energy Cost ($/MWh)

Difference

Illustrative

(A-B)

Alternative

Portfolio

$3,147

Commission

Site C

$2,852

$295

$31

$44

Assumptions

Finding: The Panel confirms there is no change to its finding that "[a]s can be seen in the table below, the cost to ratepayers of Site C and the Illustrative Alternative Portfolio are virtually equivalent, within the

uncertainty inherent in the assumptions." Corrected Table on p. 15 of the Executive Summary:

Summary Results of the Illustrative Alternative Portfolio (2018$)

Revised Alternative

High Load Forecast

Medium Load Forecast

Low Load Forecast

•

441 MW of wind

Portfolio composition

•

444 MW of wind

starting between F2029 and

projects starting

F2025, 288MW in F2026

F2031

between F2040 and

DSM initiatives (energy

F2041

DSM initiatives (energy

•

efficiency, optional time

efficiency, optional TOU

of use (TOU) rate,

rate, capacity focused DSM,

(energy efficiency,

capacity focused DSM,

industrial curtailment)

optional TOU rate,

81 MW of geothermal

capacity focused

projects starting in F2025

DSM)

industrial curtailment)

•

438 MW of wind projects

projects starting in

81 MW of geothermal

•

DSM initiatives

projects starting in F2025

Rate Impact of portfolio

$ 5,121 million

Site C Inquiry | Final Report

$4,618 million

$ 3,147 million

2 of 11

ERRATA

Corrected Illustrative Alternative Portfolio Rate Impact Sensitivity Analysis on p. 15 of the Executive Summary

Load

Termination costs

Financing costs

Term costs Amortization

Wind costs

Geothermal costs

Market price of surplus

$3,000

I $3,500

$4,000 I High Value

$4,500

$5,000

$5,500

$6,000

Low Value

Finding: The Panel confirms that the paragraph starting with "The graph shows" in the middle of page 16 should read: "The graph shows the cost to ratepayers of the Base Case described below, and variations

around the base case. The Base Case is in the centre of the graph and is $4,918 billion. Then, each variable is changed to a low or high value and the cost to ratepayers of that single change (while holding the other inputs constant) is shown. For example, if the Load forecast is changed to Low instead of Medium, the cost

| to ratepayers would be reduced by $1.558$1.647 billion from $4,918 billion to $3.36$3.271 billion, while all the other inputs remained as defined in the Base Case."

Corrected Site C Rate Impact Sensitivity Analysis on p. 16 of the Executive Summary

Totil Site C

Load

Market price ct surplus

$2,/.b0

II Si.ibU

B Mign V.jfi

Si,/bO

$4 /bO

Low V.li-.ir

Finding: The Panel confirms there is no change to its finding that "For Site C, as seen in the graph above, the

base case is completion costs of $10 billion, BC Hydro's mid load forecast and the Panel's Mid C forecast assumptions. The inputs and assumptions that have the greatest impact on rates are the Site C total costs and the load forecast. The market price of surplus energy has much less impact on the costs to ratepayers."

Site C Inquiry | Final Report

3 of 11

ERRATA Corrected Sensitivity Analysis on page 17 of the Executive Summary Rate Impact ($'m) Scenarios

A. Revised

B. Site C

Illustrative

Unit energy cost ($/MWh) Difference

Revised

(A-B)

Illustrative

Alternative

Portfolio

Commission Assumptions

Site C

$3,147

$2,852

$295

$31

$44

$4,618

$3,901

$717

$34

$44

$4,618

$4,842

($224)

$34

$54

$3,147

$3,793

($646)

$31

$54

$3,271

$2,852

$419

$32

$44

$5,121

$4,325

$796

$31

$44

$5,121

$5,266

($145)

$31

$54

Scenarios

Medium load forecast Medium load forecast

+ $12 billion Site C cost Low load forecast, $12 billion Site C cost Low load forecast + higher windgeothermal financing

High load forecast

High load forecast, $12 billion Site C cost

Findings: The Panel confirms there is no change to the paragraph introducing the sensitivity analysis: "The sensitivity analysis illustrates the effect of changing one input assumption at a time. To see the effect of changing more than one variable at a time, we provide a few sample scenario results below."

The Panel also confirms there is no change to the paragraph immediately below the sensitivity analysis: "The Illustrative Alternative Portfolio indicates that it is possible to design an alternative portfolio of commercially feasible generating projects and demand-side management initiatives that could provide similar benefits to ratepayers as Site C."

Site C Inquiry | Final Report

4 of 11

ERRATA

1.3

"Copy & Paste Error" in Table 43 ($4.9 billion, -$293 million)

Issue

In Table 43 in the Final Report, in the scenario "Medium load forecast + $12 billion Site C cost", Site C NPV

should read $4,911 million and the difference (-$293 million). Table 43: Summary of Sample Scenarios Rate Impact ($'m) Scenarios

A. Revised

B. Site C

Illustrative

Unit energy cost ($/MWh) Difference

Revised

(A-B)

Illustrative

Alternative

Portfolio Commission

$3,234

SiteC

Portfolio

$3,188

$46

$32

$44

Assumptions Scenarios

Medium load forecast

$4,618

$3,969

$649

$34

$44

Medium load forecast

$4,618

$1,129

$489

$34

$54

$4,911

($293)

$3,234

$4,129

($895)

$32

$54

$3,360

$3,188

$172

$33

$44

High load forecast

$5,121

$4,325

$796

$31

$44

High load forecast, $12

$5,121

$5,266

($145)

$31

$54

+ $12 billion Site C cost Low load forecast, $12 billion Site C cost Low load forecast + higher wind-

geothermal financing

billion Site C cost

Commission comments The Panel confirms there was a copy and paste error in Table 43. The numbers should have been $4,911 and

(-$293), therefore adding an additional scenario where the Alternative Portfolio is less expensive than Site C. Finding: The Panel notes that these numbers are now outdated due to the need to correct the Mid C price forecast and the issues pertaining to the low load case in the Commission Illustrative Alternative Portfolio. The Panel also notes that the correction to Mid C price forecasts results in changes to a number of scenarios.

Site C Inquiry | Final Report

5 of 11

ERRATA

1.4

Other Corrected Tables and Figures in the Final Report

The following tables and figure in the Final Report would read correctly as follows: Corrected table for Illustrative Alternative Portfolio Results (p. 165)

Summary Results of the Revised Illustrative Alternative Portfolios (2018$) v ;•

High Load Forecast

Medium Load Forecast

Low Load Forecast

•

. •• i.

Revised Alternative

•

Portfolio composition

441 MW of wind

444 MW of wind

starting between F2029 and

projects starting

F2025, 288MW in F2026

F2031

between F2039

DSM initiatives (energy

F2040 and F2041

•

DSM initiatives (energy

•

efficiency, optional time

efficiency, optional TOU

of use (TOU) rate,

rate, capacity focused DSM,

capacity focused DSM,

industrial curtailment)

optional TOU rate,

81 MW of geothermal

capacity focused

industrial curtailment)

•

438 MW of wind projects

projects starting in

•

DSM initiatives

(energy efficiency,

DSM, industrial

projects starting in F20252

81 MW of geothermal

curtailment)3

projects starting in

F20251 Rate Impact of

$ 5,121 million5

portfolio4

$ 4,618 million6

$^t2M3,147 million7

Corrected Table 39: Cost to ratepayers and UEC of Site C (p. 167) Output : Low LF - Alternative Portfo I i o

Site C Termination Cost (F$18)

1,395

million

Alternative Portfolio Cost (FS18)

2,539

million

Surplus Energy Sale (F$18)

Total Rate Impact (A+B+C)

Alt. Portfolio Volume (F18)

UEC (FS18) (B/E)

(788) million 3,147

million

82,784

30.67

per MWh

1 Appendix HC- Commission Illustrative Alternative Portfolio, Tab 'High LF - portfolio', with costs in Tab 'High LF - portfolio costs'. 2 Ibid, Tab 'Med LF - portfolio', with costs in Tab 'Med LF - portfolio costs'. 3 Ibid, Tab 'Low LF - portfolio', with costs in Tab 'Low LF - portfolio costs'. 4 Discount rate of 4% real, 6% nominal; export revenues valued at Panel's Mid C Forecast (at plant gate location), Site C $1.8 billion termination costs amortized over 30 years and assuming all resources are financed at BC Hydro's financing rate.

| 5 Appendix WC- Commission Illustrative Alternative Portfolio, Tab 'Input and Output', Cell 026. 6 Ibid, Tab 'Input and Output', Cell 017. | 7 Ibid., Tab 'Input and Output', Cell 08. Site C Inquiry | Final Report

6 of 11

ERRATA

Corrected Table 40: Cost to ratepayers and UEC of Site C (p. 167) Output: Low LF - Site C

Sunk Costs (F$18)

2,100 million

Site C Cost to Complete (FS18)

4,391

Flexibility Credit (F$18)

(66) million

Surplus Energy Sales (F$ 18)

(1,473) million

Total Rate Impact (B+C+D)

Volume (F18)

UEC (FS18) (B/F)

2,852

million

98,993

44.35 p er MWh :

Finding: The Panel confirms that the paragraph below Table 40 should read: "The comparison in the tables above show that the cost to ratepayers Illustrative Alternative Portfolio has a lower UEC than Site C

($31.6430.67/MWh compared to $44.35/MWh) but a cost to ratepayers slightly higher ($3.234$3.147 billion compared to $3,188 $2.852 billion for Site C)."

Site C Inquiry | Final Report

7 of 11

British Columbia November 15, 2017

Rcf.:

This is Exhibit

102700

ÂŤ f~

" referrad to in the ia;

affidavit

Mr. David Morton

sworn before me"3t

BC Utilities Commission

this3]

20 Ji.

Email: David.Morton@bcuc.com

A Commissioner for

Chair

Re: Inquiry Respecting Site C

Bmi$tor snd Solicitor

The Ministry of Energy, Mines and Petroleum Resources and Ministry of Finance are supporting the government decision process surrounding the future of the Site C project.

On behalf of our respective Ministers, we would like to thank the BC Utilities Commission (Commission) for the report Inquiry Respecting Site C. Completing an inquiry of this scope over an abbreviated timeframe and with high levels of public and First Nations input is a considerable achievement. As our ministries analyze the Commission's report, along with other implications associated with government proceeding with or terminating the Site C project, we want to ensure that we fully understand the assumptions and computations that the Commission made in the analysis of potential alternative sources of energy generation and capacity. Accordingly, we are requesting further explanation or additional information on the points listed below and in the Appendix attached to this letter. 1.

Did the Commission include sunk costs (the estimated $2.1 billion that has been spent to date on the project) and termination costs (the $ 1 .8 billion determined by the

Commission) in comparing the costs to ratepayers of completing Site C against the costs of pursuing an alternative portfolio of generation resources? . We were not able to determine whether the sensitivity analysis included on Page 17 of the report's executive summary includes sunk costs and termination costs consistently. If it does not, could the Commission advise on how including these

sunk and termination costs might change the cost to ratepayers and the unit energy cost (UEC) in both scenarios? 2.

In the event that government elects to terminate the Site C project, has the Commission assumed that BC Hydro would develop and finance the projects

Page 1 of 3

Ministry of

Office of the

Energy, Mines and Petroleum Resources

Deputy Minister

Mailing Address: PO Box 9319, Stn Prov Govt Victoria, BC V8W 9N3 Telephone: 250 952-0120 Facsimile: 250 952-0269

Location:

8lh Floor, 1810 Blanshard Street Victoria Website: www.em.gov.bc.ca/

included in the alternative portfolio (wind, geothemial) rather than independent power producers (IPPs)? We observe that the Commission has in some cases used BC Hydro's lower cost of capital financing to calculate the cost of the alternative portfolio presented in the

report, affecting the valuation of those projects. Could the Commission offer its view of the impact that a higher cost of capital would have on ratepayers if the alternative portfolio were developed by independent power producers rather than directly by BC Hydro? 3.

Government will need to consider the total cost of potential demand side management initiatives (rather than just the utility's costs) as it considers the alternatives. Could the Commission advise how the inquiry Terms of Reference led to assessing demandside measures based on the Utility Resource Cost standard, when Total Resource Cost has been the standard for prior Commission proceedings?

If the Site C project were terminated, the $4 billion sunk and remediation costs would need to be recovered, and the amortization period of that recovery would affect BC Hydro rales. Could the Commission please clarify whether it assumed that that these costs would be recovered over 10, 30 or 70 years? •

Fair and appropriate rate-setting principles for rate-regulated utilities typically aim to avoid causing future generations to pay for investments from which they will derive no benefit. From the Commission's perspective, can recovery of the sunk and remediation costs of Site C over longer periods of 30 to 70 years remain consistent with these inter-generational principles?

•

Recently it has been stated that recovering the project's sunk and remediation costs over a 10-year period would lead to a 10 per cent hike in BC Flydro rates. Is

this assertion consistent with the Commission's thinking? 5.

We are unaware of prior instances when anything other than BC Hydro's mid-load forecast has been used for planning purposes. For that reason, we would like to clarify:

•

Did the Commission assume lower demand for electricity (reflected in the lowload forecast used in the report) because it is forecasting a period of lower

economic growth for the province in which major power consumers such as mining, forestry, technology and commercial sectors are in decline? •

Does the Commission include in its load forecast the potential increased electrical power demand of meeting the province's stated objectives to reduce greenhouse gas emissions through greater electrification of our economy?

Page 2 of 3

We sincerely appreciate the Commission's timely response to these questions and requests for clarification. Government has committed to making a decision on the Site C project before the end of the year. The Commission's responses to our questions will assist our ministries in better understanding the report and the assumptions that underlie it as we prepare advice to support government in making a decision that will be in the best

interests of British Columbians.

I C 'CX j \c~. ( > , fc Dave Nikolejsin

Lori Wanamaker

Deputy Minister

Ministry of Energy, Mines

Ministry of Finance

and Petroleum Resources

Attachment

Page 3 of 3

Appendix: Detailed Questions for the Commission

We understand that while BC Hydro modelled over 60 scenarios and tested various assumptions, including a number of alternatives requested by the Commission, the alternative portfolio that the Commission included in the final report was not analyzed using BC Hydro's modelling tools. On this basis, government has asked BC Hydro to provide an assessment of the model used to develop the Commission's final alternative portfolio. BC Hydro will provide the Commission with the results of that assessment separately.

In our initial analysis of the report, our ministries have identified several areas that we would appreciate the Commission's feedback on. Several of our questions relate to the impact of certain assumptions made in the report, and how the costs of those assumptions would be recovered from ratepayers. We understand that BC Hydro follows standards for rate-regulated utilities in its financial statements and in preparing its applications for review by the Commission. This accounting framework follows a number of principles in relation to the amortization of capital assets and the deferral of other costs for the purpose of matching recoveries from ratepayers to periods over which benefits are provided. It would be helpful if the Commission could clarify how the choices of cost amortization and recovery periods in the Termination scenario fit within appropriate utility rate-setting principles that recognize and avoid unnecessarily transferring current utility costs to future user generations when there are clearly no longer directly-related assets or benefits

being provided. Such decisions lead rate-regulated accounting practice and use of regulatory accounts, which are areas of particular interest by the provincial Auditor

General as well as credit rating agencies. The Commission's process involved some deliberations on the cost of capital. The alternative portfolio presented in tire report assumes that BC Hydro will finance all newresources on its balance sheet. However, other than redevelopment of existing sites and

Site C, BC Hydro has, for almost three decades, been primarily procuring new supply from competitive processes or bilateral agreements that are benchmarked to competitive processes. This effectively means that BC Hydro avoids assuming such debt on its balance sheet and only recognizes the incremental costs of new energy purchases which would include the private sector's annual debt servicing costs and equity return within approved purchase contracts.

It would be helpful to understand how the Commission assesses the impact on ratepayers of the additional debt associated with the assumptions underlying the alternative portfolio. We would particularly appreciate better understanding the Commission's approach to using BC Hydro's cost of capital for IPP projects and the approach used for the cost of capital faced by an IPP (i.e. what IPPs actually pay) and the resultant rate impacts. For example, on page 159-160, the Commission appears to conclude that IPP financing is the relevant assumption for the alternative portfolio, and the BC Hydro

financing assumption should only be used for the Unit Energy Cost (UEC) analysis. However, on pages 1 67, 1 70 and Appendix C (Assumption 2), it appears that the

Commission has used BC Hydro financing (100% debt financing at a cost of 3.43%) for the alternative portfolio. If we are interpreting this correctly, we would appreciate clarification on which cost of capital should be used in analysing rate impacts.

BC Hydro has suggested that recovery in rates of sunk costs in a termination scenario should occur over a 10-year period. If the project were to continue as planned, the sunk costs, as part of the overall project costs, will be recovered over a 70-year period, consistent with the amortization of the Site C asset. The Commission model appears to exclude sunk costs in the termination scenario, and has removed those costs from the

completion scenario as well. Effectively this assumes that sunk costs will be recovered through rates over 70 years if the project is terminated. Recovering costs in rates over a shorter period has a material impact on the costs of the alternative portfolio. It would be helpful i f the Commission could provide an estimate of the impact on rates of using these two timeframes. The tables on page 17 of the executive summary and page 170 in the main report include a summary of the Commission's sample scenarios showing the effect of modifying one or more variables to the resulting Net Present Value cost to ratepayers. As noted above, the Commission's alternative portfolio does not appear to include sunk costs, and sunk costs

have also been removed on the continue scenario. The tables also include UECs. For the Site C scenario, the UECs reflect costs, including sunk costs, of Site C being either

$10 billion or $12 billion depending on assumptions. Our review of the Commission report suggests that the alternative portfolio does not include termination costs. It would be helpful if the Commission could confirm this and provide a version of the UEC portion of the table with termination costs included in the alternative portfolio. This would help provide a consistent basis for comparing costs between the scenarios of completing or terminating the project. It is our understanding that in previous proceedings the Commission has concluded that the Total Resource Cost (TRC) test is the appropriate way to evaluate demand side management (DSM) in comparison to other resources. In this inquiry, the Commissio n's model uses the Utility Resource Cost (URC) standard. We believe that using the URC

may underestimate the actual cost of DSM to ratepayers. It would be helpful for us to understand the Commission's rationale in choosing a test methodology that differs from past practice. Could the Commission confirm that the TRC test remains the appropriate metric, and if so, what impact would this have on the analysis? We have noted that the Commission has concluded that BC Hydro's low load forecast was most appropriate for an assessment of the need for the capacity of Site C. It would be helpful for us to further understand the rationale, and whether the assessment includes the load requirements needed to meet the Province's Clean Energy Act energy objectives of:

â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘

Reducing greenhouse gas emissions by 2050 by 80% less than 2007 levels; Encouraging the switching from one kind of energy source or use to another that decreases greenhouse gas emissions in British Columbia; and, Encouraging communities to reduce greenhouse gas emissions and use energy efficiently.

It would also be useful to know if the Commission examined the value of "dispatchable" resources versus intermittent resources, particularly as applied to the goal of moving industrial energy requirements now and in future to low carbon electricity. It has been government's assumption that electrification with low carbon electricity would be a key initiative to achieve greenhouse gas reductions. The provincial government is working with the Government of Canada on electricity system infrastructure investments to reduce and avoid greenhouse gas emissions, and has enabled

BC- Hydro to pursue electrification initiatives under the Greenhouse Gas Reduction (Clean Energy) Regulation under the Clean Energy Act. It would be. helpful for our ministries to understand if the Commission has a different outlook, and if the Commission could further describe the impact on its analysis of electrification initiatives to meet greenhouse gas reduction objectives. The report identifies an aggressive DSM program, coupled with load curtailments as a way to achieve the alternative portfolio scenario. We would appreciate further information from the Commission on how such load curtailments would practically be achieved in the natural resource sector without impairing operations, jobs and economic

growth for sectors already facing trade sanctions and pressures. We understand that BC Hydro has provided the Commission with a description of its view of what BC's economic environment would look like under a low load outlook scenario. It would helpful if the Commission could further describe its interpretation of the low load outlook. We observe that the Commission's view is that the outlook could be even lower than that presented in BC Hydro's low-load scenario, and we are interested in understanding how that outlook is based on realistic economic sustainability around

which the alternative portfolio would be premised.

$»*>#» •

* 9

* » » » ®

« • ••• «•

bcuc British Columbia

Utilities Commission

Suite 410, 900 Howe Street Vancouver, BC Canada V6Z 2N3 bcuc.com

604.660.4700

TF: 1.800.663.1385 F:

604.660.1102

INFORMATION RELEASE - BCUC responds to the Provincial Government's additional questions in the Inquiry Respecting Site C

November 23, 2017

Vancouver-The British Columbia Utilities Commission (BCUC) has responded to the joint letterfrom the Ministry of Energy, Mines and Petroleum Resources and Ministry of Finance seeking additional information in the BCUC's Inquiry respecting Site C. The BCUC's response is attached to this information release.

The BCUC's Inquiry into Site C was initiated by Order in Council No. 244 on August 2, 2017 and was completed with the issuance of the Inquiry Panel's Final Report on November 1, 2017. The Final Report, and all information submitted during the course of the Inquiry is publically available at www.sitecinciuirv.com. The BCUC is a regulatory agency responsible for oversight of energy utilities and compulsory auto insurance in the province of British Columbia. It is the BCUC's role to balance the interests of customers with the interests of the businesses we regulate. The BCUC carries out fair and transparent reviews of matters within its jurisdiction and considers public input where public interest is impacted.

CONTACT INFORMATION:

Erica Hamilton Director, Communications

Phone: 604.660.4727 Email: erica.hamilton@bcuc.com

Website: http://www.bcuc.com

This is Exhibit " (5) " referred to in the affidavit of SVtP.\fl(Y\ .£^£)Ai A sworn before me at NilCtfrrna. t fe_C— this day of -71 AAU/VI , 20 J2. A"Comm i ssi o n e r YoHaj^ntf'Affidavits Within British Columbia

SONYA A. MORGAN Barrister and Solicitor

»©«>##» •

« •

®®©»

David Morton

Suite 410, 900 Howe Street

bcuc

Chair and CEO

Vancouver, BC Canada V6Z2N3

British Columbia

David.Morton@bcuc.com

TF: 1.800.663.1385

Utilities Commission

bcuc.com

604.660.4700

604.660.1102

November 23, 2017

Sent via email

Dave Nikolejsin

Lori Wanamaker

Deputy Minister

Ministry of Energy, Mines and Petroleum Resources

Ministry of Finance

PO Box 9319, Stn Prov Govt

PO Box 9417, Stn Prov Govt

Victoria, BC V8W 9N3

Victoria, BC V8W 9V1

EMPR.Minister@gov.bc.ca

FIN.Minister@gov.bc.ca

Re:

British Columbia Hydro and Power Authority - British Columbia Utilities Commission Inquiry Respecting Site C - Project No. 1598922

Dear Dave Nikolejsin and Lori Wanamaker:

The Deputy Ministers' letter of November 15, 2017 poses a series of questions to the Commission regarding its Final Report on the Site C Inquiry, which was initiated by the Lieutenant Governor by Order in Council 244. The Commission thanks the Deputy Ministers for their inquiry and sets out its response below, trusting that any additional clarity or amplification of the messages in the Final Report will assist the government in its decision regarding Site C.

Sincerely,

Original signed by:

David Morton Chair and Chief Executive Officer

DM/kbb Enclosure

55604 1 Site C Additional Questions

1 of 1

Introduction The Inquiry initiated by Order in Council (OIC) 244 requested that the Commission evaluate the cost to BC Hydro ratepayers of continuing, suspending or terminating construction of the Site C dam. In its Final Report, the Commission drew two overall conclusions: â&#x20AC;˘

The cost to ratepayers of suspending construction would be significantly higher than either continuing

or terminating the project, to the tune of $3.6 billion.1 In addition, there are significant risks that it would not be possible to restart the project due to permitting and other issues.

â&#x20AC;˘

The cost to ratepayers of continuing or terminating construction is similar,2 given the assumptions that the Commission finds to be most reasonable. Both alternatives also have risks which may cause one or the other to be more costly to ratepayers either in the short-term or over a longer period.

Many of the questions posed in the Deputy Ministers' letter, in one way or another, relate to the estimates underlying these conclusions. We believe it will be helpful to provide some background and context before addressing the specific questions. In reaching its conclusions, the Commission was required to estimate the costs of each of the three options, and in the case of termination, the cost of the alternative energy that might be required. It is important to recognize

that each estimate comes with a degree of uncertainty. For example, when considering the cost of terminating the Site C project, the Commission found, based on information from BC Hydro and Deloitte, that costs could

range from $750 million to $2.3 billion.3 In order to make a comparison between the options, the Commission chose a reasonable "point estimate" of $1.8 billion based on BC Hydro's P90 estimate.4 But it would be quite possible, based on the information available to conclude that the cost of termination could be up to a billion dollars less, or half a billion dollars more. Nonetheless, in spite of this uncertainty, it was quite reasonable for

the Commission to conclude that the option of suspending the project, estimated to be $3.6 billion more than either continuing or terminating construction, would be significantly more expensive for ratepayers.

By comparison, the estimated costs to ratepayers of continuing or terminating construction, at $2,852 billion

and $3,147 billion respectively,5 were so close that it would be unreasonable for the Commission to draw a meaningful distinction between them. Given the range of estimates to terminate the project ($750 million to $2.3 billion) an even larger difference between the estimated costs to continue or to terminate would have resulted in the Commission drawing the same conclusion they were similar.

To further illustrate how using point estimates for input assumptions masks the potential variability of

assumptions, consider the original Site C completion costs. The original estimate of $8.35 billion was based on a

1 2 3 4 5

BCUC Site C Inquiry Respecting Site C Executive Summary (Executive Summary), p. 3. BCUC Site C Inquiry Respecting Site C Final Report (Final Report), p. 187. Final Report p. 128. This is BC Hydro's P90 estimate, which should only have a 10% chance of being exceeded. Final Report, Errata, p. 10 of 11.

lof 26

Class 3 estimate, which means that the expected accuracy range is from 20% under the budgeted amount to

30% over the budgeted amount - in this case a variance of $4.2 billion.6 Similarly, some of the costs associated with the Illustrative Alternative Portfolio are highly uncertain. Costs of acquiring wind generation equipment post 2025 for example, are estimates of future costs and, as such, may not

share the accuracy level of a Class 3 estimate. Accordingly, in order to rely on a numeric analysis of the costs of various options, the differences in results should be greater than the amount of uncertainty in the input assumptions. In the Inquiry, BC Hydro calculated the incremental cost to ratepayers of terminating the Site C project - including the cost of an alternative

portfolio - compared to the cost of completing, to be in the range of $6.2 billion to $11.1 billion. If this amount could be substantiated, it would provide a compelling case to continue. However, based on the evidence

available to the Inquiry we were unable to verify these amounts.7 That said, the estimates provided in the Final Report are based on many assumptions the Commission was required to make based on the information available to it during the Inquiry. To assist the government in its decision-making, the Commission included in the Final Report some sensitivity analyses to show how the cost

estimates would change if different assumptions were applied. An example of this is the forecast for energy demand.

The Commission has found that the forecast of energy demand is most likely to be at BC Hydro's "low load" or lower, based on available information, government policies in place and other factors. Should the government undertake future policy changes resulting in an increase in demand as high as BC Hydro's high load forecast, the

cost of Site C would be more attractive by $796 million.8 Likewise, the Commission estimates that Site C will cost $10 billion to complete. Should the government estimate that the project will end up costing $12 billion, the present value of the overall cost to ratepayers of Site C would be higher by $646 million. In the two examples just described, the difference in the estimates caused by changing the assumptions is less

than $1 billion. While this is a significant sum, recall that the estimate of termination costs could vary by that same figure. The Commission concluded based on its findings, that the cost to ratepayers of continuing or terminating the Site C project is similar. The Commission concedes that the Government might take a different view on one or

more of these assumptions, and the sensitivity analysis already provided in the Final Report should allow it to adequately evaluate the consequential effect of a change on the estimated cost to ratepayers. However, the Commission cautions that it would require a very significant difference between the estimates to conclude

reliably that one would be more expensive than the other.

In addition to the evaluation of ratepayer costs, the OIC requested that the Commission advise on the broader implications of the three options under consideration. The Final Report stated:

6 American Association of Cost Engineers, Cost Estimate Classification System - As Applied in Engineering, Procurement and Construction for the Process Industries.

7 Exhibit Fl-1, pp. 66-67 and 96-97. 3 Executive Summary, p. 17.

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We have not been asked to make recommendations or to identify which option has the highest cost to ratepayers or more significant implications than others. Nevertheless, we have provided our view that not only is the suspension scenario the greatest cost to ratepayers of the three scenarios, it also has other negative implications.

We take no position on which of the termination or completion scenarios has the greatest cost to ratepayers. The Illustrative Alternative Portfolio we have analyzed, in the low-load forecast case, has a similar cost to ratepayers as Site C. If Site C finishes further over budget, it will tend to be more costly than the Illustrative Alternative Portfolio is for ratepayers. If a higher load

forecast materializes, the cost to ratepayers for Site C will be less than the Illustrative Alternative Portfolio. We have provided a discussion of the risk implications of each alternative in order to assist in

the evaluation.9 We trust that the information in the Final Report, including the discussion of risk, and the results of the province-wide Community Input Sessions and First Nations Input Sessions, will provide useful guidance to the government beyond the question of cost.

9 Final Report, p. 187.

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Question 1: Inclusion of Site C sunk/termination costs The Deputy Ministers ask:

Did the Commission include sunk costs (the estimated $2.1 billion that has been spent to date on the project) and termination costs (the $1.8 billion determined by the Commission) in comparing the costs to ratepayers of completing Site C against the costs of pursuing an alternative portfolio of generation resources? Response

The Commission did not include sunk costs in the analysis of ratepayer impact for either Site C or the

Illustrative Alternate Portfolio of generation resources. The costs assumed in this analysis were, in both cases, only costs incurred from January 2018 onward. These costs include the termination costs of Site C which are included in the ratepayer impact of the Illustrative Alternative Portfolio. The Final Report states: In order to evaluate the cost to ratepayers of the termination case, and compare that rate

impact to the cost of completing Site C, we compare the cost to ratepayers of the energy for the alternative portfolio to the cost of completing Site C from January 1, 2018. The sunk costs of

$2.1 billion, which include the Site C regulatory account balance of approximately $0.5 billion, must be recovered in both scenarios. Accordingly, we do not consider the rate impact of the

sunk costs in the termination scenario. 10 The ratepayer impact analysis identifies the present value (PV) of the costs to ratepayers of Site C compared to an Illustrative Alternative Portfolio. The costs are modelled as a cost of service that is recovered in a revenue

requirement for the utility. The amounts are calculated annually for seventy years and are discounted (in a net present value [NPV] Analysis) to F2018 dollars. Thus we characterize the cost to ratepayers as the NPV of the seventy-year rate impact.

It is important to note that this does not necessarily reflect the same bill impact as would be faced by an individual ratepayer. That analysis would require further input assumptions, including the number of ratepayers that the revenue requirement is being collected from each year.

10 Final Report, p. 163.

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This treatment is illustrated in the tables on page 167 of the Site C Final Report:

Table 1: Site C Final Report, Tables 39 and 40u

Output: Low LF - Alternative Portfolio A

Site C Termination Cost (F$18)

1,395

million

Alternative Portfolio Cost (F$1 8}

2,539

million

Surplus Energy Sale (F$18)

Total Rate Impact (A+B+C)

(788) million

3,147 1 million

Output: Low LF - Site C

Sunk Costs (F$ 18)

2,100 million

Site C Cost to Complete (F$18)

4,391

Flexibility Credit (F$18)

(66) million

Surplus Energy Sales (F$18)

(1,473) million

Total Rate Impact (B+C+D)

2,852^ million

million

In the table above, the $1,395 billion for "Site C Termination Costs" represents the PV of the $1.8 billion of Site C termination costs amortized over 30 years.

Table 2: Rate Impact ($ million) of Site C compared to the Illustrative Alternative Portfolio â&#x20AC;˘f **

Illustrative SiteC

Alternative Portfolio

As provided in the Final Report Errata

â&#x20AC;˘

Ratepayer impact

$2, 852 million

$3, 147 million12

If sunk costs are included, the ratepayer impact of both the continue and terminate options would be affected. If

the same amortization period was chosen the effect would be the same for each alternative. We discuss the issue of amortization period for both sunk and termination costs further in our response to question 3. The Deputy Ministers also ask: We were not able to determine whether the sensitivity analysis included on Page 17 of the

report's executive summary includes sunk costs and termination costs consistently. If it does not,

11 Final Report, p. 167, as updated by A-25 errata. 12 In a letter dated November 16, 2017, BC Hydro identified an additional errata related to application of inflation factors and discount rates which would reduce the PV cost of the Illustrative Alternative Portfolio by $60 million. The Final Report was not adjusted for this subsequent errata on the grounds of materiality.

5 of 26

could the Commission advise on how including these sunk and termination costs might change

the cost to ratepayers and the unit energy cost (UEC) in both scenarios? Response

The calculation of the Unit Energy Cost differs from the calculation of cost to ratepayers. The Panel found that there is no generally accepted definition of "unit energy cost." In the Inquiry, BC Hydro stated that "Unit Energy Cost simply expresses the cost for a resource by its levelized annual cost per unit of energy produced. n

The term "levelized cost of energy" or "levelized cost of electricity" (both often referred to as LCOE), are in general use in the industry to compare the costs of energy projects. For example, the US Energy Information

Administration (EIA) describes LCOE as follows: Levelized cost of electricity (LCOE) is often cited as a convenient summary measure of the overall competitiveness of different generating technologies. It represents the per-kilowatt hour cost (in discounted real dollars) of building and operating a generating plant over an assumed financial life and duty cycle. Key inputs to calculating LCOE include capital costs, fuel costs, fixed and variable operations and maintenance (O&M) costs, financing costs, and an assumed

utilization rate for each plant type. ...14 In the Preliminary Report, the Panel defined "unit energy cost" as: "Unit Energy Cost simply expresses the cost for a resource by its levelized annual cost per unit of energy produced. n 15 There were no submissions received on this issue, and in the Final Report the Panel stated: The Panel therefore confirms the unit energy cost definition proposed in the Preliminary Report, that the Unit Energy Cost simply expresses the cost for a resource by its levelized annual cost per unit of energy produced. ... Given the definition of UEC, the Panel finds it inappropriate that the unit energy cost be adjusted for sunk costs [i.e. that the sunk costs be added to Site C cost to complete or to the

Alternative Portfolio costs, as they are sunk so only future costs matter] and termination costs [i.e. that the termination costs be added to the Alternative Portfolio cost] and will not consider

these costs in the unit energy cost analysis. 16 If sunk and termination costs are included in the UEC analysis: â&#x20AC;˘

The Site C UEC, would increase.

â&#x20AC;˘

The UEC of the Illustrative Alternative Portfolio would increase

The quantum of the increases depends upon the assumptions made concerning recovery periods. The following tables provide a sensitivity analysis. Please also refer to our response to question 4 for a more complete discussion about recovery of sunk and termination costs.

13 Fl-1 Submission, p. 61. 14 EIA Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2017, p. 1, https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf

15 Final Report, p. 154. lo The wording in the Final Report has been corrected above to clarify that Site C sunk costs are excluded from the unit energy cost comparison.

6 of 26

Table 3: Unit Energy Cost Sensitivity Analysis - Sunk and Termination Costs SiteC

Sunk costs18

Amortization

added?

period (years)

Illustrative Alternative Portfolio17 Unit Energy

Sunk costs

Termination

Amortization

Unit Energy

Cost

added?

costs19 added?

period (years)

Cost

(F18$/MWh)

n/a

$44

n/a

$31

Yes

$57

Yes

$48

$57

$49

$57

$50

$57

$52

n/a

$44

$45

$44

$46

$44

$48

$44

$49

$63

Yes

$57

$64

$57

$67

$57

$70

Yes

Table 4: Total Rate Impact Sensitivity Analysis - Sunk Costs

iil

SiteC

Illustrative Alternative Portfolio20

Sunk costs21

Amortization

Total Rate Impact

Sunk costs

Amortization period for

Total Rate Impact

added?

period (years)

(F18$million)

added?22

sunk and termination

(F18$million)

costs (years) No

n/a

$2,852

$3,147

Yes

$4,086

Yes

$4,399

$4,086

$4,530

$4,086

$4,775

$4,086

$4,969

17 All scenarios are for the low load forecast, Panel market price assumption, BC Hydro financing, Medium Wind and Geothermal costs.

18 Sunk costs of $2,100 million (F2018$) 19 Termination costs of $1,800 million (F2018$). 20 All scenarios are for the Low load forecast, Panel market price assumption, BC Hydro financing, Medium Wind and Geothermal costs.

21 Sunk costs of $2,100 million (F2018$) 22 Note that termination costs were included in the Total Rate Impact for the Alternative portfolio.

7 of 26

Question 2: Financing costs The Deputy Ministers ask:

In the event that government elects to terminate the Site C project, has the Commission assumed that BC Hydro would develop and finance the projects included in the alternative portfolio (wind, geothermai) rather than independent power producers (IPPs)? Response

The Commission did not assume that BC Hydro would develop and finance the projects included in the

alternative portfolio. Specifically, the Final Report states that "[t] he Panel makes no determination on whether BC Hydro or IPPs should undertake the investments included in the Illustrative Alternative Portfolio. Âť 23 The Deputy Ministers also ask: We observe that the Commission has in some cases used BC Hydro's lower cost of capital financing to calculate the cost of the alternative portfolio presented in the report, affecting the valuation of those projects. Could the Commission offer its view of the impact that a higher cost of capital would have on ratepayers if the alternative portfolio were developed by independent power producers rather than directly by BC Hydro? Response

The Final Report, to assist users in performing sensitivity analysis on the financing cost assumptions, described how users can perform an analysis of the effect of using IPP financing assumptions: The updated spreadsheet now allows for the application of different financing costs for wind and geothermai projects. If financing costs are assumed to be the same as BC Hydro's financing

cost for Site C (100% debt financing at a cost of 3.43%), the user should select 'BCH rate' in the drop-down menu of the 'Financing Option' variable of the 'Input and Output' tab. If these projects are assumed to be undertaken by IPPs and financed at the IPP financing rate assumed by BC Hydro at 6.4%, the user should select 'IPP rate' instead. If a different rate than 6.4% is

assumed, the user can change the value of 'IPP Financing Rate in %' directly.24

The Commission notes that selecting the IPP rate in the model results in a financing rate assumption of 6.4% in real terms, whereas BC Hydro's IPP financing rate assumption is 6.4% in nominal terms. In orderto model the

effect of use of BC Hydro's IPP financing rate, the rate in the model should therefore be set to 8.5 percent. The table below provides the results of the Illustrative Alternative Portfolio model if changes are made to the Commission financing cost assumptions. Please note that the sensitivity analysis below only reflects the increase

in financing costs of IPP financed projects, and does not reflect the corresponding decrease in ratepayer risk:

23 Final Report, pp. 159-160. 24 Final Report, Appendix C, p. 2.

8 of 26

Table 5: Sensitivity analysis regarding wind/geothermal financing cost assumption25 Illustrative Alternative Portfolio PV Cost 7,7.

Load forecast scenario

•—

Commission

Alternative financing

lncrease/(Decrease)

Assumptions 26 (BC

cost assumption (BC

in Alternative Portfolio PV cost

Hydro financing rate of

Hydro IPP financing

3.43%)

rate of 8.5%)

•

High load forecast

$5,121 million

$5,831 million

$710 million

•

Med load forecast

$4,618 million

$5,130 million

$512 million

•

Low load forecast

$3,147 million

$3,359 million

$212 million

The Deputy Ministers ask:

[By procuring new supply from competitive processes] BC Hydro avoids assuming such debt on its balance sheet and only recognizes the incremental costs of new energy purchases which would include the private sector's annual debt servicing costs and equity return within approved purchase contracts. It would be helpful to understand how the Commission assesses the impact on ratepayers of the additional debt associated with the assumptions underlying the alternative portfolio. We would particularly appreciate better understanding the Commission's approach to using BC Hydro's cost

of capital for IPP projects and the approach used for the cost of capital faced by an IPP (i.e. what IPPs actually pay) and the

resultant rate

impacts.

For example,

on page

159-160,

the

Commission appears to conclude that IPP financing is the relevant assumption for the alternative portfolio ... Response

On page 160 of the Final Report, the Commission stated that "the same financing cost should be assumed for

Site C and the Illustrative Alternative Portfolio." The Commission consistently used the BC Hydro financing rate in its comparison between Site C and the Illustrative Alternative Portfolio, for the reasons set out in the Final Report, which are repeated below for convenience. The Final Report goes on to provide an analysis of the effect of using the IPP financing rate for the alternative portfolio, as provided above. The Commission concluded that an analysis comparing Site C to an alternative portfolio should be agnostic as to the ownership structure used. The rationale for this approach is discussed in the Final Report: The question posed in the OIC- whether there is an alternative portfolio that will deliver the benefits of Site C at an equivalent or lesser cost - will yield a different response depending on

what assumptions are made regarding whether the alternative portfolio is developed by BC Hydro or by an IPP. ...

25 Results in this table are based on the revised Illustrative Alternative Portfolio spreadsheet published on Nov. 16 with the A-26 errata.

26 Final Report, p. 70, footnote 600.

9 of 26

By contracting for the supply of energy from an IPP, as opposed to developing an energy source directly, BC Hydro will transfer development, construction and operating risk to the IPP. In the Panel's view, the analysis should reflect this transfer of risk. CEABC suggests that the effect of

this transfer of risk should be reflected in the discount rate that is applied to each project. BC Hydro submits that it isn't practical to conduct such an analysis on a project to project basis. ... The Panel makes no determination on whether BC Hydro or IPPs should undertake the investments included in the Illustrative Alternative Portfolio. This Inquiry is not the place to address the question of BC Hydro versus IPP ownership and determine the optimal price/risk allocation in energy purchase agreements between BC Hydro and IPPs. Indeed, this review is agnostic with respect to ownership structure and instead focuses on the inherent cost and performance attributes of the generating assets, and how those assets will meet needs and address risk within the broader generation portfolio. In order to ensure that the outcome of this review is not biased for or against a particular ownership structure, the Panel therefore determines that an "apples to apples" comparison requires that the same financing costs be assumed for both Site C and the Illustrative Alternative Portfolio. However, to address the concerns raised by BC Hydro, the Panel provides additional scenarios with different financing assumptions. For these scenarios, BC Hydro financing will only

be applied to DSM initiatives, and IPP financing costs for all other generation sources. ...21

With regards to the reference to "additional debt" associated with the alternative portfolio, the Commission

notes that BC Hydro will be financing the Site C project with debt. Therefore, given the similar cost of Site C and the alternative portfolio, the Commission sees no "additional debt" in the event that BC Hydro were to build

alternative generating projects instead of Site C.

27 Final Report, pp. 159, 160.

10 of 26

Question 3: Demand-side management The Deputy Ministers ask: Government will need to consider the total cost of potential demand side managemen t

initiatives (rather than just the utility's costs) as it considers the alternatives. Could the Commission advise how the inquiry Terms of Reference led to assessing demand-side measures based on the Utility Resource Cost standard, when Total Resource Cost has been the standard for prior Commission proceedings? Response

The Report stated: With regard to what DSM cost should be included in the Alternative Portfolio, the Panel finds that the

cost should be the utility cost as section 3(b)(iv) of the OIC [questions] refers to the cost to

ratepayers.23 The terms of reference for the Inquiry requested that the Commission evaluate the costs to ratepayers of continuing, suspending or terminating construction of Site C. The Commission interpreted the phrase "costs to ratepayers" as referring to costs that would recovered through BC Hydro's revenue requirement . The Report also stated: "When calculating cost to ratepayers, we calculate the NPV of the incremental revenue requirement of the item in question.

ii 29

The Commission did not include costs that would be incurred by other parties, such as the government or individuals; neither did the Commission consider broader societal costs or benefits in the financial analysis. Therefore, when considering the costs to ratepayers of the DSM programs, the Commission included only the costs incurred by BC Hydro. The Deputy Ministers ask:

It is our understanding that in previous proceedings the Commission has concluded that the Total Resource Cost (TRC) test is the appropriate way to evaluate demand side management (DSM) in comparison to other resources. In this inquiry, the Commission's model uses the Utility Resource

Cost (URC) standard. We believe that using the URC model may underestimate the actual cost of DSM to ratepayers. It would be helpful for us to understand the Commission's rationale in choosing a test methodology that differs from past practice. Could the Commission confirm that

the TRC test remains the appropriate metric, and if so, what impact would this have on the analysis. Response

The total resource cost test remains an appropriate metric for analyzing whether or not to proceed with DSM programs. As we noted in the final report: "Regarding the use of the utility cost compared to the total resource

28 Final Report, p. 38. 29 Final Report, p. 164.

11 of 26

cost, the Panel agrees that BC Hydro should not be undertaking DSM programs that do not pass the total resource cost test.

Âť30

We also noted that the level of DSM investment included in the Illustrative Alternative Portfolio, a level

originally recommended by BC Hydro in the 2013 IRP,31 could reasonably be considered to pass this test: "However, the illustrative DSM portfolio only includes the first (lowest cost) block of BC Hydro's estimated incremental DSM opportunities. The Panel considers that the Illustrative Alternative Portfolio assumption that

the programs in this first block all pass the total resource cost test is reasonable. ,/32 The Commission did not use a utility resource cost standard in determining the appropriate level of DSM investment to include in the Illustrative Alternative Portfolio. Therefore, the Commission sees no impact to the analysis.

Once the level of DSM investment in the Illustrative Alternative Portfolio was determined, the Commission then addressed the question of its costs to ratepayers, as set out in the terms of reference. As explained in the answer to the question above, the Commission included only the costs that would be incurred by BC Hydro, and

thus passed on to ratepayers. The rationale for this approach is addressed in the Final Report: With regard to what DSM cost should be included in the Alternative Portfolio, the Panel finds that the cost should be the utility cost as section 3 (b)(iv) of the OIC refers to the cost to ratepayers, as opposed to the BC cost or the societal cost.

For example, the industrial load curtailment DSM program has a utility cost of $75/kW-year, while BC estimates that the total resource cost (i.e. the cost to the customer of curtailing) is $60/kW-year. The Panel considers it would not be consistent with the treatment of Site C to include in the Alternative Portfolio the cost to the industrial customer of curtailing supply (total

resource cost), instead of the cost to the utility of obtaining the curtailment (utility cost).33 The Deputy Ministers also ask: The report identifies an aggressive DSM program, coupled with load curtailments as a way to achieve the alternative portfolio scenario. We would appreciate further information from the

Commission on how such load curtailments would practically be achieved in the natural resource sector without impairing operations, jobs and economic growth for sectors already facing trade

sanctions and pressures Response

The Commission would not characterize the DSM plan included in the Illustrative Alternative Portfolio as aggressive. The level of DSM included in the Illustrative Alternative Portfolio is, in fact, the level recommended by BC Hydro in its 2013 Integrated Resource Plan, and was the least aggressive apart from one

of the five levels of DSM spending that BC Hydro modelled at that time.34

30 31 32 33 34

Final Final Final Final Final

Report, Report, Report, Report, Report,

appendix A, Appendix A, appendix A, Appendix A, Appendix A,

p. 38. p. 34. p. 38. pp. 38, 39. p. 34.

12 of 26

The Commission believes that load curtailment can be a mechanism to retain and attract additional industrial load, and so enhance, rather than impair, operations, jobs and economic growth. The Final Report identifies a desire by industry for higher levels of industrial curtailment opportunities than included in the Illustrative Alternative Portfolio. Specifically, the Association of Major Power Customers (AMPC) has argued for BC Hydro to offer higher levels of load curtailment as being in the interests of its members: Curtailable loads have already demonstrated that they can feasibly, cost-effectively and

dependably provide system capacity for the necessary duration of peak load events. AMPC's October 11 submission details the specifics of AMPC's position. Once long term curtailable tariffs are established; scalable capacity resources can be delivered in appropriate quantities and at very short notice compared to generation sources. From BC Hydro's forecasts of capacity and energy need, the immediate implementation of curtailable contracts and/or tariffs could provide the necessary time to take a more detailed look at how future energy needs are most reliably and affordably provided. This time is particularly valuable during a period of significant technological development in energy storage, to reduce the risk of adopting a potentially short

lived technology path. Moreover, this provides a non-rate mechanism to retain existing, and attract additional, industrial load. ...the Commission should, as part of any alternative energy portfolio evaluated, consider the full use of industrial load curtailment to generate needed system capacity, because load curtailment is a well-developed, well-studied program that can be implemented economically and quickly,

without the need to speculate on the its potential availability in the future.35

35 Final Report, Appendix A, pp. 72, 74, 75. Emphasis added.

13 of 26

Question 4: Amortization of sunk/termination costs The Deputy Ministers ask:

If the Site C project were terminated, the $4 billion sunk and remediation costs would need to be recovered, and the amortization period of that recovery would affect BC Hydro rates. Could the Commission please clarify whether it assumed that that these costs would be recovered over 10, 30 or 70 years? Response

The Commission made no assumptions on the recovery of sunk and termination costs. The Final Report states: Regarding the potential mechanisms to recover termination costs, the options available are either from BC Hydro ratepayers, the shareholder or some combination of the two. If these costs are to be recovered from ratepayers a further issue is over what period they should be recovered. Generally speaking, a regulated utility is entitled to recover from its ratepayers, all prudently incurred expenditures. Therefore, the issue would be whether the costs to terminate the project were prudently incurred and this can only be determined after the expenditures have been made. In regard to the recovery period, this requires further analysis. Considerations include intergenerational equity - too long a period risks forcing customers who may not benefit from the expenditure to pay for it. If the payback period is too short, there is a risk of rate shock. This Panel takes no position at this time what the recovery period should be and notes that it would be subject to Commission approval. The same principles apply to the recovery of the sunk costs. There are some that suggest that if the project is terminated, this could be an indicator that the decision to go ahead with the project was not prudent. Others argue that since the project was not approved by the Commission, the costs were, by definition, not prudently incurred.

The Panel takes no position on the recoverability from ratepayers for sunk and termination costs. Further, we take no position on the recovery period for sunk and termination costs. However, for the analysis of ratepayer impacts of the termination scenario, we have assumed that termination costs will be recovered from ratepayers over a 10, 30 and 70 year recovery period.

Although we do not consider the rate impact of sunk costs when comparing the continue and termination scenario, the costs must be recovered. In the case of Site C being completed these

costs would be included in the project costs, and barring any disallowance, would be recovered from ratepayers over the 70-year amortization period proposed. In a terminate scenario, again assuming the costs are to be recovered from ratepayers, to determine the cost impact to ratepayers requires assumptions regarding the amortization period.

14 of 26

The Deputy Ministers also ask: Fair and appropriate rate-setting principles for rate-regulated utilities typically aim to avoid

causing future generations to pay for investments from which they will derive no benefit. From

the Commission's perspective, can recovery of the sunk and remediation costs of Site C over longer periods of 30 to 70 years remain consistent with these inter-generational principles? Response

The Commission reiterates that we take no position on the recovery period for sunk and termination costs.

The recovery period would be the subject of Commission review if, and when these costs are incurred. When considering the recoverability of any costs, there are a number of regulatory principles considered, including:

Price signals that encourage efficient use and discourage inefficient use (economic efficiency); Fair apportionment of costs among customers (fairness); Avoid undue discrimination (fairness); Customer understanding and acceptance, practical and cost effective to implement (practicality); Freedom of controversies as to proper interpretation (practicality); Recovery of the revenue requirement (stability);

Revenue stability (stability); and

â&#x20AC;˘

Rate stability (stability).36

The above considerations would apply to the recovery period of both termination costs and sunk costs. We generally agree with the Deputy Ministers' statement "Fair and appropriate rate-setting principles for rateregulated utilities typically aim to avoid causing future generations to pay for investments from which they will

derive no benefit." Intergenerational equity is an important consideration when considering the deferral of cost recovery. However, in the termination case, both the sunk and termination costs relate to a stranded asset, and

it is important to note that no-one benefits from a stranded asset. Therefore there is no more - or less justification that any particular generation should be more liable than another for the costs related to that stranded asset.

The Deputy Ministers also ask: Recently it has been stated that recovering the project's sunk and remediation costs over a 10year period would lead to a 10 per cent hike in BC Hydro rates. Is this assertion consistent with

the Commission's thinking ? Response

The table below shows the initial effect on the revenue requirement of amortization of Site C sunk costs, followed by the combined effect when estimated termination costs have been incurred. BC Hydro's F2018

revenue requirement request of $4,626 million has been used to estimate the year one rate impact effect of the

3Â° Bonbright principles, BC Hydro 2015 Rate Design Application, Decision dated January 20, 2017, pp. 11, 12

15 of 26

alternative amortization options.37 BC Hydro real rate increases subsequent to F2018 will result in a lower percentage impact than that indicated on the table below. Table 6: Rate impact of alternative amortization period for Site C sunk and termination costs

Amortization Period

Year one costs recovered

(years)

Revenue requirement

impact

Site C sunk costs only ($2.1 billion) 10

302

6.5%

152

3.3%

122

2.6%

109

2.4%

Total Site C sunk costs and termination costs ($3.9 billion) 10

560

12.1%

282

6.1%

226

4.9%

203

4.4%

The Panel therefore confirms that the use of a 10-year amortization period for Site C sunk and termination costs have a potential rate impact of 10 percent. However, the actual rate impact of Site C termination will reflect the amortization period selected, which will in turn be driven by intergeneration equity and rate shock concerns,

and the degree to which sunk or termination costs prove to have been prudently incurred. The Panel notes that

the year one revenue requirement impact of Site C (before export revenues) is estimated at $499 million

(F2025).38 The scenarios for the total rate impact of the Illustrative Alternative Portfolio as presented in the Final Report39 include termination costs of $1,800 million. The analysis in the tables above suggests a situation whereby the sunk and termination costs of Site C would be recovered separately from the costs of the Illustrative Alternative Portfolio. To avoid double counting, it is therefore appropriate to present accompanying analysis that demonstrates the impact of removing termination costs from the total rate impact of the Alternative Portfolio.

Table 7 below indicates that the illustrative Portfolio would be less costly in all load forecast scenarios with termination costs excluded from the rate impact.

37 BC Hydro F2017-F2019 Revenue Requirement Application, Exhibit B-l-1, p. 1-38 33 BC Hydro Site C cost calculator (Submission Fl-4, BC Hydro, IR 2, Attachment 3), as adjusted to show total Site C costs (including sunk costs) as $10 billion.

39 Final Report Executive Summary Errata, Corrected Table 43, p. 10

16 of 26

Table 7: Total Rate Impact -Termination Costs Excluded from Alternative Portfolio

Site C- Total Rate

Illustrative Alternative Portfolio - Total

Impact

Rate Impact

(F18$milllions)

Difference between Site C and Alternative

Termination costs

Portfolio - Termination

included

excluded

costs excluded

(F18$milllions)

Low Load Forecast

2,852

3,147

1,752

($1,100)

Medium Load

3,901

4,618

3,222

($679)

4,325

5,121

3,726

($599)

Forecast

High Load Forecast

In addition, the Appendix to the Deputy Ministers' letter asks:

It would be helpful if the Commission could clarify how the choices of cost amortization and recovery periods in the Termination scenario fit within appropriate utility rate-setting principles that

recognize

and

avoid

unnecessarily

transferring

current

utility

costs

to future

user

generations when there are clearly no longer directly-related assets or benefits being provided. Such decisions lead rate-regulated accounting practice and use of regulatory accounts, which are areas of particular interest by the provincial Auditor General as well as credit rating agencies. Response

The issue of the appropriate period to recover Site C sunk and remediation costs is addressed in the Site C Final Report:

In regard to the recovery period, this requires further analysis. Considerations include intergenerational equity - too long a period risks forcing customers who may not benefit from the expenditure to pay for it. If the payback period is too short, there is a risk of rate shock. This Panel takes no position at this time what the recovery period should be and notes that it would be subject to Commission approval. ... Further, we take no position on the recovery period for sunk and termination costs. However, for the analysis of ratepayer impacts of the termination scenario, we have assumed that termination costs will be recovered from ratepayers over a 10, 30 and 70 year recovery period.

Although we do not consider the rate impact of sunk costs when comparing the continue and termination scenario, the costs must be recovered. In the case of Site C being completed these costs would be included in the project costs, and barring any disallowance, would be recovered from ratepayers over the 70-year amortization period proposed. In a terminate scenario, again assuming the costs are to be recovered from ratepayers, to determine the cost impact to

ratepayers requires assumptions regarding the amortization period.40 As noted above, the Commission considers numerous factors in determining the appropriate amortization period to use to recover Site C sunk costs and termination costs.

40 Final Report, pp. 163-164.

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Question 5: Load forecast The Deputy Ministers ask:

We are unaware of prior instances when anything other than BC Hydro's mid-load forecast has been used for planning purposes. For that reason, we would like to clarify: Did the Commission assume lower demand for electricity (reflected in the low-load forecast used in the report) because it is forecasting a period of lower economic growth for the province in which major power consumers such as mining, forestry, technology and commercial sectors are in decline? Response

The Commission did not assume a lower demand for electricity "because it is forecasting a period of lower economic growth for the province." Further, the Report does not state, nor does it suggest, that "major power consumers such as mining, forestry, technology and commercial sectors" are in or are going into "decline". On the contrary, the Report specifically acknowledges that there have been some positive developments in the nonLNG large industrial load, but goes on to conclude that these positive developments are not sufficient to offset the negative developments in the potential BC LNG sector.

The Commission's consideration of the load forecast was based on a holistic assessment of the factors that drive demand for electricity. In our answer to the Deputy Ministers' question below regarding the rationale for the Commission's position, we present a description of the seven factors we considered. These include three factors that are directly related to economic growth: recent developments in the industrial sectors, GDP and other forecast drivers, and flattening electricity demand. The Deputy Ministers also ask: Does the Commission include in its load forecast the potential increased electrical power demand of meeting the province's stated objectives to reduce greenhouse gas emissions through greater

electrification of our economy? Response

The Commission does not have a load forecast. The terms of reference required us to use BC Hydro's load forecast from the 2016 Revenue Requirements Application, which has a mid-level projection within a high and a low band. We were also required to seek BC Hydro's view on factors which might influence expected demand toward the high or low cases. The Commission did consider electrification in the Final Report both from the perspective of impacts on the load forecast over the 20-year period and disrupting trends over time. These are considered below. In its submissions, BC Hydro highlights the emerging potential for load growth from initiatives targeting greenhouse gas emission reductions through electrification of fossil-fuel powered end uses. BC Hydro states "electrification of energy loads currently served by fossil fuels such as space and water heating, vehicles and industrial equipment could reasonably cause demand for electricity to exceed BC Hydro's mid forecast in the

Current Load Forecast."

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However, BC Hydro does not account for electrification initiatives directed at reducing greenhouse gas emissions in its Current Load Forecast because the timing and magnitude of the potential increase is uncertain at this early stage. BC Hydro presents the potential for electrification to have an upward impact on the load forecast in the figure below. Figure 1: BC Hydro's Load Forecast Range, Impact of Electrification, and Deloitte's "Alternative" Load Scenario

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Although available information indicates that the effects of electrification on BC Hydro's load forecast could potentially be significant, the timing and extent of those increases remain highly uncertain. Given the uncertainty, the Site C Inquiry Panel agreed with BC Hydro that additional load requirements from potential electrification initiatives should not be included in the load forecast for the purpose of resource planning.

The extent and timing of electrification initiatives will be a matter of government policy. In the absence of such policy, it is not appropriate to include any potential additional load requirements from electrification initiatives in the load forecast for resource planning. Should the government set further policy with respect to electrification, BC Hydro would need to prepare an updated load forecast reflecting the impact of such policies. Although not taken into account in the load forecast, electrification is still an issue for consideration. In its report, the Panel noted that if electrification does materialize in the future, it is possible that some of the

higher electricity demand could be offset with aggressive conservation measures, including DSM programs that achieve

load reductions similar in magnitude to those experienced in New England.41

41 Page 75 of the Final Report includes the following submission by CanWEA: "These [downside risks] are very real risks that are being realized in many other North American electricity markets. In New England, where I am from, the most recent long-term electricity demand forecast by the Independent System Operator is for a .6% compound annual decline in energy

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The Panel also acknowledged numerous submissions identifying disruptive factors that could potentially decrease demand, including the potential impact of expanded distributed generation . However, because these downward impacts on load are uncertain, the Panel did not identify any specific trends that would suggest an adjustment to the Current Load Forecast is required. The Deputy Ministers further ask:

We have noted that the Commission has concluded that BC Hydro's low load forecast was most appropriate for an assessment of the need for the capacity of Site C. It would be helpful for us to further understand the rationale, and whether the assessment includes the load requirements needed to meet the Province's Clean Energy Act energy objectives of: â&#x20AC;˘

Reducing greenhouse gas emissions by 2050 by 80% less than 2007 levels;

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efficiently. Response

To recap the Final Report, the Commission concluded:

Overall, the Panel finds BC Hydro's mid load forecast to be excessively optimistic and considers it more appropriate to use the low load forecast in making our applicable determinations as required by the OIC. In addition, the Panel is of the view that there are risks

that could result in demand being less than the low case.42 In making findings on BC Hydro's load forecast, the Commission considered the following factors: 1.

Recent developments in the industrial sectors

Accuracy of Historical Load forecasts

GDP and other forecast drivers

Price Elasticity assumptions

Future Rate increases

Potential disrupting trends

Flattening electricity demand

Each of the seven items considered by the Commission in arriving at its determina tion on BC Hydro's load forecast are addressed in detail in the Final Report and are summarized below.

consumption over the next ten years, with no meaningful increase in peak load. New York ISO is also forecasting a decline in energy consumption (-.2% per year)."

42 Final Report, p. 77.

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Recent developments in the industrial sectors The Panel reviewed recent developments in the industrial sector and concluded: The Panel finds the developments since the Current Load Forecast was prepared, as reported by BC Hydro, can reasonably be expected to reduce demand from the expected case or mid forecast. The Panel acknowledges there have been some positive developments in the non-LNG large industrial load that BC Hydro suggests provide a net increase in demand since the Current Load Forecast was prepared (an anticipated positive total variance is approximately 750 GWh/100 MW in the short and medium term and 965 GWh/114 MW over the long-term). However, given the risk and volatility of the industrial load and its susceptibility to cyclical ups and downs, and the risks to the large industrial load set out by AMPC, the Panel is unable to draw any conclusions that these recent developments will result in a permanently positive impact on industrial demand. In any event, in the Panel's view these positive developments in the non-LNG sector are not enough to offset negative developments for a potential BC LNG sector. The Panel finds that developments since the Current Load Forecast was prepared have significantly reduced the probability that the majority of BC Hydro's forecast LNG load will materialize. Regarding the potential LNG industrial load, BC Hydro itself states there are questions as to whether BC has missed the window of opportunity for LNG. While BC Hydro points to certain third-party market views that still show some support for the opportunity to develop LNG in BC, the Panel notes the significant uncertainty expressed in most market views, the recent cancellation and postponement of several large potential BC LNG projects, and the higher costs of potential BC LNG projects compared to existing and potential projects in other jurisdictions. The Panel also agrees with several parties who express concern with the fact that BC Hydro had not made a probabilistic assessment of the likelihood of the LNG load materializing. The Panel agrees with Finn that the three projects cited by BC Hydro face

uphill

battles, especially given the current poor market conditions. 43 Accuracy of historical load forecasts After reviewing the accuracy of BC Hydro's historical load forecasts, the Panel stated: As noted in its Preliminary Report, the Panel finds that the historical instances of overforecasts are greater than under-forecasts, especially in the industrial load, and that the accuracy of BC Hydro's historical industrial forecasts looking out three and six years has been considerably below industry benchmarks.

The Panel acknowledges BC Hydro's argument that the drivers of historical industrial forecast variances are not relevant to the expected accuracy of the Current Load Forecast, especially considering the impacts of large discrete customer load attrition between 2006 and 2010 and the steps BC Hydro describes it has taken to ensure its existing industrial forecasts are reasonable. However, as pointed out by CEC, some of these declines in industrial load could or should have been anticipated and may represent a bias towards over-forecasting. Accordingly , while the Panel does not place significant weight on the historical inaccuracies in the load

43 Final Report, p. 78.

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forecast, it does approach the Current Load Forecast with some skepticism, especially as it

relates to the industrial load forecast.44 GDP and other forecast drivers After reviewing BC Hydro's GDP growth assumptions, the Panel stated: ...The Conference Board of Canada forecast projects the real GDP will grow by 2.6 percent on average between 2016 and 2020 and then drop to an average of 2.3 percent between 2021 and

2025. In contrast, BC Hydro's projection results in an average growth rate of 3.5 percent over the same five years. BC Hydro's forecast results in the BC economy being six percent larger than the CBoC's forecast by 2025. The Panel considers BC Hydro's average growth rate of 3.5 percent to be excessive.

The Panel remains concerned that BC Hydro's GDP and disposable income forecast drivers are higher than other comparable third party estimates, such as the CBoC. Based on the evidence presented in this Inquiry, the Panel can make no definitive finding on the appropriate GDP or disposable income driver to apply. However, considering the historical over-estimates in the

load forecast as noted above, the Panel approaches BC Hydro's estimates with skepticism given that these key drivers are both considerably higher than otherthird party estimates and use of the lower estimates would result in a lower load forecast. Accordingly, the Panel finds BC Hydro's mid load forecast is higher than if it used the CBoC estimates and adjusting for this

could reasonably be expected to influence demand towards the low load case. 45 Price elasticity assumptions

With regard to price elasticity, the Panel made the following findings: The Panel finds the -0.05 long-run price elasticity used by BC Hydro for all rate classes to be too low in magnitude to reflect the degree of change in demand for a given change in price. Accordingly, the Panel finds BC Hydro's mid load forecast is higher than would otherwise be the case if it used lower price elasticity factors, and that adjusting for this would reduce demand towards BC Hydro's low load forecast case. The Panel finds that BC Hydro should be using a long-run price elasticity given the long 70 year time horizon of Site C. The Panel also finds that the international literature shows that longrun elasticities are higher than short-run elasticity. It is not clear to the Panel that BC Hydro's empirical studies have appropriately estimated long-run price elasticities since the residential inclining block rate and the transmission stepped rates have not been in place over a long time horizon.

The Panel finds the residential long-run price elasticity is likely to be more than -0.05. BC Hydro's empirical evidence shows a range from 0 to -0.13; however, the zero in the low-end of the range with no price response indicates the study results may not be reliable. The Panel

44 Final Report, P. 78. 45 Final Report, pp. 78-79.

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notes the study by Paul, Myers and Palmer shows the low-end of the range to be at -0.14 for

residential long-run elasticity. BC Hydro's empirical evidence shows that the price elasticity for commercial and industrial general service customers is close to zero so BC Hydro adopted -0.05. The Panel finds that BC Hydro's empirical evidence for the price elasticity of commercial customers is unreliable in determining the long-run price elasticity. The Panel notes the international literature shows varied results for commercial customers. Paul, Myers, and Palmer had a long-run elasticity average of -0.29 with a range of -0.02 to -0.70. Bernstein and Griffin had a single estimate

of -

0.97 which suggests the elasticity could be higher than -0.05. 46 In addition, the Panel noted BC Hydro's consultant GDS's recommendation that BC Hydro's price elasticity coefficients used to estimate "rate impacts," which were developed in 2007, need to be updated. Future rate increases

BC Hydro assumed no real rate increases beyond the end of the 10 Year Rates Plan (F2024).47 The Commission concluded with regard to this assumption: The Panel finds BC Hydro's demand forecast is sensitive to rate changes even using BC Hydro's low price elasticity factors. Accordingly, any real increase in rates beyond the rates reflected in the 2013 10 Year Rates Plan and any subsequent real rate increase could reasonably be expected to influence demand towards the low load case. The Panel finds there will be considerable upward pressure on rates for the remainder of the 2013 10 Year Rates Plan and beyond fiscal 2024. The Panel finds the risk associated with this upward pressure on rates is especially concerning given the submissions related to potential "demand destruction" that could result from the impact of real rate increases on already vulnerable industrial customers and the likelihood that even nominal rate increases will increase energy poverty among BC's low income households. 48

Potential disrupting trends The Panel raised as a concern that, given the long life of the Site C asset, BC Hydro has only identified a potential upside risk to the load forecast from electrification, and had not identified any potential downside risk. The Panel concluded: Given the uncertainty, the Panel finds additional load requirements from potential electrification initiatives should not be included in BC Hydro's load forecast for the purpose of resource planning. Although available information indicates that the effects of electrificatio n on BC Hydro's load forecast could potentially be significant, the timing and extent of those increases remain highly uncertain. BC Hydro has not included in its Current Load Forecast additional load requirements from electrification initiatives to reduce greenhouse gas emissions. The Panel agrees with BC Hydro and Hendriks etal. that the timing and magnitude of the increase is uncertain at this time. However, electrification is still an issue for consideration. The Panel notes that if electrificatio n

46 Final Report, pp. 79-80. 47 Final Report, p. 65. 43

Final Report, p. 80.

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does materialize in the future, it is possible that some of the higher electricity demand could be offset with aggressive conservation measures, including DSM programs that achieve load reductions similar in magnitude to those experienced in the New England states.

The Panel acknowledges the numerous submissions identifying disruptive factors that could potentially decrease demand, including the potential impact of expanded distributed generation. However, because these downward impacts on load are uncertain, the Panel did not identify any specific trends that would suggest an adjustment to the Current Load Forecast is

required.49 Flattening electricity demand CEC, Surplus Energy Match and CanWEA all provide evidence that total demand is not growing in most jurisdictions in North America - in most cases it is flat or declining. In British Columbia

the declining use per customer over the last 10 years has largely offset the effects of population

growth.50 Figure 2: US Residential Electricity Consumption

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The Deputy Ministers ask:

It has been government's assumption that electrification with low carbon electricity would be a key initiative to achieve greenhouse gas reductions. The provincial government is working with the Government of Canada on electricity system infrastructure investments to reduce and avoid greenhouse gas emissions, and has enabled BC Hydro to pursue electrification initiatives under the Greenhouse Gas Reduction (Clean Energy) Regulation under the Clean Energy Act. It would be helpful for our ministries to understand if the Commission has a different outlook, and if the

49 Final Report, pp. 81-82. 50 Final Report, p. 82.

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Commission could further describe the impact on its analysis of electrification initiatives to meet greenhouse gas reduction objectives. Response

The Commission's outlook on electrification and its effects on the load forecast are provided in the Final Report. We refer the Deputy Ministers to our previous answer for a summary of the material. The Deputy Ministers also ask: We understand that BC Hydro has provided the Commission with a description of its view of

what BC's economic environment would look like under a low load outlook scenario. It would [be] helpful if the Commission could further describe its interpretation of the low load outlook. We

observe that the Commission's view is that the outlook could be even lower than that presented in BC Hydro's low-load scenario, and we are interested in understanding how that outlook is based on realistic economic sustainability around which the alternative portfolio would be premised. Response

The Commission's consideration of the load forecast was based on a holistic assessment of the factors that drive demand for electricity. In our answer to the question above regarding the rationale for the Commission's position, we have included a description of the seven factors we considered. These include three factors that are directly related to economic growth: recent developments in the industrial sectors, GDP and other forecast drivers, and flattening electricity demand.

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Additional question: Dispatchability The Deputy Ministers ask:

The Commission examined the value of "dispatchable" versus intermittent resources in its selection of generation options in the Illustrative Alternative Portfolio, and concluded that "increasingly viable alternative energy sources such as wind, geothermal and industrial curtailment could provide similar benefits to ratepayers

as the Site C project with an equal or lower Unit Energy Cost. n 51 Appendix A of the Final Report contains the Commission's analysis of each generation option in the Illustrative Alternative Portfolio, and the degree to which they provide "dispatchable" energy. With regards to wind energy, for example, the largest single contributor to the Illustrative Alternative Portfolio, the Commission stated: BC Hydro states that Site C (capacity 1,145 MW) can integrate 900 MW of wind. However, the Panel notes that BC Hydro's existing modest level of wind penetration (780 MW) and high levels of hydro generation providing reserves (GM Shrum, Mica and Revelstoke with a combined capacity around 8,000 MW) means that BC Hydro would not be expected to need Site C to

integrate these additional wind farms.52 In comparison, the Illustrative Alternative Portfolio includes 444 MW of wind generation in the low load forecast

and 729 MW in the high load forecast.53

51 Executive Summary, p. 3. 52 Final Report, Appendix A, p. 32. 53 Final Report, Errata, p. 6.

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