Questions of New Information Regarding Cost Effectiveness

Transcription

1 January 15, 2014 File #: Direct: BY Site C Joint Review Panel Secretariat Courtney Trevis, Panel Co-Manager Brian Murphy, Panel Co-Manager 160 Elgin Street, 22nd Floor 4 th floor, 836 Yates St., PO Box 9426 Ottawa ON K1A 0H3 Victoria BC V8W 9V1 Dear Sirs/Mesdames: Re: Questions of New Information Regarding Cost Effectiveness We are in receipt of BC Hydro s Rebuttal Evidence to Boughton Law and to the Clean Energy Association of British Columbia both of which are dated December 23, We have certain questions regarding this new information. We have undertaken our best efforts to comply with all of the instructions of Mr. Wallace in his letter dated December regarding questions on new information received during the public hearing. The enclosed questions focus on new information including the information contained in the following: 1. BC Hydro's Rebuttal Evidence dated December 23, 2013 (the "BCH Rebuttal") to our written submission dated November 25, 2013 (the "Boughton Submission") and our presentation on December 10, 2013 (the "Boughton Presentation"); 2. BC Hydro's Rebuttal Evidence dated December 23, 2013 (the "BCH/CEBC Rebuttal") to the written submission dated November 25, 2013 by the Clean Energy Association of British Columbia (the "CEBC Submission"); 3. CEBC Undertaking #12 (the CEBC Undertaking 12 ) submitted December 17, 2013; and 4. Certified transcript of the presentation by Mr. Philip Raphals on behalf of the Treaty 8 First Nations on December 10, 2013 and written submission dated November 25, Questions #1 to 15 are questions for BC Hydro. Questions #2, 3, 6, 11, 12 and 13 are questions for the Panel. Our questions focus on whether Site C is cost effective compared to alternatives. Certain questions probe new information in the analysis which BC Hydro uses to support their premise that Site C is the most cost-effective option. Certain questions probe new information about alternative generation projects. These are important questions since BC Hydro s fundamental premise supporting Site C is that the Project is claimed to be the most cost effective way to satisfy the future electricity needs of British Columbia. Furthermore, the significant adverse impacts are justified because the Project is claimed to be cost effective. We believe that Site C is not cost effective compared to alternatives that include independent power projects ( IPPs ) and other generation resources. Therefore, the significant adverse impacts are not justified.

2 Respectfully submitted, BOUGHTON LAW CORPORATION by Philip K. Barton Law Corporation [signed] Per: Philip K. Barton Associate Counsel - 2 -

3 QUESTIONS ON NEW INFORMATION: QUESTION 1: IN RESPONSE TO FUTURE CHANGES, WHY HAS BC HYDRO ASCRIBED ZERO VALUE TO THE FLEXIBILITY OF IMPLEMENTING A DOZEN INDIVIDUAL PROJECTS VS. THE SINGLE ALL OR NOTHING MEGA-PROJECT SITE C? New Information: Page 107 to 109 of the Certified Transcript from the Public Hearing on December 10, 2013 includes the following oral submissions by Mr. Philip Raphals of the Helios Centre on behalf of the Treaty 8 First Nations: But the essence of the block analysis is that Site C, or more specifically a portfolio including and built around Site C, is compared to two other portfolios: One based on clean generation, meaning that there's no additional thermal generation; and the other, clean plus thermal, which allows some thermal additions. The key point is that both of those two alternate portfolios are explicitly and intentionally sized to match the size of Site C, which in many ways makes for an easier one thinks one is -- one has the impression one is comparing apples to apples, because we're comparing three alternatives that produce 1100 megawatts. We're comparing three alternatives to produce 5100 gigawatt hours a year. The problem with this is that in many scenarios, Site C produces a substantial surplus which lasts for many years, and which is, in fact, a significant disadvantage. And by making the primary comparison to portfolios that have exactly that same disadvantage needlessly because when you're working with wind and all these other resources, there's no need to overbuild. One can build what -- and the lead times are very short. So by forcing this comparison with identically-sized blocks, I think essentially one creates results that are meaningless. That simply don't read -- can't be used for any serious decision making, because it's an artificial construct which very severely favours Site C over the alternatives. Page 41 to 42 of the written submission of Mr. Philip Raphals of the Helios Centre dated November 25, 2013 states: The Clean and Clean + Thermal portfolios are handicapped by being forced to reproduce the large and expensive surplus that Site C would create. The benefit flowing from the flexibility inherent in these approaches is simply lost. By its nature, there is no way to develop the Site C project without creating these large surpluses. However, that is not true for the resources that make up the other two Block Portfolios (Clean and Clean+Thermal). As stated above, a pure cost comparison between these three Block Portfolios is thus entirely misleading

4 Rationale for Question: The Panel is being asked to approve Site C now, 10 years before the In-Service Date of Once the development and construction of Site C commences, its implementation is locked in. Worse, once it is locked in, the development of other new generation resources will cease to be developed. The reason for this is that BC Hydro s 2013 IRP Base Resource Plan states that, with Site C, no other generation resources will be required until With no prospect of revenue for 15 years, IPP companies will cease investing money on developing alternative generation. Accordingly, once Site C is approved to be built the die will be cast for generation resources in B.C. In some future year, when that year s actual demand is known and the go-forward forecast can be sharpened, it will be too late to adjust. It is most likely that BC will either have too much power or too little. Incremental IPP vs. Single All or Nothing with Site C: IPPs are smaller projects. They can be brought on line faster than Site C. They can be approved and built in smaller increments at a pace that closely matches demand growth. As increments, they are a flexible tool whose size and pace can be ramped up or down. They enable the avoidance of facing outcomes of big surpluses or big shortfalls and the resultant economic losses that occur with each. Scalability is important and the ability to respond to future changes is important. We highlight that each of the following alternatives to Site C are composed of over a dozen smaller individual projects: 1. Clean Generation Block (included in the Evidentiary Update dated September 13, 2013 (the "Evidentiary Update")); 2. Clean + Thermal Generation Block #1 (included in the Evidentiary Update); 3. Clean + Thermal Generation Block #2 (included in the Evidentiary Update); 4. Boughton Block #1 with SCGT (as named in the BCH Rebuttal to the Boughton Submission); 5. Boughton Block #2 with Geothermal (as named in the BCH Rebuttal to the Boughton Submission); 6. Boughton Block with Columbia Non-Treaty Storage - from Question #13. As such, individual projects can be implemented incrementally. Further, incremental projects can evolve in response to future changes such as load growth or interest rates or natural gas prices. Over the 70 year comparison period, using several smaller projects provides the opportunity to choose new projects every 5 to 10 years (either following demand growth or as old projects expire) which gives the opportunity to benefit from: technology change (ie. distributed storage technologies to support intermittent renewables); relative prices of inputs like raw materials and labour (not just natural gas); and relative taxes (such as water license fees vs wind royalties, or carbon taxes and GHG offsets). There is also the benefit of geographic diversity and equity environmental impact vs. where the power is ultimately used - and the sharing of benefits for both local governments and First Nations blessed with wind/small hydro/biomass throughout the Province not just in the Peace River region

5 The ability of the incremental IPP approach to modify and adjust plans at zero cost is a valuable risk mitigation strategy. Otherwise, BC Hydro s ratepayers will find themselves locked in to a single mega-project for the next 80 years. Yet such flexibility an important risk reduction feature of IPP alternatives is ascribed zero value in BC Hydro s current analysis of Site C vs alternative projects. Proceeding with Site C - a single, big leap project - is a far greater risk than incrementally starting several small step projects at a pace that matches need and adjusts with changing project costs. On a capital budget of about $7.9 billion, that risk is very large. Cost of Future Changes: We note that the sensitivity tables already show many instances where alternatives show a lower Present Value Cost (BC Hydro's October 31st response to JRP Information Request 77-A): Questions for BC Hydro: Why has BC Hydro ascribed zero value to the ability to modify and adjust smaller individual projects in response to future changes? This omission does not reflect the relative risk allocation of Site C vs the alternatives. There are many cost adjustment penalties applied against IPP alternatives why is Site C not penalized with a cost adjustment to reflect its lack of scalability to be modified in response to future changes? This omission causes a distortion of the true relative risks

6 QUESTION 2: ARE SUNK COSTS EXCLUDED FROM THE PRESENT VALUE COST ANALYSIS? New Information: Page 7 of the BCH Rebuttal states: "Sunk costs, which are costs that have been incurred prior to the current analysis, are not relevant to the decision regarding which resource options available to BC Hydro are cost-effective such costs have been incurred regardless of which resource options are chosen. Accordingly, the Project-related sunk costs (about $5/MWh) should not be included in the Project adjusted UEC. BC Hydro notes that it presents similar adjustments for sunk costs in proceedings before other regulatory bodies such as the British Columbia Utilities Commission (BCUC), and such adjustments have been recognized as a proper component of an incremental cost analysis." Rationale for Question: It is our understanding that the sunk costs of Site C have been excluded from BC Hydro's analysis of Present Value Cost Difference of Site C vs alternatives. Our calculations have determined that sunk costs must currently exceed $400 million to result in an AUEC of $5 per MWh for each MWh of the 70 year period of 2024 to We also understand that the sunk costs for Site C are expected to reach $500 million by the end of F2014 (March 31, 2014). 1 1 See: Amended F12/F14 Revenue Requirement Application, Amended Appendix A, page 12, Schedule

7 If $500 million has indeed been excluded from the PV Cost differentials, we presume that such inclusion will reduce the PV Cost differential by a corresponding $500 million. Reproduced below is the summary sensitivity table from BC Hydro's October 31st response to JRP Information Request 77-A (CEAR #1645): Reducing each of the above PV Cost differentials by $500 million, would result in the majority of sensitivities showing alternatives with a lower PV Cost because the majority of the PV Cost differentials would be negative. This calculation would demonstrate that if the identical analysis occurred several years ago, prior to spending $500 million on Site C, that Site C would have shown a greater PV Cost than alternatives. In other words, Site C requires a "head-start" of $500 million over IPP alternatives because, without such a "head-start", Site C is not cost effective. The huge level of costs already sunk into Site C and the fact that it can swing the PV Cost calculations from lower than alternatives to higher than alternatives shows the hazard of choosing a single huge project compared to the flexibility of choosing smaller projects at a flexible pace

8 Questions for BC Hydro: If the identical analysis of Table 5 had occurred several years ago, prior to spending $500 million on Site C, would Site C have a greater PV Cost than alternatives? What would the present value be for each of the scenarios in Table 5 if the sunk costs (i.e. $500 million) are not excluded from Table 5? Questions for Panel: Could the Panel request that BC Hydro recalculate the PV Cost Differences in Table 5 to include the PV of the sunk costs of Site C, which will correspondingly alter all values of Difference in PV Cost? - 8 -

9 QUESTION 3: New Information: Page 7 of the BCH Rebuttal states: HAS BC HYDRO CONSIDERED THAT IGNORING SUNK COSTS DISTORTS THE REALITY OF RISK OF SMALLER PROJECTS VS A SINGLE MEGA- PROJECT? "Sunk costs, which are costs that have been incurred prior to the current analysis, are not relevant to the decision regarding which resource options available to BC Hydro are cost-effective such costs have been incurred regardless of which resource options are chosen. Accordingly, the Project-related sunk costs (about $5/MWh) should not be included in the Project adjusted UEC. BC Hydro notes that it presents similar adjustments for sunk costs in proceedings before other regulatory bodies such as the British Columbia Utilities Commission (BCUC), and such adjustments have been recognized as a proper component of an incremental cost analysis." Rationale for Question: It is too convenient for BC Hydro to ignore sunk costs of their Site C project while also ignoring the lack of scalability. We agree that sunk costs are previous capital expenditures but sunk costs also represent the risk of total loss when a project is cancelled. This risk is heightened with the inflexibility of a single all-or-nothing project which has no scalability. First Nations are strongly opposed to Site C, and could very well cause its delay or even cancellation. While the IPP sector would minimize sunk costs for projects opposed by First Nations, it appears that BC Hydro is less concerned about rapidly increasing sunk costs on Site C while strong First Nations opposition continues. As mentioned in the previous question, our calculations have determined that sunk costs must currently exceed $400 million to result in an AUEC of $5 per MWh for each MWh for the 70 year period of 2024 to We also understand that the sunk costs for Site C are expected to reach $500 million by the end of F2014 (March 31, 2014). 2 BC Hydro ratepayers pay for costs that BC Hydro has sunk into projects that fail. BC Hydro does not pay for any costs that an IPP sinks into a project that fails. Accordingly, BC Hydro should perform any economic analysis using the assumption that all costs, including sunk costs, must be included in the spending projections. To do otherwise introduces a distortion in the evaluation of alternatives vs. the Site C project as it impacts BC Hydro ratepayers. Because BC Hydro ratepayers ultimately pay for the sunk cost of BC Hydro's failed projects, ignoring them also, ironically, provides BC Hydro an incentive to spend large amounts prior to project approval, because the more it spends or commits prior to approval, the cheaper the project appears to be relative to its alternatives. 2 See: Amended F12/F14 Revenue Requirement Application, Amended Appendix A, page 12, Schedule

10 BC Hydro ratepayers have already paid the price of the cancellation of large projects: Cancelled Projects: Duke Point Generation Plant and GSX Pipeline (cancelled 2004) Hat Creek Coal (cancelled 1983) Total Loss of Sunk Costs: approx. $120 million approx. $70 million We highlight that sunk costs from cancelled IPP projects are not recovered from BC ratepayers; IPP sunk costs are the responsibility of the IPPs shareholders. Reducing the risk of total loss by allowing sunk costs to be ignored distorts the reality of risk allocation. Ignoring the lack of scalability also distorts the reality of risk allocation. Such risks increase with a mega-project. Ignoring the risk of sunk costs is an example of the risk that BC Hydro avoids when compared to the discipline of the IPP sector. Questions for BC Hydro: Has BC Hydro overlooked that losses from IPP sunk costs are not the responsibility of BC ratepayers? Where is this positive benefit of risk allocation represented in the AUEC of the portfolios of the Clean Block and the Clean + Thermal Blocks? Does BC Hydro recognize that many of the theoretical projects in the Clean Block and Clean+Thermal Blocks are, in fact, existing IPP projects, to whom BC Hydro has awarded contracts, that will be cancelled if Site C proceeds and hence their sunk costs will be a total loss to those project developers? Questions for Panel: One or the other, BC Hydro or the IPP, will lose their sunk costs if their project fails or is cancelled, but by allowing BC Hydro's sunk costs to be ignored from analysis during a comparison with IPP alternatives, results in the analysis being extremely biased toward Site C. Could the Panel request that BC Hydro include sunk costs in the comparisons of Site C against alternatives? Has BC Hydro considered that ignoring sunk costs distorts the reality of risk of smaller projects vs a single mega-project such as Site C?

11 QUESTION 4: WHY IS BC HYDRO NOT CONSISTENT WITH THE POLICY OF FORTISBC OF NOT DISCRIMINATING AGAINST IPPS ON THE BASIS OF WACC? New Information: Page 15 of the BCH Rebuttal, regarding Weighted Average Cost of Capital (WACC), states that: for purposes of comparing BC Hydro and IPP projects, there should be recognition that BC Hydro will have a lower cost of capital given its access to the Province of B.C. s high credit rating. Rationale for Questions: We understand that FortisBC avoids discrimination against IPP projects on the basis of cost of capital during its evaluation of resource options. Appendix C - Resource Option Report of the 2012 FortisBC Resource Plan states: "The financial assumptions used to calculate the cost metrics have been standardized to ensure that all resource options are evaluated consistently, regardless of the return expectations and cost of capital that might be applicable to a given project." (emphasis added) Question for BC Hydro: Why would BC Hydro use a different WACC for comparing utility projects vs IPP projects which is contrary to the current policy of FortisBC?

12 QUESTION 5: WHY IS BC HYDRO NOW REVERSING THE PREVIOUS NON-DISCRIMINATORY POLICY REGARDING WACC THAT WAS USED IN 2006? New Information: Page 15 of the BCH Rebuttal, regarding Weighted Average Cost of Capital (WACC), states that: for purposes of comparing BC Hydro and IPP projects, there should be recognition that BC Hydro will have a lower cost of capital given its access to the Province of B.C. s high credit rating. Rationale for Questions: We understand that BC Hydro formerly applied a non-discriminatory policy for evaluating resource options. The 2005 Resource Options Report of BC Hydro's 2006 Integrated Electricity Plan 3 states: "4.2 Comparability and Simplified Analysis Issues BC Hydro is both the purchaser of resources via IPP contracts and the owner of certain resources (primarily hydro projects and transmission projects via BCTC). BC Hydro is striving to ensure that the methods of representing and evaluating resource options are transparent and non-discriminatory.... For these reasons, the following issues have been identified and a recommended approach is described: BC Hydro versus IPP Cost of Capital BC Hydro has access to lower-cost pre-tax debt than IPPs because it has access to government-secured debt. IPPs can deduct interest expenses from earnings. As well, some IPPs may have stronger balance sheets than others and therefore have some advantages over other IPPs. However, such financing advantages do not alter the investment risk inherent in the project. Therefore, it is recommended that the same discount rate be applied to all resource options regardless of who develops them." (emphasis added) Questions for BC Hydro: Why has BC Hydro reversed its non-discriminatory policy on WACC when comparing Site C to IPP projects which was explicitly included in the 2006 Integrated Electricity Plan? 3 See: info_iep_2005_resource_options_report.pdf

13 QUESTION 6: GIVEN INTEREST RATE FLUCTUATIONS, WHY DOES THE WACC FOR SITE C NOT REFLECT THE LONGER TIME TO IN-SERVICE DATE AND THE LONGER PROJECT LIFE AS COMPARED TO IPPS? New Information: Page 2 of the CEBC Undertaking #12 states: "The CEBC wishes to point to the recent change in BC Hydro s WACC as evidence of yet another risk ratepayers face with Site C that they would not have with the Clean + Thermal Generation Portfolio. IPP WACC is fixed for the term of its electricity purchase agreement. BC Hydro s will vary over the life of Site C. The 6% that became 5% could become 6% or 7% or higher over the life of this project. This is not an academic concern because during the construction of BC Hydro s last major hydroelectric project, namely Revelstoke, in the 1970 s and early 80 s sharply rising interest costs dramatically and unexpectedly increased the costs of the project." (emphasis added) Rationale for Question: BC Hydro's previous experience with sharply rising interest rates should result in a WACC for Site C that is higher (not lower) to reflect the greater capital markets risk of a project that has such a long horizon - extending over 80 years: 10 years of construction and 70 years of operation. BC Hydro s assumption of a 5% WACC does not reflect risk nor the likelihood of interest rate fluctuations during the 80 year timeframe. In contrast, IPP projects accept all financing risk during the approximate 5 years to in-service and thereafter for the life of the contract, potentially up to a 40 year period. From the BC Hydro ratepayer s point of view, this is an important difference in the allocation of risk: whether interest rate fluctuations impact directly to the ratepayers (Site C) or whether those fluctuations are isolated to IPPs? To compensate for this severely increased adverse risk over an 80 year period, Site C needs a prudent contingency allowance included in its WACC. Further, the 5% WACC for Site C and the 7% WACC for IPPs distorts the Adjusted Unit Energy Costs in the Evidentiary Update dated September 13, 2013; such distortion favours Site C at the expense of cost effective alternatives. The difference between a 5% cost of capital amortized over 70 years and a 7% cost of capital amortized over 20 years (as BC Hydro imposes on all its wind project AUECs), adds over 80% to the capital portion of the UECs for all the wind projects used in the alternative portfolios. This introduces an egregious distortion into the evaluation of the alternatives to Site C

14 Further, BC Hydro s portfolio analysis indicates that a WACC differential of only 1% reduces the Present Value Cost of the Clean+Thermal Portfolio to within only $20 million of Site C. A present value cost differential of $20 million does not justify the significant adverse impacts of a mega-project of at least $7.9 Billion. This is reproduced below from Page 12 of BC Hydro's October 31 st response to JRP Information Request 77-A (CEAR #1645): This table shows that reducing the WACC Differential from 2% to 1% removes $130 million from the PV Cost of Clean+Thermal a decrease from $150 million (Base Case) to $20 million (WACC Differential = 1%). We estimate that further reducing the WACC differential to 0% would remove a further $130 million from the PV Cost of Clean+Thermal. The revised PV Cost for Clean+Thermal would then be negative $110 million. Therefore, without any difference in WACC, the Clean+Thermal would have a lower PV Cost. In addition, as discussed in Question #2, we note the possibility that $500 million in sunk costs should be included which would reduce the Difference in PV Cost by a corresponding $500 million. This would highlight that if the identical analysis occurred several years ago, prior to spending $500 million on Site C, that Site C would have a greater PV Cost than alternatives even at a 2% WACC Differential, and could be as much as $600 million inferior when evaluated using a non-discriminatory WACC. In other words, Site C requires a head-start of $500 million over IPP alternatives. Without such a headstart, Site C is not cost-effective - even with the advantage of a 2% WACC Differential. Removing the WACC-related distortions is essential to assess whether Site C is, in fact, cost-effective

15 Questions for BC Hydro: Given typical interest rate fluctuations over many years, why does the WACC for Site C not reflect the longer time to in-service date and the longer project life as compared to IPPs? Can BC Hydro confirm that a 0% WACC differential (i.e. elimination of any WACC difference between Site C and the alternative portfolios) would result in a net present value difference of negative $110 million thereby representing lower costs of $110 million for Clean+Thermal as compared to Site C? Question for Panel: Could the Panel request BC Hydro to re-calculate the PV Cost using 6% WACC for both Site C and alternatives as was done under the former policy of non-discrimination? This would provide both a prudent contingency for Site C and would remove the WACC-related distortions to adjusted unit energy costs

16 QUESTION 7: New Information: WHY DOES THE OPTIMIZER INCONSISTENTLY SELECT IPP PROJECTS? Page 3 of the BCH Rebuttal states that the primary means of analyzing alternatives is Present Value modelling using System Optimizer, as follows: "As an introductory point, BC Hydro has been clear that the Portfolio Present Value (PV) modelling using System Optimizer is the primary means of analyzing the cost-effectiveness of the Project and available alternative resources..." Rationale for Question: Presumably the IPP projects are already optimized in the Clean Generation Block but there are many adverse differences in the IPP projects in both the "Clean + Thermal Generation Block #1" and the "Clean + Thermal Generation Block #2" (Pages of the Evidentiary Update dated September 13, 2013). For example, the adverse differences between the Clean Generation Block and the Clean + Thermal Generation Block #2 are reproduced below (removals are shown as "strike-through" and additions are shown in gray): Questions for BC Hydro: If the Optimizer has already optimized, then why remove lower-cost wind projects (AUEC $ ) and insert higher-cost wind projects (AUEC $133)? If the IPP alternatives are already optimized, then why are the IPP projects not consistent between the Clean Block and the Clean+Thermal, subject only to attaining 5,100 GWh of Firm Energy?

17 QUESTION 8: New Information: WHY DOES THE OPTIMIZER REQUIRE EXCESSIVE PUMPED STORAGE? Page 3 of the BCH Rebuttal states that the primary means of analyzing alternatives is Present Value modelling using System Optimizer, as follows: "As an introductory point, BC Hydro has been clear that the Portfolio Present Value (PV) modelling using System Optimizer is the primary means of analyzing the cost-effectiveness of the Project and available alternative resources..." Rationale for Question: We have identified that BC Hydro s "Clean Generation Block" contains 500 MW of Pumped Storage when only 375 MW would be sufficient. This is because the resulting 1244 MW of Dependable Capacity is excessive and that excessive pumped storage results in excessive losses. This is reproduced below: Question for BC Hydro: Why would the Optimizer require excessive pumped storage when seeking alternatives to only 1100 MW of Dependable Capacity?

18 QUESTION 9: WHY HAVE NUMEROUS LARGE BC HYDRO PROJECTS SUFFERED SIGNIFICANT OVERRUNS BETWEEN THE BCUC APPROVED CPCN COST AND THE FINAL COST USED FOR REVENUE REQUIREMENT? New Information: Page 8 of the BCH Rebuttal states: "The Boughton Submission also appears to base its "cost overrun contingency" on a single example of a BC Hydro project cost estimate increase (Northwest Transmission Line). BC Hydro also reviewed a total of 774 self-build projects (over $1 million) completed in the last 5 years. The result is a cost of $11 million over the original expected of $3.3 billion, or within 0.34% of original expected amount. Of these projects, 63% were completed for costs less than the expected amount." Rationale for Question: We believe that BC Hydro may have chosen a large number of smaller projects and may have evaluated them from different starting points for their analysis of 774 projects. Our questions below focus on large projects. Further, we focus below on the CPCN date of the BC Utilities Commission approval as the starting point to identify cost overruns

19 We have analyzed BC Hydro s recent large projects, which should be more typical of the Site C project, and we calculate an average 23% cost overrun between the CPCN Approved Cost ($3,078,050,000) and the Final Cost in accordance with Revenue Requirement ($3,775,950,000). This analysis is below and further detail is provided in Appendix

20 We repeat our assertion that an $11 increase to the AUEC of Site C is a reasonable assumption. This $11 increase will result if Site C experiences a 15% increase in capital costs (Page 9 of BC Hydro's October 31 st response to JRP Information Request 77-A: CEAR #1645). As illustrated by the evidence above, we could argue that a 15% increase is actually conservative based on the track record of 23% over-runs on BC Hydro s large projects. Furthermore, the importance of cost overruns is further illustrated by the sensitivity analyses which show that a capital cost increase of only 10% will reverse the Present Value Cost, which is currently in favour of Site C. With only a 10% capital cost increase, the alternative of Clean+Thermal will have a PV Cost which is $120 million lower than Site C. This is reproduced below from Page 8 of BC Hydro's October 31 st response to JRP Information Request 77-A (CEAR #1645): As discussed in Question #2, we note the possibility that $500 million in sunk costs should be included which will reduce the Difference in PV Cost by a corresponding $500 million. This could highlight that if the identical analysis occurred several years ago, prior to spending $500 million on Site C, that Site C would have shown a greater PV Cost than Clean+Thermal even without any capital cost overrun. In other words, Site C requires a head-start of $500 million over IPP alternatives. Without such a headstart, Site C is not cost-effective even with the advantage of no cost overruns

21 We note that Manitoba Hydro experienced a 60% cost overrun in 2012 when the $900 million original budget estimate for the 200 MW Wuswatkim Dam resulted in a final cost of $1.69 Billion. 4 This large overrun could have partially resulted from a 20 year experience gap since construction by Manitoba Hydro of the last previous large dam project: the 1340 MW Limestone Dam in We note that 40 years will have elapsed between the 2024 In-Service Date of Site C and when BC Hydro last commissioned a new large dam: the 1984 commissioning of the Revelstoke Canyon Dam. Questions for BC Hydro: 1. Did the Vancouver Island Transmission Reinforcement project experience a $49 million cost overrun representing a 19% increase? 2. Did the Aberfeldie project experience a $33 million cost overrun representing a 48% cost increase? 3. Is there any incorrect information in our analysis of BC Hydro s recent large non-retrofit projects and our calculated average 23% cost overrun between the CPCN Approved Cost ($3,078,050,000) and the Final Cost in accordance with Revenue Requirement ($3,775,950,000)? 4. In BC Hydro s analysis of 774 self-build projects, what is meant by original expected amount? 5. Why is the amount registered on the Certificate of Public Convenience and Necessity so often exceeded by the Final Cost in accordance with Revenue Requirement Applications? 4 See: Cost-overruns,-by-nature,-are-unforeseen/1-21 -

22 QUESTION 10: WHY IS GEOTHERMAL DECLARED UNVIABLE WHEN THERE ARE 10 YEARS TO 2024 WHICH IS TWICE THE TIME PERIOD FOR WIND TO EVOLVE FROM NON-EXISTENT IN BC TO THE DOMINANT IPP ALTERNATIVE? New Information: Page 6 of the BCH Rebuttal states: " geothermal resources are not a viable alternative to the Project." The Boughton Submission did not propose that 320 MW of geothermal projects should serve as an alternative to the 1100 MW Site C Project. It proposed a cost effective alternative of 13 generation projects consisting of three wind projects, a run of river project, a wood waste project, a solid waste project and five geothermal projects. Page 6 of the BCH Rebuttal concludes that geothermal is not viable because: " no geothermal resources were bid into BC Hydro s two most recent broadly-based power acquisition processes There are no commercial geothermal electricity projects in B.C. at this time." As previously stated, we highlight that the Boughton Submission only relied upon the 5 geothermal projects that were the 5 projects are already identified and evaluated by BC Hydro in the 2013 Resource Options Report Update of the 2013 Integrated Resources Plan. Rationale for Question: In the last 5 years, wind power in BC has gone from non-existent to being the dominant source renewable generation. Wind power dominates all of the portfolio alternatives of BC Hydro's Evidentiary Update dated September 13, 2013 and the Technical Memo: Alternatives to the Project dated June 4, Prior to 2009, there were no operational wind projects in BC. Today, there are 4 operating wind facilities in BC: Name of Wind Facility / Developer Commercial Operation Date MW Capital Costs Bear Mountain / AltaGas October MW $201 million Dokie Wind / Alterrra February MW $227 million Quality Wind / Capital Power November MW $412 million Cape Scott Wind Farm / GDF Suez December MW $300 million TOTAL = 487 MW $1.1 Billion We highlight that of the approximately 200 renewable IPP bids that BC Hydro received prior to 2006 only two were from wind projects; therefore, the shift to over $1 Billion of wind capital expenditures in last 5 years has been dramatic and rapid

23 Fast forward to wind s domination of the Clean Generation Block in BC Hydro s recent Evidentiary Update. This is reproduced below from Page 34: In fact, wind power in BC has become so viable that BC Hydro s above optimization now completely excludes any run of river projects. This is presumably because small hydro is deemed uncompetitive on a cost basis. However, small run of river hydro projects have historically been the dominant fuel of successful bidders. This was the result in the 2008/2010 Clean Power Call where run of river represented 19 of 27 successful projects and represented 2,342 GWh of the 4,051 GWh of Total Energy. 5 In the 2006 Open Call for Power, run of river also represented over half of successful bids: 2,854 GWh of the total 5,093 GWh. The In-Service Date for Site C is 10 years from now. Competing alternatives such as geothermal have 10 years before they need to be in-service. That is a long time. Especially considering that there are over 11,000 MW of operating geothermal facilities in the world today. BC has great potential amount of geothermal resources; in fact, 780 MW and 5,992 GWh of Firm Energy has already been identified by BC Hydro in Table 3-15 of the 2013 Integrated Resource Plan. Questions for BC Hydro: In its conclusion that geothermal is not viable, did BC Hydro consider that wind power appeared similarly not viable prior to 2006? Would the rationale for dismissing geothermal also have dismissed a resource which now provides nearly 500 MW to BC's current electricity needs and represents over $1 Billion of private capital investment? 5 Table 3-5 of the Report on the RFP Process (August 3, 2010): q3/cpc_rfp_process_report.pdf

24 QUESTION 11: CAN BC HYDRO EXPLAIN WHY ITS $126 AUEC FOR BOUGHTON BLOCK #2 DIFFERS FROM OUR REVISED $120 AUEC ESTIMATE? New Information: Page 7-8 of the BCH rebuttal states: "The Boughton Submission states that Boughton Block #2 has an adjusted UEC of $122/MWh. BC Hydro calculates that Boughton Block #2 has an adjusted UEC of $126/MWh using the Evidentiary Update WACC assumptions and the other smaller changes described in footnote 11 on page 4 of this Rebuttal Evidence. Boughton Block #2 has a higher adjusted UEC than the Project s adjusted UEC of $94/MWh." Rationale for Question: However, we have calculated this alternative with 320 MW of geothermal using the same Evidentiary Update WACC assumptions and footnote 11 assumptions. Our result is an AUEC of $120. This calculation is reproduced below with illustrated changes against the Clean Block of the Evidentiary Update (removals are shown as "strike-through" and additions are shown in gray):

25 Our data sources are the Evidentiary Update and the 2013 Integrated Resources Plan (see Appendix 1). We disagree with a $94 AUEC for Site C; it should have an AUEC of at least $126 based on the following: AUEC Comments $110 Based on 6% WACC from Technical Memo dated June 4, 2013 "Alternatives to the Project" (not based on 5% WACC from the Evidentiary Update dated Sept 13, 2013). + $5 Addition of Sunk Costs + $11 Addition of Cost Overrun Contingency = $126 Our portfolio has an AUEC of $120. Questions for BC Hydro: Can BC Hydro explain why its $126 AUEC for Boughton Block #2 differs from our revised $120 AUEC estimate? Can BC Hydro provide the detailed analysis supporting its calculation of their AUEC? Questions for Panel: Despite the basis of our $120 alternative being a 7% WACC and the $126 Site C is based on 6% WACC, our portfolio is more cost effective. Could the Panel request that BC Hydro calculate what would be the decreased cost of our alternative at a non-discriminatory WACC of 6% for both IPP and Site C? Even without our $16 additions to Site C, would the $110 Site C vs. the $120 alternative still justify the significant adverse impacts imposed by Site C?

26 QUESTION 12: CAN BC HYDRO EXPLAIN WHY ITS $133 AUEC FOR BOUGHTON BLOCK #1 DIFFERS FROM OUR REVISED $129 ESTIMATE? New Information: Page 5-6 of the BCH Rebuttal states: "The Boughton Submission states that Boughton Block #1 has an adjusted UEC of $138/MWh. BC Hydro calculates that Boughton Block #1 has an adjusted UEC of $133/MWh using the Evidentiary Update WACC assumptions and the other smaller changes described in footnote 11 on page 4 of this Rebuttal Evidence. Boughton Block #1 has a higher adjusted UEC than the Project s adjusted UEC of $94/MWh, and is slightly more expensive than BC Hydro's Clean + Thermal Blocks provided in the Evidentiary Update." Rationale for Question: However, we have calculated this alternative with 356 MW of SCGT using the same Evidentiary Update WACC assumptions and footnote 11 assumptions. Our result is an AUEC of $129. This calculation is reproduced below with illustrated changes against the Clean+Thermal Block #2 of the Evidentiary Update (removals are shown as "strike-through" and additions are shown in gray): Our data sources are the Evidentiary Update and the 2013 Integrated Resources Plan (see Appendix 1)

27 We repeat that Site C should have an AUEC of at least $126. This alternative has an AUEC of $129. Questions for BC Hydro: Can BC Hydro explain why its $133 AUEC for Boughton Block #1 differs from our revised $129 estimate? Can BC Hydro provide the detailed analysis supporting its calculation of their AUEC? Questions for Panel: Despite the basis of our $129 alternative being a 7% WACC and the $126 Site C is based on 6% WACC, the costs are nearly identical. Could the Panel request that BC Hydro calculate what would be the decreased cost of our alternative at a non-discriminatory WACC of 6% for both IPP and Site C? Based on $126 vs. $129, does Site C still justify its significant adverse impacts? Even without our $16 additions to Site C, does the $110 Site C still justify the significant adverse impacts imposed by Site C against a $129 alternative that has considerably less impact?

28 QUESTION 13: WHY DID BC HYDRO NOT INCLUDE THE COST EFFECTIVE 560 MW OF CAPACITY AVAILABLE UNDER THE COLUMBIA NON-TREATY STORAGE AGREEMENT AS OPTIONS FOR ALTERNATIVE PORTFOLIOS WITH IPPS? New Information: Page 3 of the BCH Rebuttal states; BC Hydro does not agree that it has overlooked important alternative power generation projects. There is only one resource included in either of the Boughton Blocks geothermal that BC Hydro has not included in its Block Analysis and Portfolio PV modelling. Rationale for Question: The resources from the Columbia River Treaty Storage and Columbia Non-Treaty Storage are extremely costeffective resources within which to firm and shape Clean Block resources. Given that the US has already indicated it is considering less flood protection and increased environmental flows in their initial position for re-negotiation of the Columbia River Treaty which is required between 2014 (notification) and 2024 (expiry), this should be included in the analysis of alternatives to Site C. Columbia River Treaty Downstream Benefits ("CRT-DSBs"): BC Hydro lists the repatriation of the Columbia River Treaty Downstream Benefits as a resource option in its 2013 Integrated Resource Plan (IRP). In the IRP, BC Hydro already proposes to rely on the market backed up by the CRT-DSBs to meet any system capacity shortages during a period of shortfall. Columbia Non-Treaty Storage ("CN-TS"): BC Hydro is providing valuable storage and shaping services to Bonneville Power Administration (BPA) under the Columbia River Non Treaty Storage Agreement (NTSA) at Mica. That service could be used domestically to firm and shape intermittent renewable energy in the Clean Block portfolios. Export profits should not take precedence over domestic customers especially when combined with the ability to avoid the significant adverse impacts of Site C. Furthermore, recall power which formed part of a treaty, was also an important issue to the Joint Federal- Provincial Review Panel for the Lower Churchill projects of Nalcor Energy (824 MW Muskrat Falls and 2250 MW Gull Island hydro projects in Central Labrador). The recommendations of this Joint Federal-Provincial Review Panel in the 2011 decision included: " why Nalcor s least cost alternative to meet domestic demand to 2067 does not include Churchill Falls power which would be available in large quantities from 2041, or any recall power in excess of Labrador s needs prior to that date, especially since both would be available at near zero generation cost (recognizing that there would be transmission costs involved);" (emphasis added) 6 6 See: Page 25 of the Executive Summary:

29 It is our understanding that the CN-TS allocated to Bonneville Power is approximately 560 MW of capacity and 1,440 GWh of Firm Energy. This is because only four generating units were originally installed at Mica for a combined maximum capacity of 1805 MW and energy is reported as 7,202 GWh. However, Mica was originally designed to hold six generating units and we understand that BC Hydro is adding those two generating units to attain 2800 MW of maximum capacity. We estimate that the Non-Treaty Storage is equal to approximately 40% of 2800 MW = 1120 MW of which half is allocated to Bonneville Power (560 MW and 1440 GWh) Further, we understand that this CN-TS of 560 MW and 1440 GWh will be available at very cost effective rates. From discussions with several energy industry participants, we understand that the Unit Capacity Cost of the planned upgrades of GMS should provide an accurate estimate: $35 per KW-yr. We understand that the Wind Integration Cost should provide an accurate estimate for the UEC of the 1440 GWh of Firm Energy: $15 per MWh. We can re-calculate the Clean Block to an AUEC of only $100 when using the 560 MW CN-TS to replace the 500 MW Pumped Storage and the 220 MW GMS. This calculation is reproduced below with illustrated changes against the Clean Block of the Evidentiary Update (removals are shown as "strike-through" and additions are shown in gray):

30 BC Hydro claims that Site C has a AUEC of $110 at 6% WACC or $94 at 5% WACC. Even without the previously discussed $16 additions to Site C, the $110 AUEC for Site C would not be cost effective against this $100 alternative. While the $94 AUEC for Site C is only barely cost effective against this $100 alternative, we do not believe that Site C would justify the significant adverse impacts. Questions for BC Hydro: 1. Regarding the Columbia River Treaty: a. Confirmation that the Assured Annual Flood Control storage at the three BC Treaty dams is 8.45 million acre feet. b. Confirmation that, unless renegotiated, the Assured Annual Flood Control provision expires in 2024 and it reverts back to BC. 2. Regarding the CN-TS and NTSA: a. Confirmation that successive agreements between BC Hydro and BPA in relation to initial filling non Treaty reservoirs and the use of Columbia River Non-Treaty Storage have expired and that short term, seasonal non-treaty storage agreements were in place between 2006 to b. Confirmation that the NTSA with Bonneville Power dated 2012 expires at 2400hrs on September 15, c. Confirmation that the NTSA can be cancelled on December 31 of any calendar year with two years notice and notification by September 1 of any calendar year. d. Confirmation that the NTSA storage was built into Mica when it constructed as part of the Columbia River Treaty and it currently exists at Mica. e. Confirmation that the NTSA live storage at Mica is 5 million acre feet (MAF). f. Confirmation that the NTSA allocates 1.5 MAF to Bonneville Power under an active account and 1.0 MAF under a recallable account. g. Confirm the storage and shaping capacity and energy of the 2.5 MAF of live storage allocated to BPA at Mica under the NTSA. 3. Regarding the Downstream Benefits: a. Confirmation that these benefits could be available in the future for alternatives. b. Why did BC Hydro not include the repatriation of the Columbia River Treaty Downstream Benefits (CRT-DSBs) as a resource option in one of its alternatives? 4. Regarding the AUEC of $100 for the above alternative with 560 MW of CN-TS: a. Why did BC Hydro not include the use of Columbia Non-Treaty Storage (CN-TS) as a resource option in one of its alternatives? b. Did BC Hydro consider the alternative portfolio above which has an AUEC of $100? If not, why not? c. Are there any incorrect assumptions with our alternative using 560 MW of CN-TS including a Unit Energy Cost of $15 per MWh and a Unit Capacity Cost of $35 per kw-yr?

31 Questions for Panel: Could the Panel request that BC Hydro recalculate the Clean Blocks and the Clean+Thermal Blocks with capacity from Columbia River Treaty Assured Flood Control Storage? Could the Panel request that BC Hydro recalculate the Clean Blocks and Clean+Thermal Blocks with capacity from Columbia Non-Treaty Storage? Could the Panel request an explanation from BC Hydro why, during the multi-year development of the Site C EIS, that BC Hydro did not more fully consider the available alternative of CN-TS?

32 QUESTION 14: IS THE RATIO OF CAPITAL COST TO INSTALLED CAPACITY FOR SITE C EQUAL TO $7,200 / KW AND HOW DOES THIS COMPARE TO THE $4,250 / KW FOR THE PROPOSED 565 MW KLEANA HYDRO PROJECT? New Information: Slide 3 of the presentation by Dr. Eunall on December 10, 2013 regarding the 565 MW Kleana Project states: Projected Total Capex of $2.4 billion, under $4,250/kW installed, (For reference Site C projection is $7,200/kW). Slide 4 of the presentation by Dr. Eunall also states: "Broad local First Nation support and partnerships." Slide 6 of the presentation by Dr. Eunall also states: Project Status: Fixed firm price bid into last Clean Call. Project was a finalist. Rationale for Question: Since the Kleana project was bid into BC Hydro and was thoroughly reviewed prior to being selected as a finalist, BC Hydro has the necessary information to calculate Kleana s Capital Cost to Installed Capacity Ratio. Furthermore, the Kleana project has the support of local First Nations. We understand that BC Hydro s fundamental premise for requesting approval of Site C is that the significant adverse impacts are justified because Site C is claimed to be cost effective. This premise was recently echoed by Bill Bennett, Minister of Energy and Mines, in the Vancouver Sun on December 7, 2013, as follows: Governments make decisions on balance, and the balance in this case leads us to think this is the best available source of a large amount of electricity, and that justifies the environmental impact. Kleana appears to have a capital to capacity ratio which is more than 40% less than Site C. It is unclear how Site C compares to Kleana on the basis of capital to energy ratio ($/MWh). Question for BC Hydro: Is the ratio of capital cost to installed capacity for Site C equal to $7,200 per KW and how does this compare to the $4,250 per KW for the proposed 565 MW Kleana hydro project? How does Site C compare to Kleana on the basis of capital cost per MWh?

33 QUESTION 15: HOW DOES SITE C COMPARE, ON AN IMPACTED SURFACE FOOTPRINT PER KWH BASIS, TO OTHER GREENFIELD HYDRO PROJECTS IN BC? New Information: Slide 4 of the presentation by Dr. Eunall on December 10, 2013 regarding the 565 MW Kleana Project states: One of the lowest surface footprint per kwh for any known water based project. Slide 3 of the presentation by Dr. Eunall also states: "Entire diversion underground with no surface footprint" Slide 5 of the presentation by Dr. Eunall also states: The Kleana Information Sheet submitted December 10, 2013 states: The Kleana project would have the smallest environmental footprint per kilowatt-hour of any new greenfield power project in B.C.... Question for BC Hydro: How does Site C compare, on an impacted surface footprint per kwh basis, to other greenfield hydro projects in B.C., including large run-of-river IPP projects such as Kleana, Forrest Kerr, Ashlu, Mamquam and Toba- Montrose?